Ugi Utilities 10-Q 7 Feb 14 2014 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Dec. 31, 2013	Jan. 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	31-Dec-13	'
Amendment Flag	'false	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q1	'
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 $)	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'	'
Cash and cash equivalents	$13,008	$4,707	$7,924
Restricted cash	0	3,181	2,106
Accounts receivable (less allowances for doubtful accounts of $5,885, $5,519 and $4,232, respectively)	111,840	53,341	97,821
Accounts receivable — related parties	9,431	3,497	7,230
Accrued utility revenues	66,370	18,868	59,036
Inventories	80,675	89,661	61,861
Deferred income taxes	12,317	14,165	22,094
Regulatory assets	361	8,217	3,632
Derivative financial instruments	2,058	43	4,760
Prepaid expenses & other current assets	14,649	15,862	20,948
Total current assets	310,709	211,542	287,412
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $865,852, $853,675 and $826,781, respectively)	1,594,554	1,574,135	1,496,606
Goodwill	182,145	182,145	182,145
Regulatory assets	233,636	236,694	326,996
Other assets	5,626	5,806	5,836
Total assets	2,326,670	2,210,322	2,298,995
Current liabilities:	'	'	'
Current maturities of long-term debt	0	0	133,000
Bank loans	73,500	17,500	73,100
Accounts payable	60,405	51,970	48,762
Accounts payable — related parties	17,250	12,487	8,476
Deferred fuel refunds	7,524	8,283	1,916
Derivative financial instruments	3,272	6,677	35,947
Other current liabilities	131,513	110,596	121,726
Total current liabilities	293,464	207,513	422,927
Long-term debt	642,000	642,000	467,000
Deferred income taxes	440,645	436,810	401,481
Deferred investment tax credits	4,185	4,270	4,526
Pension and postretirement benefit obligations	73,132	72,505	177,094
Other noncurrent liabilities	53,610	55,610	57,498
Total liabilities	1,507,036	1,418,708	1,530,526
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	470,189	470,098	468,985
Retained earnings	297,417	269,977	266,191
Accumulated other comprehensive loss	-8,231	-8,720	-26,966
Total common stockholder’s equity	819,634	791,614	768,469
Total liabilities and stockholder’s equity	$2,326,670	$2,210,322	$2,298,995

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Allowance for doubtful accounts on accounts receivable	$5,885	$5,519	$4,232
Accumulated depreciation and amortization on property, plant and equipment	$865,852	$853,675	$826,781
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 (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Revenues	$298,899	$273,797
Costs and expenses:	'	'
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	151,865	138,277
Operating and administrative expenses	41,145	44,235
Operating and administrative expenses — related parties	1,843	1,805
Taxes other than income taxes	4,179	4,276
Depreciation	13,622	12,753
Amortization	828	818
Other income, net	-426	-931
Total costs and expenses	213,056	201,233
Operating income	85,843	72,564
Interest expense	8,797	10,077
Income before income taxes	77,046	62,487
Income taxes	31,760	25,675
Net income	$45,286	$36,812

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Net income	$45,286	$36,812
Net gains in fair value of derivative instruments (net of tax of $0 and $(1,799), respectively)	0	2,537
Reclassifications of net losses on derivative instruments (net of tax of $(278) and $(84), respectively)	391	119
Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(70) and $(139), respectively)	98	195
Other comprehensive income	489	2,851
Comprehensive income	$45,775	$39,663

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Tax on (loss) gain on derivative instruments	$0	$1,799
Tax on reclassifications of net losses (gains) on derivative instruments	278	84
Tax on benefit plans	$70	$139

Condensed_Consolidated_Stateme3

Condensed Consolidated Statements of Cash Flows (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
Net income	$45,286	$36,812
Adjustments to reconcile net income to net cash from operating activities:	'	'
Depreciation and amortization	14,450	13,571
Deferred income taxes, net	5,157	6,554
Provision for uncollectible accounts	2,249	2,106
Other, net	-124	514
Net change in:	'	'
Accounts receivable and accrued utility revenues	-114,184	-97,349
Inventories	8,985	5,473
Deferred fuel and power costs	2,086	4,845
Accounts payable	13,198	292
Other current assets	802	8,936
Other current liabilities	24,405	-7,126
Net cash provided (used) by operating activities	2,310	-25,372
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Expenditures for property, plant and equipment	-34,254	-29,728
Net costs of property, plant and equipment disposals	-1,491	-322
Decrease (increase) in restricted cash	3,181	-2,106
Net cash used by investing activities	-32,564	-32,156
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Payment of dividends	-17,536	0
Increase in bank loans	56,000	63,900
Other	91	293
Net cash provided by financing activities	38,555	64,193
Cash and cash equivalents increase	8,301	6,665
CASH AND CASH EQUIVALENTS:	'	'
End of period	13,008	7,924
Beginning of period	4,707	1,259
Increase	$8,301	$6,665

Nature_of_Operations

Nature of Operations	3 Months Ended
	Dec. 31, 2013
Nature of Operations [Abstract]	'
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 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.” 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	3 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
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 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 months ended December 31, 2013 are as follows:
		Postretirement			Derivative
		Benefit Plans			Instruments			Total
	Balance, September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
	Reclassification of benefit plan actuarial losses and prior service cost	98			—			98
	Reclassifications of net losses on interest rate protection agreements	—			391			391
	Balance, December 31, 2013	$	(5,185	)	$	(3,046	)	$	(8,231	)
	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 Statement 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 December 31, 2012, Condensed Consolidated Balance Sheet. We evaluated the impact of the error and have determined that such error is not material. We have revised the December 31, 2012, Condensed Consolidated Balance Sheet to correct the error which revision 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	3 Months Ended
	Dec. 31, 2013
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
Accounting Changes	'
	Adoption of New Accounting Standards
	Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. During the three months ended December 31, 2013, 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. During the three months ended December 31, 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 or subject to 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.

Segment_Information

Segment Information	3 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
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 December 31, 2013:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	298,899	$	271,562	$	26,961	$	376
	Cost of sales	$	151,865	$	135,487	$	16,378	$	—
	Depreciation and amortization	$	14,450	$	13,384	$	1,066	$	—
	Operating income	$	85,843	$	82,053	$	3,689	$	101
	Interest expense	$	8,797	$	8,386	$	411	$	—
	Income before income taxes	$	77,046	$	73,667	$	3,278	$	101
	Total assets (at period end)	$	2,326,670	$	2,188,623	$	138,047	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	34,254	$	32,812	$	1,442	$	—
	Three Months Ended December 31, 2012:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	273,797	$	248,254	$	25,118	$	425
	Cost of sales	$	138,277	$	123,574	$	14,703	$	—
	Depreciation and amortization	$	13,571	$	12,605	$	966	$	—
	Operating income	$	72,564	$	69,789	$	2,624	$	151
	Interest expense	$	10,077	$	9,572	$	505	$	—
	Income before income taxes	$	62,487	$	60,217	$	2,119	$	151
	Total assets (at period end)	$	2,298,995	$	2,144,693	$	154,302	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	29,728	$	28,519	$	1,209	$	—

Inventories

Inventories	3 Months Ended
	Dec. 31, 2013
Inventory Disclosure [Abstract]	'
Inventories	'
	Inventories comprise the following:
		December 31, 2013		September 30, 2013		December 31, 2012
	Gas Utility natural gas	$	69,117	$	78,950	$	51,838
	Materials, supplies and other	11,558		10,711		10,023
	Total inventories	$	80,675	$	89,661	$	61,861
	At December 31, 2013, 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, Inc. (“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 December 31, 2013, September 30, 2013 and December 31, 2012, comprising 9.8 billion cubic feet (“bcf”), 11.0 bcf and 9.1 bcf of natural gas, was $39,362, $44,366 and $27,251, respectively. In conjunction with these SCAAs, UGI Utilities held total security deposits received from its SCAA counterparties of $17,600 at December 31, 2013, and $16,500 at September 30, 2013 and December 31, 2012. 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	3 Months Ended
	Dec. 31, 2013
Regulatory Assets and Liabilities Disclosure [Abstract]	'
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:
		December 31, 2013		September 30, 2013		December 31, 2012
	Regulatory assets:
	Income taxes recoverable	$	106,435	$	106,069	$	103,665
	Underfunded pension and postretirement plans	92,755		94,515		184,764
	Environmental costs	14,910		17,054		17,119
	Deferred fuel and power costs	427		8,283		7,797
	Removal costs, net	13,748		13,333		11,541
	Other	5,722		5,657		5,742
	Total regulatory assets	$	233,997	$	244,911	$	330,628
	Regulatory liabilities:
	Postretirement benefits	$	16,846	$	16,497	$	13,486
	Environmental overcollections	2,329		2,552		3,077
	Deferred fuel and power refunds	7,524		8,283		1,916
	State tax benefits — distribution system repairs	8,725		8,453		7,750
	Other	1,332		1,502		570
	Total regulatory liabilities	$	36,756	$	37,287	$	26,799
	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 December 31, 2013, September 30, 2013, and December 31, 2012, were $1,968, $(1,743) and $(440), respectively.
	Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because 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 December 31, 2013, September 30, 2013, and December 31, 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $3,182, $4,759 and $8,182, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs 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 December 31, 2013, September 30, 2013, and December 31, 2012, were not material.

Defined_Benefit_Pension_and_Ot

Defined Benefit Pension and Other Postretirement Plans	3 Months Ended
	Dec. 31, 2013
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]	'
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
		December 31,						December 31,
		2013			2012			2013			2012
	Service cost	$	1,623		$	2,053		$	41		51
	Interest cost	5,721			5,196			127			143
	Expected return on assets	(6,650		)	(6,198		)	(139		)	(132		)
	Amortization of:
	Prior service benefit	—			—			(160		)	(105		)
	Actuarial loss	1,748			3,428			37			91
	Net benefit cost (income)	2,442			4,479			(94		)	48
	Change in associated regulatory liabilities	—			—			918			815
	Net expense	$	2,442		$	4,479		$	824		$	863
	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 $14,399 to the Pension Plan during the remainder of Fiscal 2014. During the three months ended December 31, 2013 and 2012, the Company made contributions to the Pension Plan of $3,486 and $5,730, 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. Amounts contributed to the VEBA by UGI Utilities were not material during the three months ended December 31, 2013 and 2012, nor are they expected to be material for all of Fiscal 2014.
	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	3 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
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 was recently renewed and is scheduled to terminate at the end of 2018. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At December 31, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $16,900 and $14,965, 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 December 31, 2013, 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 it 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.
	Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount or range of possible clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012. There have been no recent developments in this matter.
	Other Matters
	We cannot predict with certainty the final results of any environmental claim or legal action described above. However, it is reasonably possible that such a claim could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, that may be recovered by such a claim or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. In addition to the matter described above, there are other pending claims and legal actions arising in the normal course of our businesses. While the results of these other pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, the final outcome of such other matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
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 $6,448 during the three months ended December 31, 2013 and $4,324 during the three months ended December 31, 2012. 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 December 31, 2013, and $16,500 as of September 30, 2013 and December 31, 2012.
	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 December 31, 2013, comprising approximately 6.8 bcf of natural gas, was $27,052. 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 December 31, 2012, comprising approximately 9.1 bcf of natural gas, was $27,251.
	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 months ended December 31, 2013 and 2012, totaled $19,378 and $17,825, respectively.
	From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2013 and 2012, revenues associated with such sales to Energy Services totaled $17,116 and $19,824, 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 months ended December 31, 2013 and 2012, the aggregate amount of such purchases totaled $22,078 and $19,020, 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	3 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
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 December 31, 2013, September 30, 2013 and December 31, 2012:
		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)
	December 31, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts	$	2,058			$	—			$	—			$	2,058
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	(266	)		$	(3,006	)		$	—			$	(3,272	)
	September 30, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts	$	43			$	—			$	—			$	43
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	(2,162	)		$	(4,515	)		$	—			$	(6,677	)
	December 31, 2012:
	Assets:
	Derivative financial instruments:
	Commodity contracts	$	374			$	160			$	—			$	534
	Interest rate contracts	$	—			$	4,226			$	—			$	4,226
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	(1,315	)		$	(7,726	)		$	—			$	(9,041	)
	Interest rate contracts	$	—			$	(30,412	)		$	—			$	(30,412	)
	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 December 31, 2013, were $642,000 and $694,220, respectively. The carrying amount and estimated fair value of our long-term debt at December 31, 2012, were $600,000 and $696,217, 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. 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 includes cash or letters of credit. Any cash collateral paid by us to our derivative counterparties is reflected in the table below to offset derivative liabilities. Any cash collateral received by us from our derivative counterparties 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 Amounts Not Offset in the Balance Sheet
		Gross Amount Recognized			Gross Amount Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet				Financial Instruments			Cash Collateral		Net Amount
	December 31, 2013:
	Derivative assets	$	2,130		$	(72	)	$	2,058			$	—		$	—	$	2,058
	Derivative (liabilities)	$	(3,344	)	$	72		$	(3,272	)		$	—		$	—	$	(3,272	)
	September 30, 2013:
	Derivative assets	$	92		$	(49	)	$	43			$	—		$	—	$	43
	Derivative (liabilities)	$	(6,726	)	$	49		$	(6,677	)		$	—		$	1,407	$	(5,270	)
	December 31, 2012:
	Derivative assets	$	4,971		$	(211	)	$	4,760			$	—		$	—	$	4,760
	Derivative (liabilities)	$	(39,664	)	$	211		$	(39,453	)		$	—		$	700	$	(38,753	)

Disclosures_About_Derivative_I

Disclosures About Derivative Instruments and Hedging Activities	3 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
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 December 31, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.7 million dekatherms and 13.0 million dekatherms, respectively. At December 31, 2013, 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 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 December 31, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising net losses of $3,182 and $8,182, respectively, are reflected in current derivative financial instrument 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. At December 31, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 324.4 million kilowatt hours and 482.3 million kilowatt hours, respectively. At December 31, 2013, 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 December 31, 2013 and 2012, the volumes associated with Electric Utility FTRs totaled 117.9 million kilowatt hours and 118.2 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 accumulated other comprehensive income (“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 December 31, 2013 we had no unsettled IRPAs. As of December 31, 2012, the total notional amounts of unsettled IRPAs was $173,000.
	At December 31, 2013, the amount of net losses associated with settled IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $2,680.
	Derivative Financial Instrument Credit Risk
	Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2013, there was no restricted cash in brokerage accounts. At December 31, 2012, restricted cash in brokerage accounts totaled $2,106.
	The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of December 31, 2013 and 2012:
		Derivative Assets										Derivative (Liabilities)
		Balance Sheet		Fair Value								Balance Sheet	Fair Value
		Location		2013				2012				Location	2013			2012
	Derivatives Designated as Hedging Instruments:
	Interest rate contracts	Derivative financial instruments		$	—			$	4,226			Derivative financial instruments	$	—		$	(30,412	)
	Derivatives Subject to Utility Rate Regulation:
	Commodity contracts	Derivative financial instruments		1,969				420				Derivative financial instruments and Other noncurrent liabilities	(3,272		)	(9,041		)
	Derivatives Not Designated as Hedging Instruments:
	Commodity contracts	Derivative financial instruments		89				114				Derivative financial instruments	—			—
	Total Derivatives			$	2,058			$	4,760				$	(3,272	)	$	(39,453	)
	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 months ended December 31, 2013 and 2012:
	Three Months Ended December 31, :
		Gain (Loss) Recognized in AOCI								Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
		2013				2012				2013			2012			(Loss) Reclassified from AOCI into Income
	Cash Flow Hedges:
	Interest rate contracts	$	—			$	4,336			$	(669	)	$	(203	)	Interest expense
	Derivatives Not Designated
	as Hedging Instruments:	Gain (Loss) Recognized in Income														Location of Gain (Loss) Recognized in Income
		2013				2012
	Commodity contracts	$	97			$	(2	)								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.

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	3 Months Ended
	Dec. 31, 2013
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 Changes in Accumulated Other Comprehensive (Tables)	3 Months Ended
	Dec. 31, 2013
Changes AOCI [Abstract]	'
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	'
		Postretirement			Derivative
		Benefit Plans			Instruments			Total
	Balance, September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
	Reclassification of benefit plan actuarial losses and prior service cost	98			—			98
	Reclassifications of net losses on interest rate protection agreements	—			391			391
	Balance, December 31, 2013	$	(5,185	)	$	(3,046	)	$	(8,231	)

Segment_Information_Tables

Segment Information (Tables)	3 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Information	'
	Financial information by business segment follows:
	Three Months Ended December 31, 2013:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	298,899	$	271,562	$	26,961	$	376
	Cost of sales	$	151,865	$	135,487	$	16,378	$	—
	Depreciation and amortization	$	14,450	$	13,384	$	1,066	$	—
	Operating income	$	85,843	$	82,053	$	3,689	$	101
	Interest expense	$	8,797	$	8,386	$	411	$	—
	Income before income taxes	$	77,046	$	73,667	$	3,278	$	101
	Total assets (at period end)	$	2,326,670	$	2,188,623	$	138,047	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	34,254	$	32,812	$	1,442	$	—
	Three Months Ended December 31, 2012:
				Reportable Segments
		Total		Gas		Electric		Other
				Utility		Utility
	Revenues	$	273,797	$	248,254	$	25,118	$	425
	Cost of sales	$	138,277	$	123,574	$	14,703	$	—
	Depreciation and amortization	$	13,571	$	12,605	$	966	$	—
	Operating income	$	72,564	$	69,789	$	2,624	$	151
	Interest expense	$	10,077	$	9,572	$	505	$	—
	Income before income taxes	$	62,487	$	60,217	$	2,119	$	151
	Total assets (at period end)	$	2,298,995	$	2,144,693	$	154,302	$	—
	Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
	Capital expenditures	$	29,728	$	28,519	$	1,209	$	—

Inventories_Tables

Inventories (Tables)	3 Months Ended
	Dec. 31, 2013
Inventory Disclosure [Abstract]	'
Inventories	'
	Inventories comprise the following:
		December 31, 2013		September 30, 2013		December 31, 2012
	Gas Utility natural gas	$	69,117	$	78,950	$	51,838
	Materials, supplies and other	11,558		10,711		10,023
	Total inventories	$	80,675	$	89,661	$	61,861

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities and Regulatory Matters (Tables)	3 Months Ended
	Dec. 31, 2013
Regulatory Assets and Liabilities Disclosure [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:
		December 31, 2013		September 30, 2013		December 31, 2012
	Regulatory assets:
	Income taxes recoverable	$	106,435	$	106,069	$	103,665
	Underfunded pension and postretirement plans	92,755		94,515		184,764
	Environmental costs	14,910		17,054		17,119
	Deferred fuel and power costs	427		8,283		7,797
	Removal costs, net	13,748		13,333		11,541
	Other	5,722		5,657		5,742
	Total regulatory assets	$	233,997	$	244,911	$	330,628
	Regulatory liabilities:
	Postretirement benefits	$	16,846	$	16,497	$	13,486
	Environmental overcollections	2,329		2,552		3,077
	Deferred fuel and power refunds	7,524		8,283		1,916
	State tax benefits — distribution system repairs	8,725		8,453		7,750
	Other	1,332		1,502		570
	Total regulatory liabilities	$	36,756	$	37,287	$	26,799

Defined_Benefit_Pension_and_Ot1

Defined Benefit Pension and Other Postretirement Plans (Tables)	3 Months Ended
	Dec. 31, 2013
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]	'
Component 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
		December 31,						December 31,
		2013			2012			2013			2012
	Service cost	$	1,623		$	2,053		$	41		51
	Interest cost	5,721			5,196			127			143
	Expected return on assets	(6,650		)	(6,198		)	(139		)	(132		)
	Amortization of:
	Prior service benefit	—			—			(160		)	(105		)
	Actuarial loss	1,748			3,428			37			91
	Net benefit cost (income)	2,442			4,479			(94		)	48
	Change in associated regulatory liabilities	—			—			918			815
	Net expense	$	2,442		$	4,479		$	824		$	863

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Fair Value, by Balance Sheet Grouping [Table Text Block]	'
												Gross Amounts Not Offset in the Balance Sheet
		Gross Amount Recognized			Gross Amount Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet				Financial Instruments			Cash Collateral		Net Amount
	December 31, 2013:
	Derivative assets	$	2,130		$	(72	)	$	2,058			$	—		$	—	$	2,058
	Derivative (liabilities)	$	(3,344	)	$	72		$	(3,272	)		$	—		$	—	$	(3,272	)
	September 30, 2013:
	Derivative assets	$	92		$	(49	)	$	43			$	—		$	—	$	43
	Derivative (liabilities)	$	(6,726	)	$	49		$	(6,677	)		$	—		$	1,407	$	(5,270	)
	December 31, 2012:
	Derivative assets	$	4,971		$	(211	)	$	4,760			$	—		$	—	$	4,760
	Derivative (liabilities)	$	(39,664	)	$	211		$	(39,453	)		$	—		$	700	$	(38,753	)
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 December 31, 2013, September 30, 2013 and December 31, 2012:
		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)
	December 31, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts	$	2,058			$	—			$	—			$	2,058
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	(266	)		$	(3,006	)		$	—			$	(3,272	)
	September 30, 2013:
	Assets:
	Derivative financial instruments:
	Commodity contracts	$	43			$	—			$	—			$	43
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	(2,162	)		$	(4,515	)		$	—			$	(6,677	)
	December 31, 2012:
	Assets:
	Derivative financial instruments:
	Commodity contracts	$	374			$	160			$	—			$	534
	Interest rate contracts	$	—			$	4,226			$	—			$	4,226
	Liabilities:
	Derivative financial instruments:
	Commodity contracts	$	(1,315	)		$	(7,726	)		$	—			$	(9,041	)
	Interest rate contracts	$	—			$	(30,412	)		$	—			$	(30,412	)

Disclosures_About_Derivative_I1

Disclosures About Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Dec. 31, 2013
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 December 31, 2013 and 2012:
		Derivative Assets										Derivative (Liabilities)
		Balance Sheet		Fair Value								Balance Sheet	Fair Value
		Location		2013				2012				Location	2013			2012
	Derivatives Designated as Hedging Instruments:
	Interest rate contracts	Derivative financial instruments		$	—			$	4,226			Derivative financial instruments	$	—		$	(30,412	)
	Derivatives Subject to Utility Rate Regulation:
	Commodity contracts	Derivative financial instruments		1,969				420				Derivative financial instruments and Other noncurrent liabilities	(3,272		)	(9,041		)
	Derivatives Not Designated as Hedging Instruments:
	Commodity contracts	Derivative financial instruments		89				114				Derivative financial instruments	—			—
	Total Derivatives			$	2,058			$	4,760				$	(3,272	)	$	(39,453	)
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 months ended December 31, 2013 and 2012:
	Three Months Ended December 31, :
		Gain (Loss) Recognized in AOCI								Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
		2013				2012				2013			2012			(Loss) Reclassified from AOCI into Income
	Cash Flow Hedges:
	Interest rate contracts	$	—			$	4,336			$	(669	)	$	(203	)	Interest expense
	Derivatives Not Designated
	as Hedging Instruments:	Gain (Loss) Recognized in Income														Location of Gain (Loss) Recognized in Income
		2013				2012
	Commodity contracts	$	97			$	(2	)								Operating expenses/other income, net

Significant_Accounting_Policie3

Significant Accounting Policies (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2013
Schedule of Accumulated Other Comprehensive Income [Line Items]	'	'	'
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	$5,185	'	$5,283
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	-3,046	'	-3,437
Accumulated other comprehensive loss	-8,231	-26,966	-8,720
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	98	'	'
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	391	119	'
Quantifying Misstatement in Current Year Financial Statements, Amount	'	20,709	'
Derivative [Member]	'	'	'
Schedule of Accumulated Other Comprehensive Income [Line Items]	'	'	'
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	$391	'	'

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2013
	Segment
Segment Reporting [Abstract]	'	'	'
Number of reportable segments (in segments)	2	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	$298,899	$273,797	'
Cost of sales	151,865	138,277	'
Depreciation and amortization	14,450	13,571	'
Operating income	85,843	72,564	'
Interest expense	8,797	10,077	'
Income before income taxes	77,046	62,487	'
Total assets (at period end)	2,326,670	2,298,995	2,210,322
Goodwill (at period end)	182,145	182,145	182,145
Capital expenditures	34,254	29,728	'
Gas Utility [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	271,562	248,254	'
Cost of sales	135,487	123,574	'
Depreciation and amortization	13,384	12,605	'
Operating income	82,053	69,789	'
Interest expense	8,386	9,572	'
Income before income taxes	73,667	60,217	'
Total assets (at period end)	2,188,623	2,144,693	'
Goodwill (at period end)	182,145	182,145	'
Capital expenditures	32,812	28,519	'
Electric Utility [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	26,961	25,118	'
Cost of sales	16,378	14,703	'
Depreciation and amortization	1,066	966	'
Operating income	3,689	2,624	'
Interest expense	411	505	'
Income before income taxes	3,278	2,119	'
Total assets (at period end)	138,047	154,302	'
Goodwill (at period end)	0	0	'
Capital expenditures	1,442	1,209	'
Other [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	376	425	'
Cost of sales	0	0	'
Depreciation and amortization	0	0	'
Operating income	101	151	'
Interest expense	0	0	'
Income before income taxes	101	151	'
Total assets (at period end)	0	0	'
Goodwill (at period end)	0	0	'
Capital expenditures	$0	$0	'

Inventories_Details

Inventories (Details) (USD $)	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Inventory, Net [Abstract]	'	'	'
Total inventories	$80,675	$89,661	$61,861
Gas Utility Natural Gas [Member]	'	'	'
Inventory, Net [Abstract]	'	'	'
Total inventories	69,117	78,950	51,838
Materials, Supplies and Other [Member]	'	'	'
Inventory, Net [Abstract]	'	'	'
Total inventories	$11,558	$10,711	$10,023

Inventories_Textual_Details

Inventories Textual (Details) (USD $)	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	ft3	ft3	ft3
Inventory, Net [Abstract]	'	'	'
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)	9,800,000,000	11,000,000,000	9,100,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates	$39,362	$44,366	$27,251
SCAAs [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Number of storage agreements (in storage agreements)	4	'	'
SCAAs [Member] | Other current liabilities [Member]	'	'	'
Inventory, Net [Abstract]	'	'	'
Security Deposit Liability	'	$16,500	$16,500

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $)	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Assets	$233,997	$244,911	$330,628
Regulatory Liabilities	36,756	37,287	26,799
Postretirement benefits [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Liabilities	16,846	16,497	13,486
Environmental overcollections [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Liabilities	2,329	2,552	3,077
Deferred fuel and power refunds [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Liabilities	7,524	8,283	1,916
State tax benefits -- distribution system repairs [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Liabilities	8,725	8,453	7,750
Other [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Liabilities	1,332	1,502	570
Income taxes recoverable [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Assets	106,435	106,069	103,665
Underfunded pension and postretirement plans [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Assets	92,755	94,515	184,764
Environmental costs [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Assets	14,910	17,054	17,119
Deferred fuel and power costs [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Assets	427	8,283	7,797
Removal costs, net [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Assets	13,748	13,333	11,541
Other [Member]	'	'	'
Regulatory Assets and Liabilities [Line Items]	'	'	'
Regulatory Assets	$5,722	$5,657	$5,742

Regulatory_Assets_and_Liabilit3

Regulatory Assets and Liabilities and Regulatory Matters Textual (Details) (USD $)	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Regulatory Assets [Line Items]	'	'	'
Fair value of electric utility electricity supply contracts	($3,344)	($6,726)	($39,664)
Deferral Fuel and Power [Member]	'	'	'
Regulatory Assets [Line Items]	'	'	'
GasUtilityUnrealizedGainOrLossOnDerivativeFinancialInstrumentsContracts	1,968	-1,743	-440
Electric Utility Electric Supply Contracts [Member]	'	'	'
Regulatory Assets [Line Items]	'	'	'
Fair value of electric utility electricity supply contracts	$3,182	($4,759)	($8,182)

Defined_Benefit_Pension_and_Ot2

Defined Benefit Pension and Other Postretirement Plans (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]	'	'
Components of net periodic pension expense and other postretirement benefit costs [Abstract]	'	'
Service cost	$1,623	$2,053
Interest cost	5,721	5,196
Expected return on assets	-6,650	-6,198
Amortization of:	'	'
Prior service cost (benefit)	0	0
Actuarial loss	1,748	3,428
Net benefit cost	2,442	4,479
Change in associated regulatory liabilities	0	0
Net expense	2,442	4,479
Other Postretirement Benefits [Member]	'	'
Components of net periodic pension expense and other postretirement benefit costs [Abstract]	'	'
Service cost	41	51
Interest cost	127	143
Expected return on assets	-139	-132
Amortization of:	'	'
Prior service cost (benefit)	-160	-105
Actuarial loss	37	91
Net benefit cost	-94	48
Change in associated regulatory liabilities	918	815
Net expense	$824	$863

Defined_Benefit_Pension_and_Ot3

Defined Benefit Pension and Other Postretirement Plans Textual (Details) (Pension Benefits [Member], USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Expected contribution to pensions plans in the remainder of current fiscal year	$14,399	'
Contribution made to Pension Plan	$3,486	$5,730

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
	Environmental Issue [Member]	Environmental Issue [Member]	Environmental Remediation Expense [Member]	Environmental Remediation Expense [Member]	CPG and PNG COAs [Member]	CPG and PNG COAs [Member]
		PNG MGP [Member]	CPG MGP [Member]	PNG MGP [Member]
Commitments and Contingencies [Line Items]	'	'	'	'	'	'
Environmental expenditures cap during calendar year	'	'	$1,800	$1,100	'	'
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	'	'	'	'	$16,900	$14,965
Base year for determination of investigation and remediation cost (in years)	'5 years	'	'	'	'	'

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)

3 Months Ended

3 Months Ended

3 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Energy Services [Member]

Energy Services [Member]

Inventories [Member]

Inventories [Member]

Inventories [Member]

SCAAs [Member]

SCAAs [Member]

SCAAs [Member]

SCAAs [Member]

SCAAs [Member]

Exclusive of transactions pursuant SCAAs [Member]

Exclusive of transactions pursuant SCAAs [Member]

SCAAs [Member]

Energy Services [Member]

Energy Services [Member]

Energy Services [Member]

Energy Services [Member]

Energy Services [Member]

Other current liabilities [Member]

Other current liabilities [Member]

Other current liabilities [Member]

Energy Services [Member]

Energy Services [Member]

Storage_Agreement

ft3

ft3

ft3

Energy Services [Member]

Energy Services [Member]

Energy Services [Member]

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of storage agreements (in storage agreements)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

Related party costs incurred

$1,843

$1,805

'

'

'

'

'

$6,448

$4,324

'

'

'

$19,378

$17,825

'

Related party security deposits

'

'

'

'

'

'

'

'

'

10,600

16,500

16,500

'

'

'

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

'

'

'

'

6,800,000,000

10,400,000,000

9,100,000,000

'

'

'

'

'

'

'

'

Natural gas storage inventory, related parties, current

'

'

'

'

27,052

41,988

27,251

'

'

'

'

'

'

'

'

Revenue from related parties

'

'

17,116

19,824

'

'

'

'

'

'

'

'

'

'

'

Purchases from related party

'

'

$22,078

$19,020

'

'

'

'

'

'

'

'

'

'

'

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Derivative financial instruments, assets	$2,058	$43	$4,760
Derivative financial instruments, liabilities	-3,272	-6,677	-39,453
Commodity contracts [Member] | Fair Value, Measurements, Recurring [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Derivative financial instruments, assets	2,058	43	534
Derivative financial instruments, liabilities	-3,272	-6,677	-9,041
Commodity contracts [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Derivative financial instruments, assets	2,058	43	374
Derivative financial instruments, liabilities	-266	-2,162	-1,315
Commodity contracts [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Derivative financial instruments, assets	0	0	160
Derivative financial instruments, liabilities	-3,006	-4,515	-7,726
Commodity contracts [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	0	0	0
Interest rate contracts [Member] | Fair Value, Measurements, Recurring [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Derivative financial instruments, assets	'	'	4,226
Derivative financial instruments, liabilities	'	'	-30,412
Interest rate contracts [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Derivative financial instruments, assets	'	'	0
Derivative financial instruments, liabilities	'	'	0
Interest rate contracts [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Derivative financial instruments, assets	'	'	4,226
Derivative financial instruments, liabilities	'	'	-30,412
Interest rate contracts [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Derivative financial instruments, liabilities	'	'	$0

Fair_Value_Measurements_Textua

Fair Value Measurements Textual (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Carrying amount of long-term debt	$642,000	$600,000
Fair value of long-term debt	$694,220	$696,217

Fair_Value_Measurements_Offset

Fair Value Measurements Offsetting Derivative Assets and Liabilities (Details) (USD $)	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Offsetting Derivatives Table [Line Items]	'	'	'
Derivative Asset, Fair Value, Gross Asset	$2,130	$92	$4,971
Fair value of electric utility electricity supply contracts	-3,344	-6,726	-39,664
Derivative Asset Offset Amount	-72	-49	-211
Derivative Assets	2,058	43	4,760
Derivative Asset, Fair Value, Gross Liability	0	0	0
Derivative, Collateral, Right to Reclaim Cash	0	0	0
Derivative Assets Net Presentation	2,058	43	4,760
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability Offset Amount	72	49	211
Derivative Liabilities	-3,272	-6,677	-39,453
Derivative, Collateral, Obligation to Return Cash	0	1,407	700
Derivative Liability Net Presentation	($3,272)	($5,270)	($38,753)

Disclosures_About_Derivative_I2

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

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

In Thousands, unless otherwise specified

Electric Utility electric transmission congestion [Member]

Electric Utility electric transmission congestion [Member]

Gas Utility [Member]

Gas Utility [Member]

Electric Utility [Member]

Electric Utility [Member]

Interest Rate Protection Agreements [Member]

Interest Rate Protection Agreements [Member]

Interest Rate Swap [Member]

kWh

kWh

DTH

DTH

kWh

kWh

Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount (in units)

'

'

'

117,900,000

118,200,000

9,700,000

13,000,000

324,400,000

482,300,000

'

'

'

Total Derivatives Liability

$3,344

$6,726

$39,664

'

'

'

'

($3,182)

($8,182)

'

'

'

Derivative Assets

2,058

43

4,760

'

'

'

'

'

'

'

'

'

Derivative Liabilities

3,272

6,677

39,453

'

'

'

'

'

'

'

'

'

Total Derivatives Assets

2,130

92

4,971

'

'

'

'

'

'

'

'

'

Underlying variable rate debt

'

'

'

'

'

'

'

'

'

0

173,000

'

Recorded loss amount included in Other Income, Net

'

'

'

'

'

'

'

'

'

'

'

0

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

'

'

'

'

'

'9 months

'

'11 months

'

'

'

'

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

2,680

'

'

'

'

'

'

'

'

'

'

'

Restricted Cash in brokerage accounts

$0

$3,181

$2,106

'

'

'

'

'

'

'

'

'

Disclosures_About_Derivative_I3

Disclosures About Derivative Instruments and Hedging Activities (Details) (USD $)	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Balance sheet location and fair value of derivative assets and liabilities	'	'	'
Total Derivatives Assets	$2,130	$92	$4,971
Total Derivatives Liability	-3,344	-6,726	-39,664
Derivative Assets	2,058	43	4,760
Derivative Liabilities	3,272	6,677	39,453
Interest rate contracts [Member] | Derivatives Designated as Hedging Instruments [Member] | Derivative financial instruments [Member]	'	'	'
Balance sheet location and fair value of derivative assets and liabilities	'	'	'
Derivative Assets	0	'	4,226
Interest rate contracts [Member] | Derivatives Designated as Hedging Instruments [Member] | Derivative financial instruments and other noncurrent liabilities [Member]	'	'	'
Balance sheet location and fair value of derivative assets and liabilities	'	'	'
Derivative Liabilities	0	'	30,412
Commodity contracts [Member] | Derivatives Subject to Utility Rate Regulation [Member] | Derivative financial instruments [Member]	'	'	'
Balance sheet location and fair value of derivative assets and liabilities	'	'	'
Derivative Assets	1,969	'	420
Commodity contracts [Member] | Derivatives Subject to Utility Rate Regulation [Member] | Derivative financial instruments and other noncurrent liabilities [Member]	'	'	'
Balance sheet location and fair value of derivative assets and liabilities	'	'	'
Derivative Liabilities	3,272	'	9,041
Commodity contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Derivative financial instruments [Member]	'	'	'
Balance sheet location and fair value of derivative assets and liabilities	'	'	'
Derivative Liabilities	0	'	0
Commodity contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Derivative financial instruments [Member]	'	'	'
Balance sheet location and fair value of derivative assets and liabilities	'	'	'
Derivative Assets	$89	'	$114

Disclosures_About_Derivative_I4

Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Interest rate contracts [Member] | Interest expense, net [Member] | Cash Flow Hedges [Member]	'	'
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest	'	'
Gain or (loss) recognized in AOCI	$0	$4,336
Gain (loss) reclassified from AOCI into income	-669	-203
Derivatives Not Designated as Hedging Instruments [Member] | Commodity contracts [Member] | Operating expenses/other income, net [Member]	'	'
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest	'	'
Gain (Loss) recognized in income	$97	($2)