Ugi Utilities 10-Q 5 Feb 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Dec. 31, 2015	Jan. 31, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	100,548
Document Type	10-Q
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--09-30
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		26,781,785

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 15,585	$ 3,099	$ 14,267
Restricted cash	6,324	6,602	8,963
Accounts receivable (less allowances for doubtful accounts of $5,283, $5,599 and $6,764, respectively)	78,954	55,659	116,454
Accounts receivable — related parties	2,671	1,271	2,901
Accrued utility revenues	30,776	12,051	52,743
Inventories	49,365	51,716	85,429
Deferred income taxes	0	24,694	1,600
Income taxes receivable	31,465	10,026	0
Regulatory assets	3,905	4,105	16,773
Derivative instruments	234	934	0
Prepaid expenses & other current assets	28,670	23,903	19,052
Total current assets	247,949	194,060	318,182
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $940,655, $929,130 and $897,802, respectively)	1,870,732	1,824,369	1,727,117
Goodwill	182,145	182,145	182,145
Regulatory assets	297,914	300,103	253,826
Other assets	7,559	7,501	7,351
Total assets	2,606,299	2,508,178	2,488,621
Current liabilities:
Current maturities of long-term debt	175,000	247,000	92,000
Short-term borrowings	217,700	71,700	153,500
Accounts payable	51,954	58,135	65,574
Accounts payable — related parties	7,069	4,430	10,716
Regulatory liability — deferred fuel refunds	28,083	36,638	0
Derivative instruments	10,351	12,591	9,434
Other current liabilities	112,528	103,265	123,285
Total current liabilities	602,685	533,759	454,509
Long-term debt	375,000	375,000	550,000
Deferred income taxes	524,287	512,497	466,037
Deferred investment tax credits	3,513	3,597	3,849
Pension and postretirement benefit obligations	132,899	135,003	96,861
Derivative instruments	0	0	344
Other noncurrent liabilities	58,469	57,702	53,418
Total liabilities	$ 1,696,853	$ 1,617,558	$ 1,625,018
Commitments and contingencies
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	471,952	471,904	471,076
Retained earnings	388,494	372,143	339,927
Accumulated other comprehensive loss	(11,259)	(13,686)	(7,659)
Total common stockholder’s equity	909,446	890,620	863,603
Total liabilities and stockholder’s equity	$ 2,606,299	$ 2,508,178	$ 2,488,621

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 5,283	$ 5,599	$ 6,764
Accumulated depreciation and amortization	$ 940,655	$ 929,130	$ 897,802
Common stock, par value (in usd per share)	$ 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 Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Revenues	$ 197,982	$ 287,306
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	75,439	143,052
Operating and administrative expenses	48,027	46,548
Operating and administrative expenses — related parties	2,180	2,782
Taxes other than income taxes	3,769	4,104
Depreciation	15,827	14,558
Amortization	874	867
Other operating loss (income), net	3,570	(245)
Total costs and expenses	149,686	211,666
Operating income	48,296	75,640
Interest expense	9,494	10,649
Income before income taxes	38,802	64,991
Income taxes	15,451	26,152
Net income	$ 23,351	$ 38,839

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income	$ 23,351	$ 38,839
Other comprehensive income:
Net gains on derivative instruments (net of tax of $(1,332) and $0, respectively)	1,877	0
Reclassifications of net losses on derivative instruments (net of tax of $(276) and $(278), respectively)	390	391
Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(113) and $(91), respectively)	160	131
Other comprehensive income	2,427	522
Comprehensive income	$ 25,778	$ 39,361

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net gains in fair value of derivative instruments, tax	$ (1,332)	$ 0
Reclassifications of net losses on derivative instruments, tax	(276)	(278)
Benefit plans reclassifications of actuarial losses and prior service costs, tax	$ (113)	$ (91)

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 23,351	$ 38,839
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	16,701	15,425
Deferred income taxes, net	15,607	3,921
Provision for uncollectible accounts	1,930	2,490
Other, net	4,331	3,534
Net change in:
Accounts receivable and accrued utility revenues	(46,757)	(92,313)
Inventories	2,351	9,790
Deferred fuel and power costs, net of changes in unsettled derivatives	(6,788)	4,393
Accounts payable	(3,642)	6,075
Other current assets	(4,767)	(4,821)
Other current liabilities	6,449	25,356
Net cash provided by operating activities	8,766	12,689
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(60,457)	(55,029)
Net costs of property, plant and equipment disposals	(3,150)	(2,028)
Decrease (increase) in restricted cash	278	(5,371)
Net cash used by investing activities	(63,329)	(62,428)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(7,000)	(15,600)
Repayments of long-term debt	(72,000)	0
Increase in short-term borrowings	146,000	67,200
Other	49	5
Net cash provided by financing activities	67,049	51,605
Cash and cash equivalents increase	12,486	1,866
CASH AND CASH EQUIVALENTS:
End of period	15,585	14,267
Beginning of period	$ 3,099	$ 12,401

Nature of Operations

Nature of Operations	3 Months Ended
	Dec. 31, 2015
Nature of Operations [Abstract]
Nature of Operations	Note 1 — 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.” Prior to June 1, 2015, PNG also had a heating, ventilation and air-conditioning service business (“UGI Penn HVAC Services, Inc.”) which operated principally in the PNG service territory (“HVAC Business”). The assets of the HVAC business principally comprising customer contracts were sold on June 1, 2015. 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2 — Summary of 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, 2015 , 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, 2015 (“the Company’s 2015 Annual Report”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year. Derivative Instruments Derivative instruments are reported in the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP and such exception has been elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or is designated and qualifies for hedge accounting. Gains and losses on substantially all of the derivative instruments used by Gas Utility and Electric Utility to hedge commodity prices are included in regulatory assets and liabilities in accordance with GAAP regarding accounting for rate-regulated entities. Certain of our derivative instruments are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (“AOCI”), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Certain other commodity derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments are included in cash flows from operating activities. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 9 . Reclassifications. Certain prior period amounts have been reclassified to conform to current period presentation. Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

Accounting Changes

Accounting Changes	3 Months Ended
	Dec. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Note 3 — Accounting Changes Adoption of New Accounting Standard Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. We applied this guidance prospectively and, as such, prior period amounts were not retrospectively adjusted. Accounting Standards Not Yet Adopted Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015 (Fiscal 2017). Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance effective September 30, 2016. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This standard is effective for the Company for interim and annual periods beginning October 1, 2018 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our consolidated financial statements.

Inventories

Inventories	3 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventories	Note 4 — Inventories Inventories comprise the following: December 31, 2015 September 30, 2015 December 31, 2014 Gas Utility natural gas $ 35,923 $ 37,510 $ 72,442 Materials, supplies and other 13,442 14,206 12,987 Total inventories $ 49,365 $ 51,716 $ 85,429 At December 31, 2015 , UGI Utilities is a party to two principal storage contract administrative agreements (“SCAAs”) having terms of three years. One of the SCAAs is with UGI Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 11 ) and one of the SCAAs is with a non-affiliate. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above. The carrying value of gas storage inventories released under the SCAAs at December 31, 2015 , September 30, 2015 and December 31, 2014 , comprising 8.9 billion cubic feet (“bcf”), 9.0 bcf and 9.9 bcf of natural gas, was $22,061 , $22,694 and $41,937 , respectively. At December 31, 2015 , September 30, 2015 and December 31, 2014 , UGI Utilities held a total of $15,100 , $17,700 and $17,600 , respectively, of security deposits from its SCAA counterparties. These amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets. For additional information related to the SCAAs with Energy Services, see Note 11 .

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities and Regulatory Matters	3 Months Ended
	Dec. 31, 2015
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities and Regulatory Matters	Note 5 — 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 in the Company’s 2015 Annual Report. 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, 2015 September 30, 2015 December 31, 2014 Regulatory assets: Income taxes recoverable $ 117,396 $ 115,946 $ 111,075 Underfunded pension and postretirement plans 138,294 140,762 107,827 Environmental costs 17,643 19,983 14,738 Deferred fuel and power costs — — 16,761 Removal costs, net 22,346 21,223 17,550 Other 6,140 6,294 2,648 Total regulatory assets $ 301,819 $ 304,208 $ 270,599 Regulatory liabilities: Postretirement benefits $ 20,314 $ 19,975 $ 18,959 Deferred fuel and power refunds 28,083 36,638 — State tax benefits — distribution system repairs 13,712 13,266 10,349 Other 1,073 1,125 3,580 Total regulatory liabilities (a) $ 63,182 $ 71,004 $ 32,888 (a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and noncurrent liabilities in the Condensed Consolidated Balance Sheets. Deferred fuel and power — costs and refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability. Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at December 31, 2015 , September 30, 2015 , and December 31, 2014 , were $(4,488) , $(3,262) and $(6,798) , respectively. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Prior to March 1, 2015, we did not elect the NPNS exception under GAAP for these contracts. Therefore, we recognized the fair value of these contracts on the balance sheet with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At December 31, 2015 , September 30, 2015 , and December 31, 2014 , the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(450) , $(533) and $(2,397) , respectively. These amounts are reflected in current and noncurrent derivative assets and current and noncurrent derivative liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above. Effective with Electric Utility forward contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet (see Note 9 ). In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at December 31, 2015 , September 30, 2015 , and December 31, 2014 , were not material. UGI Gas Base Rate Filing. On January 19, 2016, UGI Utilities filed a request with the PUC to increase UGI Gas base operating revenues for residential, commercial and industrial customers by $58,600 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. UGI Utilities is requesting that the new gas rates become effective March 19, 2016. However, the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. This review process is expected to last approximately nine months, however, the Company cannot predict the timing or the ultimate outcome of the rate case review process.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 6 — Commitments and Contingencies Contingencies Environmental Matters 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 December 31, 2015 and 2014 , our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11,679 and $11,233 , respectively. We have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable. From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility. UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five -year average of such prudently incurred remediation costs, and (2) CPG and PNG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At December 31, 2015 , 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. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

Defined Benefit Pension and Oth

Defined Benefit Pension and Other Postretirement Plans	3 Months Ended
	Dec. 31, 2015
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Defined Benefit Pension and Other Postretirement Plans	Note 7 — Defined Benefit Pension and Other Postretirement Plans We sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plan”). Pension Plan benefits are based on years of service, age and employee compensation. We also 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 include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended December 31, 2015 2014 2015 2014 Service cost $ 1,732 $ 1,741 $ 46 $ 48 Interest cost 5,817 5,627 116 119 Expected return on assets (7,167 ) (7,224 ) (149 ) (153 ) Amortization of: Prior service cost (benefit) 87 87 (160 ) (160 ) Actuarial loss 2,393 2,198 24 32 Net benefit cost (income) 2,862 2,429 (123 ) (114 ) Change in associated regulatory liabilities — — 878 937 Net benefit cost after change in regulatory liabilities $ 2,862 $ 2,429 $ 755 $ 823 Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. During the three months ended December 31, 2015 and 2014 , the Company made contributions to the Pension Plan of $2,467 and $2,783 , respectively. The Company expects to make additional discretionary cash contributions of approximately $7,400 to the Pension Plan during the remainder of Fiscal 2016 . UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the three months ended December 31, 2015 and 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.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 8 — Fair Value Measurements Derivative Instruments The following table presents on a gross basis our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of December 31, 2015 , September 30, 2015 and December 31, 2014 : Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2015: Assets: Commodity contracts $ 234 $ — $ — $ 234 Interest rate contracts $ — $ 572 $ — $ 572 Liabilities: Commodity contracts $ (4,986 ) $ (1,557 ) $ — $ (6,543 ) Interest rate contracts $ — $ (4,380 ) $ — $ (4,380 ) September 30, 2015: Assets: Commodity contracts $ 934 $ 373 $ — $ 1,307 Liabilities: Commodity contracts $ (4,560 ) $ (1,388 ) $ — $ (5,948 ) Interest rate contracts $ — $ (7,016 ) $ — $ (7,016 ) December 31, 2014: Assets: Commodity contracts $ — $ 177 $ — $ 177 Liabilities: Commodity contracts $ (7,355 ) $ (2,600 ) $ — $ (9,955 ) The fair values of our Level 1 exchange-traded commodity futures and option derivative 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 (including current maturities) at December 31, 2015 , were $550,000 and $615,213 , respectively. The carrying amount and estimated fair value of our long-term debt (including current maturities) at December 31, 2014 , were $642,000 and $741,853 , 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).

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 9 — 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, 2015 and 2014 , the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 12.4 million dekatherms and 11.2 million dekatherms, respectively. At December 31, 2015 , the maximum period over which Gas Utility is economically hedging natural gas market price risk is 9 months . Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 5 ). 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. For such contracts entered into prior to March 1, 2015, Electric Utility chose not to elect the NPNS exception under GAAP related to these derivative instruments and the fair values of these contracts are reflected in current and noncurrent derivative instrument assets and liabilities in the accompanying Condensed Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Condensed Consolidated Balance Sheets in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 5 ). Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet. At December 31, 2015 and 2014 , the volumes of Electric Utility’s forward electricity purchase contracts were 333.3 million kilowatt hours and 486.2 million kilowatt hours, respectively. At December 31, 2015 , the maximum period over which these contracts extend is 11 months . In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 5 ). At December 31, 2015 and 2014 , the total volumes associated with FTRs totaled 172.6 million kilowatt hours and 144.6 million kilowatt hours, respectively. At December 31, 2015 , the maximum period over which we are economically hedging electricity congestion is 5 months . 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. 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. As of December 31, 2015 , the notional amount of our unsettled IRPA contracts was $290,000 . At December 31, 2014 , we had no unsettled IRPAs. Our December 31, 2015 , unsettled IRPA contracts hedge forecasted interest payments expected to occur over ten - and thirty -year periods beginning in Fiscal 2016. At December 31, 2015 , the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is approximately $2,200 . Derivative Instrument Credit Risk Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2015 and 2014 , restricted cash in brokerage accounts totaled $6,324 and $8,963 , respectively. Offsetting Derivative Assets and Liabilities Derivative assets and liabilities are presented net by counterparty on our Condensed Consolidated Balance Sheets if the right of offset exists. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange or clearinghouse to enter, execute or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions. In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on our Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements. Fair Value of Derivative Instruments The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of December 31, 2015 and 2014 : December 31, 2015 December 31, 2014 Derivative assets: Derivatives designated as hedging instruments: Interest rate contracts $ 572 $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts 234 177 Total derivative assets - gross 806 177 Gross amounts offset in the balance sheet (572 ) (177 ) Total derivative assets - net $ 234 $ — Derivative liabilities: Derivatives designated as hedging instruments: Interest rate contracts $ (4,380 ) $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts (6,278 ) (9,398 ) Derivatives not subject to PGC and DS mechanisms: Commodity contracts (265 ) (557 ) Total derivative liabilities - gross (10,923 ) (9,955 ) Gross amounts offset in the balance sheet 572 177 Total derivative liabilities - net $ (10,351 ) $ (9,778 ) Effect of Derivative Instruments The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Condensed Consolidated Statements of Income and changes in AOCI for the three months ended December 31, 2015 and 2014 : Gain (Loss) Recognized in AOCI Gain (Loss) Reclassified from AOCI into Income Location of Gain Three Months Ended December 31, 2015 2014 2015 2014 Cash Flow Hedges: Interest rate contracts $ 3,209 $ — $ (666 ) $ (669 ) Interest expense Gain (Loss) Recognized in Income Location of Gain (Loss) Recognized in Income Three Months Ended December 31, 2015 2014 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ (65 ) $ (522 ) Operating expenses/other operating income, net We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal 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.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	3 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Accumulated Other Comprehensive Income	Note 10 — Accumulated Other Comprehensive Income The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2015 and 2014 : Postretirement Benefit Plans Derivative Instruments Total Three Months Ended December 31, 2015 AOCI - September 30, 2015 $ (9,276 ) $ (4,410 ) $ (13,686 ) Net gains on IRPAs — 1,877 1,877 Reclassifications of benefit plan actuarial losses and prior service costs 160 — 160 Reclassifications of net losses on IRPAs — 390 390 AOCI - December 31, 2015 $ (9,116 ) $ (2,143 ) $ (11,259 ) Three Months Ended December 31, 2014 AOCI - September 30, 2014 $ (6,311 ) $ (1,870 ) $ (8,181 ) Reclassifications of benefit plan actuarial losses and prior service costs 131 — 131 Reclassifications of net losses on IRPAs — 391 391 AOCI - December 31, 2014 $ (6,180 ) $ (1,479 ) $ (7,659 )

Related Party Transactions

Related Party Transactions	3 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Note 11 — 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 under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities for all periods presented were not material. From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) 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 $1,870 and $4,956 during the three months ended December 31, 2015 and 2014 , respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amount of such security deposits, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, was $8,100 , $10,700 , and $10,600 as of December 31, 2015 , September 30, 2015 and December 31, 2014 , respectively. 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, 2015 , September 30, 2015 and December 31, 2014 , comprising approximately 5.1 bcf, 5.0 bcf and 6.5 bcf of natural gas, were $12,684 , $12,889 and $27,501 , respectively. 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 primarily 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, 2015 and 2014 totaled $27,364 and $23,747 , respectively. From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2015 and 2014 , revenues associated with such sales to Energy Services totaled $8,766 and $16,190 , 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, 2015 and 2014 , such purchases totaled $8,192 and $21,775 , respectively.

Segment Information

Segment Information	3 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Information	Note 12 — 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, prior to its sale in June 2015, did not meet the quantitative thresholds for separate segment reporting under GAAP relating to business segment reporting and has been included in “Other” below. The accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s 2015 Annual Report. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes. Financial information by business segment follows: Three Months Ended December 31, 2015 : Reportable Segments Total Gas Utility Electric Utility Revenues $ 197,982 $ 176,942 $ 21,040 Cost of sales $ 75,439 $ 64,229 $ 11,210 Depreciation and amortization $ 16,701 $ 15,504 $ 1,197 Operating income $ 48,296 $ 45,820 $ 2,476 Interest expense $ 9,494 $ 9,066 $ 428 Income before income taxes $ 38,802 $ 36,754 $ 2,048 Capital expenditures $ 61,464 $ 59,270 $ 2,194 As of December 31, 2015 Total assets (at period end) $ 2,606,299 $ 2,462,508 $ 143,791 Goodwill (at period end) $ 182,145 $ 182,145 $ — Three Months Ended December 31, 2014 : Reportable Segments Total Gas Utility Electric Utility Other Revenues $ 287,306 $ 260,478 $ 26,423 $ 405 Cost of sales $ 143,052 $ 127,208 $ 15,844 $ — Depreciation and amortization $ 15,425 $ 14,280 $ 1,145 $ — Operating income $ 75,640 $ 71,846 $ 3,719 $ 75 Interest expense $ 10,649 $ 10,130 $ 519 $ — Income before income taxes $ 64,991 $ 61,716 $ 3,200 $ 75 Capital expenditures $ 55,029 $ 53,492 $ 1,537 $ — As of December 31, 2014 Total assets (at period end) $ 2,488,621 $ 2,346,169 $ 142,452 $ — Goodwill (at period end) $ 182,145 $ 182,145 $ — $ —

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Derivative Instruments	Derivative Instruments Derivative instruments are reported in the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP and such exception has been elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or is designated and qualifies for hedge accounting. Gains and losses on substantially all of the derivative instruments used by Gas Utility and Electric Utility to hedge commodity prices are included in regulatory assets and liabilities in accordance with GAAP regarding accounting for rate-regulated entities. Certain of our derivative instruments are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (“AOCI”), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Certain other commodity derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments are included in cash flows from operating activities. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 9 .
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.
Accounting Standards Not Yet Adopted	Adoption of New Accounting Standard Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. We applied this guidance prospectively and, as such, prior period amounts were not retrospectively adjusted. Accounting Standards Not Yet Adopted Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015 (Fiscal 2017). Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance effective September 30, 2016. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This standard is effective for the Company for interim and annual periods beginning October 1, 2018 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our consolidated financial statements.

Inventories (Tables)

Inventories (Tables)	3 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories comprise the following: December 31, 2015 September 30, 2015 December 31, 2014 Gas Utility natural gas $ 35,923 $ 37,510 $ 72,442 Materials, supplies and other 13,442 14,206 12,987 Total inventories $ 49,365 $ 51,716 $ 85,429

Regulatory Assets and Liabili22

Regulatory Assets and Liabilities and Regulatory Matters (Tables)	3 Months Ended
	Dec. 31, 2015
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: December 31, 2015 September 30, 2015 December 31, 2014 Regulatory assets: Income taxes recoverable $ 117,396 $ 115,946 $ 111,075 Underfunded pension and postretirement plans 138,294 140,762 107,827 Environmental costs 17,643 19,983 14,738 Deferred fuel and power costs — — 16,761 Removal costs, net 22,346 21,223 17,550 Other 6,140 6,294 2,648 Total regulatory assets $ 301,819 $ 304,208 $ 270,599 Regulatory liabilities: Postretirement benefits $ 20,314 $ 19,975 $ 18,959 Deferred fuel and power refunds 28,083 36,638 — State tax benefits — distribution system repairs 13,712 13,266 10,349 Other 1,073 1,125 3,580 Total regulatory liabilities (a) $ 63,182 $ 71,004 $ 32,888 (a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and noncurrent liabilities in the Condensed Consolidated Balance Sheets.

Defined Benefit Pension and O23

Defined Benefit Pension and Other Postretirement Plans (Tables)	3 Months Ended
	Dec. 31, 2015
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 include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended December 31, 2015 2014 2015 2014 Service cost $ 1,732 $ 1,741 $ 46 $ 48 Interest cost 5,817 5,627 116 119 Expected return on assets (7,167 ) (7,224 ) (149 ) (153 ) Amortization of: Prior service cost (benefit) 87 87 (160 ) (160 ) Actuarial loss 2,393 2,198 24 32 Net benefit cost (income) 2,862 2,429 (123 ) (114 ) Change in associated regulatory liabilities — — 878 937 Net benefit cost after change in regulatory liabilities $ 2,862 $ 2,429 $ 755 $ 823

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of Financial Assets and Financial Liabilities that are Measured at Fair Value on a Recurring Basis	The following table presents on a gross basis our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of December 31, 2015 , September 30, 2015 and December 31, 2014 : Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2015: Assets: Commodity contracts $ 234 $ — $ — $ 234 Interest rate contracts $ — $ 572 $ — $ 572 Liabilities: Commodity contracts $ (4,986 ) $ (1,557 ) $ — $ (6,543 ) Interest rate contracts $ — $ (4,380 ) $ — $ (4,380 ) September 30, 2015: Assets: Commodity contracts $ 934 $ 373 $ — $ 1,307 Liabilities: Commodity contracts $ (4,560 ) $ (1,388 ) $ — $ (5,948 ) Interest rate contracts $ — $ (7,016 ) $ — $ (7,016 ) December 31, 2014: Assets: Commodity contracts $ — $ 177 $ — $ 177 Liabilities: Commodity contracts $ (7,355 ) $ (2,600 ) $ — $ (9,955 )

Derivative Instruments and He25

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Balance Sheet Location and Fair Value of Derivative Assets and Liabilities	The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of December 31, 2015 and 2014 : December 31, 2015 December 31, 2014 Derivative assets: Derivatives designated as hedging instruments: Interest rate contracts $ 572 $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts 234 177 Total derivative assets - gross 806 177 Gross amounts offset in the balance sheet (572 ) (177 ) Total derivative assets - net $ 234 $ — Derivative liabilities: Derivatives designated as hedging instruments: Interest rate contracts $ (4,380 ) $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts (6,278 ) (9,398 ) Derivatives not subject to PGC and DS mechanisms: Commodity contracts (265 ) (557 ) Total derivative liabilities - gross (10,923 ) (9,955 ) Gross amounts offset in the balance sheet 572 177 Total derivative liabilities - net $ (10,351 ) $ (9,778 )
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 not subject to ratemaking mechanisms on the Condensed Consolidated Statements of Income and changes in AOCI for the three months ended December 31, 2015 and 2014 : Gain (Loss) Recognized in AOCI Gain (Loss) Reclassified from AOCI into Income Location of Gain Three Months Ended December 31, 2015 2014 2015 2014 Cash Flow Hedges: Interest rate contracts $ 3,209 $ — $ (666 ) $ (669 ) Interest expense Gain (Loss) Recognized in Income Location of Gain (Loss) Recognized in Income Three Months Ended December 31, 2015 2014 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ (65 ) $ (522 ) Operating expenses/other operating income, net

Accumulated Other Comprehensi26

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Schedule of Changes in Accumulated Other Comprehensive Income	The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2015 and 2014 : Postretirement Benefit Plans Derivative Instruments Total Three Months Ended December 31, 2015 AOCI - September 30, 2015 $ (9,276 ) $ (4,410 ) $ (13,686 ) Net gains on IRPAs — 1,877 1,877 Reclassifications of benefit plan actuarial losses and prior service costs 160 — 160 Reclassifications of net losses on IRPAs — 390 390 AOCI - December 31, 2015 $ (9,116 ) $ (2,143 ) $ (11,259 ) Three Months Ended December 31, 2014 AOCI - September 30, 2014 $ (6,311 ) $ (1,870 ) $ (8,181 ) Reclassifications of benefit plan actuarial losses and prior service costs 131 — 131 Reclassifications of net losses on IRPAs — 391 391 AOCI - December 31, 2014 $ (6,180 ) $ (1,479 ) $ (7,659 )

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Information	Financial information by business segment follows: Three Months Ended December 31, 2015 : Reportable Segments Total Gas Utility Electric Utility Revenues $ 197,982 $ 176,942 $ 21,040 Cost of sales $ 75,439 $ 64,229 $ 11,210 Depreciation and amortization $ 16,701 $ 15,504 $ 1,197 Operating income $ 48,296 $ 45,820 $ 2,476 Interest expense $ 9,494 $ 9,066 $ 428 Income before income taxes $ 38,802 $ 36,754 $ 2,048 Capital expenditures $ 61,464 $ 59,270 $ 2,194 As of December 31, 2015 Total assets (at period end) $ 2,606,299 $ 2,462,508 $ 143,791 Goodwill (at period end) $ 182,145 $ 182,145 $ — Three Months Ended December 31, 2014 : Reportable Segments Total Gas Utility Electric Utility Other Revenues $ 287,306 $ 260,478 $ 26,423 $ 405 Cost of sales $ 143,052 $ 127,208 $ 15,844 $ — Depreciation and amortization $ 15,425 $ 14,280 $ 1,145 $ — Operating income $ 75,640 $ 71,846 $ 3,719 $ 75 Interest expense $ 10,649 $ 10,130 $ 519 $ — Income before income taxes $ 64,991 $ 61,716 $ 3,200 $ 75 Capital expenditures $ 55,029 $ 53,492 $ 1,537 $ — As of December 31, 2014 Total assets (at period end) $ 2,488,621 $ 2,346,169 $ 142,452 $ — Goodwill (at period end) $ 182,145 $ 182,145 $ — $ —

Nature of Operations (Details)

Nature of Operations (Details)	3 Months Ended
	Dec. 31, 2015county
Nature of Operations [Abstract]
Number of counties of operation	1

Inventories (Details)

Inventories (Details) $ in Thousands	3 Months Ended
	Dec. 31, 2015USD ($)agreementBcf	Sep. 30, 2015USD ($)Bcf	Dec. 31, 2014USD ($)Bcf
Public Utilities, Inventory
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet) | Bcf	8.9	9	9.9
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $	$ 22,061	$ 22,694	$ 41,937
SCAAs
Public Utilities, Inventory
Number of storage agreements	2
Term of agreements (in years)	3 years
Number of storage agreements with Energy Services	1
Number of storage agreements with non-affiliates	1
SCAAs | Other Current Liabilities
Public Utilities, Inventory
Security deposit liability | $	$ 15,100	$ 17,700	$ 17,600

Inventories - Schedule of Inven

Inventories - Schedule of Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Public Utilities, Inventory
Total inventories	$ 49,365	$ 51,716	$ 85,429
Gas Utility Natural Gas
Public Utilities, Inventory
Total inventories	35,923	37,510	72,442
Materials, Supplies and Other
Public Utilities, Inventory
Total inventories	$ 13,442	$ 14,206	$ 12,987

Regulatory Assets and Liabili31

Regulatory Assets and Liabilities and Regulatory Matters (Details) - USD ($) $ in Thousands	Jan. 19, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Gas Utility
Regulatory Assets
Fair value of unrealized gains (losses)		$ (4,488)	$ (3,262)	$ (6,798)
Electric Utility
Regulatory Assets
Fair value of unrealized gains (losses)		$ (450)	$ (533)	$ (2,397)
Pennsylvania Public Utility Commission | Subsequent Event
Regulatory Assets
Requested operating revenue increase	$ 58,600
Estimated time period for regulatory approval (in months)	9 months

Regulatory Assets and Liabili32

Regulatory Assets and Liabilities and Regulatory Matters - Schedule of Regulatory Assets and Liabilities Associated With Gas Utility and Electric Utility (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Regulatory Assets and Liabilities
Regulatory Assets		$ 301,819	$ 304,208	$ 270,599
Regulatory Liabilities	[1]	63,182	71,004	32,888
Postretirement Benefits
Regulatory Assets and Liabilities
Regulatory Liabilities		20,314	19,975	18,959
Deferred Fuel and Power Refunds
Regulatory Assets and Liabilities
Regulatory Liabilities		28,083	36,638	0
State Tax Benefits -- Distribution System Repairs
Regulatory Assets and Liabilities
Regulatory Liabilities		13,712	13,266	10,349
Other
Regulatory Assets and Liabilities
Regulatory Liabilities		1,073	1,125	3,580
Income Taxes Recoverable
Regulatory Assets and Liabilities
Regulatory Assets		117,396	115,946	111,075
Underfunded Pension and Postretirement Plans
Regulatory Assets and Liabilities
Regulatory Assets		138,294	140,762	107,827
Environmental Costs
Regulatory Assets and Liabilities
Regulatory Assets		17,643	19,983	14,738
Deferred Fuel and Power Costs
Regulatory Assets and Liabilities
Regulatory Assets		0	0	16,761
Removal Costs, Net
Regulatory Assets and Liabilities
Regulatory Assets		22,346	21,223	17,550
Other
Regulatory Assets and Liabilities
Regulatory Assets		$ 6,140	$ 6,294	$ 2,648
[1]	Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and noncurrent liabilities in the Condensed Consolidated Balance Sheets.

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($)	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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	$ 11,679,000	$ 11,233,000
Environmental Issue
Commitments and Contingencies
Base year for determination of investigation and remediation cost (in years)	5 years
CPG MGP
Commitments and Contingencies
Environmental remediation expense	$ 1,800,000
PNG MGP
Commitments and Contingencies
Environmental remediation expense	$ 1,100,000

Defined Benefit Pension and O34

Defined Benefit Pension and Other Postretirement Plans (Details) - USD ($)	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure
Contribution made to Pension Plan	$ 2,467,000	$ 2,783,000
Expected contribution to pensions plans in the remainder of current fiscal year	7,400,000
VEBA
Defined Benefit Plan Disclosure
Contribution made to Pension Plan	$ 0	$ 0

Defined Benefit Pension and O35

Defined Benefit Pension and Other Postretirement Plans - Schedule of Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 1,732	$ 1,741
Interest cost	5,817	5,627
Expected return on assets	(7,167)	(7,224)
Amortization of:
Prior service cost (benefit)	87	87
Actuarial loss	2,393	2,198
Net benefit cost (income)	2,862	2,429
Change in associated regulatory liabilities	0	0
Net benefit cost after change in regulatory liabilities	2,862	2,429
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	46	48
Interest cost	116	119
Expected return on assets	(149)	(153)
Amortization of:
Prior service cost (benefit)	(160)	(160)
Actuarial loss	24	32
Net benefit cost (income)	(123)	(114)
Change in associated regulatory liabilities	878	937
Net benefit cost after change in regulatory liabilities	$ 755	$ 823

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Carrying amount of long-term debt	$ 550,000	$ 642,000
Estimated fair value of long-term debt	$ 615,213	$ 741,853

Fair Value Measurements - Finan

Fair Value Measurements - Financial Assets and Financial Liabilities That are Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Assets:
Derivative assets	$ 806		$ 177
Liabilities:
Derivative liabilities	(10,923)		(9,955)
Fair Value, Measurements, Recurring | Commodity Contracts
Assets:
Derivative assets	234	$ 1,307	177
Liabilities:
Derivative liabilities	(6,543)	(5,948)	(9,955)
Fair Value, Measurements, Recurring | Interest rate contracts
Assets:
Derivative assets	572
Liabilities:
Derivative liabilities	(4,380)	(7,016)
Fair Value, Measurements, Recurring | Level 1 | Commodity Contracts
Assets:
Derivative assets	234	934	0
Liabilities:
Derivative liabilities	(4,986)	(4,560)	(7,355)
Fair Value, Measurements, Recurring | Level 1 | Interest rate contracts
Assets:
Derivative assets	0
Liabilities:
Derivative liabilities	0	0
Fair Value, Measurements, Recurring | Level 2 | Commodity Contracts
Assets:
Derivative assets	0	373	177
Liabilities:
Derivative liabilities	(1,557)	(1,388)	(2,600)
Fair Value, Measurements, Recurring | Level 2 | Interest rate contracts
Assets:
Derivative assets	572
Liabilities:
Derivative liabilities	(4,380)	(7,016)
Fair Value, Measurements, Recurring | Level 3 | Commodity Contracts
Assets:
Derivative assets	0	0	0
Liabilities:
Derivative liabilities	0	0	$ 0
Fair Value, Measurements, Recurring | Level 3 | Interest rate contracts
Assets:
Derivative assets	0
Liabilities:
Derivative liabilities	$ 0	$ 0

Derivative Instruments and He38

Derivative Instruments and Hedging Activities (Details) kWh in Millions, MMBTU in Millions	3 Months Ended
	Dec. 31, 2015USD ($)kWhMMBTU	Dec. 31, 2014USD ($)kWhMMBTU	Sep. 30, 2015USD ($)
Derivative
Restricted cash in brokerage accounts	$ 6,324,000	$ 8,963,000	$ 6,602,000
Gas Utility
Derivative
Notional amount (energy measure) | MMBTU	12.4	11.2
Maximum length of time hedged in price risk cash flow hedges (in months)	9 months
Electric Utility
Derivative
Notional amount (energy measure) | kWh	333.3	486.2
Maximum length of time hedged in price risk cash flow hedges (in months)	11 months
Electric Utility | Electric Utility Electric Transmission Congestion
Derivative
Notional amount (energy measure) | kWh	172.6	144.6
Maximum length of time hedged in price risk cash flow hedges (in months)	5 months
Interest Rate Protection Agreements
Derivative
Notional Amount	$ 290,000,000	$ 0
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	$ 2,200,000
Minimum | Interest Rate Protection Agreements
Derivative
Duration of forecasted interest payments covered by unsettled hedges (in years)	10 years
Maximum [Member] | Interest Rate Protection Agreements
Derivative
Duration of forecasted interest payments covered by unsettled hedges (in years)	30 years

Derivative Instruments and He39

Derivative Instruments and Hedging Activities - Balance Sheet Location and Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative assets:
Derivative assets	$ 806	$ 177
Gross amounts offset in the balance sheet	(572)	(177)
Total derivative assets - net	234	0
Derivative liabilities:
Derivative liabilities	(10,923)	(9,955)
Gross amounts offset in the balance sheet	572	177
Total derivative liabilities - net	(10,351)	(9,778)
Commodity Contracts | Derivatives Subject to PGC and DS Mechanisms
Derivative assets:
Derivative assets	234	177
Derivative liabilities:
Derivative liabilities	(6,278)	(9,398)
Commodity Contracts | Derivatives Not Subject To PGC And DS Mechanisms
Derivative liabilities:
Derivative liabilities	(265)	(557)
Derivative assets | Interest rate contracts | Designated as Hedging Instrument
Derivative assets:
Derivative assets	572	0
Derivative liabilities | Interest rate contracts | Designated as Hedging Instrument
Derivative liabilities:
Derivative liabilities	$ (4,380)	$ 0

Derivative Instruments and He40

Derivative Instruments and Hedging Activities - Effects of Derivatives on Statements of Income and AOCI (Details) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivatives Not Subject To PGC And DS Mechanisms | Gasoline Contracts | Operating Expenses/Other Operating Income, Net
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in income	$ (65)	$ (522)
Cash Flow Hedges | Interest rate contracts
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI	3,209	0
Cash Flow Hedges | Interest rate contracts | Interest Expense
Derivative Instruments, Gain (Loss)
Gain (loss) reclassified from AOCI into income	$ (666)	$ (669)

Accumulated Other Comprehensi41

Accumulated Other Comprehensive Income - Schedule of Changes in Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	$ (13,686)	$ (8,181)
Net gains on IRPAs	1,877
Reclassifications, net of tax	160	131
AOCI, net of tax - ending balance	(11,259)	(7,659)
Interest Rate Protection Agreements
Accumulated Other Comprehensive Income (Loss)
Reclassifications, net of tax	390	391
Postretirement Benefit Plans
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(9,276)	(6,311)
Net gains on IRPAs	0
Reclassifications, net of tax	160	131
AOCI, net of tax - ending balance	(9,116)	(6,180)
Postretirement Benefit Plans | Interest Rate Protection Agreements
Accumulated Other Comprehensive Income (Loss)
Reclassifications, net of tax	0	0
Derivative Instruments
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(4,410)	(1,870)
Net gains on IRPAs	1,877
Reclassifications, net of tax	0	0
AOCI, net of tax - ending balance	(2,143)	(1,479)
Derivative Instruments | Interest Rate Protection Agreements
Accumulated Other Comprehensive Income (Loss)
Reclassifications, net of tax	$ 390	$ 391

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	3 Months Ended
	Dec. 31, 2015USD ($)Bcf	Dec. 31, 2014USD ($)Bcf	Sep. 30, 2015USD ($)Bcf
Related Party Transaction
Related party costs incurred	$ 2,180	$ 2,782
Energy Services
Related Party Transaction
Revenue from related parties	$ 8,766	16,190
Term of agreements (in years)	1 year
Purchases from related party	$ 8,192	$ 21,775
Inventories | Energy Services
Related Party Transaction
Volume of gas storage inventory (in bcf of natural gas) | Bcf	5.1	6.5	5
Natural gas storage inventory, related parties, current	$ 12,684	$ 27,501	$ 12,889
SCAAs | Energy Services
Related Party Transaction
SCAA contract term (in years)	3 years
Related party costs incurred	$ 1,870	4,956
SCAAs | Other Current Liabilities | Energy Services
Related Party Transaction
Related party security deposits	8,100	10,600	$ 10,700
Exclusive of Transactions Pursuant SCAAs | Energy Services
Related Party Transaction
Related party costs incurred	$ 27,364	$ 23,747

Segment Information (Details)

Segment Information (Details)	3 Months Ended
	Dec. 31, 2015segmentcounty
Segment Reporting Information
Number of reportable segments | segment	2
Number of counties of operation	1
Electric Utility
Segment Reporting Information
Number of counties of operation	2

Segment Information - Schedule

Segment Information - Schedule of Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2015
Segment Reporting Information
Revenues	$ 197,982	$ 287,306
Cost of sales	75,439	143,052
Depreciation and amortization	16,701	15,425
Operating income	48,296	75,640
Interest expense	9,494	10,649
Income before income taxes	38,802	64,991
Capital expenditures	61,464	55,029
Total assets (at period end)	2,606,299	2,488,621	$ 2,508,178
Goodwill (at period end)	182,145	182,145	$ 182,145
Reportable Segments | Gas Utility
Segment Reporting Information
Revenues	176,942	260,478
Cost of sales	64,229	127,208
Depreciation and amortization	15,504	14,280
Operating income	45,820	71,846
Interest expense	9,066	10,130
Income before income taxes	36,754	61,716
Capital expenditures	59,270	53,492
Total assets (at period end)	2,462,508	2,346,169
Goodwill (at period end)	182,145	182,145
Reportable Segments | Electric Utility
Segment Reporting Information
Revenues	21,040	26,423
Cost of sales	11,210	15,844
Depreciation and amortization	1,197	1,145
Operating income	2,476	3,719
Interest expense	428	519
Income before income taxes	2,048	3,200
Capital expenditures	2,194	1,537
Total assets (at period end)	143,791	142,452
Goodwill (at period end)	$ 0	0
Other
Segment Reporting Information
Revenues		405
Cost of sales		0
Depreciation and amortization		0
Operating income		75
Interest expense		0
Income before income taxes		75
Capital expenditures		0
Total assets (at period end)		0
Goodwill (at period end)		$ 0