Ugi Utilities Inactive 10-Q6 Feb 182018 Q1 Quarterly reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
Document and Entity Information - shares	Dec. 31, 2017	Jan. 31, 2018
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, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,018
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, 2017	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 7,289	$ 5,203	$ 9,838
Restricted cash	3,665	3,046	0
Accounts receivable (less allowances for doubtful accounts of $6,398, $4,052 and $5,518, respectively)	105,141	53,720	97,188
Accounts receivable — related parties	1,406	2,807	1,886
Accrued utility revenues	95,854	13,296	55,616
Inventories	49,717	53,309	39,693
Prepaid income taxes	1,977	7,711	2,013
Regulatory assets	605	8,338	1,635
Derivative instruments	678	1,354	7,077
Prepaid expenses & other current assets	23,066	16,406	26,131
Total current assets	289,398	165,190	241,077
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $1,026,450, $1,010,781 and $987,850, respectively)	2,327,664	2,274,548	2,071,718
Goodwill	182,145	182,145	182,145
Regulatory assets	362,237	360,591	391,229
Other assets	13,249	11,541	12,354
Total assets	3,174,693	2,994,015	2,898,523
Current liabilities:
Current maturities of long-term debt	144,374	39,996	39,981
Short-term borrowings	181,500	170,000	98,400
Accounts payable	69,697	71,559	70,703
Accounts payable — related parties	13,420	6,890	11,385
Regulatory liabilities	17,091	12,988	25,830
Derivative instruments	2,244	1,071	295
Other current liabilities	106,177	110,978	113,468
Total current liabilities	534,503	413,482	360,062
Long-term debt	711,242	711,105	731,030
Deferred income taxes	340,772	635,465	566,519
Deferred investment tax credits	2,870	2,950	3,189
Pension and postretirement benefit obligations	140,224	143,674	181,809
Regulatory liabilities, Noncurrent	340,391	36,242	32,838
Other noncurrent liabilities	62,670	63,192	63,340
Total liabilities	2,132,672	2,006,110	1,938,787
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	473,580	473,580	473,580
Retained earnings	534,161	480,857	456,781
Accumulated other comprehensive loss	(25,979)	(26,791)	(30,884)
Total common stockholder’s equity	1,042,021	987,905	959,736
Total liabilities and stockholder’s equity	$ 3,174,693	$ 2,994,015	$ 2,898,523

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 6,398	$ 4,052	$ 5,518
Accumulated depreciation and amortization	$ 1,026,450	$ 1,010,781	$ 987,850
Common stock, par value (in usd per share)	$ 2.25	$ 2.25	$ 2.25
Common stock, shares authorized (in shares)	40,000,000	40,000,000	40,000,000
Common stock, shares issued (in shares)	26,781,785	26,781,785	26,781,785
Common stock, shares outstanding (in shares)	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, 2017	Dec. 31, 2016
Income Statement [Abstract]
Revenues	$ 323,105	$ 261,413
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	151,774	109,471
Operating and administrative expenses	51,984	49,716
Operating and administrative expenses — related parties	2,689	2,564
Depreciation and amortization	20,354	17,391
Other operating expense, net	9	35
Total costs and expenses	226,810	179,177
Operating income	96,295	82,236
Interest expense	10,939	10,028
Income before income taxes	85,356	72,208
Income taxes	17,053	27,943
Net income	$ 68,303	$ 44,265

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 68,303	$ 44,265
Other comprehensive income:
Reclassifications of net losses on derivative instruments (net of tax of $(279) and $(351), respectively)	592	495
Benefit plans reclassifications of actuarial losses and net prior service credits (net of tax of $(104) and $(169), respectively)	220	239
Other comprehensive income	812	734
Comprehensive income	$ 69,115	$ 44,999

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net losses on derivative instruments, tax	$ 0	$ 0
Reclassifications of net losses on derivative instruments, tax	(279)	(351)
Benefit plans reclassifications of actuarial losses and prior service costs, tax	$ (104)	$ (169)

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 68,303	$ 44,265
Adjustments to reconcile net income to net cash (used) provided by operating activities:
Depreciation and amortization	20,354	17,391
Deferred income tax expense	4,328	14,049
Provision for uncollectible accounts	3,459	2,442
Other, net	1,161	4,117
Net change in:
Accounts receivable and accrued utility revenues	(136,036)	(99,289)
Inventories	3,592	2,647
Deferred fuel and power costs, net of changes in unsettled derivatives	11,572	(1,000)
Accounts payable	21,655	19,358
Other current assets	(6,661)	(4,122)
Other current liabilities	1,172	4,888
Net cash (used) provided by operating activities	(7,101)	4,746
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(88,686)	(69,639)
Net costs of property, plant and equipment disposals	(2,382)	(4,061)
(Increase) decrease in restricted cash	(619)	583
Net cash used by investing activities	(91,687)	(73,117)
CASH FLOWS FROM FINANCING ACTIVITIES
Payments of dividends	(15,000)	(10,000)
Issuances of long-term debt, net of issuance costs	124,374	99,490
Repayments of long-term debt	(20,000)	0
Increase (decrease) in short-term borrowings	11,500	(14,100)
Net cash provided by financing activities	100,874	75,390
Cash and cash equivalents increase	2,086	7,019
CASH AND CASH EQUIVALENTS
End of period	7,289	9,838
Beginning of period	5,203
Increase	$ 2,086	$ 7,019

Nature of Operations

Nature of Operations	3 Months Ended
Nature of Operations	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [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 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.” The term “UGI Utilities” is used herein as an abbreviated reference to UGI Utilities, Inc., or collectively to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2017
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 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, 2017 , 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, 2017 (“the Company’s 2017 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 on the condensed consolidated balance sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception. 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 UGI Utilities (for which NPNS has not been elected) to hedge commodity prices are included in regulatory assets and liabilities. From time to time we enter into derivative instruments that are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative financial instruments are recorded in accumulated other comprehensive income (loss) (“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 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. We do not currently have derivative instruments that are designated and qualify as cash flow hedges. 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 11 . Use of Estimates. The preparation of financial statements 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. Reclassifications. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

Accounting Changes

Accounting Changes	3 Months Ended
Accounting Changes	Dec. 31, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Note 3 — Accounting Changes Accounting Standards Not Yet Adopted Pension and Other Postretirement Benefit Costs. In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 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. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue. The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.

Inventories

Inventories	3 Months Ended
Inventories	Dec. 31, 2017
Inventory Disclosure [Abstract]
Inventories	Note 4 — Inventories Inventories comprise the following: December 31, 2017 September 30, 2017 December 31, 2016 Gas Utility natural gas $ 34,587 $ 39,486 $ 25,777 Materials, supplies and other 15,130 13,823 13,916 Total inventories $ 49,717 $ 53,309 $ 39,693 At December 31, 2017 , UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) which have terms of up to three years. Four of the SCAAs were with UGI Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 13 ) and one of the SCAAs was 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 values of gas storage inventories released under the SCAAs at December 31, 2017 , September 30, 2017 and December 31, 2016 , comprising 7.8 billion cubic feet (“bcf”), 9.1 bcf and 7.8 bcf of natural gas, were $22,191 , $26,064 and $17,700 , respectively. At December 31, 2017 , September 30, 2017 and December 31, 2016 , UGI Utilities held a total of $13,840 , $15,040 and $15,000 , respectively, of security deposits received 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 13 .

Income Taxes (Notes)

Income Taxes (Notes)	3 Months Ended
Income Taxes (Notes)	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax Disclosure	Note 5 — Income Tax Reform On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was enacted into law. The significant changes resulting from the law that impact UGI Utilities include a reduction in the U.S. federal income tax rate from 35% to 21% effective January 1, 2018 (resulting in a blended rate of 24.5% for Fiscal 2018) and the elimination of bonus depreciation for regulated utilities. In accordance with GAAP as determined by ASC 740, “Income Taxes,” we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three months ended December 31, 2017, contain provisional estimates of the impact of the TCJA. These amounts are considered provisional because they use estimates for which tax returns have not yet been filed and because estimated amounts may be impacted by future regulatory and accounting guidance if and when issued. We will adjust these provisional amounts as further information becomes available and as we refine our calculations. As permitted by recent guidance issued by the SEC, these adjustments will occur during a reasonable “measurement period” not to exceed twelve months from the date of enactment. As a result, during the three months ended December 31, 2017, we reduced our net deferred income tax liabilities by $223,660 due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of enactment. Because a significant amount of the reduction relates to our regulated utility plant assets, most of the reduction to our excess deferred income taxes is not being recognized immediately in income tax expense. During the three months ended December 31, 2017, the amount of the reduction in our net deferred income tax liabilities that reduced income tax expense totaled $8,122 . In order for utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred income taxes be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. At December 31, 2017, we have recorded a regulatory liability of $216,098 associated with the excess deferred federal income taxes related to our regulated utility plant assets. This regulatory liability has been increased, and a federal deferred income tax asset has been recorded, in the amount of $87,803 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. For further information on this regulatory liability, see Note 6 to condensed consolidated financial statements. For the three months ended December 31, 2017, we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rate. We are subject to a blended federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contains the effective date of the rate change from 35% to 21% on January 1, 2018. As a result, the U.S. federal income tax rate included in our estimated annual effective tax rate is based on this 24.5% blended rate for Fiscal 2018. The PUC has not issued any orders with respect to the lower income tax rate. Our estimated annual effective tax rate for Fiscal 2018 does not reflect the impact of any regulatory action that may be taken by the PUC with respect to the TCJA.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities and Regulatory Matters	3 Months Ended
Regulatory Assets and Liabilities and Regulatory Matters	Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities and Regulatory Matters	Note 6 — 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 2017 Annual Report. Other than removal costs, UGI Utilities currently does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with UGI Utilities are included in the accompanying condensed consolidated balance sheets: December 31, 2017 September 30, 2017 December 31, 2016 Regulatory assets: Income taxes recoverable $ 126,509 $ 121,421 $ 117,777 Underfunded pension and postretirement plans 138,287 141,310 179,364 Environmental costs 60,760 61,566 61,437 Deferred fuel and power costs 108 7,685 — Removal costs, net 31,426 30,996 27,062 Other 5,752 5,951 7,224 Total regulatory assets $ 362,842 $ 368,929 $ 392,864 Regulatory liabilities: Postretirement benefits $ 17,315 $ 17,493 $ 17,259 Deferred fuel and power refunds 12,658 10,621 23,809 State tax benefits — distribution system repairs 19,101 18,430 15,579 Excess federal deferred income taxes (a) 303,901 — — Other 4,507 2,686 2,021 Total regulatory liabilities $ 357,482 $ 49,230 $ 58,668 (a) Balance at December 31, 2017 , comprises excess federal deferred income taxes resulting from the enactment of the TCJA (see below and Note 5 ). Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that 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 (losses) gains on such contracts at December 31, 2017 , September 30, 2017 , and December 31, 2016 , were $(1,720) , $146 and $6,927 , respectively. 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, 2017 , September 30, 2017 , and December 31, 2016 , were not material. Excess federal deferred income taxes. This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 5 ). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that these excess federal deferred income taxes be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess federal deferred income taxes, ranging from 1 year to approximately 65 years . This regulatory liability has been increased to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. This regulatory liability will be amortized and credited to tax expense. Other Regulatory Matters Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PUC to increase its annual base distribution revenues by $9,200 . The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. Electric Utility requested that the new electric rates become effective March 27, 2018, although 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 up to nine months; however, the Company cannot predict the timing or the ultimate outcome of the rate case review process. On August 31, 2017, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for an $11,250 annual base distribution rate increase for PNG. The increase became effective on October 20, 2017. On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27,000 annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016. Distribution System Improvement Charge. State legislation permits gas and electric utilities in Pennsylvania to recover a distribution system improvement charge (“DSIC”) on eligible capital investments as an alternative ratemaking mechanism providing for a more-timely cost recovery of qualifying capital expenditures between base rate cases. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero , in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In May 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018. PNG’s DSIC has been reset to zero as a result of its most recent rate case. The DSIC rate for PNG will resume upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its recent base rate case. In November 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.

Debt

Debt	3 Months Ended
Debt	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Note 7 — Debt On October 31, 2017, UGI Utilities entered into a $125,000 unsecured variable-rate term loan agreement (the “Term Loan”) with a group of banks which initially matures on October 30, 2018. Such maturity will be automatically extended to October 30, 2022, after UGI Utilities receives a securities certificate from the PUC authorizing issuance of the security and upon delivery of such certificate to the agent. Proceeds from the Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Term Loan is payable in equal quarterly installments of $1,563 with the balance of the principal being due and payable in full on the maturity date. Under the Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The Term Loan requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. Because UGI Utilities has not yet received a securities certificate from the PUC authorizing the extension of the maturity date to October 30, 2022, the Term Loan has been reflected in “ Current maturities of long-term debt ” on the December 31, 2017 , Condensed Consolidated Balance Sheet.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
Commitments and Contingencies	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 8 — Commitments and Contingencies Contingencies From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of manufactured gas plants (“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 also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into a consent order and agreement (“COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2,500 , $1,750 , and $1,100 , for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively. At December 31, 2017 , September 30, 2017 and December 31, 2016 , our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $53,409 , $54,250 , and $55,300 , respectively. UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 6 ). UGI Utilities does not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Utilities, CPG and PNG receive ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. 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 a former subsidiary. 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 a former subsidiary 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. At December 31, 2017 , September 30, 2017 and December 31, 2016 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material. Other Matters Manor Township, Pennsylvania Natural Gas Explosion. On July 2, 2017, an explosion occurred in Manor Township, Pennsylvania which resulted in the death of a Company employee, significant injuries to two other Company employees and an employee of the local sewer authority, and significant property damage. The National Transportation Safety Board (“NTSB”), the Occupational Safety and Health Administration (“OSHA”) and the PUC are investigating the Manor Township incident. The NTSB investigative team includes representatives from the Company, the PUC, the local fire department and the Pipeline and Hazardous Materials Safety Administration and the Company is cooperating with the investigation. The Company continues to provide information requested by the investigating parties. While the investigation into this incident is still underway and the cause of the explosion has not been determined, the Company has received claims as a result of the explosion and may become involved in lawsuits relative to the incident. The Company maintains workers’ compensation insurance and liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of the Company’s deductible, are expected to be recovered through the Company’s insurance. Although the Company cannot predict the result of these pending or future claims, we believe that claims and expenses associated with the explosion will not have a material impact on our consolidated financial statements. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial statements.

Defined Benefit Pension and Oth

Defined Benefit Pension and Other Postretirement Plans	3 Months Ended
Defined Benefit Pension and Other Postretirement Plans	Dec. 31, 2017
Defined Benefit Plan [Abstract]
Defined Benefit Pension and Other Postretirement Plans	Note 9 — 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 (“Other Postretirement Plans”). Net periodic pension expense and other postretirement benefit costs include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended December 31, 2017 2016 2017 2016 Service cost $ 1,881 $ 2,023 $ 67 $ 61 Interest cost 5,767 5,539 112 108 Expected return on assets (7,777 ) (7,497 ) (177 ) (164 ) Amortization of: Prior service cost (benefit) 63 81 (110 ) (160 ) Actuarial loss 2,984 3,707 24 28 Net benefit cost (benefit) 2,918 3,853 (84 ) (127 ) Change in associated regulatory liabilities — — (123 ) (122 ) Net benefit cost (benefit) after change in regulatory liabilities $ 2,918 $ 3,853 $ (207 ) $ (249 ) 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, UGI Corporation Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. During the three months ended December 31, 2017 and 2016 , the Company made contributions to the Pension Plan of $3,359 and $2,849 , respectively. The Company expects to make additional discretionary cash contributions of approximately $10,077 to the Pension Plan during the remainder of Fiscal 2018 . 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. The difference between such amount and the amounts included in UGI Gas’ and Electric Utility’s rates, if any, 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, 2017 and 2016 . 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
Fair Value Measurements	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 10 — 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, 2017 , September 30, 2017 and December 31, 2016 : Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2017: Assets: Commodity contracts $ 678 $ 19 $ — $ 697 Liabilities: Commodity contracts $ (2,151 ) $ (112 ) $ — $ (2,263 ) September 30, 2017: Assets: Commodity contracts $ 1,735 $ 72 $ — $ 1,807 Liabilities: Commodity contracts $ (1,447 ) $ (73 ) $ — $ (1,520 ) December 31, 2016: Assets: Commodity contracts $ 7,077 $ — $ — $ 7,077 Liabilities: Commodity contracts $ — $ (295 ) $ — $ (295 ) 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, 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. 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). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at December 31, 2017 , September 30, 2017 and December 31, 2016 were as follows: December 31, 2017 September 30, 2017 December 31, 2016 Carrying amount $ 860,000 $ 755,000 $ 775,000 Estimated fair value $ 909,283 $ 791,378 $ 800,504

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
Derivative Instruments and Hedging Activities	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 11 — Derivative Instruments and Hedging Activities We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk 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, 2017 , September 30, 2017 and December 31, 2016 , the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.4 million dekatherms, 14.8 million dekatherms and 11.7 million dekatherms, respectively. At December 31, 2017 , 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 natural gas option contracts are recorded in regulatory assets or liabilities on the condensed consolidated balance sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 6 ). Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At December 31, 2017 , September 30, 2017 and December 31, 2016 , all Electric Utility forward electricity purchase contracts were subject to the NPNS exception. 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 on the condensed consolidated balance sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6 ). At December 31, 2017 , September 30, 2017 and December 31, 2016 , the total volumes associated with FTRs totaled 63.1 million kilowatt hours, 101.2 million kilowatt hours and 36.2 million kilowatt hours, respectively. At December 31, 2017 , 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 contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. At December 31, 2017 , September 30, 2017 and December 31, 2016 , the total volumes associated with gasoline futures contracts were not material. 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, 2017 , September 30, 2017 and December 31, 2016 , we had no unsettled IRPAs. At December 31, 2017 , the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,485 . Derivative Instrument Credit Risk Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2017 and September 30, 2017 , restricted cash in brokerage accounts totaled $3,665 and $3,046 , respectively. At December 31, 2016 , there were no such amounts. Offsetting Derivative Assets and Liabilities Derivative assets and liabilities are presented net by counterparty on the 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 the 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, 2017 , September 30, 2017 and December 31, 2016 : December 31, 2017 September 30, 2017 December 31, 2016 Derivative assets: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ 450 $ 1,665 $ 6,926 Derivatives not subject to PGC and DS mechanisms: Commodity contracts 247 142 151 Total derivative assets — gross 697 1,807 7,077 Gross amounts offset in the balance sheet (19 ) (450 ) — Total derivative assets — net (a) $ 678 $ 1,357 $ 7,077 Derivative liabilities: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ (2,263 ) $ (1,520 ) $ (295 ) Total derivative liabilities — gross (2,263 ) (1,520 ) (295 ) Gross amounts offset in the balance sheet 19 450 — Total derivative liabilities — net (a) $ (2,244 ) $ (1,070 ) $ (295 ) (a) Derivative assets and liabilities with maturities greater than one year are recorded in “ Other assets ” and “ Other noncurrent liabilities ” on the Condensed Consolidated Balance Sheets. 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, 2017 and 2016 : Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Three Months Ended December 31, 2017 2016 Cash Flow Hedges: Interest rate contracts $ (871 ) $ (846 ) Interest expense Gain Recognized in Income Location of Gain Recognized in Income Three Months Ended December 31, 2017 2016 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ 149 $ 130 Operating and administrative expenses 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 NPNS exception accounting 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
Accumulated Other Comprehensive Income	Dec. 31, 2017
Equity [Abstract]
Accumulated Other Comprehensive Income	Note 12 — Accumulated Other Comprehensive Income The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2017 and 2016 : Three Months Ended December 31, 2017 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2017 $ (8,995 ) $ (17,796 ) $ (26,791 ) Reclassifications of benefit plans actuarial losses and net prior service credits 220 — 220 Reclassifications of net losses on IRPAs — 592 592 AOCI — December 31, 2017 $ (8,775 ) $ (17,204 ) $ (25,979 ) Three Months Ended December 31, 2016 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2016 $ (11,834 ) $ (19,784 ) $ (31,618 ) Reclassifications of benefit plans actuarial losses and net prior service credits 239 — 239 Reclassifications of net losses on IRPAs — 495 495 AOCI — December 31, 2016 $ (11,595 ) $ (19,289 ) $ (30,884 )

Related Party Transactions

Related Party Transactions	3 Months Ended
Related Party Transactions	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Note 13 — 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 totaled $1,046 and $1,169 during the three months ended December 31, 2017 and 2016 , respectively. 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. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $3,101 and $2,294 during the three months ended December 31, 2017 and 2016 , respectively. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. These payments totaled $718 and $564 during the three months ended December 31, 2017 and 2016 , respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets, at December 31, 2017 , September 30, 2017 and December 31, 2016 , were $11,040 , $11,040 , and $11,000 , 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) in “Inventories” on the Condensed Consolidated Balance Sheets. The carrying values of these gas storage inventories at December 31, 2017 , September 30, 2017 and December 31, 2016 , comprising approximately 6.1 bcf, 6.8 bcf and 5.9 bcf of natural gas, were $17,043 , $19,323 and $12,851 , 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, 2017 and 2016 totaled $34,588 and $30,510 , respectively. From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2017 and 2016 , revenues associated with such sales to Energy Services totaled $21,147 and $10,972 , respectively. Also from time to time, UGI Utilities 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, 2017 and 2016 , such purchases totaled $37,597 and $22,023 , respectively.

Segment Information

Segment Information	3 Months Ended
Segment Information	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information	Note 14 — 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 and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s 2017 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: Reportable Segments Three Months Ended December 31, 2017 Total Gas Utility Electric Utility Revenues $ 323,105 $ 299,965 $ 23,140 Cost of sales — gas, fuel and purchased power $ 151,774 $ 138,858 $ 12,916 Depreciation and amortization $ 20,354 $ 19,000 $ 1,354 Operating income $ 96,295 $ 93,681 $ 2,614 Interest expense $ 10,939 $ 10,526 $ 413 Income before income taxes $ 85,356 $ 83,155 $ 2,201 Capital expenditures (including the effects of accruals) $ 71,699 $ 68,842 $ 2,857 As of December 31, 2017 Total assets $ 3,174,693 $ 3,038,250 $ 136,443 Goodwill $ 182,145 $ 182,145 $ — Reportable Segments Three Months Ended December 31, 2016 Total Gas Utility Electric Utility Revenues $ 261,413 $ 237,100 $ 24,313 Cost of sales — gas, fuel and purchased power $ 109,471 $ 95,567 $ 13,904 Depreciation and amortization $ 17,391 $ 16,155 $ 1,236 Operating income $ 82,236 $ 78,967 $ 3,269 Interest expense $ 10,028 $ 9,583 $ 445 Income before income taxes $ 72,208 $ 69,384 $ 2,824 Capital expenditures (including the effects of accruals) $ 64,096 $ 61,742 $ 2,354 As of December 31, 2016 Total assets $ 2,898,523 $ 2,736,908 $ 161,615 Goodwill $ 182,145 $ 182,145 $ —

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	3 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation. Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or the “Company”). We eliminate 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.
Derivative Instruments	Derivative Instruments Derivative instruments are reported on the condensed consolidated balance sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception. 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 UGI Utilities (for which NPNS has not been elected) to hedge commodity prices are included in regulatory assets and liabilities. From time to time we enter into derivative instruments that are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative financial instruments are recorded in accumulated other comprehensive income (loss) (“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 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. We do not currently have derivative instruments that are designated and qualify as cash flow hedges. 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 11 .
Use of Estimates	Use of Estimates. The preparation of financial statements 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.
Reclassifications	Reclassifications. Certain prior-period amounts have been reclassified to conform to the current-period presentation.
Adoption of New Accounting Standard and Accounting Standards Not Yet Adopted	Accounting Standards Not Yet Adopted Pension and Other Postretirement Benefit Costs. In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 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. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue. The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.

Inventories (Tables)

Inventories (Tables)	3 Months Ended
Inventories (Tables)	Dec. 31, 2017
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories comprise the following: December 31, 2017 September 30, 2017 December 31, 2016 Gas Utility natural gas $ 34,587 $ 39,486 $ 25,777 Materials, supplies and other 15,130 13,823 13,916 Total inventories $ 49,717 $ 53,309 $ 39,693

Regulatory Assets and Liabili24

Regulatory Assets and Liabilities and Regulatory Matters (Tables)	3 Months Ended
	Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets Associated with Gas Utility and Electric Utility	The following regulatory assets and liabilities associated with UGI Utilities are included in the accompanying condensed consolidated balance sheets: December 31, 2017 September 30, 2017 December 31, 2016 Regulatory assets: Income taxes recoverable $ 126,509 $ 121,421 $ 117,777 Underfunded pension and postretirement plans 138,287 141,310 179,364 Environmental costs 60,760 61,566 61,437 Deferred fuel and power costs 108 7,685 — Removal costs, net 31,426 30,996 27,062 Other 5,752 5,951 7,224 Total regulatory assets $ 362,842 $ 368,929 $ 392,864 Regulatory liabilities: Postretirement benefits $ 17,315 $ 17,493 $ 17,259 Deferred fuel and power refunds 12,658 10,621 23,809 State tax benefits — distribution system repairs 19,101 18,430 15,579 Excess federal deferred income taxes (a) 303,901 — — Other 4,507 2,686 2,021 Total regulatory liabilities $ 357,482 $ 49,230 $ 58,668
Schedule of Regulatory Liabilities Associated with Gas Utility and Electric Utility	The following regulatory assets and liabilities associated with UGI Utilities are included in the accompanying condensed consolidated balance sheets: December 31, 2017 September 30, 2017 December 31, 2016 Regulatory assets: Income taxes recoverable $ 126,509 $ 121,421 $ 117,777 Underfunded pension and postretirement plans 138,287 141,310 179,364 Environmental costs 60,760 61,566 61,437 Deferred fuel and power costs 108 7,685 — Removal costs, net 31,426 30,996 27,062 Other 5,752 5,951 7,224 Total regulatory assets $ 362,842 $ 368,929 $ 392,864 Regulatory liabilities: Postretirement benefits $ 17,315 $ 17,493 $ 17,259 Deferred fuel and power refunds 12,658 10,621 23,809 State tax benefits — distribution system repairs 19,101 18,430 15,579 Excess federal deferred income taxes (a) 303,901 — — Other 4,507 2,686 2,021 Total regulatory liabilities $ 357,482 $ 49,230 $ 58,668

Defined Benefit Pension and O25

Defined Benefit Pension and Other Postretirement Plans (Tables)	3 Months Ended
	Dec. 31, 2017
Defined Benefit Plan [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, 2017 2016 2017 2016 Service cost $ 1,881 $ 2,023 $ 67 $ 61 Interest cost 5,767 5,539 112 108 Expected return on assets (7,777 ) (7,497 ) (177 ) (164 ) Amortization of: Prior service cost (benefit) 63 81 (110 ) (160 ) Actuarial loss 2,984 3,707 24 28 Net benefit cost (benefit) 2,918 3,853 (84 ) (127 ) Change in associated regulatory liabilities — — (123 ) (122 ) Net benefit cost (benefit) after change in regulatory liabilities $ 2,918 $ 3,853 $ (207 ) $ (249 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2017
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, 2017 , September 30, 2017 and December 31, 2016 : Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2017: Assets: Commodity contracts $ 678 $ 19 $ — $ 697 Liabilities: Commodity contracts $ (2,151 ) $ (112 ) $ — $ (2,263 ) September 30, 2017: Assets: Commodity contracts $ 1,735 $ 72 $ — $ 1,807 Liabilities: Commodity contracts $ (1,447 ) $ (73 ) $ — $ (1,520 ) December 31, 2016: Assets: Commodity contracts $ 7,077 $ — $ — $ 7,077 Liabilities: Commodity contracts $ — $ (295 ) $ — $ (295 )
Schedule of Carrying Amount and Estimated Fair Value of Long-term Debt	The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at December 31, 2017 , September 30, 2017 and December 31, 2016 were as follows: December 31, 2017 September 30, 2017 December 31, 2016 Carrying amount $ 860,000 $ 755,000 $ 775,000 Estimated fair value $ 909,283 $ 791,378 $ 800,504

Derivative Instruments and He27

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
Derivative Instruments and Hedging Activities (Tables)	Dec. 31, 2017
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, 2017 , September 30, 2017 and December 31, 2016 : December 31, 2017 September 30, 2017 December 31, 2016 Derivative assets: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ 450 $ 1,665 $ 6,926 Derivatives not subject to PGC and DS mechanisms: Commodity contracts 247 142 151 Total derivative assets — gross 697 1,807 7,077 Gross amounts offset in the balance sheet (19 ) (450 ) — Total derivative assets — net (a) $ 678 $ 1,357 $ 7,077 Derivative liabilities: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ (2,263 ) $ (1,520 ) $ (295 ) Total derivative liabilities — gross (2,263 ) (1,520 ) (295 ) Gross amounts offset in the balance sheet 19 450 — Total derivative liabilities — net (a) $ (2,244 ) $ (1,070 ) $ (295 )
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, 2017 and 2016 : Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Three Months Ended December 31, 2017 2016 Cash Flow Hedges: Interest rate contracts $ (871 ) $ (846 ) Interest expense Gain Recognized in Income Location of Gain Recognized in Income Three Months Ended December 31, 2017 2016 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ 149 $ 130 Operating and administrative expenses

Accumulated Other Comprehensi28

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
Accumulated Other Comprehensive Income (Tables)	Dec. 31, 2017
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, 2017 and 2016 : Three Months Ended December 31, 2017 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2017 $ (8,995 ) $ (17,796 ) $ (26,791 ) Reclassifications of benefit plans actuarial losses and net prior service credits 220 — 220 Reclassifications of net losses on IRPAs — 592 592 AOCI — December 31, 2017 $ (8,775 ) $ (17,204 ) $ (25,979 ) Three Months Ended December 31, 2016 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2016 $ (11,834 ) $ (19,784 ) $ (31,618 ) Reclassifications of benefit plans actuarial losses and net prior service credits 239 — 239 Reclassifications of net losses on IRPAs — 495 495 AOCI — December 31, 2016 $ (11,595 ) $ (19,289 ) $ (30,884 )

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
Segment Information (Tables)	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Information	Financial information by business segment follows: Reportable Segments Three Months Ended December 31, 2017 Total Gas Utility Electric Utility Revenues $ 323,105 $ 299,965 $ 23,140 Cost of sales — gas, fuel and purchased power $ 151,774 $ 138,858 $ 12,916 Depreciation and amortization $ 20,354 $ 19,000 $ 1,354 Operating income $ 96,295 $ 93,681 $ 2,614 Interest expense $ 10,939 $ 10,526 $ 413 Income before income taxes $ 85,356 $ 83,155 $ 2,201 Capital expenditures (including the effects of accruals) $ 71,699 $ 68,842 $ 2,857 As of December 31, 2017 Total assets $ 3,174,693 $ 3,038,250 $ 136,443 Goodwill $ 182,145 $ 182,145 $ — Reportable Segments Three Months Ended December 31, 2016 Total Gas Utility Electric Utility Revenues $ 261,413 $ 237,100 $ 24,313 Cost of sales — gas, fuel and purchased power $ 109,471 $ 95,567 $ 13,904 Depreciation and amortization $ 17,391 $ 16,155 $ 1,236 Operating income $ 82,236 $ 78,967 $ 3,269 Interest expense $ 10,028 $ 9,583 $ 445 Income before income taxes $ 72,208 $ 69,384 $ 2,824 Capital expenditures (including the effects of accruals) $ 64,096 $ 61,742 $ 2,354 As of December 31, 2016 Total assets $ 2,898,523 $ 2,736,908 $ 161,615 Goodwill $ 182,145 $ 182,145 $ —

Nature of Operations (Details)

Nature of Operations (Details)	3 Months Ended
Nature of Operations (Details)	Dec. 31, 2017county
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of counties of operation	1

Inventories - Schedule of Inven

Inventories - Schedule of Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Public Utilities, Inventory
Total inventories	$ 49,717	$ 53,309	$ 39,693
Gas Utility natural gas
Public Utilities, Inventory
Total inventories	34,587	39,486	25,777
Materials, supplies and other
Public Utilities, Inventory
Total inventories	$ 15,130	$ 13,823	$ 13,916

Inventories - Narrative (Detail

Inventories - Narrative (Details) $ in Thousands	3 Months Ended
Inventories - Narrative (Details) $ in Thousands	Dec. 31, 2017USD ($)agreementBcf	Sep. 30, 2017USD ($)Bcf	Dec. 31, 2016USD ($)Bcf
Public Utilities, Inventory
Number of storage agreements	5
Number of storage agreements with Energy Services	4
Number of storage agreements with non-affiliates	1
Volume of gas storage inventories released under SCAAs with non-affiliates (in bcf) \| Bcf	7.8	9.1	7.8
Carrying value of gas storage inventories released under SCAAs with non-affiliates \| $	$ 22,191	$ 26,064	$ 17,700
Security deposit liability \| $	$ 13,840	$ 15,040	$ 15,000
Maximum
Public Utilities, Inventory
Term of agreements (in years)	3 years

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Sep. 30, 2018
Operating Loss Carryforwards [Line Items]
Tax Cuts and Jobs Act of 2017, reduction of net deferred income tax liabilities	$ 223,660
Tax Cuts and Jobs Act of 2017, reduction of income tax expense	8,122
Tax Cuts and Jobs Act of 2017, change in tax rate, provisional unrecognized deferred tax liability	216,098
Increase in regulatory liabilities, excess deferred income taxes	$ 87,803
Scenario, Forecast
Operating Loss Carryforwards [Line Items]
Federal statutory income tax rate		24.50%

Regulatory Assets and Liabili34

Regulatory Assets and Liabilities and Regulatory Matters - Schedule of Regulatory Assets and Liabilities Associated With Gas Utility and Electric Utility (Details) - USD ($) $ in Thousands	Jan. 26, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Regulatory Assets
Regulatory assets		$ 362,842	$ 368,929	$ 392,864
Regulatory Liabilities
Regulatory liabilities		357,482	49,230	58,668
Pension and postretirement benefit obligations		140,224	143,674	181,809
Income taxes recoverable
Regulatory Assets
Regulatory assets		126,509	121,421	117,777
Underfunded pension and postretirement plans
Regulatory Assets
Regulatory assets		138,287	141,310	179,364
Environmental costs
Regulatory Assets
Regulatory assets		60,760	61,566	61,437
Deferred fuel and power costs
Regulatory Assets
Regulatory assets		108	7,685	0
Removal costs, net
Regulatory Assets
Regulatory assets		31,426	30,996	27,062
Other
Regulatory Assets
Regulatory assets		5,752	5,951	7,224
Scenario, Forecast \| Subsequent Event \| Pennsylvania Public Utilities Commission
Regulatory Assets
Requested operating revenue increase	$ 9,200
Postretirement benefits
Regulatory Liabilities
Regulatory liabilities		17,315	17,493	17,259
Deferred fuel and power refunds
Regulatory Liabilities
Regulatory liabilities		12,658	10,621	23,809
State tax benefits — distribution system repairs
Regulatory Liabilities
Regulatory liabilities		19,101	18,430	15,579
Excess federal deferred income taxes (a)
Regulatory Liabilities
Regulatory liabilities		303,901	0	0
Other
Regulatory Liabilities
Regulatory liabilities		$ 4,507	$ 2,686	$ 2,021

Regulatory Assets and Liabili35

Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) - USD ($) $ in Thousands	Oct. 20, 2017	Jul. 01, 2017	Oct. 14, 2016	Apr. 01, 2016	Apr. 01, 2015	Mar. 31, 2016	Dec. 31, 2017	Sep. 30, 2014	Sep. 30, 2017	Dec. 31, 2016
Minimum
Regulatory Assets
Average remaining depreciable lives of associated property.							1 year
Maximum
Regulatory Assets
Average remaining depreciable lives of associated property.							65 years
Pennsylvania PUC
Regulatory Assets
Distribution system improvement charge, percent of amount billed to customers							5.00%
Pennsylvania PUC \| Maximum
Regulatory Assets
Distribution system improvement charge, percent of amount billed to customers								0.00%
Pennsylvania PUC \| PNG
Regulatory Assets
Increase in annual base distribution rate	$ 11,250
Distribution system improvement charge, percent of amount billed to customers		7.50%
Pennsylvania PUC \| PNG \| Maximum
Regulatory Assets
Distribution system improvement charge, percent of amount billed to customers					0.00%
Pennsylvania PUC \| UGI Gas
Regulatory Assets
Increase in annual base distribution rate			$ 27,000
Pennsylvania PUC \| CPG
Regulatory Assets
Distribution system improvement charge, percent of amount billed to customers		7.50%
Pennsylvania PUC \| CPG \| Maximum
Regulatory Assets
Distribution system improvement charge, percent of amount billed to customers				0.00%		10.00%
Gas Utility
Regulatory Assets
Fair value of unrealized gains (losses)							$ (1,720)		$ 146	$ 6,927

Debt (Details)

Debt (Details) - USD ($) $ in Thousands	Oct. 31, 2017	Oct. 31, 2016
Senior Notes \| Senior Notes due October 2046
Debt Instrument [Line Items]
Aggregate principal amount		$ 125,000
Unsecured Debt
Debt Instrument [Line Items]
Debt Instrument, Periodic Payment, Principal	$ 1,563
Minimum \| Unsecured Debt
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.00%
Maximum \| Unsecured Debt
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.875%

Commitments and Contingencies (

Commitments and Contingencies (Details)	3 Months Ended
Commitments and Contingencies (Details)	Dec. 31, 2017USD ($)subsidiary	Sep. 30, 2017USD ($)	Dec. 31, 2016USD ($)
UGI Gas \| Environmental Issue
Loss Contingencies [Line Items]
Environmental expenditures cap during year	$ 2,500,000
CPG MGP \| Environmental Issue
Loss Contingencies [Line Items]
Environmental expenditures cap during year	1,750,000
PNG MGP \| Environmental Issue
Loss Contingencies [Line Items]
Environmental expenditures cap during year	1,100,000
CPG, PNG and UGI Gas COAs
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies	$ 53,409,000	$ 54,250,000	$ 55,300,000
PNG and CPG
Loss Contingencies [Line Items]
Number of subsidiaries acquired with similar histories \| subsidiary	2

Defined Benefit Pension and O38

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, 2017	Dec. 31, 2016
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 1,881	$ 2,023
Interest cost	5,767	5,539
Expected return on assets	(7,777)	(7,497)
Amortization of:
Prior service cost (benefit)	63	81
Actuarial loss	2,984	3,707
Net benefit cost (income)	2,918	3,853
Change in associated regulatory liabilities	0	0
Net benefit cost (benefit) after change in regulatory liabilities	2,918	3,853
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	67	61
Interest cost	112	108
Expected return on assets	(177)	(164)
Amortization of:
Prior service cost (benefit)	(110)	(160)
Actuarial loss	24	28
Net benefit cost (income)	(84)	(127)
Change in associated regulatory liabilities	(123)	(122)
Net benefit cost (benefit) after change in regulatory liabilities	$ (207)	$ (249)

Defined Benefit Pension and O39

Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) - USD ($)	3 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits
Defined Benefit Plan Disclosure
Contribution made to Pension Plan	$ 3,359,000	$ 2,849,000
Expected contribution to pensions plans in the remainder of current fiscal year	10,077,000
VEBA
Defined Benefit Plan Disclosure
Contribution made to Pension Plan	$ 0	$ 0

Fair Value Measurements - Finan

Fair Value Measurements - Financial Assets and Financial Liabilities That are Measured at Fair Value on a Recurring Basis (Details) - Fair Value, Measurements, Recurring - Commodity contracts - USD ($) $ in Thousands	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Assets:
Derivative assets	$ 697	$ 1,807	$ 7,077
Liabilities:
Derivative liabilities	(2,263)	(1,520)	(295)
Level 1
Assets:
Derivative assets	678	1,735	7,077
Liabilities:
Derivative liabilities	(2,151)	(1,447)	0
Level 2
Assets:
Derivative assets	19	72	0
Liabilities:
Derivative liabilities	(112)	(73)	(295)
Level 3
Assets:
Derivative assets	0	0	0
Liabilities:
Derivative liabilities	$ 0	$ 0	$ 0

Fair Value Measurements - Long-

Fair Value Measurements - Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Carrying amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 860,000	$ 755,000	$ 775,000
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 909,283	$ 791,378	$ 800,504

Derivative Instruments and He42

Derivative Instruments and Hedging Activities - Narrative (Details) kWh in Millions, MMBTU in Millions	3 Months Ended
	Dec. 31, 2017USD ($)kWhMMBTU	Sep. 30, 2017USD ($)kWhMMBTU	Dec. 31, 2016USD ($)kWhMMBTU
Derivative
Restricted cash in brokerage accounts	$ 3,665,000	$ 3,046,000	$ 0
IRPAs
Derivative
Notional amount of unsettled IRPA contracts	0	$ 0	$ 0
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	$ (3,485,000)
Gas Utility
Derivative
Notional amount (energy measure) (in mmbtu) \| MMBTU	13.4	14.8	11.7
Maximum length of time hedged in price risk cash flow hedges (in months)	9 months
Electric Utility \| Electric Utility Electric Transmission Congestion
Derivative
Notional amount (energy measure) (in mmbtu) \| kWh	63.1	101.2	36.2
Maximum length of time hedged in price risk cash flow hedges (in months)	5 months

Derivative Instruments and He43

Derivative Instruments and Hedging Activities - Balance Sheet Location and Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Derivative assets
Derivative assets:
Derivative assets	$ 697	$ 1,807	$ 7,077
Gross amounts offset in the balance sheet	(19)	(450)	0
Total derivative assets — net (a)	678	1,357	7,077
Derivative assets \| Derivatives subject to PGC and DS mechanisms \| Commodity contracts
Derivative assets:
Derivative assets	450	1,665	6,926
Derivative assets \| Derivatives not subject to PGC and DS mechanisms \| Commodity contracts
Derivative assets:
Derivative assets	247	142	151
Derivative liabilities
Derivative liabilities:
Derivative liabilities	(2,263)	(1,520)	(295)
Gross amounts offset in the balance sheet	19	450	0
Total derivative liabilities — net (a)	(2,244)	(1,070)	(295)
Derivative liabilities \| Derivatives subject to PGC and DS mechanisms \| Commodity contracts
Derivative liabilities:
Derivative liabilities	$ (2,263)	$ (1,520)	$ (295)

Derivative Instruments and He44

Derivative Instruments and Hedging Activities - Effects of Derivatives on Statements of Income and AOCI (Details) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Derivatives Not Subject To PGC And DS Mechanisms \| Gasoline contracts \| Operating and administrative expenses
Derivative Instruments, Gain (Loss)
Gain Recognized in Income	$ 149	$ 130
Cash Flow Hedges \| Interest rate contracts \| Interest expense
Derivative Instruments, Gain (Loss)
Location of Loss Reclassified from AOCI into Income	$ (871)	$ (846)

Accumulated Other Comprehensi45

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	$ 987,905
Reclassifications, net of tax	220	$ 239
AOCI, net of tax - end balance	1,042,021	959,736
IRPAs
Accumulated Other Comprehensive Income (Loss)
Reclassifications, net of tax	592	495
Postretirement Benefit Plans
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(8,995)	(11,834)
Reclassifications, net of tax	220	239
AOCI, net of tax - end balance	(8,775)	(11,595)
Postretirement Benefit Plans \| IRPAs
Accumulated Other Comprehensive Income (Loss)
Reclassifications, net of tax	0	0
Derivative Instruments
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(17,796)	(19,784)
Reclassifications, net of tax	0	0
AOCI, net of tax - end balance	(17,204)	(19,289)
Derivative Instruments \| IRPAs
Accumulated Other Comprehensive Income (Loss)
Reclassifications, net of tax	592	495
Total
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(26,791)	(31,618)
AOCI, net of tax - end balance	$ (25,979)	$ (30,884)

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	3 Months Ended
Related Party Transactions (Details) $ in Thousands	Dec. 31, 2017USD ($)Bcf	Dec. 31, 2016USD ($)Bcf	Sep. 30, 2017USD ($)Bcf
Related Party Transaction
Related party costs incurred	$ 2,689	$ 2,564
UGI and Subsidiaries \| Administrative Services
Related Party Transaction
Amount of related party transaction	$ 1,046	$ 1,169
Energy Services
Related Party Transaction
Volume of gas storage inventory (in bcf of natural gas) \| Bcf	6.1	5.9	6.8
Natural gas storage inventory, related parties, current	$ 17,043	$ 12,851	$ 19,323
Revenue from related parties	$ 21,147	10,972
Term of agreements (in years)	1 year
Purchases from related party	$ 37,597	22,023
Energy Services \| SCAAs
Related Party Transaction
Amount of related party transaction	$ 718	564
SCAA contract term (in years)	3 years
Related party costs incurred	$ 3,101	2,294
Related party security deposits	11,040	11,000	$ 11,040
Energy Services \| Exclusive of Transactions Pursuant SCAAs
Related Party Transaction
Related party costs incurred	$ 34,588	$ 30,510

Segment Information - Narrative

Segment Information - Narrative (Details)	3 Months Ended
Segment Information - Narrative (Details)	Dec. 31, 2017segmentcounty
Segment Reporting [Abstract]
Number of reportable segments \| segment	2
Segment Reporting Information
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, 2017	Dec. 31, 2016	Sep. 30, 2017
Segment Reporting Information
Revenues	$ 323,105	$ 261,413
Cost of sales — gas, fuel and purchased power	151,774	109,471
Depreciation and amortization	20,354	17,391
Operating income	96,295	82,236
Interest expense	10,939	10,028
Income before income taxes	85,356	72,208
Capital expenditures (including the effects of accruals)	71,699	64,096
Total assets	3,174,693	2,898,523	$ 2,994,015
Goodwill	182,145	182,145	$ 182,145
Gas Utility
Segment Reporting Information
Revenues	299,965	237,100
Cost of sales — gas, fuel and purchased power	138,858	95,567
Depreciation and amortization	19,000	16,155
Operating income	93,681	78,967
Interest expense	10,526	9,583
Income before income taxes	83,155	69,384
Capital expenditures (including the effects of accruals)	68,842	61,742
Total assets	3,038,250	2,736,908
Goodwill	182,145	182,145
Electric Utility
Segment Reporting Information
Revenues	23,140	24,313
Cost of sales — gas, fuel and purchased power	12,916	13,904
Depreciation and amortization	1,354	1,236
Operating income	2,614	3,269
Interest expense	413	445
Income before income taxes	2,201	2,824
Capital expenditures (including the effects of accruals)	2,857	2,354
Total assets	136,443	161,615
Goodwill	$ 0	$ 0