Ugi Utilities 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
Entity Information [Line Items]	'	'
Entity Registrant Name	'UGI UTILITIES INC	'
Entity Central Index Key	'0000100548	'
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 Well-known Seasoned Issuer	'No	'
Entity Voluntary Filers	'No	'
Entity Current Reporting Status	'Yes	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	26,781,785

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (unaudited) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Thousands, unless otherwise specified
Current assets:	'	'	'
Cash and cash equivalents	$28,480	$4,707	$82,027
Restricted cash	1,109	3,181	2,636
Accounts receivable (less allowances for doubtful accounts of $13,517, $5,519 and $9,166, respectively)	97,144	53,341	78,677
Accounts receivable — related parties	3,484	3,497	4,086
Accrued utility revenues	7,950	18,868	11,836
Inventories	58,750	89,661	53,998
Deferred income taxes	11,908	14,165	17,910
Regulatory assets	9,354	8,217	3,747
Derivative financial instruments	1,703	43	8,228
Prepaid expenses & other current assets	11,057	15,862	9,766
Total current assets	230,939	211,542	272,911
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $888,279, $853,675 and $846,941, respectively)	1,635,867	1,574,135	1,531,440
Goodwill	182,145	182,145	182,145
Regulatory assets	233,272	236,694	317,216
Other assets	7,618	5,806	3,635
Total assets	2,289,841	2,210,322	2,307,347
Current liabilities:	'	'	'
Current maturities of long-term debt	20,000	0	133,000
Bank loans	0	17,500	0
Accounts payable	47,396	51,970	35,587
Accounts payable — related parties	21,131	12,487	17,176
Deferred fuel refunds	0	8,283	14,156
Derivative financial instruments	31	6,677	22,911
Other current liabilities	140,404	110,596	123,438
Total current liabilities	228,962	207,513	346,268
Long-term debt	622,000	642,000	467,000
Deferred income taxes	454,871	436,810	422,994
Deferred investment tax credits	4,017	4,270	4,355
Pension and postretirement benefit obligations	61,991	72,505	172,721
Other noncurrent liabilities	53,439	55,610	51,999
Total liabilities	1,425,280	1,418,708	1,465,337
Commitments and contingencies (note 8)	'	'	'
Common stockholder’s equity:	'	'	'
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)	60,259	60,259	60,259
Additional paid-in capital	470,844	470,098	469,736
Retained earnings	340,714	269,977	327,298
Accumulated other comprehensive loss	-7,256	-8,720	-15,283
Total common stockholder’s equity	864,561	791,614	842,010
Total liabilities and stockholder’s equity	$2,289,841	$2,210,322	$2,307,347

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (unaudited) Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'	'
Allowance for doubtful accounts on accounts receivable	$13,517	$5,519	$9,166
Accumulated depreciation and amortization on property, plant and equipment	$888,279	$853,675	$846,941
Common stock, par value	$2.25	$2.25	$2.25
Common stock, shares authorized	40,000,000	40,000,000	40,000,000
Common stock, shares issued	26,781,785	26,781,785	26,781,785
Common stock, shares outstanding	26,781,785	26,781,785	26,781,785

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Income (unaudited) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Statement [Abstract]	'	'	'	'
Revenues	$152,694	$148,798	$965,549	$818,496
Costs and expenses:	'	'	'	'
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	63,323	64,332	515,612	415,394
Operating and administrative expenses	49,862	46,420	145,313	143,076
Operating and administrative expenses — related parties	2,385	1,940	7,997	6,757
Taxes other than income taxes	3,768	3,756	12,748	12,716
Depreciation	14,048	13,201	41,485	38,849
Amortization	844	832	2,500	2,467
Other (income), net	-1,256	-561	-3,623	-1,435
Total costs and expenses	132,974	129,920	722,032	617,824
Operating income	19,720	18,878	243,517	200,672
Interest expense	10,433	9,690	28,036	29,587
Income before income taxes	9,287	9,188	215,481	171,085
Income taxes	2,397	3,815	87,195	70,641
Net income	$6,890	$5,373	$128,286	$100,444

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Statement of Comprehensive Income [Abstract]	'	'	'	'
Net income	$6,890	$5,373	$128,286	$100,444
Other comprehensive income:	'	'	'	'
Net gains in fair value of derivative instruments (net of tax of $0, $(5,301), $0 and $(9,638), respectively)	0	7,475	0	13,590
Reclassifications of net losses on derivative instruments (net of tax of $(278), $(84), $(834) and $(252), respectively)	393	119	1,176	356
Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(67), $(140), $(206) and $(418), respectively)	95	195	288	588
Other comprehensive income	488	7,789	1,464	14,534
Comprehensive income	$7,378	$13,162	$129,750	$114,978

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements of Comprehensive Income (unaudited) Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, 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	$5,301	$0	$9,638
Tax on reclassifications of net losses (gains) on derivative instruments	278	84	834	252
Tax on benefit plans	$67	$140	$206	$418

Condensed_Consolidated_Stateme3

Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
Net income	$128,286	$100,444
Adjustments to reconcile net income to net cash from operating activities:	'	'
Depreciation and amortization	43,985	41,316
Deferred income taxes, net	18,747	23,369
Provision for uncollectible accounts	11,657	8,297
Other, net	-2,809	4,647
Net change in:	'	'
Accounts receivable and accrued utility revenues	-44,530	-34,052
Inventories	30,911	13,336
Deferred fuel and power costs, net of changes in unsettled derivatives	-17,611	20,549
Accounts payable	4,070	-4,183
Other current assets	4,690	19,675
Other current liabilities	27,947	-4,753
Net cash provided by operating activities	205,343	188,645
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Expenditures for property, plant and equipment	-104,117	-94,480
Net costs of property, plant and equipment disposals	-5,222	-2,604
Decrease (increase) in restricted cash	2,072	-2,636
Net cash used by investing activities	-107,267	-99,720
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Payment of dividends	-57,549	0
Issuances of long-term debt	175,000	0
Repayments of long-term debt	-175,000	0
Decrease in bank loans	-17,500	-9,200
Other	746	1,043
Net cash used by financing activities	-74,303	-8,157
Cash and cash equivalents increase	23,773	80,768
CASH AND CASH EQUIVALENTS:	'	'
End of period	28,480	82,027
Beginning of period	4,707	1,259
Increase	$23,773	$80,768

Nature_of_Operations

Nature of Operations	9 Months Ended
	Jun. 30, 2014
Nature of Operations [Abstract]	'
Nature of Operations	'
	Nature of Operations
	UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries, UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“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 its small Maryland service territory, 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.” PNG also has a heating, ventilation and air-conditioning service business, UGI Penn HVAC Services, Inc., which operates principally in the PNG service territory (“HVAC Business”).
	The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.

Significant_Accounting_Policie

Significant Accounting Policies	9 Months Ended
	Jun. 30, 2014
Accounting Policies [Abstract]	'
Significant Accounting Policies	'
	Significant Accounting Policies
	Basis of Presentation. Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or the “Company”). We eliminate all significant intercompany accounts when we consolidate.
	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 do 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 (“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.
	Comprehensive Income. Comprehensive income comprises net income and other comprehensive income. Other comprehensive income principally reflects net gains (losses) on interest rate protection agreements qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.
	Changes in accumulated other comprehensive loss during the three and nine months ended June 30, 2014 are as follows:
		Postretirement			Derivative
	Three Months Ended June 30, 2014:	Benefit Plans			Instruments			Total
	Balance, March 31, 2014	$	(5,090	)	$	(2,654	)	$	(7,744	)
	Reclassification of benefit plan actuarial losses and prior service cost	95			—			95
	Reclassifications of net losses on interest rate protection agreements	—			393			393
	Balance, June 30, 2014	$	(4,995	)	$	(2,261	)	$	(7,256	)
	Nine Months Ended June 30, 2014:
	Balance, September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
	Reclassification of benefit plan actuarial losses and prior service cost	288			—			288
	Reclassifications of net losses on interest rate protection agreements	—			1,176			1,176
	Balance, June 30, 2014	$	(4,995	)	$	(2,261	)	$	(7,256	)
	Amounts in the table above are net of tax.
	Reclassifications of net losses on interest rate protection agreements are reflected in interest expense on the Condensed Consolidated Statements of Income.
	Restricted Cash. Restricted cash represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
	Correction of Error. We identified an error in the classification of deferred income tax assets on the June 30, 2013, Condensed Consolidated Balance Sheet. We evaluated the impact of the error and have determined that such error is not material. We have revised the June 30, 2013, Condensed Consolidated Balance Sheet to correct the error which decreased the following Condensed Consolidated Balance Sheet items by $20,709: current deferred income taxes; total current assets and total assets; long-term deferred income tax liabilities; total liabilities; and total liabilities and stockholder’s equity.
	Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

Accounting_Changes

Accounting Changes	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 accumulated other comprehensive income (“AOCI”). The disclosures required by the new accounting guidance are included in the Note 2 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 for all periods presented. The disclosures required are included in Note 10 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.

Segment_Information

Segment Information	9 Months Ended
	Jun. 30, 2014
Segment Reporting [Abstract]	'
Segment Information	'
	Segment Information
	We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The HVAC Business does not meet the quantitative thresholds for separate segment reporting under GAAP relating to business segment reporting and has been included in “Other.”
	The accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s 2013 Annual Financial Statements and Notes. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.
	No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States and all of our reportable segments’ long-lived assets are located in the United States.
	Financial information by business segment follows:
	Three Months Ended June 30, 2014:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	152,694	$	128,264	$	23,954	$	476
	Cost of sales	$	63,323	$	49,257	$	14,066	$	—
	Depreciation and amortization	$	14,892	$	13,774	$	1,118	$	—
	Operating income	$	19,720	$	17,115	$	2,304	$	301
	Interest expense	$	10,433	$	9,904	$	529	$	—
	Income before income taxes	$	9,287	$	7,211	$	1,775	$	301
	Total assets (at period end)	$	2,289,841	$	2,147,407	$	142,434	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	38,215	$	35,955	$	2,260	$	—
	Three Months Ended June 30, 2013:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	148,798	$	126,725	$	21,535	$	538
	Cost of sales	$	64,332	$	52,365	$	11,967	$	—
	Depreciation and amortization	$	14,033	$	13,012	$	1,021	$	—
	Operating income	$	18,878	$	16,054	$	2,584	$	240
	Interest expense	$	9,690	$	9,172	$	518	$	—
	Income before income taxes	$	9,188	$	6,882	$	2,066	$	240
	Total assets (at period end)	$	2,307,347	$	2,143,726	$	163,621	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	38,961	$	37,224	$	1,737	$	—
	Nine Months Ended June 30, 2014:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	965,549	$	879,989	$	84,467	$	1,093
	Cost of sales	$	515,612	$	463,492	$	52,120	$	—
	Depreciation and amortization	$	43,985	$	40,733	$	3,252	$	—
	Operating income	$	243,517	$	233,728	$	9,485	$	304
	Interest expense	$	28,036	$	26,652	$	1,384	$	—
	Income before income taxes	$	215,481	$	207,076	$	8,101	$	304
	Total assets (at period end)	$	2,289,841	$	2,147,407	$	142,434	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	104,117	$	98,806	$	5,311	$	—
	Nine Months Ended June 30, 2013:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	818,496	$	743,614	$	73,604	$	1,278
	Cost of sales	$	415,394	$	372,681	$	42,713	$	—
	Depreciation and amortization	$	41,316	$	38,348	$	2,968	$	—
	Operating income	$	200,672	$	191,592	$	8,597	$	483
	Interest expense	$	29,587	$	28,071	$	1,516	$	—
	Income before income taxes	$	171,085	$	163,521	$	7,081	$	483
	Total assets (at period end)	$	2,307,347	$	2,143,726	$	163,621	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	94,480	$	90,173	$	4,307	$	—

Inventories

Inventories	9 Months Ended
	Jun. 30, 2014
Inventory Disclosure [Abstract]	'
Inventories	'
	Inventories
	Inventories comprise the following:
		June 30, 2014		September 30, 2013		June 30, 2013
	Gas Utility natural gas	$	45,701	$	78,950	$	43,052
	Materials, supplies and other	13,049		10,711		10,946
	Total inventories	$	58,750	$	89,661	$	53,998
	At June 30, 2014, UGI Utilities is a party to four storage contract administrative agreements (“SCAAs”) having terms of one to three years. Three of the SCAAs are with Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 9). Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.
	The carrying value of gas storage inventories released under UGI Utilities’ principal SCAAs at June 30, 2014, September 30, 2013 and June 30, 2013, comprising 6.1 billion cubic feet (“bcf”), 11.0 bcf and 5.6 bcf of natural gas, was $28,299, $44,366 and $24,389, respectively. In conjunction with these SCAAs, UGI Utilities held total security deposits received from its SCAA counterparties of $17,600 at June 30, 2014, and $16,500 at September 30, 2013 and June 30, 2013. These amounts are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets.

Regulatory_Assets_and_Liabilit

Regulatory Assets and Liabilities and Regulatory Matters	9 Months Ended
	Jun. 30, 2014
Regulatory Assets and Liabilities Disclosure [Abstract]	'
Regulatory Assets and Liabilities and Regulatory Matters	'
	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 4 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, 2014		September 30, 2013		June 30, 2013
	Regulatory assets:
	Income taxes recoverable	$	107,166	$	106,069	$	104,731
	Underfunded pension and postretirement plans	89,236		94,515		177,846
	Environmental costs	14,581		17,054		16,642
	Deferred fuel and power costs	9,354		8,283		4,109
	Removal costs, net	15,620		13,333		12,074
	Other	6,669		5,657		5,561
	Total regulatory assets	$	242,626	$	244,911	$	320,963
	Regulatory liabilities:
	Postretirement benefits	$	17,545	$	16,497	$	14,244
	Environmental overcollections	1,631		2,552		2,906
	Deferred fuel and power refunds	—		8,283		14,156
	State tax benefits — distribution system repairs	9,271		8,453		8,024
	Other	1,862		1,502		672
	Total regulatory liabilities	$	30,309	$	37,287	$	40,002
	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 overcollections 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 $680, $(1,743) and $(1,352), 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 qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are recognized on the Condensed Consolidated Balance Sheet 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 $760, $(4,759) and $(6,060), 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
	We currently sponsor one defined benefit pension plan (“Pension Plan”) for employees hired prior to January 1, 2009, of UGI Utilities, PNG, CPG, UGI and certain of UGI’s other wholly owned domestic subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all active and retired employees.
	Net periodic pension expense and other postretirement benefit costs relating to our employees include the following components:
		Pension Benefits						Other Postretirement Benefits
		Three Months Ended						Three Months Ended
		June 30,						June 30,
		2014			2013			2014			2013
	Service cost	$	1,623		$	2,052		$	41		$	51
	Interest cost	5,721			5,196			127			143
	Expected return on assets	(6,649		)	(6,197		)	(139		)	(133		)
	Amortization of:
	Prior service cost (benefit)	87			62			(160		)	(105		)
	Actuarial loss	1,660			3,366			37			91
	Net benefit cost (income)	2,442			4,479			(94		)	47
	Change in associated regulatory liabilities	—			—			918			815
	Net expense	$	2,442		$	4,479		$	824		$	862
		Pension Benefits						Other Postretirement Benefits
		Nine Months Ended						Nine Months Ended
		June 30,						June 30,
		2014			2013			2014			2013
	Service cost	$	4,869		$	6,158		$	123		$	154
	Interest cost	17,163			15,587			381			428
	Expected return on assets	(19,949		)	(18,594		)	(417		)	(396		)
	Amortization of:
	Prior service cost (benefit)	261			187			(480		)	(317		)
	Actuarial loss	4,982			10,098			111			273
	Net benefit cost (income)	7,326			13,436			(282		)	142
	Change in associated regulatory liabilities	—			—			2,754			2,446
	Net expense	$	7,326		$	13,436		$	2,472		$	2,588
	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 required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $6,900 to the Pension Plan during the remainder of Fiscal 2014. During the nine months ended June 30, 2014 and 2013, the Company made contributions to the Pension Plan of $10,975 and $13,365, 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 participate in an unfunded and non-qualified defined benefit supplemental executive retirement plan. Net benefit costs associated with this plan for all periods presented were not material.

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Jun. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	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 $1,800 and $1,100, 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 $11,381 and $14,399, 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.
	The Company 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 Gas and PNG Gas are currently getting 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 for UGI Utilities.
	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.
	There are pending claims and legal actions arising in the normal course of our businesses. While the results of these pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, that the final outcome of such matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

Related_Party_Transactions

Related Party Transactions	9 Months Ended
	Jun. 30, 2014
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as operating and administrative expenses — related parties in the Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries, principally payroll-related services. Amounts billed to these entities by UGI Utilities for all periods presented were not material.
	UGI Utilities is a party to several SCAAs with Energy Services which have terms of one to three years. Under the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives 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. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $16,894 and $23,590 during the three and nine months ended June 30, 2014, respectively, and $21,570 and $26,596 during the three and nine months ended June 30, 2013, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets, were $10,600 as of June 30, 2014, and $16,500 as of September 30, 2013 and June 30, 2013.
	UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at June 30, 2014, comprising approximately 4.0 bcf of natural gas, was $19,410. The carrying value of these gas storage inventories at September 30, 2013, comprising approximately 10.4 bcf of natural gas, was $41,988. The carrying value of these gas storage inventories at June 30, 2013, comprising approximately 5.6 bcf of natural gas, was $24,389.
	UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three and nine months ended June 30, 2014, totaled $1,551 and $34,259, respectively. During the three and nine months ended June 30, 2013, such transactions totaled $0 and $32,526, respectively.
	From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2014, revenues associated with such sales to Energy Services totaled $9,869 and $102,118, respectively. During the three and nine months ended June 30, 2013, revenues associated with such sales to Energy Services totaled $14,956 and $60,208, respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three and nine months ended June 30, 2014, the aggregate amount of such purchases totaled $22,114 and $114,811, respectively. During the three and nine months ended June 30, 2013, the aggregate amount of such purchases totaled $24,426 and $61,659, respectively. These transactions did not have a material effect on the Company’s 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	$	807			$	896			$	—	$	1,703
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	—			$	(31	)		$	—	$	(31	)
	September 30, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts	$	43			$	—			$	—	$	43
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	(2,162	)		$	(4,515	)		$	—	$	(6,677	)
	June 30, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts	$	103			$	—			$	—	$	103
	Interest rate contracts	$	—			$	8,125			$	—	$	8,125
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	(1,885	)		$	(5,759	)		$	—	$	(7,644	)
	Interest rate contracts	$	—			$	(15,306	)		$	—	$	(15,306	)
	The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts and certain non exchange-traded electricity forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments and electricity forward contracts, which are designated as Level 2, are generally based upon recent market transactions and related market indicators. 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. The carrying amount and estimated fair value of our long-term debt at June 30, 2014, were $642,000 and $708,916, respectively. The carrying amount and estimated fair value of our long-term debt at June 30, 2013, were $600,000 and $663,178, 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 types of debt (Level 2).
	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 over-the-counter transactions and those that are executed on an exchange and centrally cleared. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. 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 may be subject to conditional rights of offset through counterparty nonperformance, insolvency, or other conditions.
	In general, most of our over-the-counter transactions and most 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 tables below but could reduce our net exposure to such counterparties because they are subject to master netting or similar arrangements.
		Gross Amount Recognized			Gross Amount Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet
	June 30, 2014:
	Derivative assets	$	2,516		$	(813	)	$	1,703
	Derivative (liabilities)	$	(844	)	$	813		$	(31	)
	September 30, 2013:
	Derivative assets	$	92		$	(49	)	$	43
	Derivative (liabilities)	$	(6,726	)	$	49		$	(6,677	)
	June 30, 2013:
	Derivative assets	$	10,809		$	(2,581	)	$	8,228
	Derivative (liabilities)	$	(25,531	)	$	2,581		$	(22,950	)

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 and (2) interest 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. Because most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations.
	Commodity Price Risk
	Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At 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 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 accounting guidance related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 6).
	Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because 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 net gains of $760 and net losses of $6,060, 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 electric transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly auctions. 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 6). At June 30, 2014 and 2013, the volumes associated with Electric Utility FTRs totaled 232.1 million kilowatt hours and 260.6 million kilowatt hours, 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.
	Interest Rate Risk
	Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in AOCI, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. As of June 30, 2014, we had no unsettled IRPAs. As of June 30, 2013, the total notional amounts of unsettled IRPAs was $173,000.
	At June 30, 2014, the amount of net losses associated with settled IRPAs expected to be reclassified into earnings during the next twelve months is $2,677.
	Derivative Financial Instrument Credit Risk
	Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2014 and 2013, there was $1,109 and $2,636 of restricted cash in brokerage accounts.
	The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of June 30, 2014 and 2013:
		Derivative Assets										Derivative (Liabilities)
				Fair Value									Fair Value
				June 30,									June 30,
		Balance Sheet Location		2014				2013				Balance Sheet Location	2014			2013
	Derivatives Designated as Hedging Instruments:
	Interest rate contracts	Derivative financial instruments		$	—			$	8,125			Derivative financial instruments	$	—		$	(15,306	)
	Derivatives Subject to Utility Rate Regulation:
	Commodity contracts	Derivative financial instruments		1,637				67				Derivative financial instruments and Other noncurrent liabilities	(31		)	(7,644		)
	Derivatives Not Designated as Hedging Instruments:
	Commodity contracts	Derivative financial instruments		66				36				Derivative financial instruments	—			—
	Total Derivatives			$	1,703			$	8,228				$	(31	)	$	(22,950	)
	The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for the three and nine months ended June 30, 2014 and 2013:
	Three Months Ended June 30, :
		Gain (Loss) Recognized in AOCI								Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
		2014				2013				2014			2013			(Loss) Reclassified from AOCI into Income
	Cash Flow Hedges:
	Interest rate contracts	$	—			$	12,776			$	(671	)	$	(203	)	Interest expense
	Derivatives Not Designated
	as Hedging Instruments:	Gain (Loss) Recognized in Income														Location of Gain (Loss) Recognized in Income
		2014				2013
	Commodity contracts	$	49			$	(93	)								Operating expenses/other income, net
	Nine Months Ended June 30, :
		Gain (Loss) Recognized in AOCI								Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
		2014				2013				2014			2013			(Loss) Reclassified from AOCI into Income
	Cash Flow Hedges:
	Interest rate contracts	$	—			$	23,228			$	(2,010	)	$	(608	)	Interest expense
	Derivatives Not Designated
	as Hedging Instruments:	Gain (Loss) Recognized in Income														Location of Gain (Loss) Recognized in Income
		2014				2013
	Commodity contracts	$	128			$	12									Operating expenses/other income, net
	We are also a party to a number of 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 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 purchase and normal sale 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.

Debt

Debt	9 Months Ended
	Jun. 30, 2014
Debt Disclosure [Abstract]	'
Debt Disclosure	'
	Debt
	On March 26, 2014, UGI Utilities issued in a private placement $175,000 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 $175,000 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.

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	9 Months Ended
	Jun. 30, 2014
Accounting Policies [Abstract]	'
Comprehensive Income	'
	Comprehensive Income. Comprehensive income comprises net income and other comprehensive income. Other comprehensive income principally reflects net gains (losses) on interest rate protection agreements qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.
Restricted Cash	'
	Restricted Cash. Restricted cash represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
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]	'
Schedule of Changes in AOCI	'
	Changes in accumulated other comprehensive loss during the three and nine months ended June 30, 2014 are as follows:
		Postretirement			Derivative
	Three Months Ended June 30, 2014:	Benefit Plans			Instruments			Total
	Balance, March 31, 2014	$	(5,090	)	$	(2,654	)	$	(7,744	)
	Reclassification of benefit plan actuarial losses and prior service cost	95			—			95
	Reclassifications of net losses on interest rate protection agreements	—			393			393
	Balance, June 30, 2014	$	(4,995	)	$	(2,261	)	$	(7,256	)
	Nine Months Ended June 30, 2014:
	Balance, September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
	Reclassification of benefit plan actuarial losses and prior service cost	288			—			288
	Reclassifications of net losses on interest rate protection agreements	—			1,176			1,176
	Balance, June 30, 2014	$	(4,995	)	$	(2,261	)	$	(7,256	)

Segment_Information_Tables

Segment Information (Tables)	9 Months Ended
	Jun. 30, 2014
Segment Reporting [Abstract]	'
Segment Information	'
	No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States and all of our reportable segments’ long-lived assets are located in the United States.
	Financial information by business segment follows:
	Three Months Ended June 30, 2014:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	152,694	$	128,264	$	23,954	$	476
	Cost of sales	$	63,323	$	49,257	$	14,066	$	—
	Depreciation and amortization	$	14,892	$	13,774	$	1,118	$	—
	Operating income	$	19,720	$	17,115	$	2,304	$	301
	Interest expense	$	10,433	$	9,904	$	529	$	—
	Income before income taxes	$	9,287	$	7,211	$	1,775	$	301
	Total assets (at period end)	$	2,289,841	$	2,147,407	$	142,434	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	38,215	$	35,955	$	2,260	$	—
	Three Months Ended June 30, 2013:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	148,798	$	126,725	$	21,535	$	538
	Cost of sales	$	64,332	$	52,365	$	11,967	$	—
	Depreciation and amortization	$	14,033	$	13,012	$	1,021	$	—
	Operating income	$	18,878	$	16,054	$	2,584	$	240
	Interest expense	$	9,690	$	9,172	$	518	$	—
	Income before income taxes	$	9,188	$	6,882	$	2,066	$	240
	Total assets (at period end)	$	2,307,347	$	2,143,726	$	163,621	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	38,961	$	37,224	$	1,737	$	—
	Nine Months Ended June 30, 2014:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	965,549	$	879,989	$	84,467	$	1,093
	Cost of sales	$	515,612	$	463,492	$	52,120	$	—
	Depreciation and amortization	$	43,985	$	40,733	$	3,252	$	—
	Operating income	$	243,517	$	233,728	$	9,485	$	304
	Interest expense	$	28,036	$	26,652	$	1,384	$	—
	Income before income taxes	$	215,481	$	207,076	$	8,101	$	304
	Total assets (at period end)	$	2,289,841	$	2,147,407	$	142,434	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	104,117	$	98,806	$	5,311	$	—
	Nine Months Ended June 30, 2013:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	818,496	$	743,614	$	73,604	$	1,278
	Cost of sales	$	415,394	$	372,681	$	42,713	$	—
	Depreciation and amortization	$	41,316	$	38,348	$	2,968	$	—
	Operating income	$	200,672	$	191,592	$	8,597	$	483
	Interest expense	$	29,587	$	28,071	$	1,516	$	—
	Income before income taxes	$	171,085	$	163,521	$	7,081	$	483
	Total assets (at period end)	$	2,307,347	$	2,143,726	$	163,621	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	94,480	$	90,173	$	4,307	$	—

Inventories_Tables

Inventories (Tables)	9 Months Ended
	Jun. 30, 2014
Inventory Disclosure [Abstract]	'
Schedule of Inventories	'
	Inventories comprise the following:
		June 30, 2014		September 30, 2013		June 30, 2013
	Gas Utility natural gas	$	45,701	$	78,950	$	43,052
	Materials, supplies and other	13,049		10,711		10,946
	Total inventories	$	58,750	$	89,661	$	53,998

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities and Regulatory Matters (Tables)	9 Months Ended
	Jun. 30, 2014
Regulatory Assets and Liabilities Disclosure [Abstract]	'
Schedule of 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, 2014		September 30, 2013		June 30, 2013
	Regulatory assets:
	Income taxes recoverable	$	107,166	$	106,069	$	104,731
	Underfunded pension and postretirement plans	89,236		94,515		177,846
	Environmental costs	14,581		17,054		16,642
	Deferred fuel and power costs	9,354		8,283		4,109
	Removal costs, net	15,620		13,333		12,074
	Other	6,669		5,657		5,561
	Total regulatory assets	$	242,626	$	244,911	$	320,963
	Regulatory liabilities:
	Postretirement benefits	$	17,545	$	16,497	$	14,244
	Environmental overcollections	1,631		2,552		2,906
	Deferred fuel and power refunds	—		8,283		14,156
	State tax benefits — distribution system repairs	9,271		8,453		8,024
	Other	1,862		1,502		672
	Total regulatory liabilities	$	30,309	$	37,287	$	40,002

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]	'
Schedule of components of net periodic pension expense and other postretirement benefit costs	'
	Net periodic pension expense and other postretirement benefit costs relating to our employees include the following components:
		Pension Benefits						Other Postretirement Benefits
		Three Months Ended						Three Months Ended
		June 30,						June 30,
		2014			2013			2014			2013
	Service cost	$	1,623		$	2,052		$	41		$	51
	Interest cost	5,721			5,196			127			143
	Expected return on assets	(6,649		)	(6,197		)	(139		)	(133		)
	Amortization of:
	Prior service cost (benefit)	87			62			(160		)	(105		)
	Actuarial loss	1,660			3,366			37			91
	Net benefit cost (income)	2,442			4,479			(94		)	47
	Change in associated regulatory liabilities	—			—			918			815
	Net expense	$	2,442		$	4,479		$	824		$	862
		Pension Benefits						Other Postretirement Benefits
		Nine Months Ended						Nine Months Ended
		June 30,						June 30,
		2014			2013			2014			2013
	Service cost	$	4,869		$	6,158		$	123		$	154
	Interest cost	17,163			15,587			381			428
	Expected return on assets	(19,949		)	(18,594		)	(417		)	(396		)
	Amortization of:
	Prior service cost (benefit)	261			187			(480		)	(317		)
	Actuarial loss	4,982			10,098			111			273
	Net benefit cost (income)	7,326			13,436			(282		)	142
	Change in associated regulatory liabilities	—			—			2,754			2,446
	Net expense	$	7,326		$	13,436		$	2,472		$	2,588

Fair_Value_Measurements_Tables

Fair Value Measurements (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	$	807			$	896			$	—	$	1,703
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	—			$	(31	)		$	—	$	(31	)
	September 30, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts	$	43			$	—			$	—	$	43
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	(2,162	)		$	(4,515	)		$	—	$	(6,677	)
	June 30, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts	$	103			$	—			$	—	$	103
	Interest rate contracts	$	—			$	8,125			$	—	$	8,125
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	(1,885	)		$	(5,759	)		$	—	$	(7,644	)
	Interest rate contracts	$	—			$	(15,306	)		$	—	$	(15,306	)
Schedule of fair value, by balance sheet grouping	'
	ash 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 tables below but could reduce our net exposure to such counterparties because they are subject to master netting or similar arrangements.
		Gross Amount Recognized			Gross Amount Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet
	June 30, 2014:
	Derivative assets	$	2,516		$	(813	)	$	1,703
	Derivative (liabilities)	$	(844	)	$	813		$	(31	)
	September 30, 2013:
	Derivative assets	$	92		$	(49	)	$	43
	Derivative (liabilities)	$	(6,726	)	$	49		$	(6,677	)
	June 30, 2013:
	Derivative assets	$	10,809		$	(2,581	)	$	8,228
	Derivative (liabilities)	$	(25,531	)	$	2,581		$	(22,950	)

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 balance sheet location and fair values of our derivative assets and liabilities existing as of June 30, 2014 and 2013:
		Derivative Assets										Derivative (Liabilities)
				Fair Value									Fair Value
				June 30,									June 30,
		Balance Sheet Location		2014				2013				Balance Sheet Location	2014			2013
	Derivatives Designated as Hedging Instruments:
	Interest rate contracts	Derivative financial instruments		$	—			$	8,125			Derivative financial instruments	$	—		$	(15,306	)
	Derivatives Subject to Utility Rate Regulation:
	Commodity contracts	Derivative financial instruments		1,637				67				Derivative financial instruments and Other noncurrent liabilities	(31		)	(7,644		)
	Derivatives Not Designated as Hedging Instruments:
	Commodity contracts	Derivative financial instruments		66				36				Derivative financial instruments	—			—
	Total Derivatives			$	1,703			$	8,228				$	(31	)	$	(22,950	)
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest	'
	The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for the three and nine months ended June 30, 2014 and 2013:
	Three Months Ended June 30, :
		Gain (Loss) Recognized in AOCI								Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
		2014				2013				2014			2013			(Loss) Reclassified from AOCI into Income
	Cash Flow Hedges:
	Interest rate contracts	$	—			$	12,776			$	(671	)	$	(203	)	Interest expense
	Derivatives Not Designated
	as Hedging Instruments:	Gain (Loss) Recognized in Income														Location of Gain (Loss) Recognized in Income
		2014				2013
	Commodity contracts	$	49			$	(93	)								Operating expenses/other income, net
	Nine Months Ended June 30, :
		Gain (Loss) Recognized in AOCI								Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
		2014				2013				2014			2013			(Loss) Reclassified from AOCI into Income
	Cash Flow Hedges:
	Interest rate contracts	$	—			$	23,228			$	(2,010	)	$	(608	)	Interest expense
	Derivatives Not Designated
	as Hedging Instruments:	Gain (Loss) Recognized in Income														Location of Gain (Loss) Recognized in Income
		2014				2013
	Commodity contracts	$	128			$	12									Operating expenses/other income, net

Significant_Accounting_Policie3

Significant Accounting Policies - Schedule of Changes in AOCI (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Mar. 31, 2014	Sep. 30, 2013
Schedule of Accumulated Other Comprehensive Income	'	'	'	'	'	'
Accumulated other comprehensive loss	($7,256)	($15,283)	($7,256)	($15,283)	($7,744)	($8,720)
Reclassification of benefit plan actuarial losses and prior service cost	95	'	288	'	'	'
Reclassifications of net losses on interest rate protection agreements	393	119	1,176	356	'	'
Quantifying Misstatement in Current Year Financial Statements, Amount	'	'	20,709	'	'	'
Derivative Instruments	'	'	'	'	'	'
Schedule of Accumulated Other Comprehensive Income	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	-2,261	'	-2,261	'	-2,654	-3,437
Reclassification of benefit plan actuarial losses and prior service cost	0	'	0	'	'	'
Reclassifications of net losses on interest rate protection agreements	393	'	1,176	'	'	'
Postretirement Benefit Plans	'	'	'	'	'	'
Schedule of Accumulated Other Comprehensive Income	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	-4,995	'	-4,995	'	-5,090	-5,283
Reclassification of benefit plan actuarial losses and prior service cost	-95	'	-288	'	'	'
Reclassifications of net losses on interest rate protection agreements	$0	'	$0	'	'	'

Significant_Accounting_Policie4

Significant Accounting Policies Significant Accounting Policies - Phantom (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014
Condensed Balance Sheet Statements, Captions	'
Quantifying Misstatement in Current Year Financial Statements, Amount	$20,709
Current Deferred Income Tax	'
Condensed Balance Sheet Statements, Captions	'
Quantifying Misstatement in Current Year Financial Statements, Amount	20,700
Total Current Assets	'
Condensed Balance Sheet Statements, Captions	'
Quantifying Misstatement in Current Year Financial Statements, Amount	20,700
Total Assets	'
Condensed Balance Sheet Statements, Captions	'
Quantifying Misstatement in Current Year Financial Statements, Amount	20,700
Long-term Deferred Income Tax Liability	'
Condensed Balance Sheet Statements, Captions	'
Quantifying Misstatement in Current Year Financial Statements, Amount	20,700
Total Liabilities	'
Condensed Balance Sheet Statements, Captions	'
Quantifying Misstatement in Current Year Financial Statements, Amount	20,700
Total Liabilities and Stockholders' Equity	'
Condensed Balance Sheet Statements, Captions	'
Quantifying Misstatement in Current Year Financial Statements, Amount	$20,700

Segment_Information_Segment_In

Segment Information - Segment Information (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Sep. 30, 2013
	Segment
Segment Reporting Information	'	'	'	'	'
Number of reportable segments (in segments)	2	'	'	'	'
Concentration risk, percentage	10.00%	'	'	'	'
Number of intersegment transactions	'	'	0	'	'
Revenues	$152,694	$148,798	$965,549	$818,496	'
Cost of sales	63,323	64,332	515,612	415,394	'
Depreciation and amortization	14,892	14,033	43,985	41,316	'
Operating income	19,720	18,878	243,517	200,672	'
Interest expense	10,433	9,690	28,036	29,587	'
Income before income taxes	9,287	9,188	215,481	171,085	'
Total assets (at period end)	2,289,841	2,307,347	2,289,841	2,307,347	2,210,322
Goodwill (at period end)	182,145	182,145	182,145	182,145	182,145
Capital expenditures	38,215	38,961	104,117	94,480	'
Gas Utility	'	'	'	'	'
Segment Reporting Information	'	'	'	'	'
Revenues	128,264	126,725	879,989	743,614	'
Cost of sales	49,257	52,365	463,492	372,681	'
Depreciation and amortization	13,774	13,012	40,733	38,348	'
Operating income	17,115	16,054	233,728	191,592	'
Interest expense	9,904	9,172	26,652	28,071	'
Income before income taxes	7,211	6,882	207,076	163,521	'
Total assets (at period end)	2,147,407	2,143,726	2,147,407	2,143,726	'
Goodwill (at period end)	182,145	182,145	182,145	182,145	'
Capital expenditures	35,955	37,224	98,806	90,173	'
Electric Utility	'	'	'	'	'
Segment Reporting Information	'	'	'	'	'
Counties of operation, number	2	'	'	'	'
Revenues	23,954	21,535	84,467	73,604	'
Cost of sales	14,066	11,967	52,120	42,713	'
Depreciation and amortization	1,118	1,021	3,252	2,968	'
Operating income	2,304	2,584	9,485	8,597	'
Interest expense	529	518	1,384	1,516	'
Income before income taxes	1,775	2,066	8,101	7,081	'
Total assets (at period end)	142,434	163,621	142,434	163,621	'
Goodwill (at period end)	0	0	0	0	'
Capital expenditures	2,260	1,737	5,311	4,307	'
Other	'	'	'	'	'
Segment Reporting Information	'	'	'	'	'
Revenues	476	538	1,093	1,278	'
Cost of sales	0	0	0	0	'
Depreciation and amortization	0	0	0	0	'
Operating income	301	240	304	483	'
Interest expense	0	0	0	0	'
Income before income taxes	301	240	304	483	'
Total assets (at period end)	0	0	0	0	'
Goodwill (at period end)	0	0	0	0	'
Capital expenditures	$0	$0	$0	$0	'
Customer Concentration Risk | Revenue	'	'	'	'	'
Segment Reporting Information	'	'	'	'	'
Number of Customers Exceeding Threshold	0	'	'	'	'

Inventories_Narrative_Details

Inventories - Narrative (Details) (USD $)	0 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
		ft3	ft3	ft3
Public Utilities, Inventory	'	'	'	'
Term of agreements	'1 year	'	'	'
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)	'	6,100,000,000	11,000,000,000	5,600,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates	'	$28,299	$44,366	$24,389
Security Deposit Liability	'	17,600	'	'
SCAAs	'	'	'	'
Public Utilities, Inventory	'	'	'	'
Number of storage agreements (in storage agreements)	4	4	'	'
Number of storage agreements with Energy Services	3	3	'	'
SCAAs | Other current liabilities	'	'	'	'
Public Utilities, Inventory	'	'	'	'
Security Deposit Liability	'	'	$16,500	$16,500
Minimum | SCAAs	'	'	'	'
Public Utilities, Inventory	'	'	'	'
Term of agreements	'1 year	'	'	'
Maximum | SCAAs	'	'	'	'
Public Utilities, Inventory	'	'	'	'
Term of agreements	'3 years	'	'	'

Inventories_Schedule_of_Invent

Inventories - Schedule of Inventories (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Thousands, unless otherwise specified
Public Utilities, Inventory	'	'	'
Total inventories	$58,750	$89,661	$53,998
Gas Utility Natural Gas	'	'	'
Public Utilities, Inventory	'	'	'
Total inventories	45,701	78,950	43,052
Materials, Supplies and Other	'	'	'
Public Utilities, Inventory	'	'	'
Total inventories	$13,049	$10,711	$10,946

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Thousands, unless otherwise specified
Gas Utility Derivative Financial Instruments	'	'	'
Regulatory Assets	'	'	'
Gas utility unrealized gain (losses) on derivative financial instrument contracts	$680	($1,743)	($1,352)
Electric Utility Forward Supply Contracts	'	'	'
Regulatory Assets	'	'	'
Net gains (losses) on electricity supply contracts	$760	($4,759)	($6,060)

Regulatory_Assets_and_Liabilit3

Regulatory Assets and Liabilities and Regulatory Matters - Schedule of Regulatory Assets and Liabilities Associated With Gas Utility and Electric Utility (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Thousands, unless otherwise specified
Regulatory Assets and Liabilities	'	'	'
Regulatory Assets	$242,626	$244,911	$320,963
Regulatory Liabilities	30,309	37,287	40,002
Postretirement benefits	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Liabilities	17,545	16,497	14,244
Environmental overcollections	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Liabilities	1,631	2,552	2,906
Deferred fuel and power refunds	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Liabilities	0	8,283	14,156
State tax benefits -- distribution system repairs	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Liabilities	9,271	8,453	8,024
Other	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Liabilities	1,862	1,502	672
Income taxes recoverable	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Assets	107,166	106,069	104,731
Underfunded pension and postretirement plans	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Assets	89,236	94,515	177,846
Environmental costs	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Assets	14,581	17,054	16,642
Deferred fuel and power costs	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Assets	9,354	8,283	4,109
Removal costs, net	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Assets	15,620	13,333	12,074
Other	'	'	'
Regulatory Assets and Liabilities	'	'	'
Regulatory Assets	$6,669	$5,657	$5,561

Defined_Benefit_Pension_and_Ot2

Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Defined Benefit Plan Disclosure	'	'
Number of Defined Benefit Plans	1	'
Pension Benefits	'	'
Defined Benefit Plan Disclosure	'	'
Expected contribution to pensions plans in the remainder of current fiscal year	$6,900	'
Contribution made to Pension Plan	$10,975	$13,365

Defined_Benefit_Pension_and_Ot3

Defined Benefit Pension and Other Postretirement Plans - Schedule of Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pension Benefits	'	'	'	'
Defined Benefit Plan Disclosure	'	'	'	'
Service cost	$1,623	$2,052	$4,869	$6,158
Interest cost	5,721	5,196	17,163	15,587
Expected return on assets	-6,649	-6,197	-19,949	-18,594
Amortization of:	'	'	'	'
Prior service cost (benefit)	87	62	261	187
Actuarial loss	1,660	3,366	4,982	10,098
Net benefit cost (income)	2,442	4,479	7,326	13,436
Change in associated regulatory liabilities	0	0	0	0
Net expense	2,442	4,479	7,326	13,436
Other Postretirement Benefit Plan, Defined Benefit	'	'	'	'
Defined Benefit Plan Disclosure	'	'	'	'
Service cost	41	51	123	154
Interest cost	127	143	381	428
Expected return on assets	-139	-133	-417	-396
Amortization of:	'	'	'	'
Prior service cost (benefit)	-160	-105	-480	-317
Actuarial loss	37	91	111	273
Net benefit cost (income)	-94	47	-282	142
Change in associated regulatory liabilities	918	815	2,754	2,446
Net expense	$824	$862	$2,472	$2,588

Commitments_and_Contingencies_

Commitments and Contingencies - Narrative (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
CPG MGP	'	'
Commitments and Contingencies	'	'
Environmental Remediation Expense	$1,800	'
PNG MGP	'	'
Commitments and Contingencies	'	'
Environmental Remediation Expense	1,100	'
CPG and PNG COAs	'	'
Commitments and Contingencies	'	'
Option to termination agreement by either party effective at end of any two-year period beginning with the original effective date in March 2004 (in years)	'2 years	'
Accrual for environmental loss contingencies	$11,381	$14,399
Environmental Issue	'	'
Commitments and Contingencies	'	'
Base year for determination of investigation and remediation cost (in years)	'5 years	'

Related_Party_Transactions_Nar

Related Party Transactions - Narrative (Details) (USD $)

0 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

In Thousands, unless otherwise specified

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

Sep. 30, 2013

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Sep. 30, 2013

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Energy Services

Energy Services

Energy Services

Energy Services

Inventories

Inventories

Inventories

SCAAs

SCAAs

SCAAs

SCAAs

SCAAs

SCAAs

SCAAs

Exclusive of transactions pursuant SCAAs

Exclusive of transactions pursuant SCAAs

Exclusive of transactions pursuant SCAAs

Exclusive of transactions pursuant SCAAs

Minimum

Maximum

Energy Services

Energy Services

Energy Services

Energy Services

Energy Services

Energy Services

Energy Services

Other current liabilities

Other current liabilities

Other current liabilities

Energy Services

Energy Services

Energy Services

Energy Services

SCAAs

SCAAs

ft3

ft3

ft3

Energy Services

Energy Services

Energy Services

Energy Services

Energy Services

Related Party Transaction

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Related Party Transaction, Term of SCAA's

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'P1Y

'P3Y

Related party costs incurred

'

$2,385

$1,940

$7,997

$6,757

'

'

'

'

'

'

'

$16,894

$21,570

$23,590

$26,596

'

'

'

$1,551

$0

$34,259

$32,526

'

'

Related party security deposits

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,600

16,500

16,500

'

'

'

'

'

'

Volume of gas storage inventory (in bcf of natural gas)

'

'

'

'

'

'

'

'

'

4,000,000,000

10,400,000,000

5,600,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Natural gas storage inventory, related parties, current

'

'

'

'

'

'

'

'

'

19,410

41,988

24,389

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue from related parties

'

'

'

'

'

9,869

14,956

102,118

60,208

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Term of agreements

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchases from related party

'

'

'

'

'

$22,114

$24,426

$114,811

$61,659

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair_Value_Measurements_Narrat

Fair Value Measurements - Narrative (Details) (USD $)	Jun. 30, 2014	Jun. 30, 2013
In Thousands, unless otherwise specified
Fair Value Disclosures [Abstract]	'	'
Long-term Debt, Carrying Amount	$642,000	$600,000
Long-term Debt, Fair Value	$708,916	$663,178

Fair_Value_Measurements_Financ

Fair Value Measurements - Financial Assets and Financial Liabilities That are Measured at Fair Value on a Recurring Basis (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	$1,703	$43	$8,228
Derivative financial instruments, liabilities	-31	-6,677	-22,950
Commodity contracts | Fair Value, Measurements, Recurring	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	1,703	43	103
Derivative financial instruments, liabilities	-31	-6,677	-7,644
Commodity contracts | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	807	43	103
Derivative financial instruments, liabilities	0	-2,162	-1,885
Commodity contracts | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	896	0	0
Derivative financial instruments, liabilities	-31	-4,515	-5,759
Commodity contracts | Fair Value, Measurements, Recurring | Fair Value Inputs (Level 3)	'	'	'
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
Interest rate contracts | Fair Value, Measurements, Recurring	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	'	'	8,125
Derivative financial instruments, liabilities	'	'	-15,306
Interest rate contracts | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	'	'	0
Derivative financial instruments, liabilities	'	'	0
Interest rate contracts | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	'	'	8,125
Derivative financial instruments, liabilities	'	'	-15,306
Interest rate contracts | Fair Value, Measurements, Recurring | Fair Value Inputs (Level 3)	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	'	'	'
Derivative financial instruments, assets	'	'	0
Derivative financial instruments, liabilities	'	'	$0

Fair_Value_Measurements_Schedu

Fair Value Measurements - Schedule of Fair Value by Balance Sheet Grouping (Details) (USD $)	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013
In Thousands, unless otherwise specified
Offsetting Derivatives Table	'	'	'
Derivative Asset, Fair Value, Gross Asset	$2,516	$92	$10,809
Derivative Asset, Offset Amount, Gross	813	49	2,581
Derivative Assets	1,703	43	8,228
Derivative Liabilities, Fair Value, Gross	-844	-6,726	-25,531
Derivative Liability, Offset Amount, Gross	813	49	2,581
Derivative Liabilities	$31	$6,677	$22,950

Disclosures_About_Derivative_I2

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

Jun. 30, 2014

Sep. 30, 2013

Jun. 30, 2013

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

In Thousands, unless otherwise specified

Gas Utility

Gas Utility

Gas Utility

Electric Utility

Electric Utility

Electric Utility

Electric Utility

Electric Utility

Interest Rate Protection Agreements

Interest Rate Protection Agreements

DTH

DTH

kWh

kWh

Electric Utility electric transmission congestion

Electric Utility electric transmission congestion

kWh

kWh

Derivative

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount (in units)

'

'

'

'

10,900,000

11,700,000

'

315,800,000

327,400,000

232,100,000

260,600,000

'

'

Maximum length of time hedged in price risk cash flow hedges (in months)

'

'

'

'9 months

'

'

'11 months

'

'

'

'

'

'

Net gains (losses) on electricity supply contracts

'

'

'

'

'

'

'

$760

($6,060)

'

'

'

'

Total Derivatives Liability

844

6,726

25,531

'

'

'

'

'

'

'

'

'

'

Underlying variable rate debt

'

'

'

'

'

'

'

'

'

'

'

0

173,000

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

'

'

'

'

'

'

'

'

'

'

'

2,677

'

Restricted Cash in brokerage accounts

$1,109

$3,181

$2,636

'

'

'

'

'

'

'

'

'

'

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 Thousands, unless otherwise specified
Derivatives, Fair Value	'	'	'
Derivative Assets	$1,703	$43	$8,228
Derivative Liabilities	-31	-6,677	-22,950
Interest rate contracts | Derivatives Designated as Hedging Instruments | Derivative financial instruments, assets	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Assets	0	'	8,125
Interest rate contracts | Derivatives Designated as Hedging Instruments | Derivative financial instruments, liabilities	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Liabilities	0	'	-15,306
Commodity contracts | Derivatives Subject to Utility Rate Regulation | Derivative financial instruments, assets	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Assets	1,637	'	67
Commodity contracts | Derivatives Subject to Utility Rate Regulation | Derivative financial instruments and other noncurrent liabilities	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Liabilities	-31	'	-7,644
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Derivative financial instruments, assets	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Assets	66	'	36
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Derivative financial instruments, liabilities	'	'	'
Derivatives, Fair Value	'	'	'
Derivative Liabilities	$0	'	$0

Disclosures_About_Derivative_I4

Disclosures About Derivative Instruments and Hedging Activities - Effects of Derivatives on Statements of Income and AOCI (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivatives Not Designated as Hedging Instruments | Commodity contracts | Operating expenses/other income, net	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain (Loss) recognized in income	$49	($93)	$128	$12
Cash Flow Hedges | Interest rate contracts | Interest expense, net	'	'	'	'
Derivative Instruments, Gain (Loss)	'	'	'	'
Gain or (loss) recognized in AOCI	0	12,776	0	23,228
Gain (loss) reclassified from AOCI into income	($671)	($203)	($2,010)	($608)

Disclosures_About_Derivative_I5

Disclosures About Derivative Instruments and Hedging Activities - Phantom (Details) (USD $)	Jun. 30, 2013	Jun. 30, 2014
In Thousands, unless otherwise specified		Interest Rate Swap
Derivative Instruments, Gain (Loss)	'	'
Other Income	'	$0
Restricted cash in brokerage accounts	$0	'

Debt_Details

Debt (Details) (USD $)	0 Months Ended
	Mar. 26, 2014
4.98% Senior Notes	'
Debt Instrument	'
Proceeds from 4.98% Senior Note	$175,000
Interest Rate	4.98%
Debt to Capital Ratio	0.65
Term Loan, 364-day Credit Agreement	'
Debt Instrument	'
Debt Repayment	$175,000
Debt Instrument, Term	'364 days