UGI (UGI) 10-Q 7 Aug 14 2014 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Jun. 30, 2014	Jul. 31, 2014
Document and Entity Information [Abstract]	'	'
Entity Registrant Name	'UGI CORP /PA/	'
Entity Central Index Key	'0000884614	'
Document Type	'10-Q	'
Document Period End Date	30-Jun-14	'
Amendment Flag	'false	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q3	'
Current Fiscal Year End Date	'--09-30	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	114,922,662

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (unaudited) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Current assets:	'	'	'
Cash and cash equivalents	$438.40	$389.30	$401.80
Restricted cash	5.9	8.3	6
Accounts receivable (less allowances for doubtful accounts of $52.5, $39.5 and $48.0, respectively)	785.4	745.6	752.6
Accrued utility revenues	8	18.9	11.8
Inventories	332	365.5	304
Deferred income taxes	9.1	10.6	6.6
Utility regulatory assets	9.4	8.2	3.7
Derivative financial instruments	12.4	23.8	18.7
Prepaid expenses and other current assets	38.3	57.1	36.1
Total current assets	1,638.90	1,627.30	1,541.30
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,702.3, $2,560.3 and $2,495.4, respectively)	4,543.40	4,480.20	4,323.70
Goodwill	2,885.10	2,871	2,834
Intangible assets, net	590.3	610.6	608.6
Other assets	420	419.7	499.2
Total assets	10,077.70	10,008.80	9,806.80
Current liabilities:	'	'	'
Current maturities of long-term debt	78.4	67.2	195.6
Bank loans	96.5	227.9	135.9
Accounts payable	403.8	472.3	384.5
Derivative financial instruments	26.2	30	56.8
Other current liabilities	609.3	627.5	552.9
Total current liabilities	1,214.20	1,424.90	1,325.70
Long-term debt	3,477.80	3,542.20	3,298.20
Deferred income taxes	986.2	962.3	933.5
Deferred investment tax credits	4	4.3	4.4
Other noncurrent liabilities	514.7	527.2	616.9
Total liabilities	6,196.90	6,460.90	6,178.70
Commitments and contingencies (Note 10)	'	'	'
UGI Corporation stockholders’ equity:	'	'	'
UGI Common Stock, without par value (authorized—300,000,000 shares; issued — 115,830,694, 115,783,794 and 115,759,694 shares, respectively)	1,216	1,208.10	1,192.90
Retained earnings	1,566.70	1,308.30	1,354.90
Accumulated other comprehensive income (loss)	25.4	8.4	-27.4
Treasury stock, at cost	-37.1	-32.3	-26.2
Total UGI Corporation stockholders’ equity	2,771	2,492.50	2,494.20
Noncontrolling interests, principally in AmeriGas Partners	1,109.80	1,055.40	1,133.90
Total equity	3,880.80	3,547.90	3,628.10
Total liabilities and equity	$10,077.70	$10,008.80	$9,806.80

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Millions, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'	'
Accounts receivable, allowances for doubtful accounts	$52.50	$39.50	$48
Property, plant and equipment, accumulated depreciation and amortization	$2,702.30	$2,560.30	$2,495.40
UGI Common Stock, without par value (in dollars per share)	'	'	'
UGI Common Stock, without par value, shares authorized (in shares)	300,000,000	300,000,000	300,000,000
UGI Common Stock, without par value, shares issued (in shares)	115,830,694	115,783,794	115,759,694

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Income (unaudited) (USD $)	3 Months Ended		9 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Statement [Abstract]	'	'	'	'
Revenues	$1,486.70	$1,374.30	$6,965.90	$5,935.70
Costs and expenses:	'	'	'	'
Cost of sales (excluding depreciation shown below)	926.5	836.8	4,357.70	3,539
Operating and administrative expenses	415.9	407.5	1,339.40	1,295.90
Utility taxes other than income taxes	3.7	3.7	12.7	12.7
Depreciation	74.6	76.4	230	222.9
Amortization	15.4	15.4	41.7	46.3
Other income, net	-12.1	-7	-30.6	-24.5
Total costs and expenses	1,424	1,332.80	5,950.90	5,092.30
Operating income	62.7	41.5	1,015	843.4
(Loss) income from equity investees	-0.1	0	-0.1	0.1
Interest expense	-60.1	-59.2	-178.9	-180.8
Income (loss) before income taxes	2.5	-17.7	836	662.7
Income tax expense	-15.2	-5.1	-243.4	-176
Net (loss) income	-12.7	-22.8	592.6	486.7
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners	33.3	31.9	-235.6	-194.4
Net income attributable to UGI Corporation	$20.60	$9.10	$357	$292.30
Earnings per common share attributable to UGI Corporation stockholders:	'	'	'	'
Basic (in dollars per share)	$0.18	$0.08	$3.10	$2.57
Diluted (in dollars per share)	$0.18	$0.08	$3.06	$2.54
Average common shares outstanding (thousands):	'	'	'	'
Basic (in shares)	115,370	114,240	115,121	113,693
Diluted (in shares)	117,048	116,196	116,731	115,275
Dividends declared per common share (in dollars per share)	$0.30	$0.28	$0.86	$0.82

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Statement of Comprehensive Income [Abstract]	'	'	'	'
Net (loss) income	($12.70)	($22.80)	$592.60	$486.70
Other comprehensive income (loss):	'	'	'	'
Net (losses) gains on derivative instruments (net of tax of $0.6, $(4.1) $(6.5) and $(7.1), respectively)	-0.6	-7.6	46.2	-7.2
Reclassifications of net (gains) losses on derivative instruments (net of tax of $(1.3), $(2.1), $4.0 and $(9.8), respectively)	-1.5	9.7	-46.7	52.3
Foreign currency adjustments (net of tax of $0.0, $(2.4), $(3.1) and $1.8, respectively)	-0.2	8.8	11.5	1.3
Benefit plans (net of tax of $(0.2), $(0.2), $(0.2) and $(0.7), respectively)	0.2	0.3	0.8	1.1
Other comprehensive (loss) income	-2.1	11.2	11.8	47.5
Comprehensive (loss) income	-14.8	-11.6	604.4	534.2
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	36.5	39.9	-230.4	-214
Comprehensive income attributable to UGI Corporation	$21.70	$28.30	$374	$320.20

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Statement of Comprehensive Income [Abstract]	'	'	'	'
Tax on (loss) gain on derivative instruments	$0.60	($4.10)	($6.50)	($7.10)
Tax on reclassifications on derivative instruments	-1.3	-2.1	4	-9.8
Tax on foreign currency adjustments	0	-2.4	-3.1	1.8
Tax on benefit plans	($0.20)	($0.20)	($0.20)	($0.70)

Condensed_Consolidated_Stateme3

Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net income	$592.60	$486.70
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation and amortization	271.7	269.2
Deferred income taxes, net	21.2	32.2
Provision for uncollectible accounts	38.2	23.9
Unrealized losses on derivative instruments	3.1	-0.7
Other, net	-4.9	-3.6
Net change in:	'	'
Accounts receivable and accrued utility revenues	-56.4	-146.2
Inventories	34.8	51.3
Utility deferred fuel and power costs, net of changes in unsettled derivatives	-17.6	20.5
Accounts payable	-40.8	-25.5
Other current assets	11.2	52.4
Other current liabilities	5	-73.8
Net cash provided by operating activities	858.1	686.4
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Expenditures for property, plant and equipment	-325.5	-291.6
Acquisitions of businesses, net of cash acquired	-23.3	-24.3
Decrease (increase) in restricted cash	2.4	-3
Other, net	9	2.2
Net cash used by investing activities	-337.4	-316.7
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Dividends on UGI Common Stock	-98.6	-93.4
Distributions on AmeriGas Partners Common Units	-176.9	-168.5
Issuances of debt	175	0
Repayments of debt	-236.8	-28.5
Decrease in bank loans	-74.6	-39
Receivables Facility net (repayments) borrowings	-57	9.5
Issuances of UGI Common Stock	7	28.5
Repurchases of UGI Common Stock	-21.4	0
Other	7.9	5.4
Net cash used by financing activities	-475.4	-286
EFFECT OF EXCHANGE RATE CHANGES ON CASH	3.8	-1.8
Cash and cash equivalents increase	49.1	81.9
Cash and cash equivalents:	'	'
End of period	438.4	401.8
Beginning of period	389.3	319.9
Increase	$49.10	$81.90

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	Treasury Stock	Noncontrolling Interests
In Millions, unless otherwise specified
Balance, beginning of period at Sep. 30, 2012	'	'	$1,157.70	$1,156	($55.20)	($28.70)	$1,085.60
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'
Common Stock issued in connection with employee and director plans (including gains (losses) on treasury stock transactions), net of tax withheld	'	'	19.7	'	'	20.8	'
Dividend reinvestment plan	'	'	1.4	'	'	0.8	'
Excess tax benefits realized on equity-based compensation	'	'	5.7	'	'	'	'
Equity-based compensation expense	'	'	8.4	'	'	'	'
Net income attributable to UGI Corporation	292.3	'	'	292.3	'	'	'
Cash dividends on Common Stock	'	'	'	-93.4	'	'	'
Net gains on derivative instruments, net of tax	-7.2	'	'	'	10.5	'	'
Reclassification of net (gains) losses on derivative instruments, net of tax	52.3	'	'	'	14.9	'	'
Benefit plans, net of tax	-1.1	'	'	'	1.1	'	'
Foreign currency, net of tax	1.3	'	'	'	1.3	'	'
Repurchases of Common Stock	'	'	'	'	'	0	'
Reacquired Common Stock - employee and director plans	'	'	'	'	'	-19.1	'
Net income attributable to noncontrolling interests, principally in AmeriGas Partners	194.4	'	'	'	'	'	194.4
Net gains (losses) on derivative instruments	'	'	'	'	'	'	-17.7
Reclassification of net (gains) losses on derivative instruments	'	'	'	'	'	'	37.3
Dividends and distributions	'	'	'	'	'	'	-168.7
Other	'	'	'	'	'	'	3
Balance, end of period at Jun. 30, 2013	3,628.10	2,494.20	1,192.90	1,354.90	-27.4	-26.2	1,133.90
Balance, beginning of period at Sep. 30, 2013	3,547.90	'	1,208.10	1,308.30	8.4	-32.3	1,055.40
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'
Common Stock issued in connection with employee and director plans (including gains (losses) on treasury stock transactions), net of tax withheld	'	'	-9.6	'	'	46.7	'
Dividend reinvestment plan	'	'	0	'	'	0	'
Excess tax benefits realized on equity-based compensation	'	'	8.4	'	'	'	'
Equity-based compensation expense	'	'	9.1	'	'	'	'
Net income attributable to UGI Corporation	357	'	'	357	'	'	'
Cash dividends on Common Stock	'	'	'	-98.6	'	'	'
Net gains on derivative instruments, net of tax	46.2	'	'	'	12.3	'	'
Reclassification of net (gains) losses on derivative instruments, net of tax	-46.7	'	'	'	-7.6	'	'
Benefit plans, net of tax	-0.8	'	'	'	0.8	'	'
Foreign currency, net of tax	11.5	'	'	'	11.5	'	'
Repurchases of Common Stock	'	'	'	'	'	-21.4	'
Reacquired Common Stock - employee and director plans	'	'	'	'	'	-30.1	'
Net income attributable to noncontrolling interests, principally in AmeriGas Partners	235.6	'	'	'	'	'	235.6
Net gains (losses) on derivative instruments	'	'	'	'	'	'	33.9
Reclassification of net (gains) losses on derivative instruments	'	'	'	'	'	'	-39.1
Dividends and distributions	'	'	'	'	'	'	-176.9
Other	'	'	'	'	'	'	0.9
Balance, end of period at Jun. 30, 2014	$3,880.80	$2,771	$1,216	$1,566.70	$25.40	($37.10)	$1,109.80

Nature_of_Operations

Nature of Operations	9 Months Ended
	Jun. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Nature of Operations	'
	Nature of Operations
	UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes 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 retail 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”) and, prior to its merger with AmeriGas OLP on July 1, 2013 (the “Merger”), AmeriGas OLP’s principal operating subsidiary Heritage Operating, L.P. (“HOLP”). AmeriGas OLP after the Merger, and AmeriGas OLP and HOLP prior to the Merger, are collectively 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 June 30, 2014, the General Partner held a 1% general partner interest and 25.3% limited partner interest in AmeriGas Partners and 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 at June 30, 2014, comprises 69,109,914 publicly held Common Units of which 4,367,362 Common Units are held by a subsidiary of Energy Transfer Partners, L.P. (“ETP”) as a result of the January 12, 2012, acquisition of substantially all of ETP’s propane operations (“Heritage Propane”). In January 2014 and June 2014, ETP sold 9,200,000 and 8,500,000, respectively, of the Common Units it held in underwritten public offerings, pursuant to its registration rights in its unitholder agreement. AmeriGas Partners did not receive any proceeds from either sale of Common Units by ETP.
	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 (which was formerly known as UGI Energy Services, Inc. prior to its merger with and into UGI Energy Services, LLC effective October 1, 2013) and its subsidiaries conduct an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic region of the United States. 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 subsequent to the merger and UGI Energy Services, Inc. prior to the merger are 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 and electric distribution utility businesses are 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.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” 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, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”

Significant_Accounting_Policie

Significant Accounting Policies	9 Months Ended
	Jun. 30, 2014
Accounting Policies [Abstract]	'
Significant Accounting Policies	'
	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 and ETP’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 all significant 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, 2013, 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 our Annual Report on Form 10-K for the fiscal year ended September 30, 2013 (the “Company’s 2013 Annual Financial Statements and Notes”). 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.
	Restricted Cash. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
	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					Nine Months Ended
			June 30,					June 30,
			2014		2013			2014			2013
	Denominator (thousands of shares):
	Average common shares outstanding for basic computation		115,370		114,240			115,121			113,693
	Incremental shares issuable for stock options and awards		1,678		1,956			1,610			1,582
	Average common shares outstanding for diluted computation		117,048		116,196			116,731			115,275
	Comprehensive Income. Comprehensive income (loss) comprises net income (loss) and other comprehensive income (loss). Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and intracompany transaction adjustments.
	Changes in accumulated other comprehensive income (“AOCI”) during the three and nine months ended June 30, 2014, are as follows:
	Three Months Ended June 30, 2014:	Postretirement			Derivative				Foreign
		Benefit Plans			Instruments				Currency			Total
	Balance, March 31, 2014	$	(15.8	)	$	(23.3	)		$	63.4		$	24.3
	Other comprehensive (loss) before reclassification adjustments (after-tax)	—			(0.6		)		(0.2		)	(0.8		)
	Amounts reclassified from AOCI and noncontrolling interests:
	Reclassification adjustments (pre-tax)	0.4			(0.2		)		—			0.2
	Reclassification adjustments tax (expense) benefit	(0.2		)	(1.3		)		—			(1.5		)
	Reclassification adjustments (after-tax)	0.2			(1.5		)		—			(1.3		)
	Other comprehensive income (loss)	0.2			(2.1		)		(0.2		)	(2.1		)
	Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			3.2				—			3.2
	Other comprehensive income (loss) attributable to UGI	0.2			1.1				(0.2		)	1.1
	Balance, June 30, 2014	$	(15.6	)	$	(22.2	)		$	63.2		$	25.4
	Nine Months Ended June 30, 2014:	Postretirement			Derivative				Foreign
		Benefit Plans			Instruments				Currency			Total
	Balance, September 30, 2013	$	(16.4	)	$	(26.9	)		$	51.7		$	8.4
	Other comprehensive income before reclassification adjustments (after-tax)	—			46.2				11.5			57.7
	Amounts reclassified from AOCI and noncontrolling interests:
	Reclassification adjustments (pre-tax)	1			(50.7		)		—			(49.7		)
	Reclassification adjustments tax (expense) benefit	(0.2		)	4				—			3.8
	Reclassification adjustments (after-tax)	0.8			(46.7		)		—			(45.9		)
	Other comprehensive income (loss)	0.8			(0.5		)		11.5			11.8
	Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			5.2				—			5.2
	Other comprehensive income attributable to UGI	0.8			4.7				11.5			17
	Balance, June 30, 2014	$	(15.6	)	$	(22.2	)		$	63.2		$	25.4
	For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 12 to condensed consolidated financial statements.
	Income Taxes. In December 2013, the French Parliament approved the Finance Bill for 2014 and amended the Finance Bill for 2013 (collectively, the “Finance Bills”). Among other things, the Finance Bills limit Antargaz’ ability to deduct interest expense for income tax purposes on certain intercompany debt and temporarily increases the corporate surtax rate for a period of two years. Based upon our review of the Finance Bills and interpretive guidance currently available, provisions of the Finance Bills associated with the deductibility of interest expense on certain intercompany debt at Antargaz applies retroactively to such interest expense incurred during Fiscal 2013. In December 2013, the Company recorded additional income taxes of $5.7 to reflect the effects of the retroactive provisions of the Finance Bills associated with the deductibility of interest expense on certain intercompany debt.
	Reclassifications. Certain prior period amounts have been reclassified to conform to current period presentation.
	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.

Restatements_of_Condensed_Cons

Restatements of Condensed Consolidated Financial Statements	9 Months Ended
	Jun. 30, 2014
Revisions of Condensed Consolidated Financial Statements [Abstract]	'
Restatements of Condensed Consolidated Financial Statements	'
	Revisions of Condensed Consolidated Financial Statements
	During the preparation of the Fiscal 2013 consolidated financial statements, management concluded that it had incorrectly accounted for certain commodity derivative instruments as cash flow hedges. Management had incorrectly applied the hedge accounting criteria when designating certain commodity derivative instruments at its Midstream & Marketing businesses as cash flow hedges. Management has discontinued the use of hedge accounting for Midstream & Marketing’s commodity derivative instruments and reports changes in the fair values of unsettled commodity derivative instruments, and gains and losses on settled commodity derivatives for which the associated forecasted transaction has not yet occurred, in net income.
	The Company had previously determined that the impact of the error was not material to the Company’s historical condensed consolidated statements of income for the three and nine months ended June 30, 2013. However, in conjunction with its conclusion that the error was material to the three months ended March 31, 2013, the Company decided to revise its consolidated financial statements for the three and nine months ended June 30, 2013. Accordingly, the accompanying condensed consolidated financial statements as of June 30, 2013, and for the three and nine months ended June 30, 2013, have been revised to report changes in the fair values of unsettled commodity derivative instruments and gains and losses on settled commodity derivative instruments for which the associated forecasted transactions have not yet occurred in cost of sales or revenues in the Condensed Consolidated Statement of Income rather than in other comprehensive income.
	The following tables set forth the effects of the revisions on the affected line items within the Company’s previously reported condensed consolidated financial statements as of and for the three and nine months ended June 30, 2013. Also included in the adjustment columns in the tables below are certain other immaterial corrections that the Company made, including, but not limited to, adjustments to correct the Partnership’s accounting for certain customer credits and to correct the classification of deferred income tax assets, as well as certain other minor adjustments related principally to the timing of certain expense and income accruals.
	Condensed Consolidated Balance Sheet
		30-Jun-13
		As Previously Reported			Adjustment			As Revised
	Assets:
	Deferred income taxes	$	27.3		$	(20.7	)	$	6.6
	Property, plant and equipment	$	4,325.00		$	(1.3	)	$	4,323.70
	Liabilities and equity:
	Deferred income taxes	$	956.9		$	(23.4	)	$	933.5
	Other noncurrent liabilities	$	613.5		$	3.4		$	616.9
	Retained earnings	$	1,361.90		$	(7.0	)	$	1,354.90
	Accumulated other comprehensive loss	$	(30.7	)	$	3.3		$	(27.4	)
	Noncontrolling interests, principally in AmeriGas Partners	$	1,132.20		$	1.7		$	1,133.90
	Condensed Consolidated Statement of Income
		For the three months ended June 30, 2013									For the nine months ended June 30, 2013
		As Previously Reported			Adjustment			As Revised			As Previously Reported			Adjustment			As Revised
	Revenues	$	1,372.30		$	2		$	1,374.30		$	5,932.60		$	3.1		$	5,935.70
	Cost of sales	$	827.9		$	8.9		$	836.8		$	3,547.30		$	(8.3	)	$	3,539.00
	Operating and administrative expenses	$	404.7		$	2.8		$	407.5		$	1,297.40		$	(1.5	)	$	1,295.90
	Depreciation	$	76.5		$	(0.1	)	$	76.4		$	220		$	2.9		$	222.9
	Other income, net	$	(9.0	)	$	2		$	(7.0	)	$	(26.5	)	$	2		$	(24.5	)
	Operating income	$	53.1		$	(11.6	)	$	41.5		$	835.4		$	8		$	843.4
	Interest expense	$	(59.2	)	$	—		$	(59.2	)	$	(179.6	)	$	(1.2	)	$	(180.8	)
	Income (loss) before income taxes	$	(6.1	)	$	(11.6	)	$	(17.7	)	$	655.9		$	6.8		$	662.7
	Income taxes	$	(9.0	)	$	3.9		$	(5.1	)	$	(174.1	)	$	(1.9	)	$	(176.0	)
	Net (loss) income	$	(15.1	)	$	(7.7	)	$	(22.8	)	$	481.8		$	4.9		$	486.7
	Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners	$	29.8		$	2.1		$	31.9		$	(192.6	)	$	(1.8	)	$	(194.4	)
	Net income attributable to UGI Corporation	$	14.7		$	(5.6	)	$	9.1		$	289.2		$	3.1		$	292.3
	Basic earnings per common share	$	0.13					$	0.08		$	2.54					$	2.57
	Diluted earnings per common share	$	0.13					$	0.08		$	2.51					$	2.54
	Condensed Consolidated Statement of Comprehensive Income
		For the three months ended June 30, 2013									For the nine months ended June 30, 2013
		As Previously Reported			Adjustment			As Revised			As Previously Reported			Adjustment			As Revised
	Net (loss) income	$	(15.1	)	$	(7.7	)	$	(22.8	)	$	481.8		$	4.9		$	486.7
	Net losses on derivative instruments	$	(11.0	)	$	3.4		$	(7.6	)	$	(11.1	)	$	3.9		$	(7.2	)
	Reclassifications of net losses on derivative instruments	$	8.9		$	0.8		$	9.7		$	59.7		$	(7.4	)	$	52.3
	Other comprehensive income	$	7		$	4.2		$	11.2		$	51		$	(3.5	)	$	47.5
	Comprehensive (loss) income	$	(8.1	)	$	(3.5	)	$	(11.6	)	$	532.8		$	1.4		$	534.2
	Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	$	37.8		$	2.1		$	39.9		$	(212.2	)	$	(1.8	)	$	(214.0	)
	Comprehensive income attributable to UGI Corporation	$	29.7		$	(1.4	)	$	28.3		$	320.6		$	(0.4	)	$	320.2
	Condensed Consolidated Statements of Cash Flows
		For the nine months ended June 30, 2013
	CASH FLOWS FROM OPERATING ACTIVITIES:	As Previously Reported			Adjustment			As Revised
	Net income	$	481.8		$	4.9		$	486.7
	Depreciation and amortization	$	266.3		$	2.9		$	269.2
	Deferred income taxes, net	$	35.5		$	(3.3	)	$	32.2
	Net change in realized gains and losses deferred as cash flow hedges	$	5		$	(5.0	)	$	—
	Unrealized losses on derivative instruments	$	—		$	(0.7	)	$	(0.7	)
	Other, net	$	(11.3	)	$	7.7		$	(3.6	)
	Net change in:
	Accounts receivable and accrued utility revenues	$	(141.1	)	$	(5.1	)	$	(146.2	)
	Inventories	$	54.1		$	(2.8	)	$	51.3
	Accounts payable	$	(26.9	)	$	1.4		$	(25.5	)
	Other current liabilities	$	(73.8	)	$	—		$	(73.8	)
	Condensed Consolidated Statements of Changes in Equity
		For the nine months ended June 30, 2013
		As Previously Reported			Adjustment			As Revised
	Retained earnings	$	1,361.90		$	(7.0	)	$	1,354.90
	Accumulated other comprehensive loss	$	(30.7	)	$	3.3		$	(27.4	)
	Noncontrolling interests	$	1,132.20		$	1.7		$	1,133.90

Accounting_Changes

Accounting Changes	9 Months Ended
	Jun. 30, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
Accounting Changes	'
	Accounting Changes
	Adoption of New Accounting Standards
	Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In Fiscal 2014, the Company adopted new accounting guidance regarding disclosures for items reclassified out of AOCI. The disclosures required by the new accounting guidance are included in Note 2 and Note 12 to the condensed consolidated financial statements. The new disclosures are applied prospectively. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.
	Disclosures about Offsetting Assets and Liabilities. Effective October 1, 2013, the Company adopted new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet as a result of an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new disclosures are applied retroactively to all periods presented. The required disclosures are included in Note 11 to the condensed consolidated financial statements. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.
	Accounting Standards Not Yet Adopted
	Revenue Recognition. In May 2014, the Financial Accounting Standards Board (“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 605, “Revenue Recognition,” and most industry-specific guidance included in the Codification. 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.
	Discontinued Operations. In April 2014, the FASB issued authoritative guidance amending existing requirements for reporting discontinued operations.  Under the new guidance, discontinued operations reporting will be limited to disposal transactions that represent strategic shifts having a major effect on operations and financial results. The amended guidance also enhances disclosures and requires assets and liabilities of a discontinued operation to be classified as such for all periods presented in the financial statements. Public entities will apply the amended guidance prospectively to all disposals occurring within annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company will adopt this standard on October 1, 2015. Due to the change in requirements for reporting discontinued operations described above, presentation and disclosure of future disposal transactions after adoption may be different than under current standards.

Goodwill_and_Intangible_Assets

Goodwill and Intangible Assets	9 Months Ended
	Jun. 30, 2014
Goodwill and Intangible Assets Disclosure [Abstract]	'
Goodwill and Intangible Assets	'
	Goodwill and Intangible Assets
	Goodwill and intangible assets comprise the following:
		June 30,			September 30,			June 30,
		2014			2013			2013
	Goodwill (not subject to amortization)	$	2,885.10		$	2,871.00		$	2,834.00
	Intangible assets:
	Customer relationships, noncompete agreements and other	$	717.3		$	706.4		$	692.6
	Trademarks and tradenames (not subject to amortization)	132			131.3			128.4
	Gross carrying amount	849.3			837.7			821
	Accumulated amortization	(259.0		)	(227.1		)	(212.4		)
	Intangible assets, net	$	590.3		$	610.6		$	608.6
	We amortize customer relationship and noncompete agreement intangible assets over their estimated periods of benefit which do not exceed 15 years. Amortization expense of intangible assets was $13.3 and $35.5 in the three and nine months ended June 30, 2014, respectively, and $13.3 and $40.2 in the three and nine months ended June 30, 2013, respectively. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. As of June 30, 2014, our expected aggregate amortization expense of intangible assets for the remainder of Fiscal 2014 and for the next four fiscal years is as follows: remainder of Fiscal 2014 — $13.1; Fiscal 2015 — $50.6; Fiscal 2016 — $44.2; Fiscal 2017 — $37.6; Fiscal 2018 — $36.3.

Segment_Information

Segment Information	9 Months Ended
	Jun. 30, 2014
Segment Reporting [Abstract]	'
Segment Information	'
	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, “Significant Accounting Policies” in the Company’s 2013 Annual Financial Statements and Notes. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership 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 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.
	Three Months Ended June 30, 2014:
																		Midstream & Marketing							UGI International
			Total			Eliminations				AmeriGas				Gas				Energy Services				Electric Generation			Antargaz				Flaga &				Corporate
										Propane				Utility															Other				& Other (b)
	Revenues		$	1,486.70		$	(50.8	)	(c)	$	613.2			$	128.3			$	248.3			$	20.5		$	249.2			$	232.3			$	45.7
	Cost of sales		$	926.5		$	(49.6	)	(c)	$	340.8			$	49.2			$	209.2			$	10.5		$	164.1			$	180.7			$	21.6
	Segment profit:
	Operating income (loss)		$	62.7		$	(0.1	)		$	7.2			$	17.1			$	23.5			$	2.6		$	(1.4	)		$	8.2			$	5.6
	Loss from equity investees		(0.1		)	—				—				—				—				—			(0.1		)		—				—
	Interest expense		(60.1		)	—				(41.4		)		(9.8		)		(0.5		)		—			(6.3		)		(1.4		)		(0.7		)
	Income (loss) before income taxes		$	2.5		$	(0.1	)		$	(34.2	)		$	7.3			$	23			$	2.6		$	(7.8	)		$	6.8			$	4.9
	Partnership EBITDA (a)		$	52.2						$	55																						$	(2.8	)
	Noncontrolling interests’ net (loss)		$	(33.3	)	$	—			$	(31.0	)		$	—			$	—			$	—		$	(0.3	)		$	—			$	(2.0	)
	Depreciation and amortization		$	90		$	—			$	47.8			$	13.7			$	3.3			$	2.7		$	14.6			$	6.2			$	1.7
	Capital expenditures		$	102.4		$	1.2			$	29.3			$	35.9			$	11.2			$	1.9		$	15.6			$	4.8			$	2.5
	Total assets (at period end)		$	10,077.70		$	(112.8	)		$	4,345.80			$	2,147.40			$	542.7			$	279.1		$	1,784.20			$	650.6			$	440.7
	Bank loans (at period end)		$	96.5		$	—			$	92.5			$	—			$	—			$	—		$	—			$	4			$	—
	Goodwill (at period end)		$	2,885.10		$	—			$	1,939.00			$	182.1			$	5.6			$	—		$	651.7			$	99.7			$	7
	Three Months Ended June 30, 2013:
																			Midstream & Marketing							UGI International
			Total			Eliminations					AmeriGas				Gas				Energy Services				Electric Generation			Antargaz				Flaga &				Corporate
											Propane				Utility															Other				& Other (b)
	Revenues		$	1,374.30		$	(61.5	)	(c)		$	581.7			$	126.7			$	233			$	16.3		$	249.3			$	182.5			$	46.3
	Cost of sales		$	836.8		$	(60.1	)	(c)		$	305.7			$	52.4			$	214.9			$	8.5		$	148.7			$	134.8			$	31.9
	Segment profit:
	Operating income (loss)		$	41.5		$	(0.2	)			$	3.8			$	14.2			$	6.4			$	0.6		$	14.6			$	6.5			$	(4.4	)
	Income from equity investees		—			—					—				—				—				—			—				—				—
	Interest expense		(59.2		)	—					(41.2		)		(9.2		)		(0.6		)		—			(6.2		)		(1.2		)		(0.8		)
	(Loss) income before income taxes		$	(17.7	)	$	(0.2	)			$	(37.4	)		$	5			$	5.8			$	0.6		$	8.4			$	5.3			$	(5.2	)
	Partnership EBITDA (a)										$	56.3
	Noncontrolling interests’ net (loss) income		$	(31.9	)	$	—				$	(31.7	)		$	—			$	—			$	—		$	(0.3	)		$	0.1			$	—
	Depreciation and amortization		$	91.8		$	(0.1	)			$	52.4			$	13.1			$	2.1			$	2.6		$	14			$	6.1			$	1.6
	Capital expenditures		$	107.6		$	(0.1	)			$	26.3			$	37.3			$	22			$	4.4		$	11.7			$	4			$	2
	Total assets (at period end)		$	9,806.80		$	(95.9	)			$	4,386.80			$	2,143.70			$	437			$	267.2		$	1,771.70			$	543.1			$	353.2
	Bank loans (at period end)		$	135.9		$	—				$	80			$	—			$	45.5			$	—		$	—			$	10.4			$	—
	Goodwill (at period end)		$	2,834.00		$	—				$	1,929.20			$	182.1			$	2.8			$	—		$	619.2			$	93.7			$	7
	(a)	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
	Three Months Ended June 30,		2014			2013
	Partnership EBITDA		$	55		$	56.3
	Depreciation and amortization		(47.8		)	(52.4		)
	Noncontrolling interests (i)		—			(0.1		)
	Operating income		$	7.2		$	3.8
	(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 gains and losses on Midstream & Marketing’s commodity derivative instruments, and net gains and losses on AmeriGas Propane’s commodity derivative instruments entered into beginning April 1, 2014, that are not associated with current period transactions, (4) net expenses of UGI’s captive general liability insurance company, and (5) UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
	(c)	Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane.
	Nine Months Ended June 30, 2014:
																			Midstream & Marketing							UGI International
			Total			Elim-					AmeriGas				Gas				Energy Services				Electric Generation			Antargaz				Flaga &				Corporate &
						inations					Propane				Utility															Other				Other (b)
	Revenues		$	6,965.90		$	(281.0	)	(c)		$	3,152.70			$	880			$	1,109.90			$	66.4		$	1,086.50			$	802.8			$	148.6
	Cost of sales		$	4,357.70		$	(278.0	)	(c)		$	1,809.00			$	463.5			$	894.2			$	30.5		$	713.3			$	635.1			$	90.1
	Segment profit:
	Operating income (loss)		$	1,015.00		$	—				$	471.7			$	233.7			$	166.8			$	16.9		$	94.7			$	32.8			$	(1.6	)
	Loss from equity investees		(0.1		)	—					—				—				—				—			(0.1		)		—				—
	Interest expense		(178.9		)	—					(125.0		)		(26.6		)		(2.5		)		—			(19.1		)		(3.8		)		(1.9		)
	Income (loss) before income taxes		$	836		$	—				$	346.7			$	207.1			$	164.3			$	16.9		$	75.5			$	29			$	(3.5	)
	Partnership EBITDA (a)		$	613.7							$	616.5																						$	(2.8	)
	Noncontrolling interests’ net income (loss)		$	235.6		$	—				$	237.6			$	—			$	—			$	—		$	—			$	—			$	(2.0	)
	Depreciation and amortization		$	271.7		$	(0.1	)			$	149.3			$	40.7			$	9.1			$	8		$	39.9			$	20			$	4.8
	Capital expenditures		$	290.5		$	—				$	80.3			$	98.8			$	41.3			$	13		$	36.7			$	13.6			$	6.8
Total assets (at period end)		$	10,077.70		$	(112.8	)			$	4,345.80			$	2,147.40			$	542.7			$	279.1		$	1,784.20			$	650.6			$	440.7
Bank loans (at period end)		$	96.5		$	—				$	92.5			$	—			$	—			$	—		$	—			$	4			$	—
Goodwill (at period end)		$	2,885.10		$	—				$	1,939.00			$	182.1			$	5.6			$	—		$	651.7			$	99.7			$	7
Nine Months Ended June 30, 2013:
																		Midstream & Marketing							UGI International
		Total			Elim-					AmeriGas				Gas				Energy Services				Electric Generation			Antargaz				Flaga &				Corporate &
					inations					Propane				Utility															Other				Other (b)
Revenues		$	5,935.70		$	(181.1	)	(c)		$	2,636.90			$	743.6			$	764.8			$	48.7		$	1,121.20			$	659			$	142.6
Cost of sales		$	3,539.00		$	(176.2	)	(c)		$	1,367.40			$	372.7			$	650.5			$	29		$	714.4			$	507.1			$	74.1
Segment profit:
Operating income		$	843.4		$	(1.1	)			$	407.5			$	189.7			$	76.5			$	1.4		$	129.9			$	30.6			$	8.9
Income from equity investees		0.1			—					—				—				—				—			0.1				—				—
Interest expense		(180.8		)	—					(125.4		)		(28.1		)		(2.4		)		—			(19.0		)		(3.8		)		(2.1		)
Income before income taxes		$	662.7		$	(1.1	)			$	282.1			$	161.6			$	74.1			$	1.4		$	111			$	26.8			$	6.8
Partnership EBITDA (a)										$	557.1
Noncontrolling interests’ net income		$	194.4		$	—				$	194.2			$	—			$	—			$	—		$	0.1			$	0.1			$	—
Depreciation and amortization		$	269.2		$	(0.1	)			$	153.4			$	38.4			$	5.6			$	7.5		$	42.3			$	17.4			$	4.7
Capital expenditures		$	292.5		$	(1.1	)			$	80.7			$	90.2			$	54.8			$	15.4		$	37.1			$	10.3			$	5.1
Total assets (at period end)		$	9,806.80		$	(95.9	)			$	4,386.80			$	2,143.70			$	437			$	267.2		$	1,771.70			$	543.1			$	353.2
Bank loans (at period end)		$	135.9		$	—				$	80			$	—			$	45.5			$	—		$	—			$	10.4			$	—
Goodwill (at period end)		$	2,834.00		$	—				$	1,929.20			$	182.1			$	2.8			$	—		$	619.2			$	93.7			$	7
(a)	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
Nine Months Ended June 30,		2014			2013
Partnership EBITDA		$	616.5		$	557.1
Depreciation and amortization		(149.3		)	(153.4		)
Noncontrolling interests (i)		4.5			3.8
Operating income		$	471.7		$	407.5
(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 gains and losses on Midstream & Marketing’s commodity derivative instruments, and net gains and losses on AmeriGas Propane’s commodity derivative instruments entered into beginning April 1, 2014, that are not associated with current period transactions, (4) net expenses of UGI’s captive general liability insurance company, and (5) UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
(c)	Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Energy_Services_Accounts_Recei

Energy Services Accounts Receivable Securitization Facility	9 Months Ended
	Jun. 30, 2014
Transfers and Servicing of Financial Assets [Abstract]	'
Energy Services Accounts Receivable Securitization Facility	'
	Energy Services Accounts Receivable Securitization Facility
	Energy Services has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper that is currently scheduled to expire in October 2014. The Receivables Facility provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November 1, 2013 to May 31, 2014, and up to $75 of eligible receivables during the period June 1, 2014 to October 31, 2014.
	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 and, prior to October 1, 2013, a commercial paper conduit of 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 or, prior to October 1, 2013, the commercial paper conduit, 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, prior to October 1, 2013, 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 nine months ended June 30, 2014 and 2013, Energy Services transferred trade receivables to ESFC totaling $1,073.1 and $766.1, respectively. During the nine months ended June 30, 2014 and 2013, ESFC sold an aggregate $196.0 and $224.0, respectively, of undivided interests in its trade receivables to the bank or commercial paper conduit, as applicable. At June 30, 2014, the outstanding balance of ESFC receivables was $57.7 and there were none sold to the bank. At June 30, 2013, the outstanding balance of ESFC receivables was $58.2 and there was $9.5 sold to the commercial paper conduit.

Utility_Regulatory_Assets_and_

Utility Regulatory Assets and Liabilities and Regulatory Matters	9 Months Ended
	Jun. 30, 2014
Regulated Operations [Abstract]	'
Utility Regulatory Assets and Liabilities and Regulatory Matters	'
	Utility Regulatory Assets and Liabilities and Regulatory Matters
	For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 to the Company’s 2013 Annual Financial Statements and Notes. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:
		June 30,		September 30,		June 30,
		2014		2013		2013
	Regulatory assets:
	Income taxes recoverable	$	107.2	$	106.1	$	104.7
	Underfunded pension and postretirement plans	89.2		94.5		177.8
	Environmental costs	14.6		17.1		16.6
	Deferred fuel and power costs	9.4		8.3		4.1
	Removal costs, net	15.6		13.3		12.1
	Other	6.6		5.6		5.6
	Total regulatory assets	$	242.6	$	244.9	$	320.9
	Regulatory liabilities:
	Postretirement benefits	$	17.5	$	16.5	$	14.2
	Environmental overcollections	1.6		2.6		2.9
	Deferred fuel and power refunds	—		8.3		14.2
	State tax benefits—distribution system repairs	9.3		8.4		8
	Other	1.9		1.5		0.7
	Total regulatory liabilities	$	30.3	$	37.3	$	40
	Deferred fuel and power—costs and refunds. Gas Utility’s tariffs 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”) rates 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 overcollected costs are classified as a regulatory liability.
	Gas Utility uses derivative financial instruments to reduce volatility in the cost of natural gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at June 30, 2014, September 30, 2013 and June 30, 2013 were $0.7, $(1.7) and $(1.4), respectively.
	Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because most of these contracts do not currently qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the Condensed Consolidated Balance Sheets with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At June 30, 2014, September 30, 2013, and June 30, 2013, the fair values of Electric Utility’s electricity supply contracts were net gains (losses) of $0.8, $(4.8) and $(6.1), respectively, which amounts are reflected in current derivative financial instrument assets and liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs or 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 financial 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 June 30, 2014, September 30, 2013, and June 30, 2013, were not material.

Defined_Benefit_Pension_and_Ot

Defined Benefit Pension and Other Postretirement Plans	9 Months Ended
	Jun. 30, 2014
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]	'
Defined Benefit Pension and Other Postretirement Plans	'
	Defined Benefit Pension and Other Postretirement Plans
	In the U.S., we currently sponsor one 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 (“Pension Plan”). We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all domestic 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 June 30,						Three Months Ended June 30,
		2014			2013			2014			2013
	Service cost	$	2.3		$	2.8		$	0.1		$	0.2
	Interest cost	6.5			5.9			0.2			0.2
	Expected return on assets	(7.3		)	(6.9		)	(0.1		)	(0.1		)
	Amortization of:
	Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
	Actuarial loss	1.9			3.7			—			0.1
	Net benefit cost	3.5			5.6			0.1			0.3
	Change in associated regulatory liabilities	—			—			0.9			0.8
	Net expense	$	3.5		$	5.6		$	1		$	1.1
		Pension Benefits						Other
								Postretirement Benefits
		Nine Months Ended						Nine Months Ended
		June 30,						June 30,
		2014			2013			2014			2013
	Service cost	$	7		$	8.5		$	0.4		$	0.5
	Interest cost	19.4			17.6			0.7			0.7
	Expected return on assets	(22.0		)	(20.7		)	(0.4		)	(0.4		)
	Amortization of:
	Prior service cost (benefit)	0.2			0.2			(0.4		)	(0.2		)
	Actuarial loss	5.7			11.2			0.1			0.3
	Net benefit cost	10.3			16.8			0.4			0.9
	Change in associated regulatory liabilities	—			—			2.7			2.4
	Net expense	$	10.3		$	16.8		$	3.1		$	3.3
	Pension Plan 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 Pension Plan benefits equal to at least the minimum contribution set forth in applicable employee benefit laws. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $6.9 to the Pension Plan during the remainder of Fiscal 2014. During the nine months ended June 30, 2014 and 2013, the Company made cash contributions to the Pension Plan of $11.0 and $13.4, respectively. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas’ and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers.
	We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans (“Supplemental Defined Benefit Plans”). We recorded pre-tax expense associated with these plans of $0.6 and $0.8 in the three months ended June 30, 2014 and 2013, respectively. We recorded pre-tax expense associated with these plans of $2.3 and $2.4 in the nine months ended June 30, 2014 and 2013, respectively.

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Jun. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	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 June 30, 2014 and 2013, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11.4 and $14.4, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.
	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 June 30, 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, and believe that they have good defenses to the FTC’s claims. We are unable to reasonably estimate the impact, if any, arising from this claim.
	Purported Class Action Lawsuits.  Following the issuance of the FTC’s administrative complaint described above, more than 25 class action lawsuits have been 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 that the Partnership and its competitor colluded 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.  We believe these lawsuits will eventually be consolidated by a multidistrict litigation panel.  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.

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Jun. 30, 2014
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	Derivative Financial Instruments
	The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of June 30, 2014, September 30, 2013 and June 30, 2013:
			Asset (Liability)
			Quoted Prices				Significant				Unobservable		Total
			in Active				Other				Inputs
			Markets for				Observable				(Level 3)
			Identical Assets				Inputs
			and Liabilities				(Level 2)
			(Level 1)
	June 30, 2014:
	Assets:
	Derivative financial instruments:
	Commodity contracts		$	6.8			$	6.4			$	—	$	13.2
	Foreign currency contracts		$	—			$	0.5			$	—	$	0.5
	Liabilities:
	Derivative financial instruments:
	Commodity contracts		$	(4.5	)		$	(6.6	)		$	—	$	(11.1	)
	Foreign currency contracts		$	—			$	(4.8	)		$	—	$	(4.8	)
	Interest rate contracts		$	—			$	(25.2	)		$	—	$	(25.2	)
	Cross-currency swaps		$	—			$	(2.0	)		$	—	$	(2.0	)
	September 30, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts		$	2.1			$	21.2			$	—	$	23.3
	Foreign currency contracts		$	—			$	0.9			$	—	$	0.9
	Liabilities:
	Derivative financial instruments:
	Commodity contracts		$	(9.7	)		$	(6.3	)		$	—	$	(16.0	)
	Foreign currency contracts		$	—			$	(7.2	)		$	—	$	(7.2	)
	Interest rate contracts		$	—			$	(31.0	)		$	—	$	(31.0	)
	Cross-currency swaps		$	—			$	(1.2	)		$	—	$	(1.2	)
	June 30, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts		$	2.2			$	7.4			$	—	$	9.6
	Foreign currency contracts		$	—			$	1			$	—	$	1
	Interest rate contracts		$	—			$	8.1			$	—	$	8.1
	Liabilities:
	Derivative financial instruments:
	Commodity contracts		$	(8.0	)		$	(24.1	)		$	—	$	(32.1	)
	Foreign currency contracts		$	—			$	(1.7	)		$	—	$	(1.7	)
	Interest rate contracts		$	—			$	(46.9	)		$	—	$	(46.9	)
	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 financial 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. 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 June 30, 2014, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,556.2 and $3,805.4, respectively. At June 30, 2013, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,493.8 and $3,621.0, 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 financial 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 from trade accounts receivable is limited because we have a large customer base that extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 12 and below.
	Disclosures about 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 financial 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 derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our 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.
		Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet
	June 30, 2014:
	Derivative assets	$	31.9		$	(18.2	)	$	13.7
	Derivative (liabilities)	$	(61.3	)	$	18.2		$	(43.1	)
	September 30, 2013:
	Derivative assets	$	26.3		$	(2.1	)	$	24.2
	Derivative (liabilities)	$	(57.5	)	$	2.1		$	(55.4	)
	June 30, 2013:
	Derivative assets	$	25.1		$	(6.4	)	$	18.7
	Derivative (liabilities)	$	(87.1	)	$	6.4		$	(80.7	)

Disclosures_About_Derivative_I

Disclosures About Derivative Instruments and Hedging Activities	9 Months Ended
	Jun. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Disclosures About Derivative Instruments and Hedging Activities	'
	Disclosures about 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, which permit customers to lock in the prices they pay for propane principally during the months of October through March, 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.
	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 economically 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 June 30, 2014 and 2013, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 10.9 million dekatherms and 11.7 million dekatherms, respectively. At June 30, 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 in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 8).
	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 most of these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At June 30, 2014 and 2013, the fair values of Electric Utility’s forward purchase power agreements comprising gains of $0.8 and losses of $6.1, respectively, are reflected in current derivative financial instrument assets and liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets and liabilities. At June 30, 2014 and 2013, the volumes of Electric Utility’s forward electricity purchase contracts were 315.8 million kilowatt hours and 327.4 million kilowatt hours, respectively. At June 30, 2014, the maximum period over which these contracts extend is 11 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 and by purchases of FTRs at monthly auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 8). Midstream & Marketing 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. At June 30, 2014 and 2013, the volumes associated with Electric Utility FTRs totaled 232.2 million kilowatt hours and 260.6 million kilowatt hours, respectively. Midstream & Marketing’s FTRs and capacity swap contracts are recorded at fair value with changes in fair value reflected in cost of sales. At June 30, 2014 and 2013, the volumes associated with Midstream & Marketing’s FTRs and NYISO capacity swap contracts totaled 427.7 million kilowatt hours and 1,609.2 million kilowatt hours, respectively.
	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, Intercontinental Exchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electricity generation facilities. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. During the three months ended March 31, 2014, Energy Services determined that it could no longer assert the normal purchases and normal sales exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation and, as a result, began accounting for these contracts at fair value on the balance sheet with changes in fair value reflected in net income. These contracts, as well as other Midstream & Marketing derivative instruments described above, are not accounted for as hedges under GAAP. These derivative instruments are recorded at fair value with changes in fair value reflected in income.
	At June 30, 2014 and 2013, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline transportation contracts totaled 83.0 million dekatherms and 19.4 million dekatherms, respectively. Total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 492.5 million kilowatt hours and 193.2 million kilowatt hours at June 30, 2014, and 927.2 million kilowatt hours and 451.0 million kilowatt hours at June 30, 2013, respectively. At June 30, 2014, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 0.5 million dekatherms and 2.9 million gallons, respectively. At June 30, 2013, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 2.7 million dekatherms and 1.8 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. Associated volumes, fair values and effects on net income were not material for all periods presented.
	At June 30, 2014 and 2013, total volumes associated with LPG commodity derivative instruments totaled 274.3 million gallons and 236.7 million gallons, respectively. At June 30, 2014, for those LPG commodity derivative instruments accounted for as cash flow hedges, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 21 months with a weighted average of 6 months.
	We account for commodity price risk contracts at our UGI International business units, and at the Partnership for commodity derivative instruments entered into prior to April 1, 2014, as cash flow hedges. Effective April 1, 2014, the Partnership determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative transactions. All unrealized and realized gains and losses on the Partnership’s derivative commodity transactions entered into beginning April 1, 2014, are included as a component of cost of sales on the Condensed Consolidated Statements of Income. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in AOCI and, with respect to the Partnership’s contracts, also in noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Condensed Consolidated Statements of Income. At June 30, 2014, the amount of net gains associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $4.0.
	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 has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its term loans, in each case through the respective scheduled maturity dates. As of June 30, 2014 and 2013, the total notional amount of existing variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) was €401.1 and €440.5, 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 June 30, 2014, we had no unsettled IRPAs. At June 30, 2013, the total notional amount of unsettled IRPAs was $173.
	We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values of interest rate swaps and IRPAs are recorded in AOCI and, with respect to the Partnership, also in noncontrolling interests, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At June 30, 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 through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG forecasted to occur during the heating-season months of October through March. At June 30, 2014 and 2013, we were hedging a total of $219.8 and $170.3 of U.S. dollar-denominated LPG purchases, respectively. At June 30, 2014, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 33 months with a weighted average of 15 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 June 30, 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. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At June 30, 2014, the amount of net losses 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 $3.6. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.
	From time to time, the Company may enter into foreign currency exchange transactions to economically hedge the local-currency purchase price of anticipated foreign business acquisitions. These transactions do not qualify for hedge accounting treatment and any changes in fair value are recorded in other income, net.
	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. 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. Changes in the fair value of our cross-currency swap are recorded in AOCI to the extent effective in offsetting changes in the underlying foreign currency exchange and interest rate risk. At June 30, 2014, the amount of net losses associated with this cross-currency swap expected to be reclassified into earnings over the next twelve months is not material.
	Derivative Financial Instrument Credit Risk
	We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2014 and 2013, restricted cash in brokerage accounts totaled $5.9 and $6.0, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at June 30, 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 June 30, 2014, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
	The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2014 and 2013:
		Derivative Assets										Derivative (Liabilities)
		Balance Sheet		Fair Value June 30,								Balance Sheet	Fair Value June 30,
		Location		2014				2013				Location	2014			2013
	Derivatives Designated as Hedging Instruments:
	Commodity contracts	Derivative financial instruments and		$	7			$	5.3			Derivative financial instruments	$	(3.1	)	$	(17.9	)
		Other assets										and Other noncurrent liabilities
	Foreign currency contracts	Derivative financial instruments and		0.5				1				Derivative financial instruments	(4.8		)	(0.4		)
		Other assets										and Other noncurrent liabilities
	Cross-currency contracts			—				—				Derivative financial instruments	(2.0		)	—
												and Other noncurrent liabilities
	Interest rate contracts	Derivative financial instruments		—				8.1				Derivative financial instruments	(25.2		)	(46.9		)
												and Other noncurrent liabilities
	Total Derivatives Designated as Hedging Instruments			$	7.5			$	14.4				$	(35.1	)	$	(65.2	)
	Derivatives Subject to Utility Rate Regulation:
	Commodity contracts	Derivative financial instruments		$	1.6			$	0.1			Derivative financial instruments	$	—		$	(7.6	)
	Derivatives Not Designated as Hedging Instruments:
	Commodity contracts	Derivative financial instruments and Other assets		$	6.4			$	4.2			Derivative financial instruments and Other noncurrent liabilities	$	(9.8	)	$	(6.6	)
	Foreign currency contracts	Derivative financial instruments		—				—				Derivative financial instruments	—			(1.3		)
	Total Derivatives Not Designated as Hedging Instruments			$	6.4			$	4.2				$	(9.8	)	$	(7.9	)
	Amounts above offset in the Balance Sheet			(1.8		)		—					1.8			—
	Total Derivatives			$	13.7			$	18.7				$	(43.1	)	$	(80.7	)
	The following tables provide information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and nine months ended June 30, 2014 and 2013:
	Three Months Ended June 30,	Gain (Loss)								Gain (Loss)						Location of
		Recognized in								Reclassified from						Gain (Loss)
		AOCI and								AOCI and Noncontrolling						Reclassified from
		Noncontrolling Interests								Interests into Income						AOCI and Noncontrolling
		2014				2013				2014			2013			Interests into Income
	Cash Flow Hedges:
	Commodity contracts	$	(1.7	)		$	(17.1	)		$	4.3		$	(8.2	)	Cost of sales
	Foreign currency contracts	1.1				(0.3		)		(0.2		)	—			Cost of sales
	Cross-currency contracts	—				—				(0.1		)	—			Interest expense
	Interest rate contracts	(0.6		)		14				(3.9		)	(3.6		)	Interest expense / other income, net
	Total	$	(1.2	)		$	(3.4	)		$	0.1		$	(11.8	)
		Gain (Loss)														Location of Gain (Loss)
		Recognized in Income														Recognized in Income
	Derivatives Not Designated as Hedging Instruments:	2014				2013
	Commodity contracts	$	(4.9	)		$	(5.7	)								Cost of sales
	Commodity contracts	—				(0.1		)								Operating expenses / other
income, net
Foreign currency contracts	—				(0.9		)								Other income, net
Total	$	(4.9	)		$	(6.7	)
Nine Months Ended June 30,	Gain (Loss)								Gain (Loss)						Location of
	Recognized in								Reclassified from						Gain (Loss)
	AOCI and								AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests								Interests into Income						AOCI and Noncontrolling
	2014				2013				2014			2013			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	59.5			$	(21.6	)		$	66.5		$	(51.4	)	Cost of sales
Foreign currency contracts	(1.6		)		(1.4		)		(3.7		)	(0.1		)	Cost of sales
Cross-currency contracts	(1.1		)		—				(0.2		)	—			Interest expense
Interest rate contracts	(4.1		)		23				(12.0		)	(10.6		)	Interest expense / other income, net
Total	$	52.7			$	—			$	50.6		$	(62.1	)
	Gain (Loss)														Location of Gain (Loss)
	Recognized in Income														Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2014				2013
Commodity contracts	$	(14.3	)		$	8.1									Cost of sales
Commodity contracts	0.1				—										Operating expenses / other
															income, net
Foreign currency contracts	—				(1.1		)								Other income, net
Total	$	(14.2	)		$	7
The amounts of derivative gains or losses representing ineffectiveness were not material for the three- and nine-month periods ended June 30, 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 and contracts that provide for the purchase and delivery, or sale, of natural gas, LPG and electricity 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, these contracts qualify for normal purchases and normal sales 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.

Inventories

Inventories	9 Months Ended
	Jun. 30, 2014
Inventory Disclosure [Abstract]	'
Inventories	'
	Inventories
	Inventories comprise the following:
		June 30,		September 30,		June 30,
		2014		2013		2013
	Non-utility LPG and natural gas	$	222.6	$	230	$	194.6
	Gas Utility natural gas	45.7		78.9		43.1
	Materials, supplies and other	63.7		56.6		66.3
	Total inventories	$	332	$	365.5	$	304
	At June 30, 2014, UGI Utilities is a party to three 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 term 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), are included in the caption “Gas Utility natural gas” in the table above.
	As of June 30, 2014, UGI Utilities had SCAAs with Energy Services and a non-affiliate. The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at June 30, 2014 and September 30, 2013, comprising 2.1 billion cubic feet (“bcf”) and 0.6 bcf of natural gas, were $8.9 and $2.4, respectively. UGI Utilities did not have any SCAAs with non-affiliates at June 30, 2013.

Debt

Debt	9 Months Ended
	Jun. 30, 2014
Debt Disclosure [Abstract]	'
Debt	'
	Debt
	On March 26, 2014, UGI Utilities issued in a private placement $175 of 4.98% Senior Notes due March 26, 2044 (“4.98% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175 of borrowings under UGI Utilities’ 364-day term loan credit agreement scheduled to expire in September 2014. The 4.98% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The 4.98% Senior Notes also contain restrictive and financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined therein, of 0.65 to 1.00.
	In June 2014, AmeriGas OLP entered into an Amended and Restated Credit Agreement (“Amended and Restated Credit Agreement”) with a group of banks which provides for borrowings up to $525 (including a sublimit of $125 for letters of credit). The Amended and Restated Credit Agreement amends and restates AmeriGas OLP’s prior Credit Agreement entered into with a group of banks in June 2011, as amended from time to time. The Amended and Restated Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the Amended and Restated Credit Agreement, plus a margin. The Amended and Restated Credit Agreement reduces the applicable margin on base rate borrowings to a range of 0.5% to 1.5% (from a range of 0.75% to 1.75% previously); reduces the applicable margin on Eurodollar Rate borrowings to a range of 1.5% to 2.5% (from a range of 1.75% to 2.75% previously); and reduces the facility fee to a range of 0.3% to 0.45% (from a range of 0.3% to 0.5% previously). The aforementioned margins and facility fees are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (each as defined in the Amended and Restated Credit Agreement). The Amended and Restated Credit Agreement expires on June 18, 2019.
	The Amended and Restated Credit Agreement restricts the incurrence of additional indebtedness and also restricts certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The Amended and Restated Credit Agreement requires that AmeriGas OLP and AmeriGas Partners maintain ratios of total indebtedness to EBITDA, as defined, below certain thresholds. In addition, the Partnership must maintain a minimum ratio of EBITDA to interest expense, as defined and as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result therefrom, AmeriGas OLP is permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter.

Subsequent_Event_Subsequent_Ev

Subsequent Event Subsequent Event	9 Months Ended
	Jun. 30, 2014
Subsequent Events [Abstract]	'
Subsequent Events	'
	Subsequent Event
	On July 29, 2014, UGI's Board of Directors approved a 3-for-2 common stock split. UGI will issue three shares for every two common shares outstanding. The new shares will be distributable September 5, 2014, to shareholders of record on August 22, 2014. Basic and diluted earnings per share attributable to UGI Corporation stockholders and dividends declared per share for the three- and nine-month periods ended June 30, 2014 and 2013, have been reflected on a pre-split basis.
	The following table presents pro forma basic and diluted earnings per share attributable to UGI Corporation stockholders to reflect the effect of the 3-for-2 common stock split:
		Three Months Ended		Nine Months Ended
		June 30,		June 30,
		2014	2013	2014	2013
	Basic earnings per share:
	As reported	$0.18	$0.08	$3.10	$2.57
	Pro forma	$0.12	$0.05	$2.07	$1.71
	Diluted earnings per share:
	As reported	$0.18	$0.08	$3.06	$2.54
	Pro forma	$0.12	$0.05	$2.04	$1.69

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	9 Months Ended
	Jun. 30, 2014
Accounting Policies [Abstract]	'
Restricted Cash	'
	Restricted Cash. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
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.
	Shares used in computing basic and diluted earnings per share are as follows:
			Three Months Ended					Nine Months Ended
			June 30,					June 30,
			2014		2013			2014			2013
	Denominator (thousands of shares):
	Average common shares outstanding for basic computation		115,370		114,240			115,121			113,693
	Incremental shares issuable for stock options and awards		1,678		1,956			1,610			1,582
	Average common shares outstanding for diluted computation		117,048		116,196			116,731			115,275
Comprehensive Income	'
	Comprehensive Income. Comprehensive income (loss) comprises net income (loss) and other comprehensive income (loss). Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and intracompany transaction adjustments.
	Changes in accumulated other comprehensive income (“AOCI”) during the three and nine months ended June 30, 2014, are as follows:
	Three Months Ended June 30, 2014:	Postretirement			Derivative				Foreign
		Benefit Plans			Instruments				Currency			Total
	Balance, March 31, 2014	$	(15.8	)	$	(23.3	)		$	63.4		$	24.3
	Other comprehensive (loss) before reclassification adjustments (after-tax)	—			(0.6		)		(0.2		)	(0.8		)
	Amounts reclassified from AOCI and noncontrolling interests:
	Reclassification adjustments (pre-tax)	0.4			(0.2		)		—			0.2
	Reclassification adjustments tax (expense) benefit	(0.2		)	(1.3		)		—			(1.5		)
	Reclassification adjustments (after-tax)	0.2			(1.5		)		—			(1.3		)
	Other comprehensive income (loss)	0.2			(2.1		)		(0.2		)	(2.1		)
	Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			3.2				—			3.2
	Other comprehensive income (loss) attributable to UGI	0.2			1.1				(0.2		)	1.1
	Balance, June 30, 2014	$	(15.6	)	$	(22.2	)		$	63.2		$	25.4
	Nine Months Ended June 30, 2014:	Postretirement			Derivative				Foreign
		Benefit Plans			Instruments				Currency			Total
	Balance, September 30, 2013	$	(16.4	)	$	(26.9	)		$	51.7		$	8.4
	Other comprehensive income before reclassification adjustments (after-tax)	—			46.2				11.5			57.7
	Amounts reclassified from AOCI and noncontrolling interests:
	Reclassification adjustments (pre-tax)	1			(50.7		)		—			(49.7		)
	Reclassification adjustments tax (expense) benefit	(0.2		)	4				—			3.8
	Reclassification adjustments (after-tax)	0.8			(46.7		)		—			(45.9		)
	Other comprehensive income (loss)	0.8			(0.5		)		11.5			11.8
	Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			5.2				—			5.2
	Other comprehensive income attributable to UGI	0.8			4.7				11.5			17
	Balance, June 30, 2014	$	(15.6	)	$	(22.2	)		$	63.2		$	25.4
	For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 12 to condensed consolidated financial statements.
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.

Significant_Accounting_Policie2

Significant Accounting Policies (Tables)	9 Months Ended
	Jun. 30, 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					Nine Months Ended
			June 30,					June 30,
			2014		2013			2014			2013
	Denominator (thousands of shares):
	Average common shares outstanding for basic computation		115,370		114,240			115,121			113,693
	Incremental shares issuable for stock options and awards		1,678		1,956			1,610			1,582
	Average common shares outstanding for diluted computation		117,048		116,196			116,731			115,275
Changes in Accumulated Other Comprehensive Income	'
	Changes in accumulated other comprehensive income (“AOCI”) during the three and nine months ended June 30, 2014, are as follows:
	Three Months Ended June 30, 2014:	Postretirement			Derivative				Foreign
		Benefit Plans			Instruments				Currency			Total
	Balance, March 31, 2014	$	(15.8	)	$	(23.3	)		$	63.4		$	24.3
	Other comprehensive (loss) before reclassification adjustments (after-tax)	—			(0.6		)		(0.2		)	(0.8		)
	Amounts reclassified from AOCI and noncontrolling interests:
	Reclassification adjustments (pre-tax)	0.4			(0.2		)		—			0.2
	Reclassification adjustments tax (expense) benefit	(0.2		)	(1.3		)		—			(1.5		)
	Reclassification adjustments (after-tax)	0.2			(1.5		)		—			(1.3		)
	Other comprehensive income (loss)	0.2			(2.1		)		(0.2		)	(2.1		)
	Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			3.2				—			3.2
	Other comprehensive income (loss) attributable to UGI	0.2			1.1				(0.2		)	1.1
	Balance, June 30, 2014	$	(15.6	)	$	(22.2	)		$	63.2		$	25.4
	Nine Months Ended June 30, 2014:	Postretirement			Derivative				Foreign
		Benefit Plans			Instruments				Currency			Total
	Balance, September 30, 2013	$	(16.4	)	$	(26.9	)		$	51.7		$	8.4
	Other comprehensive income before reclassification adjustments (after-tax)	—			46.2				11.5			57.7
	Amounts reclassified from AOCI and noncontrolling interests:
	Reclassification adjustments (pre-tax)	1			(50.7		)		—			(49.7		)
	Reclassification adjustments tax (expense) benefit	(0.2		)	4				—			3.8
	Reclassification adjustments (after-tax)	0.8			(46.7		)		—			(45.9		)
	Other comprehensive income (loss)	0.8			(0.5		)		11.5			11.8
	Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			5.2				—			5.2
	Other comprehensive income attributable to UGI	0.8			4.7				11.5			17
	Balance, June 30, 2014	$	(15.6	)	$	(22.2	)		$	63.2		$	25.4

Restatements_of_Condensed_Cons1

Restatements of Condensed Consolidated Financial Statements (Tables)	9 Months Ended
	Jun. 30, 2014
Revisions of Condensed Consolidated Financial Statements [Abstract]	'
Condensed Consolidated Balance Sheet	'
	Condensed Consolidated Balance Sheet
		30-Jun-13
		As Previously Reported			Adjustment			As Revised
	Assets:
	Deferred income taxes	$	27.3		$	(20.7	)	$	6.6
	Property, plant and equipment	$	4,325.00		$	(1.3	)	$	4,323.70
	Liabilities and equity:
	Deferred income taxes	$	956.9		$	(23.4	)	$	933.5
	Other noncurrent liabilities	$	613.5		$	3.4		$	616.9
	Retained earnings	$	1,361.90		$	(7.0	)	$	1,354.90
	Accumulated other comprehensive loss	$	(30.7	)	$	3.3		$	(27.4	)
	Noncontrolling interests, principally in AmeriGas Partners	$	1,132.20		$	1.7		$	1,133.90
Condensed Consolidated Statement of Income	'
	Condensed Consolidated Statement of Income
		For the three months ended June 30, 2013									For the nine months ended June 30, 2013
		As Previously Reported			Adjustment			As Revised			As Previously Reported			Adjustment			As Revised
	Revenues	$	1,372.30		$	2		$	1,374.30		$	5,932.60		$	3.1		$	5,935.70
	Cost of sales	$	827.9		$	8.9		$	836.8		$	3,547.30		$	(8.3	)	$	3,539.00
	Operating and administrative expenses	$	404.7		$	2.8		$	407.5		$	1,297.40		$	(1.5	)	$	1,295.90
	Depreciation	$	76.5		$	(0.1	)	$	76.4		$	220		$	2.9		$	222.9
	Other income, net	$	(9.0	)	$	2		$	(7.0	)	$	(26.5	)	$	2		$	(24.5	)
	Operating income	$	53.1		$	(11.6	)	$	41.5		$	835.4		$	8		$	843.4
	Interest expense	$	(59.2	)	$	—		$	(59.2	)	$	(179.6	)	$	(1.2	)	$	(180.8	)
	Income (loss) before income taxes	$	(6.1	)	$	(11.6	)	$	(17.7	)	$	655.9		$	6.8		$	662.7
	Income taxes	$	(9.0	)	$	3.9		$	(5.1	)	$	(174.1	)	$	(1.9	)	$	(176.0	)
	Net (loss) income	$	(15.1	)	$	(7.7	)	$	(22.8	)	$	481.8		$	4.9		$	486.7
	Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners	$	29.8		$	2.1		$	31.9		$	(192.6	)	$	(1.8	)	$	(194.4	)
	Net income attributable to UGI Corporation	$	14.7		$	(5.6	)	$	9.1		$	289.2		$	3.1		$	292.3
	Basic earnings per common share	$	0.13					$	0.08		$	2.54					$	2.57
	Diluted earnings per common share	$	0.13					$	0.08		$	2.51					$	2.54
Condensed Consolidated Statement of Comprehensive Income	'
	Condensed Consolidated Statement of Comprehensive Income
		For the three months ended June 30, 2013									For the nine months ended June 30, 2013
		As Previously Reported			Adjustment			As Revised			As Previously Reported			Adjustment			As Revised
	Net (loss) income	$	(15.1	)	$	(7.7	)	$	(22.8	)	$	481.8		$	4.9		$	486.7
	Net losses on derivative instruments	$	(11.0	)	$	3.4		$	(7.6	)	$	(11.1	)	$	3.9		$	(7.2	)
	Reclassifications of net losses on derivative instruments	$	8.9		$	0.8		$	9.7		$	59.7		$	(7.4	)	$	52.3
	Other comprehensive income	$	7		$	4.2		$	11.2		$	51		$	(3.5	)	$	47.5
	Comprehensive (loss) income	$	(8.1	)	$	(3.5	)	$	(11.6	)	$	532.8		$	1.4		$	534.2
	Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	$	37.8		$	2.1		$	39.9		$	(212.2	)	$	(1.8	)	$	(214.0	)
	Comprehensive income attributable to UGI Corporation	$	29.7		$	(1.4	)	$	28.3		$	320.6		$	(0.4	)	$	320.2
Condensed Consolidated Statements of Cash Flow	'
	Condensed Consolidated Statements of Cash Flows
		For the nine months ended June 30, 2013
	CASH FLOWS FROM OPERATING ACTIVITIES:	As Previously Reported			Adjustment			As Revised
	Net income	$	481.8		$	4.9		$	486.7
	Depreciation and amortization	$	266.3		$	2.9		$	269.2
	Deferred income taxes, net	$	35.5		$	(3.3	)	$	32.2
	Net change in realized gains and losses deferred as cash flow hedges	$	5		$	(5.0	)	$	—
	Unrealized losses on derivative instruments	$	—		$	(0.7	)	$	(0.7	)
	Other, net	$	(11.3	)	$	7.7		$	(3.6	)
	Net change in:
	Accounts receivable and accrued utility revenues	$	(141.1	)	$	(5.1	)	$	(146.2	)
	Inventories	$	54.1		$	(2.8	)	$	51.3
	Accounts payable	$	(26.9	)	$	1.4		$	(25.5	)
	Other current liabilities	$	(73.8	)	$	—		$	(73.8	)
Condensed Consolidated Statements of Changes in Equity	'
	Condensed Consolidated Statements of Changes in Equity
		For the nine months ended June 30, 2013
		As Previously Reported			Adjustment			As Revised
	Retained earnings	$	1,361.90		$	(7.0	)	$	1,354.90
	Accumulated other comprehensive loss	$	(30.7	)	$	3.3		$	(27.4	)
	Noncontrolling interests	$	1,132.20		$	1.7		$	1,133.90

Goodwill_and_Intangible_Assets1

Goodwill and Intangible Assets (Tables)	9 Months Ended
	Jun. 30, 2014
Goodwill and Intangible Assets Disclosure [Abstract]	'
Components of Company's Intangible Assets	'
	Goodwill and intangible assets comprise the following:
		June 30,			September 30,			June 30,
		2014			2013			2013
	Goodwill (not subject to amortization)	$	2,885.10		$	2,871.00		$	2,834.00
	Intangible assets:
	Customer relationships, noncompete agreements and other	$	717.3		$	706.4		$	692.6
	Trademarks and tradenames (not subject to amortization)	132			131.3			128.4
	Gross carrying amount	849.3			837.7			821
	Accumulated amortization	(259.0		)	(227.1		)	(212.4		)
	Intangible assets, net	$	590.3		$	610.6		$	608.6

Segment_Information_Tables

Segment Information (Tables)	9 Months Ended
	Jun. 30, 2014
Segment Reporting [Abstract]	'
Schedule of Segment Reporting Information	'
	Three Months Ended June 30, 2014:
																		Midstream & Marketing							UGI International
			Total			Eliminations				AmeriGas				Gas				Energy Services				Electric Generation			Antargaz				Flaga &				Corporate
										Propane				Utility															Other				& Other (b)
	Revenues		$	1,486.70		$	(50.8	)	(c)	$	613.2			$	128.3			$	248.3			$	20.5		$	249.2			$	232.3			$	45.7
	Cost of sales		$	926.5		$	(49.6	)	(c)	$	340.8			$	49.2			$	209.2			$	10.5		$	164.1			$	180.7			$	21.6
	Segment profit:
	Operating income (loss)		$	62.7		$	(0.1	)		$	7.2			$	17.1			$	23.5			$	2.6		$	(1.4	)		$	8.2			$	5.6
	Loss from equity investees		(0.1		)	—				—				—				—				—			(0.1		)		—				—
	Interest expense		(60.1		)	—				(41.4		)		(9.8		)		(0.5		)		—			(6.3		)		(1.4		)		(0.7		)
	Income (loss) before income taxes		$	2.5		$	(0.1	)		$	(34.2	)		$	7.3			$	23			$	2.6		$	(7.8	)		$	6.8			$	4.9
	Partnership EBITDA (a)		$	52.2						$	55																						$	(2.8	)
	Noncontrolling interests’ net (loss)		$	(33.3	)	$	—			$	(31.0	)		$	—			$	—			$	—		$	(0.3	)		$	—			$	(2.0	)
	Depreciation and amortization		$	90		$	—			$	47.8			$	13.7			$	3.3			$	2.7		$	14.6			$	6.2			$	1.7
	Capital expenditures		$	102.4		$	1.2			$	29.3			$	35.9			$	11.2			$	1.9		$	15.6			$	4.8			$	2.5
	Total assets (at period end)		$	10,077.70		$	(112.8	)		$	4,345.80			$	2,147.40			$	542.7			$	279.1		$	1,784.20			$	650.6			$	440.7
	Bank loans (at period end)		$	96.5		$	—			$	92.5			$	—			$	—			$	—		$	—			$	4			$	—
	Goodwill (at period end)		$	2,885.10		$	—			$	1,939.00			$	182.1			$	5.6			$	—		$	651.7			$	99.7			$	7
	Three Months Ended June 30, 2013:
																			Midstream & Marketing							UGI International
			Total			Eliminations					AmeriGas				Gas				Energy Services				Electric Generation			Antargaz				Flaga &				Corporate
											Propane				Utility															Other				& Other (b)
	Revenues		$	1,374.30		$	(61.5	)	(c)		$	581.7			$	126.7			$	233			$	16.3		$	249.3			$	182.5			$	46.3
	Cost of sales		$	836.8		$	(60.1	)	(c)		$	305.7			$	52.4			$	214.9			$	8.5		$	148.7			$	134.8			$	31.9
	Segment profit:
	Operating income (loss)		$	41.5		$	(0.2	)			$	3.8			$	14.2			$	6.4			$	0.6		$	14.6			$	6.5			$	(4.4	)
	Income from equity investees		—			—					—				—				—				—			—				—				—
	Interest expense		(59.2		)	—					(41.2		)		(9.2		)		(0.6		)		—			(6.2		)		(1.2		)		(0.8		)
	(Loss) income before income taxes		$	(17.7	)	$	(0.2	)			$	(37.4	)		$	5			$	5.8			$	0.6		$	8.4			$	5.3			$	(5.2	)
	Partnership EBITDA (a)										$	56.3
	Noncontrolling interests’ net (loss) income		$	(31.9	)	$	—				$	(31.7	)		$	—			$	—			$	—		$	(0.3	)		$	0.1			$	—
	Depreciation and amortization		$	91.8		$	(0.1	)			$	52.4			$	13.1			$	2.1			$	2.6		$	14			$	6.1			$	1.6
	Capital expenditures		$	107.6		$	(0.1	)			$	26.3			$	37.3			$	22			$	4.4		$	11.7			$	4			$	2
	Total assets (at period end)		$	9,806.80		$	(95.9	)			$	4,386.80			$	2,143.70			$	437			$	267.2		$	1,771.70			$	543.1			$	353.2
	Bank loans (at period end)		$	135.9		$	—				$	80			$	—			$	45.5			$	—		$	—			$	10.4			$	—
	Goodwill (at period end)		$	2,834.00		$	—				$	1,929.20			$	182.1			$	2.8			$	—		$	619.2			$	93.7			$	7
	(a)	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
	Three Months Ended June 30,		2014			2013
	Partnership EBITDA		$	55		$	56.3
	Depreciation and amortization		(47.8		)	(52.4		)
	Noncontrolling interests (i)		—			(0.1		)
	Operating income		$	7.2		$	3.8
	(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 gains and losses on Midstream & Marketing’s commodity derivative instruments, and net gains and losses on AmeriGas Propane’s commodity derivative instruments entered into beginning April 1, 2014, that are not associated with current period transactions, (4) net expenses of UGI’s captive general liability insurance company, and (5) UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
	(c)	Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane.
	Nine Months Ended June 30, 2014:
																			Midstream & Marketing							UGI International
			Total			Elim-					AmeriGas				Gas				Energy Services				Electric Generation			Antargaz				Flaga &				Corporate &
						inations					Propane				Utility															Other				Other (b)
	Revenues		$	6,965.90		$	(281.0	)	(c)		$	3,152.70			$	880			$	1,109.90			$	66.4		$	1,086.50			$	802.8			$	148.6
	Cost of sales		$	4,357.70		$	(278.0	)	(c)		$	1,809.00			$	463.5			$	894.2			$	30.5		$	713.3			$	635.1			$	90.1
	Segment profit:
	Operating income (loss)		$	1,015.00		$	—				$	471.7			$	233.7			$	166.8			$	16.9		$	94.7			$	32.8			$	(1.6	)
	Loss from equity investees		(0.1		)	—					—				—				—				—			(0.1		)		—				—
	Interest expense		(178.9		)	—					(125.0		)		(26.6		)		(2.5		)		—			(19.1		)		(3.8		)		(1.9		)
	Income (loss) before income taxes		$	836		$	—				$	346.7			$	207.1			$	164.3			$	16.9		$	75.5			$	29			$	(3.5	)
	Partnership EBITDA (a)		$	613.7							$	616.5																						$	(2.8	)
	Noncontrolling interests’ net income (loss)		$	235.6		$	—				$	237.6			$	—			$	—			$	—		$	—			$	—			$	(2.0	)
	Depreciation and amortization		$	271.7		$	(0.1	)			$	149.3			$	40.7			$	9.1			$	8		$	39.9			$	20			$	4.8
	Capital expenditures		$	290.5		$	—				$	80.3			$	98.8			$	41.3			$	13		$	36.7			$	13.6			$	6.8
	Total assets (at period end)		$	10,077.70		$	(112.8	)			$	4,345.80			$	2,147.40			$	542.7			$	279.1		$	1,784.20			$	650.6			$	440.7
	Bank loans (at period end)		$	96.5		$	—				$	92.5			$	—			$	—			$	—		$	—			$	4			$	—
	Goodwill (at period end)		$	2,885.10		$	—				$	1,939.00			$	182.1			$	5.6			$	—		$	651.7			$	99.7			$	7
Nine Months Ended June 30, 2013:
																		Midstream & Marketing							UGI International
		Total			Elim-					AmeriGas				Gas				Energy Services				Electric Generation			Antargaz				Flaga &				Corporate &
					inations					Propane				Utility															Other				Other (b)
Revenues		$	5,935.70		$	(181.1	)	(c)		$	2,636.90			$	743.6			$	764.8			$	48.7		$	1,121.20			$	659			$	142.6
Cost of sales		$	3,539.00		$	(176.2	)	(c)		$	1,367.40			$	372.7			$	650.5			$	29		$	714.4			$	507.1			$	74.1
Segment profit:
Operating income		$	843.4		$	(1.1	)			$	407.5			$	189.7			$	76.5			$	1.4		$	129.9			$	30.6			$	8.9
Income from equity investees		0.1			—					—				—				—				—			0.1				—				—
Interest expense		(180.8		)	—					(125.4		)		(28.1		)		(2.4		)		—			(19.0		)		(3.8		)		(2.1		)
Income before income taxes		$	662.7		$	(1.1	)			$	282.1			$	161.6			$	74.1			$	1.4		$	111			$	26.8			$	6.8
Partnership EBITDA (a)										$	557.1
Noncontrolling interests’ net income		$	194.4		$	—				$	194.2			$	—			$	—			$	—		$	0.1			$	0.1			$	—
Depreciation and amortization		$	269.2		$	(0.1	)			$	153.4			$	38.4			$	5.6			$	7.5		$	42.3			$	17.4			$	4.7
Capital expenditures		$	292.5		$	(1.1	)			$	80.7			$	90.2			$	54.8			$	15.4		$	37.1			$	10.3			$	5.1
Total assets (at period end)		$	9,806.80		$	(95.9	)			$	4,386.80			$	2,143.70			$	437			$	267.2		$	1,771.70			$	543.1			$	353.2
Bank loans (at period end)		$	135.9		$	—				$	80			$	—			$	45.5			$	—		$	—			$	10.4			$	—
Goodwill (at period end)		$	2,834.00		$	—				$	1,929.20			$	182.1			$	2.8			$	—		$	619.2			$	93.7			$	7
(a)	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
Nine Months Ended June 30,		2014			2013
Partnership EBITDA		$	616.5		$	557.1
Depreciation and amortization		(149.3		)	(153.4		)
Noncontrolling interests (i)		4.5			3.8
Operating income		$	471.7		$	407.5
(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 gains and losses on Midstream & Marketing’s commodity derivative instruments, and net gains and losses on AmeriGas Propane’s commodity derivative instruments entered into beginning April 1, 2014, that are not associated with current period transactions, (4) net expenses of UGI’s captive general liability insurance company, and (5) UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
(c)	Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Utility_Regulatory_Assets_and_1

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)	9 Months Ended
	Jun. 30, 2014
Regulated Operations [Abstract]	'
Regulatory assets and liabilities associated with Gas Utility and Electric Utility	'
	The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:
		June 30,		September 30,		June 30,
		2014		2013		2013
	Regulatory assets:
	Income taxes recoverable	$	107.2	$	106.1	$	104.7
	Underfunded pension and postretirement plans	89.2		94.5		177.8
	Environmental costs	14.6		17.1		16.6
	Deferred fuel and power costs	9.4		8.3		4.1
	Removal costs, net	15.6		13.3		12.1
	Other	6.6		5.6		5.6
	Total regulatory assets	$	242.6	$	244.9	$	320.9
	Regulatory liabilities:
	Postretirement benefits	$	17.5	$	16.5	$	14.2
	Environmental overcollections	1.6		2.6		2.9
	Deferred fuel and power refunds	—		8.3		14.2
	State tax benefits—distribution system repairs	9.3		8.4		8
	Other	1.9		1.5		0.7
	Total regulatory liabilities	$	30.3	$	37.3	$	40

Defined_Benefit_Pension_and_Ot1

Defined Benefit Pension and Other Postretirement Plans (Tables)	9 Months Ended
	Jun. 30, 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 June 30,						Three Months Ended June 30,
		2014			2013			2014			2013
	Service cost	$	2.3		$	2.8		$	0.1		$	0.2
	Interest cost	6.5			5.9			0.2			0.2
	Expected return on assets	(7.3		)	(6.9		)	(0.1		)	(0.1		)
	Amortization of:
	Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
	Actuarial loss	1.9			3.7			—			0.1
	Net benefit cost	3.5			5.6			0.1			0.3
	Change in associated regulatory liabilities	—			—			0.9			0.8
	Net expense	$	3.5		$	5.6		$	1		$	1.1
		Pension Benefits						Other
								Postretirement Benefits
		Nine Months Ended						Nine Months Ended
		June 30,						June 30,
		2014			2013			2014			2013
	Service cost	$	7		$	8.5		$	0.4		$	0.5
	Interest cost	19.4			17.6			0.7			0.7
	Expected return on assets	(22.0		)	(20.7		)	(0.4		)	(0.4		)
	Amortization of:
	Prior service cost (benefit)	0.2			0.2			(0.4		)	(0.2		)
	Actuarial loss	5.7			11.2			0.1			0.3
	Net benefit cost	10.3			16.8			0.4			0.9
	Change in associated regulatory liabilities	—			—			2.7			2.4
	Net expense	$	10.3		$	16.8		$	3.1		$	3.3

Fair_Value_Measurement_Tables

Fair Value Measurement (Tables)	9 Months Ended
	Jun. 30, 2014
Fair Value Disclosures [Abstract]	'
Financial Assets and Financial Liabilities that are Measured at Fair Value on a Recurring Basis	'
	The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of June 30, 2014, September 30, 2013 and June 30, 2013:
			Asset (Liability)
			Quoted Prices				Significant				Unobservable		Total
			in Active				Other				Inputs
			Markets for				Observable				(Level 3)
			Identical Assets				Inputs
			and Liabilities				(Level 2)
			(Level 1)
	June 30, 2014:
	Assets:
	Derivative financial instruments:
	Commodity contracts		$	6.8			$	6.4			$	—	$	13.2
	Foreign currency contracts		$	—			$	0.5			$	—	$	0.5
	Liabilities:
	Derivative financial instruments:
	Commodity contracts		$	(4.5	)		$	(6.6	)		$	—	$	(11.1	)
	Foreign currency contracts		$	—			$	(4.8	)		$	—	$	(4.8	)
	Interest rate contracts		$	—			$	(25.2	)		$	—	$	(25.2	)
	Cross-currency swaps		$	—			$	(2.0	)		$	—	$	(2.0	)
	September 30, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts		$	2.1			$	21.2			$	—	$	23.3
	Foreign currency contracts		$	—			$	0.9			$	—	$	0.9
	Liabilities:
	Derivative financial instruments:
	Commodity contracts		$	(9.7	)		$	(6.3	)		$	—	$	(16.0	)
	Foreign currency contracts		$	—			$	(7.2	)		$	—	$	(7.2	)
	Interest rate contracts		$	—			$	(31.0	)		$	—	$	(31.0	)
	Cross-currency swaps		$	—			$	(1.2	)		$	—	$	(1.2	)
	June 30, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts		$	2.2			$	7.4			$	—	$	9.6
	Foreign currency contracts		$	—			$	1			$	—	$	1
	Interest rate contracts		$	—			$	8.1			$	—	$	8.1
	Liabilities:
	Derivative financial instruments:
	Commodity contracts		$	(8.0	)		$	(24.1	)		$	—	$	(32.1	)
	Foreign currency contracts		$	—			$	(1.7	)		$	—	$	(1.7	)
	Interest rate contracts		$	—			$	(46.9	)		$	—	$	(46.9	)
Offsetting Derivative Assets and Liabilities	'
	Cash collateral paid by us to our derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our 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.
		Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet
	June 30, 2014:
	Derivative assets	$	31.9		$	(18.2	)	$	13.7
	Derivative (liabilities)	$	(61.3	)	$	18.2		$	(43.1	)
	September 30, 2013:
	Derivative assets	$	26.3		$	(2.1	)	$	24.2
	Derivative (liabilities)	$	(57.5	)	$	2.1		$	(55.4	)
	June 30, 2013:
	Derivative assets	$	25.1		$	(6.4	)	$	18.7
	Derivative (liabilities)	$	(87.1	)	$	6.4		$	(80.7	)

Disclosures_About_Derivative_I1

Disclosures About Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Jun. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Balance Sheet Location and Fair Value of Derivative Assets and Liabilities	'
	The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2014 and 2013:
		Derivative Assets										Derivative (Liabilities)
		Balance Sheet		Fair Value June 30,								Balance Sheet	Fair Value June 30,
		Location		2014				2013				Location	2014			2013
	Derivatives Designated as Hedging Instruments:
	Commodity contracts	Derivative financial instruments and		$	7			$	5.3			Derivative financial instruments	$	(3.1	)	$	(17.9	)
		Other assets										and Other noncurrent liabilities
	Foreign currency contracts	Derivative financial instruments and		0.5				1				Derivative financial instruments	(4.8		)	(0.4		)
		Other assets										and Other noncurrent liabilities
	Cross-currency contracts			—				—				Derivative financial instruments	(2.0		)	—
												and Other noncurrent liabilities
	Interest rate contracts	Derivative financial instruments		—				8.1				Derivative financial instruments	(25.2		)	(46.9		)
												and Other noncurrent liabilities
	Total Derivatives Designated as Hedging Instruments			$	7.5			$	14.4				$	(35.1	)	$	(65.2	)
	Derivatives Subject to Utility Rate Regulation:
	Commodity contracts	Derivative financial instruments		$	1.6			$	0.1			Derivative financial instruments	$	—		$	(7.6	)
	Derivatives Not Designated as Hedging Instruments:
	Commodity contracts	Derivative financial instruments and Other assets		$	6.4			$	4.2			Derivative financial instruments and Other noncurrent liabilities	$	(9.8	)	$	(6.6	)
	Foreign currency contracts	Derivative financial instruments		—				—				Derivative financial instruments	—			(1.3		)
	Total Derivatives Not Designated as Hedging Instruments			$	6.4			$	4.2				$	(9.8	)	$	(7.9	)
	Amounts above offset in the Balance Sheet			(1.8		)		—					1.8			—
	Total Derivatives			$	13.7			$	18.7				$	(43.1	)	$	(80.7	)
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 on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and nine months ended June 30, 2014 and 2013:
	Three Months Ended June 30,	Gain (Loss)								Gain (Loss)						Location of
		Recognized in								Reclassified from						Gain (Loss)
		AOCI and								AOCI and Noncontrolling						Reclassified from
		Noncontrolling Interests								Interests into Income						AOCI and Noncontrolling
		2014				2013				2014			2013			Interests into Income
	Cash Flow Hedges:
	Commodity contracts	$	(1.7	)		$	(17.1	)		$	4.3		$	(8.2	)	Cost of sales
	Foreign currency contracts	1.1				(0.3		)		(0.2		)	—			Cost of sales
	Cross-currency contracts	—				—				(0.1		)	—			Interest expense
	Interest rate contracts	(0.6		)		14				(3.9		)	(3.6		)	Interest expense / other income, net
	Total	$	(1.2	)		$	(3.4	)		$	0.1		$	(11.8	)
		Gain (Loss)														Location of Gain (Loss)
		Recognized in Income														Recognized in Income
	Derivatives Not Designated as Hedging Instruments:	2014				2013
	Commodity contracts	$	(4.9	)		$	(5.7	)								Cost of sales
	Commodity contracts	—				(0.1		)								Operating expenses / other
																income, net
	Foreign currency contracts	—				(0.9		)								Other income, net
	Total	$	(4.9	)		$	(6.7	)
	Nine Months Ended June 30,	Gain (Loss)								Gain (Loss)						Location of
		Recognized in								Reclassified from						Gain (Loss)
		AOCI and								AOCI and Noncontrolling						Reclassified from
		Noncontrolling Interests								Interests into Income						AOCI and Noncontrolling
		2014				2013				2014			2013			Interests into Income
	Cash Flow Hedges:
	Commodity contracts	$	59.5			$	(21.6	)		$	66.5		$	(51.4	)	Cost of sales
	Foreign currency contracts	(1.6		)		(1.4		)		(3.7		)	(0.1		)	Cost of sales
	Cross-currency contracts	(1.1		)		—				(0.2		)	—			Interest expense
	Interest rate contracts	(4.1		)		23				(12.0		)	(10.6		)	Interest expense / other income, net
	Total	$	52.7			$	—			$	50.6		$	(62.1	)
		Gain (Loss)														Location of Gain (Loss)
		Recognized in Income														Recognized in Income
	Derivatives Not Designated as Hedging Instruments:	2014				2013
	Commodity contracts	$	(14.3	)		$	8.1									Cost of sales
	Commodity contracts	0.1				—										Operating expenses / other
																income, net
	Foreign currency contracts	—				(1.1		)								Other income, net
	Total	$	(14.2	)		$	7

Inventories_Tables

Inventories (Tables)	9 Months Ended
	Jun. 30, 2014
Inventory Disclosure [Abstract]	'
Components of Inventories	'
	Inventories comprise the following:
		June 30,		September 30,		June 30,
		2014		2013		2013
	Non-utility LPG and natural gas	$	222.6	$	230	$	194.6
	Gas Utility natural gas	45.7		78.9		43.1
	Materials, supplies and other	63.7		56.6		66.3
	Total inventories	$	332	$	365.5	$	304

Subsequent_Event_Subseqent_Eve

Subsequent Event Subseqent Event (Tables)	9 Months Ended
	Jun. 30, 2014
Subsequent Events [Abstract]	'
Schedule of Earnings Per Share, Basic and Diluted, Pro Forma Adjustment	'
	The following table presents pro forma basic and diluted earnings per share attributable to UGI Corporation stockholders to reflect the effect of the 3-for-2 common stock split:
		Three Months Ended		Nine Months Ended
		June 30,		June 30,
		2014	2013	2014	2013
	Basic earnings per share:
	As reported	$0.18	$0.08	$3.10	$2.57
	Pro forma	$0.12	$0.05	$2.07	$1.71
	Diluted earnings per share:
	As reported	$0.18	$0.08	$3.06	$2.54
	Pro forma	$0.12	$0.05	$2.04	$1.69

Nature_of_Operations_Narrative

Nature of Operations - Narrative (Details)	1 Months Ended
	Jun. 30, 2014	Jan. 31, 2014
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)	69,109,914	'
Common Units Owned by ETP (in units)	4,367,362	'
Subsidiary units issued in secondary offering	8,500,000	9,200,000

Significant_Accounting_Policie3

Significant Accounting Policies - Narrative (Details) (USD $)	1 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Jun. 30, 2014
Accounting Policies [Abstract]	'	'
French Tax Law Change, Corporate Surtax Rate Increase, Term	'2 years	'
Significant Accounting Policies (Textual) [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%
Impact of French Tax Law Change	'	$5.70

Significant_Accounting_Policie4

Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Denominator (thousands of shares):	'	'	'	'
Average common shares outstanding for basic computation (in shares)	115,370	114,240	115,121	113,693
Incremental shares issuable for stock options and awards (in shares)	1,678	1,956	1,610	1,582
Average common shares outstanding for diluted computation (in shares)	117,048	116,196	116,731	115,275

Significant_Accounting_Policie5

Significant Accounting Policies - Schedule of Changes in Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Mar. 31, 2014	Sep. 30, 2013
Schedule of Changes in Accumulated Other Comprehensive Income	'	'	'	'	'	'
Accumulated other comprehensive loss	$25.40	($27.40)	$25.40	($27.40)	$24.30	$8.40
Other Comprehensive Income (Loss) Before Reclassifications Net Of Tax	-0.8	'	57.7	'	'	'
Reclassification Adjustment of Other Comprehensive Income, Before Tax	0.2	'	-49.7	'	'	'
Tax on reclassifications on derivative instruments	-1.3	-2.1	4	-9.8	'	'
Tax on foreign currency adjustments	0	-2.4	-3.1	1.8	'	'
Reclassification Adjustment of Other Comprehensive Income, Tax	-1.5	'	3.8	'	'	'
Reclassifications of net losses on derivative instruments	1.5	-9.7	46.7	-52.3	'	'
Foreign currency, net of tax	-0.2	8.8	11.5	1.3	'	'
Reclassification Adjustment of Other Comprehensive Income, After Tax	-1.3	'	-45.9	'	'	'
Other comprehensive (loss) income	-2.1	11.2	11.8	47.5	'	'
Reclassification Adjustment of Other Comprehensive Income, Net of Tax, attributable to Noncontrolling Interest	3.2	'	5.2	'	'	'
Other comprehensive income (loss) attributable to UGI	1.1	'	17	'	'	'
Foreign Currency	'	'	'	'	'	'
Schedule of Changes in Accumulated Other Comprehensive Income	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax	63.2	'	63.2	'	63.4	51.7
Other Comprehensive Income (Loss) Before Reclassifications Net Of Tax	-0.2	'	11.5	'	'	'
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, before Tax	0	'	0	'	'	'
Tax on foreign currency adjustments	0	'	0	'	'	'
Foreign currency, net of tax	0	'	0	'	'	'
Other comprehensive (loss) income	-0.2	'	11.5	'	'	'
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax, Portion Attributable to Noncontrolling Interest	0	'	0	'	'	'
Other comprehensive income (loss) attributable to UGI	-0.2	'	11.5	'	'	'
Derivative Instruments	'	'	'	'	'	'
Schedule of Changes in Accumulated Other Comprehensive Income	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	-22.2	'	-22.2	'	-23.3	-26.9
Other Comprehensive Income (Loss) Before Reclassifications Net Of Tax	-0.6	'	46.2	'	'	'
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, before Tax	-0.2	'	-50.7	'	'	'
Tax on reclassifications on derivative instruments	-1.3	'	4	'	'	'
Reclassifications of net losses on derivative instruments	-1.5	'	-46.7	'	'	'
Other comprehensive (loss) income	-2.1	'	-0.5	'	'	'
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax, Portion Attributable to Noncontrolling Interest	3.2	'	5.2	'	'	'
Other comprehensive income (loss) attributable to UGI	1.1	'	4.7	'	'	'
Postretirement Benefit Plans	'	'	'	'	'	'
Schedule of Changes in Accumulated Other Comprehensive Income	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	-15.6	'	-15.6	'	-15.8	-16.4
Other Comprehensive Income (Loss) Before Reclassifications Net Of Tax	0	'	0	'	'	'
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax	0.4	'	1	'	'	'
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, Tax	-0.2	'	-0.2	'	'	'
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, Net of Tax	0.2	'	0.8	'	'	'
Other comprehensive (loss) income	0.2	'	0.8	'	'	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Noncontrolling Interest	0	'	0	'	'	'
Other comprehensive income (loss) attributable to UGI	$0.20	'	$0.80	'	'	'

Restatements_of_Condensed_Cons2

Restatements of Condensed Consolidated Financial Statements - Condensed Consolidated Balance Sheet (Details) (USD $)	Jun. 30, 2014	Mar. 31, 2014	Sep. 30, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Assets:	'	'	'	'
Deferred income taxes	$9.10	'	$10.60	$6.60
Property, plant and equipment	4,543.40	'	4,480.20	4,323.70
Liabilities and equity:	'	'	'	'
Other current liabilities	609.3	'	627.5	552.9
Deferred income taxes	986.2	'	962.3	933.5
Other noncurrent liabilities	514.7	'	527.2	616.9
Retained earnings	1,566.70	'	1,308.30	1,354.90
Accumulated other comprehensive loss	25.4	24.3	8.4	-27.4
Noncontrolling interests, principally in AmeriGas Partners	1,109.80	'	1,055.40	1,133.90
As Previously Reported	'	'	'	'
Assets:	'	'	'	'
Deferred income taxes	'	'	'	27.3
Property, plant and equipment	'	'	'	4,325
Liabilities and equity:	'	'	'	'
Deferred income taxes	'	'	'	956.9
Other noncurrent liabilities	'	'	'	613.5
Retained earnings	'	'	'	1,361.90
Accumulated other comprehensive loss	'	'	'	-30.7
Noncontrolling interests, principally in AmeriGas Partners	'	'	'	1,132.20
Adjustment	'	'	'	'
Assets:	'	'	'	'
Deferred income taxes	'	'	'	-20.7
Property, plant and equipment	'	'	'	-1.3
Liabilities and equity:	'	'	'	'
Deferred income taxes	'	'	'	-23.4
Other noncurrent liabilities	'	'	'	3.4
Retained earnings	'	'	'	-7
Accumulated other comprehensive loss	'	'	'	3.3
Noncontrolling interests, principally in AmeriGas Partners	'	'	'	$1.70

Restatements_of_Condensed_Cons3

Restatements of Condensed Consolidated Financial Statements - Condensed Consolidated Statement of Income (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Revenues	$1,486.70	$1,374.30	$6,965.90	$5,935.70
Cost of sales	926.5	836.8	4,357.70	3,539
Operating and administrative expenses	415.9	407.5	1,339.40	1,295.90
Depreciation	74.6	76.4	230	222.9
Other income, net	-12.1	-7	-30.6	-24.5
Operating income	62.7	41.5	1,015	843.4
Interest expense	-60.1	-59.2	-178.9	-180.8
Income (loss) before income taxes	2.5	-17.7	836	662.7
Income taxes	-15.2	-5.1	-243.4	-176
Net (loss) income	-12.7	-22.8	592.6	486.7
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners	33.3	31.9	-235.6	-194.4
Net income attributable to UGI Corporation	20.6	9.1	357	292.3
Basic earnings per common share	$0.18	$0.08	$3.10	$2.57
Diluted earnings per common share	$0.18	$0.08	$3.06	$2.54
As Previously Reported	'	'	'	'
Revenues	'	1,372.30	'	5,932.60
Cost of sales	'	827.9	'	3,547.30
Operating and administrative expenses	'	404.7	'	1,297.40
Depreciation	'	76.5	'	220
Other income, net	'	-9	'	-26.5
Operating income	'	53.1	'	835.4
Interest expense	'	-59.2	'	-179.6
Income (loss) before income taxes	'	-6.1	'	655.9
Income taxes	'	-9	'	-174.1
Net (loss) income	'	-15.1	'	481.8
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners	'	29.8	'	-192.6
Net income attributable to UGI Corporation	'	14.7	'	289.2
Basic earnings per common share	'	$0.13	'	$2.54
Diluted earnings per common share	'	$0.13	'	$2.51
Adjustment	'	'	'	'
Revenues	'	2	'	3.1
Cost of sales	'	8.9	'	-8.3
Operating and administrative expenses	'	2.8	'	-1.5
Depreciation	'	-0.1	'	2.9
Other income, net	'	2	'	2
Operating income	'	-11.6	'	8
Interest expense	'	0	'	-1.2
Income (loss) before income taxes	'	-11.6	'	6.8
Income taxes	'	3.9	'	-1.9
Net (loss) income	'	-7.7	'	4.9
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners	'	2.1	'	-1.8
Net income attributable to UGI Corporation	'	($5.60)	'	$3.10

Restatements_of_Condensed_Cons4

Restatements of Condensed Consolidated Financial Statements - Condensed Consolidated Statement of Comprehensive income (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Net (loss) income	($12.70)	($22.80)	$592.60	$486.70
Net gains on derivative instruments, net of tax	-0.6	-7.6	46.2	-7.2
Reclassification of net (gains) losses on derivative instruments, net of tax	-1.5	9.7	-46.7	52.3
Other comprehensive income	-2.1	11.2	11.8	47.5
Comprehensive (loss) income	-14.8	-11.6	604.4	534.2
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	36.5	39.9	-230.4	-214
Comprehensive income attributable to UGI Corporation	21.7	28.3	374	320.2
As Previously Reported	'	'	'	'
Net (loss) income	'	-15.1	'	481.8
Net gains on derivative instruments, net of tax	'	-11	'	-11.1
Reclassification of net (gains) losses on derivative instruments, net of tax	'	8.9	'	59.7
Other comprehensive income	'	7	'	51
Comprehensive (loss) income	'	-8.1	'	532.8
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	'	37.8	'	-212.2
Comprehensive income attributable to UGI Corporation	'	29.7	'	320.6
Adjustment	'	'	'	'
Net (loss) income	'	-7.7	'	4.9
Net gains on derivative instruments, net of tax	'	3.4	'	3.9
Reclassification of net (gains) losses on derivative instruments, net of tax	'	0.8	'	-7.4
Other comprehensive income	'	4.2	'	-3.5
Comprehensive (loss) income	'	-3.5	'	1.4
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	'	2.1	'	-1.8
Comprehensive income attributable to UGI Corporation	'	($1.40)	'	($0.40)

Restatements_of_Condensed_Cons5

Restatements of Condensed Consolidated Financial Statements - Condensed Consolidated Statements of Cash Flows (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Net (loss) income	$592.60	$486.70
Depreciation and amortization	271.7	269.2
Deferred income taxes, net	21.2	32.2
Net change in realized gains and losses deferred as cash flow hedges	'	0
Unrealized losses on derivative instruments	3.1	-0.7
Other, net	-4.9	-3.6
Accounts receivable and accrued utility revenues	-56.4	-146.2
Inventories	34.8	51.3
Accounts payable	-40.8	-25.5
Other current liabilities	5	-73.8
As Previously Reported	'	'
Net (loss) income	'	481.8
Depreciation and amortization	'	266.3
Deferred income taxes, net	'	35.5
Net change in realized gains and losses deferred as cash flow hedges	'	5
Unrealized losses on derivative instruments	'	0
Other, net	'	-11.3
Accounts receivable and accrued utility revenues	'	-141.1
Inventories	'	54.1
Accounts payable	'	-26.9
Other current liabilities	'	-73.8
Adjustment	'	'
Net (loss) income	'	4.9
Depreciation and amortization	'	2.9
Deferred income taxes, net	'	-3.3
Net change in realized gains and losses deferred as cash flow hedges	'	-5
Unrealized losses on derivative instruments	'	-0.7
Other, net	'	7.7
Accounts receivable and accrued utility revenues	'	-5.1
Inventories	'	-2.8
Accounts payable	'	1.4
Other current liabilities	'	$0

Restatements_of_Condensed_Cons6

Restatements of Condensed Consolidated Financial Statements - Condensed Consolidated Statements of Equity (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013	Sep. 30, 2012
In Millions, unless otherwise specified
UGI Corporation stockholders’ equity	$2,771	$2,492.50	$2,494.20	'
Noncontrolling interests	3,880.80	3,547.90	3,628.10	'
Retained earnings	'	'	'	'
UGI Corporation stockholders’ equity	'	'	1,354.90	'
Noncontrolling interests	1,566.70	1,308.30	1,354.90	1,156
Accumulated other comprehensive loss	'	'	'	'
UGI Corporation stockholders’ equity	'	'	-27.4	'
Noncontrolling interests	25.4	8.4	-27.4	-55.2
Noncontrolling interests	'	'	'	'
Noncontrolling interests	1,109.80	1,055.40	1,133.90	1,085.60
As Previously Reported | Retained earnings	'	'	'	'
UGI Corporation stockholders’ equity	'	'	1,361.90	'
As Previously Reported | Accumulated other comprehensive loss	'	'	'	'
UGI Corporation stockholders’ equity	'	'	-30.7	'
As Previously Reported | Noncontrolling interests	'	'	'	'
Noncontrolling interests	'	'	1,132.20	'
Adjustment | Retained earnings	'	'	'	'
UGI Corporation stockholders’ equity	'	'	-7	'
Adjustment | Accumulated other comprehensive loss	'	'	'	'
UGI Corporation stockholders’ equity	'	'	3.3	'
Adjustment | Noncontrolling interests	'	'	'	'
Noncontrolling interests	'	'	$1.70	'

Goodwill_and_Intangible_Assets2

Goodwill and Intangible Assets - Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Finite-Lived Intangible Assets	'	'	'	'
Amortization expense of intangible assets	$13.30	$13.30	$35.50	$40.20
Remainder of Fiscal 2014	13.1	'	13.1	'
Fiscal 2015	50.6	'	50.6	'
Fiscal 2016	44.2	'	44.2	'
Fiscal 2017	37.6	'	37.6	'
Fiscal 2018	36.3	'	36.3	'
Customer Relationships | Maximum	'	'	'	'
Finite-Lived Intangible Assets	'	'	'	'
Useful lives of amortizable intangible assets	'15 years	'	'	'
Noncompete Agreements | Maximum	'	'	'	'
Finite-Lived Intangible Assets	'	'	'	'
Useful lives of amortizable intangible assets	'15 years	'	'	'
Cost of Sales	'	'	'	'
Finite-Lived Intangible Assets	'	'	'	'
Amortization expense of intangible assets	$0	$0	$0	$0

Goodwill_and_Intangible_Assets3

Goodwill and Intangible Assets - Components of Company's Intangible Assets (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Goodwill and Intangible Assets Disclosure [Abstract]	'	'	'
Goodwill (not subject to amortization)	$2,885.10	$2,871	$2,834
Intangible assets:	'	'	'
Customer relationships, noncompete agreements and other	717.3	706.4	692.6
Trademarks and tradenames (not subject to amortization)	132	131.3	128.4
Gross carrying amount	849.3	837.7	821
Accumulated amortization	-259	-227.1	-212.4
Intangible assets, net	$590.30	$610.60	$608.60

Segment_Information_Narrative_

Segment Information - Narrative (Details)	9 Months Ended
	Jun. 30, 2014
	Reportable_Segments
Segment Reporting Information	'
Number of reportable segments (in reportable segments)	6

Segment_Information_Schedule_o

Segment Information - Schedule of Segment Reporting Information (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013		Sep. 30, 2013
Segment Reporting Information	'		'		'		'		'
Revenues	$1,486.70		$1,374.30		$6,965.90		$5,935.70		'
Cost of sales	926.5		836.8		4,357.70		3,539		'
Segment profit:	'		'		'		'		'
Operating income (loss)	62.7		41.5		1,015		843.4		'
(Loss) income from equity investees	-0.1		0		-0.1		0.1		'
Interest expense	-60.1		-59.2		-178.9		-180.8		'
Income (loss) before income taxes	2.5		-17.7		836		662.7		'
Partnership EBITDA	52.2	[1]	'		613.7	[2]	557.1	[2]	'
Noncontrolling interests’ net (loss) income	-33.3		-31.9		235.6		194.4		'
Depreciation and amortization	90		91.8		271.7		269.2		'
Capital expenditures	102.4		107.6		290.5		292.5		'
Total assets (at period end)	10,077.70		9,806.80		10,077.70		9,806.80		10,008.80
Bank loans (at period end)	96.5		135.9		96.5		135.9		227.9
Goodwill (at period end)	2,885.10		2,834		2,885.10		2,834		2,871
Limited Liability Company or Limited Partnership Managing Member or General Partner Ownership Interest Percentage	1.01%		'		'		'		'
Eliminations	'		'		'		'		'
Segment Reporting Information	'		'		'		'		'
Revenues	-50.8	[3]	-61.5	[3]	-281	[3]	-181.1	[3]	'
Cost of sales	-49.6	[3]	-60.1	[3]	-278	[3]	-176.2	[3]	'
Segment profit:	'		'		'		'		'
Operating income (loss)	-0.1		-0.2		0		-1.1		'
(Loss) income from equity investees	0		0		0		0		'
Interest expense	0		0		0		0		'
Income (loss) before income taxes	-0.1		-0.2		0		-1.1		'
Noncontrolling interests’ net (loss) income	0		0		0		0		'
Depreciation and amortization	0		-0.1		-0.1		-0.1		'
Capital expenditures	1.2		-0.1		0		-1.1		'
Total assets (at period end)	-112.8		-95.9		-112.8		-95.9		'
Bank loans (at period end)	0		0		0		0		'
Goodwill (at period end)	0		0		0		0		'
AmeriGas Propane	'		'		'		'		'
Segment Reporting Information	'		'		'		'		'
Revenues	613.2		581.7		3,152.70		2,636.90		'
Cost of sales	340.8		305.7		1,809		1,367.40		'
Segment profit:	'		'		'		'		'
Operating income (loss)	7.2		3.8		471.7		407.5		'
(Loss) income from equity investees	0		0		0		0		'
Interest expense	-41.4		-41.2		-125		-125.4		'
Income (loss) before income taxes	-34.2		-37.4		346.7		282.1		'
Partnership EBITDA	55	[1]	56.3	[1]	616.5	[2]	557.1		'
Noncontrolling interests’ net (loss) income	-31		-31.7		237.6		194.2		'
Depreciation and amortization	47.8		52.4		149.3		153.4		'
Capital expenditures	29.3		26.3		80.3		80.7		'
Total assets (at period end)	4,345.80		4,386.80		4,345.80		4,386.80		'
Bank loans (at period end)	92.5		80		92.5		80		'
Goodwill (at period end)	1,939		1,929.20		1,939		1,929.20		'
Noncontrolling Interests Principally General Partners Interest in Related Parties	0	[4]	-0.1	[4]	4.5	[4]	3.8	[4]	'
Gas Utility	'		'		'		'		'
Segment Reporting Information	'		'		'		'		'
Revenues	128.3		126.7		880		743.6		'
Cost of sales	49.2		52.4		463.5		372.7		'
Segment profit:	'		'		'		'		'
Operating income (loss)	17.1		14.2		233.7		189.7		'
(Loss) income from equity investees	0		0		0		0		'
Interest expense	-9.8		-9.2		-26.6		-28.1		'
Income (loss) before income taxes	7.3		5		207.1		161.6		'
Noncontrolling interests’ net (loss) income	0		0		0		0		'
Depreciation and amortization	13.7		13.1		40.7		38.4		'
Capital expenditures	35.9		37.3		98.8		90.2		'
Total assets (at period end)	2,147.40		2,143.70		2,147.40		2,143.70		'
Bank loans (at period end)	0		0		0		0		'
Goodwill (at period end)	182.1		182.1		182.1		182.1		'
Midstream & Marketing, Energy Services	'		'		'		'		'
Segment Reporting Information	'		'		'		'		'
Revenues	248.3		233		1,109.90		764.8		'
Cost of sales	209.2		214.9		894.2		650.5		'
Segment profit:	'		'		'		'		'
Operating income (loss)	23.5		6.4		166.8		76.5		'
(Loss) income from equity investees	0		0		0		0		'
Interest expense	-0.5		-0.6		-2.5		-2.4		'
Income (loss) before income taxes	23		5.8		164.3		74.1		'
Noncontrolling interests’ net (loss) income	0		0		0		0		'
Depreciation and amortization	3.3		2.1		9.1		5.6		'
Capital expenditures	11.2		22		41.3		54.8		'
Total assets (at period end)	542.7		437		542.7		437		'
Bank loans (at period end)	0		45.5		0		45.5		'
Goodwill (at period end)	5.6		2.8		5.6		2.8		'
Midstream & Marketing, Electric Generation	'		'		'		'		'
Segment Reporting Information	'		'		'		'		'
Revenues	20.5		16.3		66.4		48.7		'
Cost of sales	10.5		8.5		30.5		29		'
Segment profit:	'		'		'		'		'
Operating income (loss)	2.6		0.6		16.9		1.4		'
(Loss) income from equity investees	0		0		0		0		'
Interest expense	0		0		0		0		'
Income (loss) before income taxes	2.6		0.6		16.9		1.4		'
Noncontrolling interests’ net (loss) income	0		0		0		0		'
Depreciation and amortization	2.7		2.6		8		7.5		'
Capital expenditures	1.9		4.4		13		15.4		'
Total assets (at period end)	279.1		267.2		279.1		267.2		'
Bank loans (at period end)	0		0		0		0		'
Goodwill (at period end)	0		0		0		0		'
International Propane, Antargaz	'		'		'		'		'
Segment Reporting Information	'		'		'		'		'
Revenues	249.2		249.3		1,086.50		1,121.20		'
Cost of sales	164.1		148.7		713.3		714.4		'
Segment profit:	'		'		'		'		'
Operating income (loss)	-1.4		14.6		94.7		129.9		'
(Loss) income from equity investees	-0.1		0		-0.1		0.1		'
Interest expense	-6.3		-6.2		-19.1		-19		'
Income (loss) before income taxes	-7.8		8.4		75.5		111		'
Noncontrolling interests’ net (loss) income	-0.3		-0.3		0		0.1		'
Depreciation and amortization	14.6		14		39.9		42.3		'
Capital expenditures	15.6		11.7		36.7		37.1		'
Total assets (at period end)	1,784.20		1,771.70		1,784.20		1,771.70		'
Bank loans (at period end)	0		0		0		0		'
Goodwill (at period end)	651.7		619.2		651.7		619.2		'
International Propane, Flaga & Other	'		'		'		'		'
Segment Reporting Information	'		'		'		'		'
Revenues	232.3		182.5		802.8		659		'
Cost of sales	180.7		134.8		635.1		507.1		'
Segment profit:	'		'		'		'		'
Operating income (loss)	8.2		6.5		32.8		30.6		'
(Loss) income from equity investees	0		0		0		0		'
Interest expense	-1.4		-1.2		-3.8		-3.8		'
Income (loss) before income taxes	6.8		5.3		29		26.8		'
Noncontrolling interests’ net (loss) income	0		0.1		0		0.1		'
Depreciation and amortization	6.2		6.1		20		17.4		'
Capital expenditures	4.8		4		13.6		10.3		'
Total assets (at period end)	650.6		543.1		650.6		543.1		'
Bank loans (at period end)	4		10.4		4		10.4		'
Goodwill (at period end)	99.7		93.7		99.7		93.7		'
Corporate & Other	'		'		'		'		'
Segment Reporting Information	'		'		'		'		'
Revenues	45.7	[5]	46.3	[5]	148.6	[6]	142.6	[6]	'
Cost of sales	21.6	[5]	31.9	[5]	90.1	[6]	74.1	[6]	'
Segment profit:	'		'		'		'		'
Operating income (loss)	5.6	[5]	-4.4	[5]	-1.6	[6]	8.9	[6]	'
(Loss) income from equity investees	0	[5]	0	[5]	0	[6]	0	[6]	'
Interest expense	-0.7	[5]	-0.8	[5]	-1.9	[6]	-2.1	[6]	'
Income (loss) before income taxes	4.9	[5]	-5.2	[5]	-3.5	[6]	6.8	[6]	'
Partnership EBITDA	-2.8	[1]	'		-2.8	[2]	'		'
Noncontrolling interests’ net (loss) income	-2	[5]	0	[5]	-2	[6]	0	[6]	'
Depreciation and amortization	1.7	[5]	1.6	[5]	4.8	[6]	4.7	[6]	'
Capital expenditures	2.5	[5]	2	[5]	6.8	[6]	5.1		'
Total assets (at period end)	440.7	[5],[6]	353.2	[5],[6]	440.7	[5],[6]	353.2	[5],[6]	'
Bank loans (at period end)	0	[5],[6]	0	[5],[6]	0	[5],[6]	0	[5],[6]	'
Goodwill (at period end)	$7	[5],[6]	$7	[5],[6]	$7	[5],[6]	$7	[5],[6]	'
[1]	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:Three Months Ended June 30, 2014 2013Partnership EBITDA $55.0 $56.3Depreciation and amortization (47.8) (52.4)Noncontrolling interests (i) — (0.1)Operating income $7.2 $3.8(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
[2]	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:Nine Months Ended June 30, 2014 2013Partnership EBITDA $616.5 $557.1Depreciation and amortization (149.3) (153.4)Noncontrolling interests (i) 4.5 3.8Operating income $471.7 $407.5(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
[3]	Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane.
[4]	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
[5]	Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net gains and losses on Midstream & Marketing’s commodity derivative instruments, and net gains and losses on AmeriGas Propane’s commodity derivative instruments entered into beginning April 1, 2014, that are not associated with current period transactions, (4) net expenses of UGI’s captive general liability insurance company, and (5) UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
[6]	.

Energy_Services_Accounts_Recei1

Energy Services Accounts Receivable Securitization Facility - Narrative (Details) (USD $)	7 Months Ended	9 Months Ended				5 Months Ended
In Millions, unless otherwise specified	31-May-14	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Oct. 31, 2014
	Maximum	Energy Services	Energy Services	Energy Services Funding Corporation	Energy Services Funding Corporation	Scenario, Forecast
						Maximum
Accounts, Notes, Loans and Financing Receivable	'	'	'	'	'	'
Receivables facility	$150	'	'	'	'	$75
Sale of trade receivables	'	1,073.10	766.1	'	'	'
Sale of undivided interests in its trade receivables to the commercial paper conduit	'	'	'	196	224	'
Outstanding balance of trade receivables	'	'	'	57.7	58.2	'
Outstanding balance of trade receivables sold	'	'	'	$0	$9.50	'

Utility_Regulatory_Assets_and_2

Utility Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Regulatory Assets	'	'	'
Gas utility unrealized gains (losses) on derivative financial instruments contracts	$0.70	($1.70)	($1.40)
Electric Utility Electric Supply Contracts	'	'	'
Regulatory Assets	'	'	'
Fair value of Electric Utility's electricity supply contracts	$0.80	($4.80)	($6.10)

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 $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory assets	$242.60	$244.90	$320.90
Regulatory liabilities	30.3	37.3	40
Postretirement benefits	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory liabilities	17.5	16.5	14.2
Environmental overcollections	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory liabilities	1.6	2.6	2.9
Deferred fuel and power refunds	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory liabilities	0	8.3	14.2
State tax benefits—distribution system repairs	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory liabilities	9.3	8.4	8
Other	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory liabilities	1.9	1.5	0.7
Income taxes recoverable	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory assets	107.2	106.1	104.7
Underfunded pension and postretirement plans	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory assets	89.2	94.5	177.8
Environmental costs	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory assets	14.6	17.1	16.6
Deferred fuel and power costs	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory assets	9.4	8.3	4.1
Removal costs, net	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory assets	15.6	13.3	12.1
Other	'	'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'	'	'
Regulatory assets	$6.60	$5.60	$5.60

Defined_Benefit_Pension_and_Ot2

Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]	'	'	'	'
Expected contribution to pensions plans during remainder of fiscal year	$6.90	'	'	'
Contribution made to Pension Plan	'	'	11	13.4
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans	$0.60	$0.80	$2.30	$2.40

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		9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pension Benefits	'	'	'	'
Components of net periodic pension expense and other postretirement benefit costs	'	'	'	'
Service cost	$2.30	$2.80	$7	$8.50
Interest cost	6.5	5.9	19.4	17.6
Expected return on assets	-7.3	-6.9	-22	-20.7
Amortization of:	'	'	'	'
Prior service cost (benefit)	0.1	0.1	0.2	0.2
Actuarial loss	1.9	3.7	5.7	11.2
Net benefit cost	3.5	5.6	10.3	16.8
Change in associated regulatory liabilities	0	0	0	0
Net expense	3.5	5.6	10.3	16.8
Other Postretirement Benefits	'	'	'	'
Components of net periodic pension expense and other postretirement benefit costs	'	'	'	'
Service cost	0.1	0.2	0.4	0.5
Interest cost	0.2	0.2	0.7	0.7
Expected return on assets	-0.1	-0.1	-0.4	-0.4
Amortization of:	'	'	'	'
Prior service cost (benefit)	-0.1	-0.1	-0.4	-0.2
Actuarial loss	0	0.1	0.1	0.3
Net benefit cost	0.1	0.3	0.4	0.9
Change in associated regulatory liabilities	0.9	0.8	2.7	2.4
Net expense	$1	$1.10	$3.10	$3.30

Commitments_and_Contingencies_

Commitments and Contingencies - Narrative (Details) (USD $)	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2013
	lb	Minimum	PNG MGP	Environmental Matters	Environmental Matters	Environmental Matters	CPG and PNG COAs	CPG and PNG COAs
		lawsuit		CPG MGP	PNG MGP	UGI Utilities	UGI Utilities	UGI Utilities
Commitments and Contingencies	'	'	'	'	'	'	'	'
Environmental expenditures cap during calendar year	'	'	'	$1.80	$1.10	'	'	'
Loss Contingency, Settlement Agreement, Terms	'	'	'P2Y	'	'	'	'	'
Accrual for environmental loss contingencies	'	'	'	'	'	'	$11.40	$14.40
Base year for determination of investigation and remediation cost (in years)	'	'	'	'	'	'5 years	'	'
Amount of propane in cylinders before reduction	17	'	'	'	'	'	'	'
Amount of propane in cylinders after reduction	15	'	'	'	'	'	'	'
Class action lawsuits (more than 20)	'	20	'	'	'	'	'	'

Fair_Value_Measurements_Fair_V

Fair Value Measurements Fair Value Measurements - Narrative (Details) (USD $)	Jun. 30, 2014	Jun. 30, 2013
In Millions, unless otherwise specified
Fair Value Disclosures [Abstract]	'	'
Long-term Debt, Carrying Value	$3,556.20	$3,493.80
Long-term Debt, Fair Value	$3,805.40	$3,621

Fair_Value_Measurements_Financ

Fair Value Measurements - Financial Assets and Liabilities that are Measured at Fair Value on a Recurring Basis (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	$13.70	$24.20	$18.70
Derivative financial instruments, liabilities	-43.1	-55.4	-80.7
Fair Value, Measurements, Recurring | Commodity contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	13.2	23.3	9.6
Derivative financial instruments, liabilities	-11.1	-16	-32.1
Fair Value, Measurements, Recurring | Foreign currency contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	0.5	0.9	1
Derivative financial instruments, liabilities	-4.8	-7.2	-1.7
Fair Value, Measurements, Recurring | Interest rate contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	'	'	8.1
Derivative financial instruments, liabilities	-25.2	-31	-46.9
Fair Value, Measurements, Recurring | Cross currency swap	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, liabilities	-2	-1.2	'
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | Fair Value, Measurements, Recurring | Commodity contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	6.8	2.1	2.2
Derivative financial instruments, liabilities	-4.5	-9.7	-8
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | Fair Value, Measurements, Recurring | Foreign currency contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	0	0	0
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | Fair Value, Measurements, Recurring | Interest rate contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	'	'	0
Derivative financial instruments, liabilities	0	0	0
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | Fair Value, Measurements, Recurring | Cross currency swap	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, liabilities	0	0	'
Significant Other Observable Inputs (Level 2) | Fair Value, Measurements, Recurring | Commodity contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	6.4	21.2	7.4
Derivative financial instruments, liabilities	-6.6	-6.3	-24.1
Significant Other Observable Inputs (Level 2) | Fair Value, Measurements, Recurring | Foreign currency contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	0.5	0.9	1
Derivative financial instruments, liabilities	-4.8	-7.2	-1.7
Significant Other Observable Inputs (Level 2) | Fair Value, Measurements, Recurring | Interest rate contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	'	'	8.1
Derivative financial instruments, liabilities	-25.2	-31	-46.9
Significant Other Observable Inputs (Level 2) | Fair Value, Measurements, Recurring | Cross currency swap	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, liabilities	-2	-1.2	'
Unobservable Inputs (Level 3) | Fair Value, Measurements, Recurring | Commodity contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	0	0	0
Unobservable Inputs (Level 3) | Fair Value, Measurements, Recurring | Foreign currency contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	0	0	0
Unobservable Inputs (Level 3) | Fair Value, Measurements, Recurring | Interest rate contracts	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	'	'	0
Derivative financial instruments, liabilities	0	0	0
Unobservable Inputs (Level 3) | Fair Value, Measurements, Recurring | Cross currency swap	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, liabilities	$0	$0	'

Fair_Value_Measurements_Offset

Fair Value Measurements - Offsetting Derivative Assets and Liabilities (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Fair Value Disclosures [Abstract]	'	'	'
Derivative Asset, Fair Value, Gross Asset	$31.90	$26.30	$25.10
Derivative Asset, Offset Amount, Gross	18.2	2.1	6.4
Derivative Asset	13.7	24.2	18.7
Derivative Liability, Fair Value, Gross Liability	-61.3	-57.5	-87.1
Derivative Liability, Offset Amount, Gross	18.2	2.1	6.4
Derivative Liability	$43.10	$55.40	$80.70

Disclosures_About_Derivative_I2

Disclosures About Derivative Instruments and Hedging Activities - Narrative (Details)

9 Months Ended

0 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Jun. 30, 2014

Sep. 30, 2013

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

USD ($)

USD ($)

USD ($)

LPG (millions of gallons)

LPG (millions of gallons)

LPG (millions of gallons)

Brokerage Accounts

Brokerage Accounts

Interest Rate Swaps

Interest Rate Swaps

Interest Rate Protection Agreements

Interest Rate Protection Agreements

Foreign Currency

Foreign Currency

Foreign Currency

Cross Currency Interest Rate Contract

Gas Utility

Gas Utility

Gas Utility

Electric 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

gal

gal

USD ($)

USD ($)

EUR (€)

EUR (€)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

DTH

DTH

USD ($)

USD ($)

Electric transmission congestion - Electric Utility

Electric transmission congestion - Electric Utility

Electric transmission congestion (excluding Electric Utility)

Electric transmission congestion (excluding Electric Utility)

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 Storage

Natural Gas Storage

kWh

kWh

kWh

kWh

kWh

kWh

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

kWh

kWh

kWh

kWh

gal

gal

DTH

DTH

DTH

DTH

Derivative

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding derivative commodity instruments volumes

'

'

'

'

274,300,000

236,700,000

'

'

'

'

'

'

'

'

'

'

'

10,900,000

11,700,000

'

315,800,000

327,400,000

232,200,000

260,600,000

427,700,000

1,609,200,000

492,500,000

927,200,000

193,200,000

451,000,000

2,900,000

1,800,000

83,000,000

19,400,000

500,000

2,700,000

Maximum Length of Time Hedged in Price Risk Cash Flow Hedges

'

'

'

'21 months

'

'

'

'

'

'

'

'

'33 months

'

'

'

'9 months

'

'

'11 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Liability, Fair Value, Gross Liability

$61.30

$57.50

$87.10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$0.80

($6.10)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Length of Time Hedged in Price Risk Cash Flow Hedge

'

'

'

'6 months

'

'

'

'

'

'

'

'

'15 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount

'

'

'

'

'

'

'

'

401.1

440.5

0

173

'

219.8

170.3

52

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

2.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum Approximate Range of Estimated Purchases of Product

'

'

'

'

'

'

'

'

'

'

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum approximate range of estimated dollar-denominated purchases of LPG (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

30.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

3.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restricted cash

5.9

8.3

6

'

'

'

5.9

6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Instruments, Loss Reclassified from Accumulated OCI into Income, Effective Portion

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Disclosures_About_Derivative_I3

Disclosures About Derivative Instruments and Hedging Activities - Balance Sheet Location and Fair Value of Derivative Assets and Liabilities (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Derivatives, Fair Value	'	'	'
Derivative Asset, Offset Amount, Net	($1.80)	'	$0
Derivative Asset	13.7	24.2	18.7
Derivative Liability, Offset Amount, Net	1.8	'	0
Derivative Liability	43.1	55.4	80.7
Designated as Hedging Instrument	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Asset, Fair Value, Net	7.5	'	14.4
Derivative Liability, Fair Value, Net	-35.1	'	-65.2
Designated as Hedging Instrument | Cross Currency Interest Rate Contract	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Asset, Fair Value, Net	0	'	0
Derivatives Not Designated as Hedging Instruments	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Asset, Fair Value, Net	6.4	'	4.2
Derivative Liability, Fair Value, Net	-9.8	'	-7.9
Derivative Financial Instruments and Other Assets | Designated as Hedging Instrument | Commodity Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Asset, Fair Value, Net	7	'	5.3
Derivative Financial Instruments and Other Assets | Designated as Hedging Instrument | Foreign Currency Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Asset, Fair Value, Net	0.5	'	1
Derivative Financial Instruments and Other Assets | Derivatives Not Designated as Hedging Instruments | Commodity Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Asset, Fair Value, Net	6.4	'	4.2
Derivative Financial Instruments, Assets | Designated as Hedging Instrument | Interest Rate Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Asset, Fair Value, Net	0	'	8.1
Derivative Financial Instruments, Assets | Derivatives Subject to Utility Rate Regulation | Commodity Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Asset, Fair Value, Net	1.6	'	0.1
Derivative Financial Instruments, Assets | Derivatives Not Designated as Hedging Instruments | Foreign Currency Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Asset, Fair Value, Net	0	'	0
Derivative Financial Instruments and Other Noncurrent Liabilities | Designated as Hedging Instrument | Commodity Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Liability, Fair Value, Net	-3.1	'	-17.9
Derivative Financial Instruments and Other Noncurrent Liabilities | Designated as Hedging Instrument | Foreign Currency Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Liability, Fair Value, Net	-4.8	'	-0.4
Derivative Financial Instruments and Other Noncurrent Liabilities | Designated as Hedging Instrument | Cross Currency Interest Rate Contract	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Liability, Fair Value, Net	-2	'	0
Derivative Financial Instruments and Other Noncurrent Liabilities | Designated as Hedging Instrument | Interest Rate Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Liability, Fair Value, Net	-25.2	'	-46.9
Derivative Financial Instruments and Other Noncurrent Liabilities | Derivatives Subject to Utility Rate Regulation | Commodity Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Liability, Fair Value, Net	0	'	-7.6
Derivative Financial Instruments and Other Noncurrent Liabilities | Derivatives Not Designated as Hedging Instruments | Commodity Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Liability, Fair Value, Net	-9.8	'	-6.6
Derivative Financial Instruments, Liabilities [Member] | Derivatives Not Designated as Hedging Instruments | Foreign Currency Contracts	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Liability, Fair Value, Net	$0	'	($1.30)

Disclosures_About_Derivative_I4

Disclosures About 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		9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivatives Not Designated as Hedging Instruments	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain (Loss) Recognized in Income	($4.90)	($6.70)	($14.20)	$7
Cash Flow Hedges	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain (loss) recognized in AOCI and noncontrolling interests	-1.2	-3.4	52.7	0
Gain (loss) reclassified from AOCI and noncontrolling interest into income	0.1	-11.8	50.6	-62.1
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Cost of Sales	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain (Loss) Recognized in Income	-4.9	-5.7	-14.3	8.1
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Operating Expenses / Other Income	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain (Loss) Recognized in Income	0	-0.1	0.1	0
Commodity Contracts | Cash Flow Hedges | Cost of Sales	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain (loss) recognized in AOCI and noncontrolling interests	-1.7	-17.1	59.5	-21.6
Gain (loss) reclassified from AOCI and noncontrolling interest into income	4.3	-8.2	66.5	-51.4
Foreign Currency Contracts | Derivatives Not Designated as Hedging Instruments | Other Income	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain (Loss) Recognized in Income	0	-0.9	0	-1.1
Foreign Currency Contracts | Cash Flow Hedges | Cost of Sales	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain (loss) recognized in AOCI and noncontrolling interests	1.1	-0.3	-1.6	-1.4
Gain (loss) reclassified from AOCI and noncontrolling interest into income	-0.2	0	-3.7	-0.1
Cross Currency Interest Rate Contract | Cash Flow Hedges | Interest Expense	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain (loss) recognized in AOCI and noncontrolling interests	0	0	-1.1	0
Gain (loss) reclassified from AOCI and noncontrolling interest into income	-0.1	0	-0.2	'
Interest Rate Contracts | Cash Flow Hedges | Interest Expense / Other Income	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain (loss) recognized in AOCI and noncontrolling interests	-0.6	14	-4.1	23
Gain (loss) reclassified from AOCI and noncontrolling interest into income	($3.90)	($3.60)	($12)	($10.60)

Inventories_Narrative_Details

Inventories - Narrative (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2014	Jun. 30, 2014
In Millions, unless otherwise specified	ft3	ft3	Minimum	Maximum
	Storage_Agreement
Inventory	'	'	'	'
Number of Storage Agreements	3	'	'	'
SCAA Contract Term, in years	'	'	'1 year	'3 years
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet)	2,100,000,000	600,000,000	'	'
Carrying value of gas storage inventories released under SCAAs with non-affiliates	$8.90	$2.40	'	'

Inventories_Components_of_Inve

Inventories - Components of Inventories (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Inventory	'	'	'
Total inventories	$332	$365.50	$304
Non-utility LPG and Natural Gas	'	'	'
Inventory	'	'	'
Total inventories	222.6	230	194.6
Gas Utility Natural Gas	'	'	'
Inventory	'	'	'
Total inventories	45.7	78.9	43.1
Materials, Supplies and Other	'	'	'
Inventory	'	'	'
Total inventories	$63.70	$56.60	$66.30

Debt_Narrative_Details

Debt - Narrative (Details) (USD $)

3 Months Ended

0 Months Ended

0 Months Ended

1 Months Ended

Jun. 30, 2014

Mar. 26, 2014

Mar. 26, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

4.98% Senior Notes

4.98% Senior Notes

Term Loan, 364-day Credit Agreement

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Federal Funds Rate

Base Rate

Base Rate

Base Rate

Base Rate

Eurodollar

Eurodollar

Eurodollar

Eurodollar

Amended and Restated Credit Agreement

Amended and Restated Credit Agreement

Credit Agreement

Credit Agreement

Letter of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Minimum

Maximum

Minimum

Maximum

Amended and Restated Credit Agreement

Amended and Restated Credit Agreement

Amended and Restated Credit Agreement

Credit Agreement

Credit Agreement

Amended and Restated Credit Agreement

Amended and Restated Credit Agreement

Credit Agreement

Credit Agreement

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Debt Instrument

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from 4.98% Senior Note

'

$175,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest Rate

4.98%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Repayment

'

'

175,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Term

'

'

'364 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt to Capital Ratio

0.65

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum borrowing capacity

'

'

'

$525,000,000

'

'

'

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$125,000,000

'

'

'

'

'

'

'

'

'

Applicable margin

'

'

'

'

'

'

'

'

'

0.50%

0.50%

1.50%

0.80%

1.80%

1.50%

2.50%

1.80%

2.80%

Commitment fee percentage

'

'

'

'

0.30%

0.45%

0.30%

0.50%

'

'

'

'

'

'

'

'

'

'

Subsequent_Event_Subsequent_Ev1

Subsequent Event Subsequent Events (Details) (USD $)	3 Months Ended		9 Months Ended		0 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jul. 29, 2014
					Subsequent Event
Subsequent Event	'	'	'	'	'
Basic earnings per common share	$0.18	$0.08	$3.10	$2.57	'
Basic earnings per common share, pro forma effect of stock split	$0.12	$0.05	$2.07	$1.71	'
Diluted earnings per common share	$0.18	$0.08	$3.06	$2.54	'
Diluted earnings per common share, pro forma effect of stock split	$0.12	$0.05	$2.04	$1.69	'
3-for-2 common stock split	'	'	'	'	0.67