Ugi Utilities 10-Q 8 May 19 2019 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Mar. 31, 2019	Apr. 30, 2019
Document and Entity Information [Abstract]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	0000100548
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
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	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018
Current assets:
Cash and cash equivalents	$ 41,421	$ 10,314	$ 4,710
Restricted cash	837	1,190	1,572
Accounts receivable (less allowances for doubtful accounts of $16,205, $9,760 and $15,582, respectively)	156,634	71,507	169,555
Accounts receivable — related parties	1,999	2,273	1,564
Accrued utility revenues	52,068	13,977	62,343
Inventories	19,942	52,413	19,717
Prepaid income taxes	536	53,857	41
Regulatory assets	1,343	7,475	2,942
Derivative instruments	1,047	3,004	1,014
Prepaid expenses	5,883	9,006	8,746
Other current assets	10,692	8,003	11,451
Total current assets	292,402	233,019	283,655
Property, plant and equipment, at cost (less accumulated depreciation of $1,101,798, $1,074,521 and $1,038,824, respectively)	2,646,983	2,541,768	2,363,373
Goodwill	182,145	182,145	182,145
Regulatory assets	298,026	293,527	358,696
Other assets	18,881	16,117	16,176
Total assets	3,438,437	3,266,576	3,204,045
Current liabilities:
Current maturities of long-term debt	8,546	9,001	6,250
Short-term borrowings	105,000	189,500	135,000
Accounts payable	74,833	87,861	59,870
Accounts payable — related parties	8,881	9,585	11,188
Regulatory liabilities	36,558	40,131	41,154
Other current liabilities	107,722	114,256	126,643
Total current liabilities	341,540	450,334	380,105
Long-term debt	974,779	828,995	827,878
Deferred income taxes	423,377	400,939	339,008
Pension and postretirement benefit obligations	75,626	81,590	136,687
Regulatory liabilities	342,966	350,044	339,567
Other noncurrent liabilities	68,354	61,386	63,784
Total liabilities	2,226,642	2,173,288	2,087,029
Commitments and contingencies (Note 9)
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	704,051	579,778	608,344
Accumulated other comprehensive loss	(26,095)	(20,329)	(25,167)
Total common stockholder’s equity	1,211,795	1,093,288	1,117,016
Total liabilities and stockholder’s equity	$ 3,438,437	$ 3,266,576	$ 3,204,045

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 16,205	$ 9,760	$ 15,582
Accumulated depreciation and amortization	$ 1,101,798	$ 1,074,521	$ 1,038,824
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		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Income Statement [Abstract]
Revenues	$ 429,592	$ 483,261	$ 752,317	$ 806,366
Costs and expenses:
Cost of sales — gas and purchased power (excluding depreciation shown below)	217,976	257,302	377,495	409,076
Operating and administrative expenses	63,932	66,410	122,872	117,819
Operating and administrative expenses — related parties	5,198	3,766	8,710	6,455
Depreciation	22,341	21,158	44,815	41,512
Other operating expense (income), net	279	(1,146)	1,485	(1,137)
Total costs and expenses	309,726	347,490	555,377	573,725
Operating income	119,866	135,771	196,940	232,641
Pension and other postretirement plans non-service income	395	(644)	807	(1,219)
Interest expense	(12,231)	(11,091)	(23,969)	(22,030)
Income before income taxes	108,030	124,036	173,778	209,392
Income tax expense	(25,170)	(34,852)	(41,030)	(51,905)
Net income	$ 82,860	$ 89,184	$ 132,748	$ 157,487

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Statement of Comprehensive Income [Abstract]
Net income	$ 82,860	$ 89,184	$ 132,748	$ 157,487
Other comprehensive income (loss):
Net losses on derivative instruments (net of tax of $252, $0, $739 and $0, respectively)	(621)	0	(1,819)	0
Reclassifications of net losses on derivative instruments (net of tax of $(251), $(280), $(503) and $(559), respectively)	619	592	1,239	1,184
Reclassifications of benefit plans actuarial losses and net prior service benefits (net of tax of $(54), $(104), $(108) and $(208), respectively)	133	220	265	440
Other comprehensive income (loss)	131	812	(315)	1,624
Comprehensive income	$ 82,991	$ 89,996	$ 132,433	$ 159,111

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Statement of Comprehensive Income [Abstract]
Net losses on derivative instruments, tax	$ 252	$ 0	$ 739	$ 0
Reclassifications of net losses on derivative instruments, tax	(251)	(280)	(503)	(559)
Benefit plans reclassifications of actuarial losses and prior service costs, tax	$ (54)	$ (104)	$ (108)	$ (208)

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 132,748	$ 157,487
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	44,815	41,512
Deferred income tax expense (benefit), net	6,966	(1,619)
Provision for uncollectible accounts	11,078	13,142
Other, net	3,881	(345)
Net change in:
Accounts receivable and accrued utility revenues	(134,022)	(176,795)
Inventories	32,471	33,592
Deferred fuel and power costs, net of changes in unsettled derivatives	(16,951)	31,481
Accounts payable	16,252	17,302
Other current assets	59,962	(3,791)
Other current liabilities	3,764	23,090
Net cash provided by operating activities	160,964	135,056
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(177,338)	(151,468)
Net costs of property, plant and equipment disposals	(2,769)	(3,397)
Net cash used by investing activities	(180,107)	(154,865)
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of dividends	(10,000)	(30,000)
Issuances of long-term debt, net of issuance costs	149,211	124,404
Repayments of long-term debt	(4,814)	(41,562)
Decrease in short-term borrowings	(84,500)	(35,000)
Net cash provided by financing activities	49,897	17,842
CASH AND CASH EQUIVALENTS
Cash, cash equivalents, and restricted cash, period end	42,258	6,282
Cash, cash equivalents, and restricted cash, period beginning	11,504	8,249
Cash, cash equivalents and restricted cash increase (decrease)	$ 30,754	$ (1,967)

Condensed Consolidated Statem_5

Condensed Consolidated Statement Of Changes In Equity Statement - USD ($) $ in Thousands	Total	Common Stock	Retained Earnings	Additional Paid-in Capital	AOCI Including Portion Attributable to Noncontrolling Interest
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative effect of change in accounting for employee share-based payments			$ 0
Balance, end of period		$ 60,259	480,857	$ 473,580	$ (26,791)
Balance, beginning of period at Sep. 30, 2017		60,259	480,857	473,580	(26,791)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Tax cuts and jobs act of 2017, reclassification from AOCI to retained earnings, tax effect			0		0
Net income	$ 157,487		157,487
Cash dividends on common stock			(30,000)
Net loss on derivative instruments	0				0
Reclassifications of net losses on derivatives instruments	1,184				1,184
Reclassifications of benefits plans actuarial losses and net prior service costs	440				440
Balance, end of period		60,259	480,857	473,580	(26,791)
Cumulative effect of change in accounting for employee share-based payments			0
Balance, end of period		60,259	534,160	473,580	(25,979)
Balance, beginning of period at Dec. 31, 2017		60,259	534,160	473,580	(25,979)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Tax cuts and jobs act of 2017, reclassification from AOCI to retained earnings, tax effect			0		0
Net income	89,184		89,184
Cash dividends on common stock			(15,000)
Net loss on derivative instruments	0				0
Reclassifications of net losses on derivatives instruments	592				592
Reclassifications of benefits plans actuarial losses and net prior service costs	220				220
Balance, end of period		60,259	534,160	473,580	(25,979)
Balance, end of period	$ 1,117,016	60,259	608,344	473,580	(25,167)
Common stock, par value (in usd per share)	$ 2.25
Balance, beginning of period at Sep. 30, 2018		60,259	579,778	473,580	(20,329)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, end of period		60,259	579,778	473,580	(20,329)
Cumulative effect of change in accounting for employee share-based payments			(3,926)
Balance, end of period		60,259	579,778	473,580	(20,329)
Common stock, par value (in usd per share)	$ 2.25
Balance, beginning of period at Sep. 30, 2018		60,259	579,778	473,580	(20,329)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Tax cuts and jobs act of 2017, reclassification from AOCI to retained earnings, tax effect			5,451		(5,451)
Net income	$ 132,748		132,748
Cash dividends on common stock			(10,000)
Net loss on derivative instruments	(1,819)				(1,819)
Reclassifications of net losses on derivatives instruments	1,239				1,239
Reclassifications of benefits plans actuarial losses and net prior service costs	265				265
Balance, end of period		60,259	579,778	473,580	(20,329)
Cumulative effect of change in accounting for employee share-based payments			0
Balance, end of period		60,259	626,191	473,580	(26,226)
Balance, beginning of period at Dec. 31, 2018		60,259	626,191	473,580	(26,226)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Tax cuts and jobs act of 2017, reclassification from AOCI to retained earnings, tax effect			0		0
Net income	82,860		82,860
Cash dividends on common stock			(5,000)
Net loss on derivative instruments	(621)				(621)
Reclassifications of net losses on derivatives instruments	619				619
Reclassifications of benefits plans actuarial losses and net prior service costs	133				133
Balance, end of period		60,259	626,191	473,580	(26,226)
Balance, end of period	$ 1,211,795	$ 60,259	$ 704,051	$ 473,580	$ (26,095)
Common stock, par value (in usd per share)	$ 2.25

Nature of Operations

Nature of Operations	6 Months Ended
	Mar. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations	Note 1 — Nature of Operations UGI Utilities owns and operates Gas Utility, a natural gas distribution utility business in eastern and central Pennsylvania and in a portion of one Maryland county directly and, prior to the Utility Merger on October 1, 2018, through PNG and CPG. Gas Utility is subject to regulation by the PAPUC and the FERC and, with respect to a small service territory in one Maryland county, the MDPSC. UGI Utilities also owns and operates Electric Utility, an electric distribution utility located in northeastern Pennsylvania. Electric Utility is subject to regulation by the PAPUC and the FERC.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Mar. 31, 2019
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. 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 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, 2018 , Condensed Consolidated Balance Sheet was derived from audited financial statements but does not include all disclosures required by GAAP. These financial statements should be read in conjunction with the Company’s 2018 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. Revenue Recognition. Effective October 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,” which, as amended, is included in ASC 606. This new accounting guidance supersedes previous revenue recognition requirements in ASC 605. ASC 606 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. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reported in accordance with ASC 605. The Company recorded a $3,926 reduction to opening retained earnings as of October 1, 2018, to reflect the cumulative effect of ASC 606 on certain contracts not complete as of the date of adoption. Although the adoption of ASC 606 did not, and is not expected to, have a material impact on the amount or timing of our revenue recognition and on our consolidated net income, cash flows or financial position, beginning October 1, 2018, certain performance obligations primarily associated with the release of capacity contracts are reflected on a gross, rather than net, basis and revenues from certain other negotiated rate contracts are reflected on a straight-line basis over the length of the contract, rather than as invoiced. The amount of revenues reflected on a gross, rather than net, basis for the three and six months ended March 31, 2019 , was approximately $17,000 and $32,000 , respectively, with no impact on net income. Certain revenues such as revenue from leases, financial instruments and other revenues are not within the scope of ASC 606 because they are not from contracts with customers. Such revenues, if any, are accounted for in accordance with other GAAP. Revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, are not included in revenues. Electric Utility’s gross receipts taxes are presented on a gross basis. The Company has elected to use the practical expedient to expense the costs to obtain contracts when incurred as such amounts are generally not material. See Note 4 for additional disclosures regarding the Company’s revenue from contracts with customers. Restricted Cash. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. Upon adoption of revised accounting guidance in October 2018 (see Note 3 ), changes in restricted cash is no longer reflected as a separate investing activity but included in cash, cash equivalents and restricted cash when reconciling the beginning and end of period total amounts in the Company’s Condensed Consolidated Statements of Cash Flows. The guidance required retrospective application, which resulted in adjustments to the previously reported cash flows from investing activities for the six months ended March 31, 2018 , increasing net cash used by investing activities by $1,474 . The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Company’s Condensed Consolidated Balance Sheets to the corresponding amounts reported on the Condensed Consolidated Statements of Cash Flows. Cash, Cash Equivalents and Restricted Cash March 31, 2019 March 31, 2018 September 30, 2018 September 30, 2017 Cash and cash equivalents $ 41,421 $ 4,710 $ 10,314 $ 5,203 Restricted cash 837 1,572 1,190 3,046 Cash, cash equivalents and restricted cash $ 42,258 $ 6,282 $ 11,504 $ 8,249 Derivative Instruments. Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the NPNS exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument, whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes. Gains and losses on substantially all of the derivative instruments used by UGI Utilities to hedge commodity prices (for which NPNS has not been elected) are included in regulatory assets and liabilities. From time to time we enter into derivative instruments that qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative financial instruments are recorded in 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. 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 on the Condensed Consolidated Statements of Cash Flows. 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 12 . Income Taxes. Our results for the three and six-months ended March 31, 2018 were significantly affected by the enactment of the TCJA. For additional information regarding the effects of the TCJA and associated regulatory effects, see Notes 6 and 7. 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 amounts for the three and six months ended March 31, 2018 , have been reclassified as a result of the adoption of revised accounting guidance pertaining to certain net periodic pension and other postretirement benefit costs and restricted cash (see Note 3 ). In addition, certain other prior-period amounts have been reclassified to conform to the current-period presentation.

Accounting Changes

Accounting Changes	6 Months Ended
	Mar. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Note 3 — Accounting Changes New Accounting Standards Adopted Effective October 1, 2018 Revenue Recognition. Effective October 1, 2018, the Company adopted new accounting guidance regarding revenue recognition. See Notes 2 and 4 for a detailed description of the impact of the new guidance and related disclosures. Cloud Computing Implementation Costs. In August 2018, the FASB issued ASU No. 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.” The new guidance requires a customer in a cloud computing arrangement that is a service contract to capitalize certain implementation costs as if the arrangement was an internal-use software project. These deferred implementation costs are expensed over the fixed, noncancelable term of the service arrangement plus any reasonably certain renewal periods. The new guidance also requires the entity to present the expense related to the capitalized implementation costs in the same income statement line as the hosting service fees; to classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments for hosting service fees; and to present the capitalized implementation costs in the balance sheet in the same line item in which prepaid hosting service fees are presented. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We adopted this ASU effective October 1, 2018, and applied the guidance prospectively to all implementation costs associated with cloud computing arrangements that are service contracts incurred beginning October 1, 2018. The adoption of the new guidance did not have a material impact on our results of operations for the three and six months ended March 31, 2019 . Stranded Tax Effects in Accumulated Other Comprehensive Income. In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded tax effects in AOCI resulting from the remeasurement of deferred income taxes associated with items included in AOCI due to the enactment of the TCJA may be reclassified to retained earnings, at the election of the entity, in the period the ASU is adopted. We adopted this ASU effective October 1, 2018. In connection with the adoption of this guidance, we reclassified a benefit of $5,451 from AOCI to opening retained earnings as of October 1, 2018, to reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of AOCI. Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued 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 income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization, when applicable. For entities subject to rate regulation, including UGI Utilities, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability. The guidance became effective for the Company beginning October 1, 2018, with retrospective adoption for the presentation of pension and postretirement expense on the income statement and a prospective adoption for capitalization. The Company’s Condensed Consolidated Statement of Income for the three and six months ended March 31, 2018 , has been recast to reflect the retrospective adoption for the presentation of the non-service cost component of net periodic pension and other postretirement benefit costs, net of estimated amounts capitalized, as “Pension and other postretirement plans non-service income (expense)” on the Condensed Consolidated Statements of Income. Previously, the non-service cost components were reflected in “Operating and administrative expenses.” The amount of income (expense) comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, presented in "Pension and other postretirement plans non-service income (expense)” on the Condensed Consolidated Statements of Income, totaled $395 and $807 , respectively, for the three and six months ended March 31, 2019 and $(644) and $(1,219) , respectively, for the three and six months ended March 31, 2018 . Statement of Cash Flows - Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” The guidance in this ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, as well as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents are included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. The amendments in the ASU are required to be adopted on a retrospective basis. We adopted this ASU effective October 1, 2018. Adoption of this new guidance resulted in a change in presentation of restricted cash on the Condensed Consolidated Statements of Cash Flows; otherwise, this guidance did not have a significant impact on our Condensed Consolidated Statements of Cash Flows and disclosures (see Note 2 , “Restricted Cash”). Accounting Standards Not Yet Adopted Pension and Other Postretirement Benefit Costs Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. The amendments in this ASU are effective for interim and annual periods beginning October 1, 2020 (Fiscal 2021). The guidance shall be adopted retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. The amendments in this ASU are effective for annual periods beginning October 1, 2020 (Fiscal 2021). The guidance regarding removing and modifying disclosures will be adopted on a retrospective basis and the guidance regarding new disclosures will be adopted on a prospective basis. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required prospectively. 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, as subsequently updated, 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 the Company for interim and annual periods beginning October 1, 2019 (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 unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption. We will adopt ASU No. 2016-02, as updated, effective October 1, 2019 and expect to adopt the transition option which would allow the Company to maintain historical presentation for periods before October 1, 2019. The Company has completed a preliminary assessment for evaluating the impact of the guidance and anticipates that its adoption will result in a significant amount of right-of-use assets and lease liabilities for leases in effect at the adoption date. The Company has begun implementation activities including accumulating contracts and lease data in formats compatible with a new lease management system that will assist with the initial adoption and future reporting required by the standard.

Revenue from Contracts with Cus

Revenue from Contracts with Customers (Notes)	6 Months Ended
	Mar. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	Note 4 — Revenue from Contracts with Customers The Company recognizes revenue when control of promised goods or services is transferred to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The Company generally has the right to consideration from a customer in an amount that corresponds directly with the value to the customer for our performance completed to date. As such, we have elected to recognize revenue in the amount to which we have a right to invoice except in the case of certain large delivery service customers for which we recognize revenue on a straight-line basis over the term of the contract, consistent with when the performance obligations are satisfied by the Company. We do not have significant financing terms in our contracts because we generally receive payment shortly before, at, or shortly after the transfer of control of the good or service. Because the period between the time the performance obligation is satisfied and payment is received is one year or less, the Company has elected to apply the significant financing component practical expedient and no amount of consideration has been allocated as a financing component. UGI Utilities supplies natural gas and electricity and provides distribution services of natural gas and electricity to residential, commercial, and industrial customers who are generally billed at standard regulated tariff rates approved by the PAPUC through the ratemaking process. Tariff rates include a component that provides for a reasonable opportunity to recover operating costs and expenses and to earn a return on net investment, and a component that provides for the recovery, subject to reasonableness reviews, of PGC and DS costs. Customers may choose to purchase their natural gas and electricity from Gas Utility or Electric Utility, or, alternatively, may contract separately with alternate suppliers. Accordingly, our contracts with customers comprise two promised goods or services: (1) delivery service of natural gas and electricity through the Company’s utility distribution systems and (2) the natural gas or electricity commodity itself for those customers who choose to purchase the natural gas or electricity directly from the Company. Revenue is not recorded for the sale of natural gas or electricity to customers who have contracted separately with alternate suppliers. For those customers who choose to purchase their natural gas or electricity from the Company, the performance obligation includes both the supply of the commodity and the delivery service. The terms of our core market customer contracts are generally considered day-to-day as customers can discontinue service at any time without penalty. Performance obligations are generally satisfied over time as the natural gas or electricity is delivered to customers, at which point the customers simultaneously receive and consume the benefits provided by the delivery service and, when applicable, the commodity. Amounts are billed to customers based upon the reading of a customer’s meter which occurs on a cycle basis throughout each reporting period. An unbilled amount is recorded at the end of each reporting period based upon estimated amounts of natural gas or electricity delivered to customers since the date of the last meter reading. These unbilled estimates consider various factors such as historical customer usage patterns, customer rates and weather. UGI Utilities has certain fixed-term contracts with large commercial and industrial customers to provide natural gas delivery services at contracted rates and at volumes generally based on the customer’s needs. The performance obligation to provide the contracted delivery service for these large commercial and industrial customers is satisfied over time and revenue is generally recognized on a straight-line basis. UGI Utilities makes off-system sales whereby natural gas delivered to our system in excess of amounts needed to fulfill our distribution system needs is sold to other customers, primarily other distributors of natural gas, based on an agreed-upon price and volume between the Company and the counterparty. Gas Utility also sells excess capacity whereby interstate pipeline capacity in excess of amounts needed to meet our customer obligations is sold to other distributors of natural gas based upon an agreed-upon rate. Off-system sales and capacity releases are generally entered into one month at a time and comprise the sale of a specific volume of gas or pipeline capacity at a specific delivery point or points over a specific time. As such, performance obligations associated with off-system sales and capacity release customers are satisfied, and associated revenue is recorded, when the agreed upon volume of natural gas is delivered or capacity is provided, and title is transferred, in accordance with the contract terms. Electric Utility provides transmission services to PJM by allowing PJM to access Electric Utility’s electricity transmission facilities. In exchange for providing access, PJM pays Electric Utility consideration determined by a formula-based rate approved by FERC. The formula-based rate, which is updated annually, allows recovery of costs incurred to provide transmissions services and return on transmission-related net investment. We recognize revenue over time as we provide transmission service. Other revenues represent revenues from other ancillary services provided to customers and are generally recorded as the service is provided to customers. Contract Balances The timing of revenue recognition may differ from the timing of invoicing to customers or cash receipts. Contract assets represent our right to consideration after the performance obligations have been satisfied when such right is conditioned on something other than the passage of time. Contract assets were not material at March 31, 2019 . All of our receivables are unconditional rights to consideration and are included in “Accounts receivable” and “Accrued utility revenues” on the Condensed Consolidated Balance Sheets. Amounts billed are generally due within the following month. Contract liabilities arise when payment from a customer is received before the performance obligations have been satisfied and represent the Company’s obligations to transfer goods or services to a customer for which we have received consideration. The balances of contract liabilities were $6,481 and $5,897 at March 31, 2019 and October 1, 2018, respectively, and are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets. Revenue recognized for the six months ended March 31, 2019 from the amount included in contract liabilities at October 1, 2018 was not material. Revenue Disaggregation The following table presents our disaggregated revenues by reportable segment for the three and six months ended March 31, 2019 : Three Months Ended March 31, 2019 Six Months Ended March 31, 2019 Total Gas Utility Electric Utility Total Gas Utility Electric Utility Revenues from contracts with customers: Core Market: Residential $ 240,316 $ 220,728 $ 19,588 $ 416,007 $ 379,285 $ 36,722 Commercial & industrial 100,686 94,412 6,274 168,260 155,787 12,473 Large delivery service 44,038 44,038 — 83,585 83,585 — Off-system sales and capacity releases 46,403 46,403 — 84,534 84,534 — Other (a) (2,446 ) (4,761 ) 2,315 (1,275 ) (5,840 ) 4,565 Total revenues from contracts with customers 428,997 400,820 28,177 751,111 697,351 53,760 Other revenues (b) 595 595 — 1,206 1,206 — Total revenues $ 429,592 $ 401,415 $ 28,177 $ 752,317 $ 698,557 $ 53,760 (a) Gas Utility includes unallocated negative surcharge revenue of $(10,496) and $(14,624) for the three and six months ended March 31, 2019 , respectively, as a result of a PAPUC Order issued May 17, 2018, related to the TCJA (see Note 7). (b) Represents certain revenues not from contracts with customers that are not within the scope of ASC 606 and accounted for in accordance with other GAAP. Remaining Performance Obligations The Company has elected to use practical expedients as allowed in ASC 606 to exclude disclosures related to the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied for core market customers and off-system sales and capacity releases as of the end of the reporting period because these contracts have an initial expected term of one year or less. Certain contracts with large delivery service customers contain minimum future performance obligations through 2053. At March 31, 2019 , the Company expects to record approximately $195,000 of revenues related to the minimum future performance obligations over the remaining terms of the related contracts.

Inventories

Inventories	6 Months Ended
	Mar. 31, 2019
Inventory Disclosure [Abstract]
Inventories	Note 5 — Inventories Inventories comprise the following: March 31, 2019 September 30, 2018 March 31, 2018 Gas Utility natural gas $ 3,396 $ 37,287 $ 3,459 Materials, supplies and other 16,546 15,126 16,258 Total inventories $ 19,942 $ 52,413 $ 19,717 At March 31, 2019 , UGI Utilities was party to five principal SCAAs with terms of up to three years. Four of the SCAAs were with Energy Services (see Note 14 ) and one of the SCAAs was with a non-affiliate. Pursuant to the 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 March 31, 2019 , September 30, 2018 and March 31, 2018 , comprising 0.8 bcf, 9.0 bcf and 0.9 bcf of natural gas, were $2,075 , $23,136 and $2,532 , respectively. At March 31, 2019 , September 30, 2018 and March 31, 2018 , UGI Utilities held a total of $11,840 , $13,840 and $13,840 , 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 14 .

Income Taxes (Notes)

Income Taxes (Notes)	6 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Income Tax Disclosure	Note 6 — Income Tax Reform On December 22, 2017, the TCJA was enacted into law. The significant changes resulting from the law that impacted 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 on regulated utility property beginning in Fiscal 2019. In accordance with GAAP as determined by ASC 740, we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three and six months ended March 31, 2018, contained provisional estimates of the impact of the TCJA. These amounts were considered provisional because they used estimates for which tax returns had not yet been filed and because estimated amounts could have been impacted by future regulatory and accounting guidance if and when issued. We adjusted provisional amounts as further information became available and as we refined our calculations. As permitted by SEC Staff Bulletin No. 118, these adjustments occurred during the reasonable “measurement period” defined as twelve months from the date of enactment. During the three months ended December 31, 2018, adjustments to provisional amounts recorded in prior periods were not material. As a result of the TCJA, during the three months ended December 31, 2017, we reduced our net deferred income tax liabilities by $223,660 due to the remeasurement of existing federal deferred income tax assets and liabilities from 35% to 21%. Because a significant amount of the reduction related to our regulated utility plant assets, most of the reduction to our deferred income taxes was not recognized immediately in income tax expense. During the six months ended March 31, 2018, the amount of the reduction in deferred income taxes 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 federal income taxes resulting from the remeasurement of deferred income taxes on regulated utility plant be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. In December 2017, we recorded a regulatory liability of $216,098 associated with the excess deferred federal income taxes related to our regulated utility plant assets. The regulatory liability was increased, and a federal deferred income tax asset was recorded, in the amount of $87,803 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. For the three and six months ended March 31, 2019 and 2018, we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rates. We were subject to a blended U.S. federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contained the effective date of the rate change from 35% to 21% . We are subject to a 21% U.S. federal tax rate in Fiscal 2019. As a result, our annual effective tax rates used for the three and six months ended March 31, 2019 were based upon a federal income tax rate of 21% , and our annual effective tax rates used for the three and six months ended March 31, 2018, were based upon a federal income tax rate of 24.5% . Our estimated annual effective tax rate was not impacted by any regulatory action taken by the PAPUC.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities and Regulatory Matters	6 Months Ended
	Mar. 31, 2019
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities and Regulatory Matters	Note 7 — 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 2018 Annual Report. Other than removal costs, UGI Utilities does not recover a rate of return on its regulatory assets listed below. The following regulatory assets and liabilities associated with UGI Utilities are included on the Condensed Consolidated Balance Sheets: March 31, 2019 September 30, 2018 March 31, 2018 Regulatory assets: Income taxes recoverable $ 120,279 $ 110,129 $ 128,267 Underfunded pension and postretirement plans 83,563 87,106 135,263 Environmental costs 58,758 58,836 59,788 Removal costs, net 30,055 32,025 30,478 Other 6,714 12,906 7,842 Total regulatory assets $ 299,369 $ 301,002 $ 361,638 Regulatory liabilities: Postretirement benefits $ 16,914 $ 17,781 $ 17,105 Deferred fuel and power refunds 17,731 36,723 35,278 State tax benefits — distribution system repairs 24,294 22,611 19,888 PAPUC temporary rates order 25,098 24,430 — Excess federal deferred income taxes 276,659 285,221 301,151 Other 18,828 3,409 7,299 Total regulatory liabilities $ 379,524 $ 390,175 $ 380,721 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 PGC rates in the case of Gas Utility and DS tariffs in the case of Electric Utility. These 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 retail core-market customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel and power costs or refunds. Net unrealized gains on such contracts at March 31, 2019 , September 30, 2018 , and March 31, 2018 , were $1,047 , $2,856 and $269 , respectively. PAPUC temporary rates order. On May 17, 2018, the PAPUC ordered each regulated utility currently not in a general base rate case proceeding, including UGI Gas, PNG and CPG, to reduce their rates through the establishment of a negative surcharge applied to bills rendered on or after July 1, 2018. In accordance with the terms of the temporary rates order, the initial temporary negative surcharge was reconciled at the end of Fiscal 2018 to reflect the difference in the amount of bill credit received by customers and the amount of benefits received by the Company through the fiscal year end period and updated negative surcharges were placed in effect on January 1, 2019 at rates of 4.71% , 2.87% and 6.34% , respectively, for the UGI South, UGI North and UGI Central rate districts (as described below). These negative surcharges will remain in place until the effective date of new rates established in UGI Gas’s current general base rate proceeding filed January 28, 2019. In its May 17, 2018 Order, the PAPUC also required Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate. The rate treatment of this regulatory liability is addressed in UGI Gas’s base rate proceeding filed January 28, 2019 (see “ Base Rate Filings ” below). In its initial filing, UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $24,029 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, plus applicable interest, thereby satisfying a requirement to make a proposal for distributing those benefits within three years of the May 17, 2018, Order. As proposed, the negative surcharge would become effective for a twelve-month period beginning on the effective date of the new base rates. For Pennsylvania utilities that were in a general base rate proceeding, including Electric Utility, no negative surcharge applies. The tax benefits that accrued during the period January 1, 2018 through October 26, 2018, the date before Electric Utility’s base rate case became effective (see below), were refunded to Electric Utility ratepayers through a one-time bill credit. 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 6). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess federal deferred income taxes resulting from the remeasurement 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 and is being amortized and credited to tax expense. Other Regulatory Matters Utility Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and MDPSC, respectively, to merge PNG and CPG into UGI Utilities. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged with and into UGI Utilities, effective October 1, 2018. Consistent with the MDPSC order issued July 25, 2018, and the PAPUC order issued September, 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type schedules for limited future ratemaking purposes. Base Rate Filings. On January 28, 2019, UGI Gas filed a request with the PAPUC to increase its operating revenues for residential, commercial and industrial customers by $71,090 annually. The requested rate increase applies to the consolidated UGI Central, UGI North and UGI South rate districts. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Additionally, UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $24,029 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, plus applicable interest. As proposed, the negative surcharge would become effective for a twelve-month period beginning on the effective date of the new base rates. UGI Gas requested that the new gas rates become effective March 29, 2019. The PAPUC entered an Order dated February 28, 2019, suspending the effective date for the rate increase to allow for investigation and public hearings. Unless a settlement is reached sooner, this review process is expected to last up to nine months from the date of filing. The Company cannot predict the timing or the ultimate outcome of the rate case review process. On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution revenues by $9,200 , which was later reduced by the Company to $7,700 to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $3,201 annual base distribution rate increase for Electric Utility effective October 27, 2018. As part of the final order, Electric Utility provided customers with a one-time $210 billing credit associated with 2018 TCJA tax benefits. On November 26, 2018, the Pennsylvania Office of Consumer Advocate filed an appeal to the Pennsylvania Commonwealth Court challenging the PAPUC’s acceptance of the Company’s use of a fully projected future test year and handling of consolidated federal income tax benefits. The Company cannot predict the ultimate outcome of this appeal. On January 19, 2017, PNG (now the UGI North rate district of Gas Utility) filed a rate request with the PAPUC to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21,700 annually. The increased revenues would be used to fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PAPUC providing for an $11,250 PNG annual base distribution rate increase. On August 31, 2017, the PAPUC approved the Joint Petition and the increase became effective on October 20, 2017. Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017, explosion in Manor Township, Lancaster County, Pennsylvania, that resulted in the death of one Company employee and injuries to two Company employees and one sewer authority employee, and destroyed two residences and damaged several other homes, the BIE filed a formal complaint at the PAPUC in which BIE alleged that the Company committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion, and it requested that the PAPUC order the Company to pay approximately $2,100 in civil penalties, which is the maximum allowable fine. On November 16, 2018, the Company filed its formal written answer contesting the BIE complaint. The matter remains pending before the PAPUC. See additional discussion in Note 9.

Debt

Debt	6 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Debt	Note 8 — Debt On February 1, 2019, UGI Utilities issued in a private placement $150,000 of 4.55% Senior Notes due February 1, 2049. The 4.55% Senior Notes were issued pursuant to a Note Purchase Agreement dated December 21, 2018, between UGI Utilities and certain note purchasers. The 4.55% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.55% Senior Notes were used to reduce short-term borrowings and for general corporate purposes. The 4.55% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The 4.55% Senior Notes require UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 9 — 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 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 South and Electric Utility. Beginning in 2006 and 2008, UGI Utilities also owned and operated two acquired subsidiaries (CPG and PNG), which now constitute UGI North and UGI Central, with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. CPG and PNG merged into UGI Utilities effective October 1, 2018. Prior to the Utility Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, were subject to COAs with the PADEP to address the remediation of specified former MGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the Utility Merger, UGI Utilities, as the successor to CPG and PNG, is 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 and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap (i.e. minimum expenditure threshold). The cost cap of the three COAs, in the aggregate, is $5,350 . The three COAs are currently scheduled to terminate at the end of 2031, 2020 and 2020. At March 31, 2019 , September 30, 2018 and March 31, 2018 , our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $50,844 , $50,970 , and $51,941 , respectively. UGI Utilities has recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 7 ). 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 receives 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 March 31, 2019 , September 30, 2018 and March 31, 2018 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside 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 one Company employee and injuries to two other Company employees and an employee of the local sewer authority, and significant property damage. The Company has received several claims for property damage and personal injuries related to the explosion but no civil lawsuit has been filed to date. On the regulatory side, on February 25, 2019, the NTSB issued a Pipeline Accident Brief of its investigation into the incident, in which it concluded that the explosion resulted from gas that migrated from an incorrectly installed mechanical tapping tee connecting the Company’s distribution main and service line to the home that exploded. In its report, the NTSB also restated its four recommendations that it issued in a June 25, 2018 preliminary report concerning the mechanical tapping tee manufacturer’s installation instructions and the oversight of mechanical tapping tees by the Pipeline and Hazardous Materials Safety Administration. With the issuance of the NTSB report, the one remaining regulatory matter arising from the incident is the BIE formal complaint before the PAPUC in which the BIE alleged that the Company committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion and requested that the PAPUC order the Company to pay approximately $2,100 in civil penalties, which is the maximum allowable fine. On November 16, 2018, the Company filed its formal written answer contesting the BIE complaint. The Company maintains workers’ compensation insurance and liability insurance for personal injury, property and casualty damages and anticipates that third-party claims associated with the explosion, in excess of the Company’s deductible, will 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	6 Months Ended
	Mar. 31, 2019
Defined Benefit Plan [Abstract]
Defined Benefit Pension and Other Postretirement Plans	Note 10 — 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 benefits are based on years of service, age and employee compensation. We also provide limited postretirement health care benefits to certain retirees and postretirement life insurance benefits to certain active and retired employees. Net periodic pension expense and other postretirement benefit costs include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended March 31, 2019 2018 2019 2018 Service cost $ 1,638 $ 1,881 $ 32 $ 67 Interest cost 6,051 5,767 109 112 Expected return on assets (8,140 ) (7,777 ) (184 ) (177 ) Amortization of: Prior service cost (benefit) 62 63 (109 ) (110 ) Actuarial loss 1,721 2,984 17 24 Net benefit cost (benefit) 1,332 2,918 (135 ) (84 ) Change in associated regulatory liabilities — — (342 ) (123 ) Net benefit cost (benefit) after change in regulatory liabilities $ 1,332 $ 2,918 $ (477 ) $ (207 ) Pension Benefits Other Postretirement Benefits Six Months Ended March 31, 2019 2018 2019 2018 Service cost $ 3,275 $ 3,762 $ 63 $ 134 Interest cost 12,101 11,534 218 224 Expected return on assets (16,280 ) (15,554 ) (369 ) (354 ) Amortization of: Prior service cost (benefit) 125 126 (218 ) (220 ) Actuarial loss 3,441 5,968 34 48 Net benefit cost (benefit) 2,662 5,836 (272 ) (168 ) Change in associated regulatory liabilities — — (685 ) (246 ) Net benefit cost (benefit) after change in regulatory liabilities $ 2,662 $ 5,836 $ (957 ) $ (414 ) 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 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 six months ended March 31, 2019 and 2018 , the Company made cash contributions to the Pension Plan of $5,000 and $6,720 , respectively. The Company expects to make additional cash contributions of approximately $6,500 to the Pension Plan during the remainder of Fiscal 2019 . UGI Utilities has established a 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 cash deposits or expense recorded 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 six months ended March 31, 2019 and 2018 . 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	6 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 11 — 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: Asset (Liability) Level 1 Level 2 Level 3 Total March 31, 2019: Assets: Commodity contracts $ 1,258 $ — $ — $ 1,258 Liabilities: Commodity contracts $ (251 ) $ — $ — $ (251 ) Interest rate contracts $ — $ (2,528 ) $ — $ (2,528 ) September 30, 2018: Assets: Commodity contracts $ 3,154 $ — $ — $ 3,154 Interest rate contracts $ — $ 30 $ — $ 30 Liabilities: Commodity contracts $ (146 ) $ — $ — $ (146 ) March 31, 2018: Assets: Commodity contracts $ 1,042 $ 9 $ — $ 1,051 Liabilities: Commodity contracts $ (582 ) $ (7 ) $ — $ (589 ) 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 type 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 March 31, 2019 , September 30, 2018 and March 31, 2018 were as follows: March 31, 2019 September 30, 2018 March 31, 2018 Carrying amount $ 988,080 $ 842,130 $ 838,437 Estimated fair value $ 1,005,920 $ 826,470 $ 871,853

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	6 Months Ended
	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 12 — 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. For more information on the accounting for our derivative instruments, see Note 2 . Commodity Price Risk Gas Utility’s tariffs contain clauses that permit recovery of all 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 PAPUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses 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 March 31, 2019 , September 30, 2018 and March 31, 2018 , the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.6 million dekatherms, 23.2 million dekatherms and 12.7 million dekatherms, respectively. At March 31, 2019 , the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 months . Gains and losses on Gas Utility 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 7 ). 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 March 31, 2019 , September 30, 2018 and March 31, 2018 , all Electric Utility forward electricity purchase contracts were subject to the NPNS exception. 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 March 31, 2019 , September 30, 2018 and March 31, 2018 , the total volumes associated with gasoline futures contracts were not material. Interest Rate Risk UGI Utilities has a variable-rate term loan that is indexed to short-term market interest rates. UGI Utilities has entered into a forward starting, amortizing, pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on borrowings at 3.00% beginning September 30, 2019 through July 2022. We have designated this forward-starting interest rate swap as a cash flow hedge. The initial notional amount of term loan debt subject to this interest rate swap agreement is $114,063 . Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issuances 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 IRPAs. We account for IRPAs as cash flow hedges. As of March 31, 2019 , September 30, 2018 and March 31, 2018 , we had no unsettled IRPAs. At March 31, 2019 , the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3,485 . Derivative Instrument Credit Risk Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2019 , September 30, 2018 and March 31, 2018 , restricted cash in brokerage accounts totaled $837 , $1,190 and $1,572 , respectively. 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: March 31, 2019 September 30, 2018 March 31, 2018 Derivative assets: Derivatives designated as hedging instruments: Interest rate contracts $ — $ 30 $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts 1,258 3,002 860 Derivatives not designated as hedging instruments: Commodity contracts — 152 191 Total derivative assets — gross 1,258 3,184 1,051 Gross amounts offset in the balance sheet (211 ) (146 ) (37 ) Total derivative assets — net (a) $ 1,047 $ 3,038 $ 1,014 Derivative liabilities: Derivatives designated as hedging instruments: Interest rate contracts $ (2,528 ) $ — $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts (211 ) (146 ) (589 ) Derivatives not designated as hedging instruments: Commodity contracts (40 ) — — Total derivative liabilities — gross (2,779 ) (146 ) (589 ) Gross amounts offset in the balance sheet 211 146 37 Total derivative liabilities — net (a) $ (2,568 ) $ — $ (552 ) (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. Derivative liabilities with maturities less than one year are recorded in “ Other current liabilities ” on the Condensed Consolidated Balance Sheets. Effects 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 and six months ended March 31, 2019 and 2018 : Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Three Months Ended March 31, 2019 2018 2019 2018 Cash Flow Hedges: Interest rate contracts $ (873 ) $ — $ (870 ) $ (872 ) Interest expense Gain Recognized in Income Location of Gain Recognized in Income Three Months Ended March 31, 2019 2018 Derivatives Not Subject to PGC and DS Mechanisms: Commodity contracts $ 129 $ 12 Operating and administrative expenses Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Six Months Ended March 31, 2019 2018 2019 2018 Cash Flow Hedges: Interest rate contracts $ (2,558 ) $ — $ (1,742 ) $ (1,743 ) Interest expense (Loss) Gain Recognized in Income Location of (Loss) Gain Recognized in Income Six Months Ended March 31, 2019 2018 Derivatives Not Subject to PGC and DS Mechanisms: Commodity contracts $ (267 ) $ 161 Operating and administrative expenses The amounts of derivative gains and losses on cash flow hedges representing ineffectiveness were not material for all periods presented. 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	6 Months Ended
	Mar. 31, 2019
Equity [Abstract]
Accumulated Other Comprehensive Income	Note 13 — Accumulated Other Comprehensive Income The tables below present changes in AOCI, net of tax, during the three and six months ended March 31, 2019 and 2018 : Three Months Ended March 31, 2019 Postretirement Benefit Plans Derivative Instruments Total AOCI — December 31, 2018 $ (6,500 ) $ (19,726 ) $ (26,226 ) Net losses on interest rate contract — (621 ) (621 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 133 — 133 Reclassifications of net losses on IRPAs — 619 619 AOCI — March 31, 2019 $ (6,367 ) $ (19,728 ) $ (26,095 ) Three Months Ended March 31, 2018 Postretirement Benefit Plans Derivative Instruments Total AOCI — December 31, 2017 $ (8,775 ) $ (17,204 ) $ (25,979 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 220 — 220 Reclassifications of net losses on IRPAs — 592 592 AOCI — March 31, 2018 $ (8,555 ) $ (16,612 ) $ (25,167 ) Six Months Ended March 31, 2019 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2018 $ (4,920 ) $ (15,409 ) $ (20,329 ) Net losses on interest rate contract — (1,819 ) (1,819 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 265 — 265 Reclassifications of net losses on IRPAs — 1,239 1,239 Reclassification of stranded income tax effects related to TCJA (1,712 ) (3,739 ) (5,451 ) AOCI — March 31, 2019 $ (6,367 ) $ (19,728 ) $ (26,095 ) Six Months Ended March 31, 2018 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2017 $ (8,995 ) $ (17,796 ) $ (26,791 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 440 — 440 Reclassifications of net losses on IRPAs — 1,184 1,184 AOCI — March 31, 2018 $ (8,555 ) $ (16,612 ) $ (25,167 )

Related Party Transactions

Related Party Transactions	6 Months Ended
	Mar. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	Note 14 — 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 PAPUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. UGI Utilities also engages in other services with various other affiliates pursuant to arrangements authorized by the PAPUC using similar allocation or market-based pricing methods. 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 PAPUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities totaled $1,510 and $1,359 during the three months ended March 31, 2019 and 2018 , respectively, and $2,692 and $2,405 during the six months ended March 31, 2019 and 2018 , respectively. UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. At March 31, 2019 , UGI Utilities was a party to four SCAAs with Energy Services, and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. 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 $168 and $179 during the three months ended March 31, 2019 and 2018 , respectively, and $3,269 and $3,280 during the six months ended March 31, 2019 and 2018 , 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 $776 and $708 during the three months ended March 31, 2019 and 2018 , respectively, and $1,519 and $1,426 during the six months ended March 31, 2019 and 2018 , 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 March 31, 2019 was $9,040 and at September 30, 2018 and March 31, 2018 , was $11,040 . 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. At March 31, 2019 , September 30, 2018 and March 31, 2018 , the carrying values of these gas storage inventories, comprising approximately 0.8 bcf, 6.7 bcf and 0.9 bcf of natural gas, were $2,075 , $17,701 and $2,532 , 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 March 31, 2019 and 2018 totaled $54,120 and $47,366 , respectively, and during the six months ended March 31, 2019 and 2018 totaled $90,357 and $81,954 , respectively. From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During the three months ended March 31, 2019 and 2018 , revenues associated with such sales to Energy Services totaled $24,564 and $61,245 , respectively. During the six months ended March 31, 2019 and 2018 , revenues associated with such sales to Energy Services totaled $47,426 and $82,392 , respectively. Also from time to time, UGI Utilities purchases natural gas and pipeline capacity 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 March 31, 2019 and 2018 , such purchases totaled $46,295 and $83,429 , respectively. During the six months ended March 31, 2019 and 2018 , such purchases totaled $90,677 and $121,026 , respectively.

Segment Information

Segment Information	6 Months Ended
	Mar. 31, 2019
Segment Reporting [Abstract]
Segment Information	Note 15 — 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 2018 Annual Report. Our Chief Operating Decision Maker evaluates 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 March 31, 2019 Total Gas Utility Electric Utility Revenues $ 429,592 $ 401,415 $ 28,177 Cost of sales $ 217,976 $ 202,164 $ 15,812 Depreciation $ 22,341 $ 20,902 $ 1,439 Operating income $ 119,866 $ 116,580 $ 3,286 Pension and other postretirement plans non-service income $ 395 $ 346 $ 49 Interest expense $ (12,231 ) $ (11,622 ) $ (609 ) Income before income taxes $ 108,030 $ 105,304 $ 2,726 Capital expenditures (including the effects of accruals) $ 70,799 $ 66,766 $ 4,033 Reportable Segments Three Months Ended March 31, 2018 Total Gas Utility Electric Utility Revenues $ 483,261 $ 455,973 $ 27,288 Cost of sales $ 257,302 $ 241,031 $ 16,271 Depreciation $ 21,158 $ 19,776 $ 1,382 Operating income (a) $ 135,771 $ 134,738 $ 1,033 Pension and other postretirement plans non-service expense (a) $ (644 ) $ (563 ) $ (81 ) Interest expense $ (11,091 ) $ (10,866 ) $ (225 ) Income before income taxes $ 124,036 $ 123,309 $ 727 Capital expenditures (including the effects of accruals) $ 55,089 $ 51,363 $ 3,726 Reportable Segments Six Months Ended March 31, 2019 Total Gas Utility Electric Utility Revenues $ 752,317 $ 698,557 $ 53,760 Cost of sales $ 377,495 $ 347,284 $ 30,211 Depreciation $ 44,815 $ 41,942 $ 2,873 Operating income $ 196,940 $ 190,164 $ 6,776 Pension and other postretirement plans non-service income $ 807 $ 707 $ 100 Interest expense $ (23,969 ) $ (22,840 ) $ (1,129 ) Income before income taxes $ 173,778 $ 168,031 $ 5,747 Capital expenditures (including the effects of accruals) $ 148,118 $ 141,840 $ 6,278 As of March 31, 2019 Total assets $ 3,438,437 $ 3,252,092 $ 186,345 Goodwill $ 182,145 $ 182,145 $ — Reportable Segments Six Months Ended March 31, 2018 Total Gas Utility Electric Utility Revenues $ 806,366 $ 755,938 $ 50,428 Cost of sales $ 409,076 $ 379,889 $ 29,187 Depreciation $ 41,512 $ 38,776 $ 2,736 Operating income (a) $ 232,641 $ 228,923 $ 3,718 Pension and other postretirement plans non-service expense (a) $ (1,219 ) $ (1,067 ) $ (152 ) Interest expense $ (22,030 ) $ (21,392 ) $ (638 ) Income before income taxes $ 209,392 $ 206,464 $ 2,928 Capital expenditures (including the effects of accruals) $ 126,788 $ 120,205 $ 6,583 As of March 31, 2018 Total assets $ 3,204,045 $ 3,033,352 $ 170,693 Goodwill $ 182,145 $ 182,145 $ — (a) Amounts reflect the reclassification of non-service income (expense) associated with our pension and other postretirement plans from “Operating and administrative expenses” to “Pension and other postretirement plans non-service income (expense)” on the Condensed Consolidated Statements of Income as a result of the adoption of ASU No. 2017-07 (see Note 3).

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation. Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries. 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 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 NPNS exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument, whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes. Gains and losses on substantially all of the derivative instruments used by UGI Utilities to hedge commodity prices (for which NPNS has not been elected) are included in regulatory assets and liabilities. From time to time we enter into derivative instruments that qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative financial instruments are recorded in 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. 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 on the Condensed Consolidated Statements of Cash Flows. 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 12 .
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 amounts for the three and six months ended March 31, 2018 , have been reclassified as a result of the adoption of revised accounting guidance pertaining to certain net periodic pension and other postretirement benefit costs and restricted cash (see Note 3 ). In addition, certain other 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 Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. The amendments in this ASU are effective for interim and annual periods beginning October 1, 2020 (Fiscal 2021). The guidance shall be adopted retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. The amendments in this ASU are effective for annual periods beginning October 1, 2020 (Fiscal 2021). The guidance regarding removing and modifying disclosures will be adopted on a retrospective basis and the guidance regarding new disclosures will be adopted on a prospective basis. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required prospectively. 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, as subsequently updated, 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 the Company for interim and annual periods beginning October 1, 2019 (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 unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption. We will adopt ASU No. 2016-02, as updated, effective October 1, 2019 and expect to adopt the transition option which would allow the Company to maintain historical presentation for periods before October 1, 2019. The Company has completed a preliminary assessment for evaluating the impact of the guidance and anticipates that its adoption will result in a significant amount of right-of-use assets and lease liabilities for leases in effect at the adoption date. The Company has begun implementation activities including accumulating contracts and lease data in formats compatible with a new lease management system that will assist with the initial adoption and future reporting required by the standard.
Revenue From Contracts With Customers	Revenue Recognition. Effective October 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,” which, as amended, is included in ASC 606. This new accounting guidance supersedes previous revenue recognition requirements in ASC 605. ASC 606 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. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reported in accordance with ASC 605. The Company recorded a $3,926 reduction to opening retained earnings as of October 1, 2018, to reflect the cumulative effect of ASC 606 on certain contracts not complete as of the date of adoption. Although the adoption of ASC 606 did not, and is not expected to, have a material impact on the amount or timing of our revenue recognition and on our consolidated net income, cash flows or financial position, beginning October 1, 2018, certain performance obligations primarily associated with the release of capacity contracts are reflected on a gross, rather than net, basis and revenues from certain other negotiated rate contracts are reflected on a straight-line basis over the length of the contract, rather than as invoiced. The amount of revenues reflected on a gross, rather than net, basis for the three and six months ended March 31, 2019 , was approximately $17,000 and $32,000 , respectively, with no impact on net income.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Restrictions on Cash and Cash Equivalents	The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Company’s Condensed Consolidated Balance Sheets to the corresponding amounts reported on the Condensed Consolidated Statements of Cash Flows. Cash, Cash Equivalents and Restricted Cash March 31, 2019 March 31, 2018 September 30, 2018 September 30, 2017 Cash and cash equivalents $ 41,421 $ 4,710 $ 10,314 $ 5,203 Restricted cash 837 1,572 1,190 3,046 Cash, cash equivalents and restricted cash $ 42,258 $ 6,282 $ 11,504 $ 8,249

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	6 Months Ended
	Mar. 31, 2019
Revenue from Contract with Customer [Abstract]
Summary of Disaggregation of Revenue	The following table presents our disaggregated revenues by reportable segment for the three and six months ended March 31, 2019 : Three Months Ended March 31, 2019 Six Months Ended March 31, 2019 Total Gas Utility Electric Utility Total Gas Utility Electric Utility Revenues from contracts with customers: Core Market: Residential $ 240,316 $ 220,728 $ 19,588 $ 416,007 $ 379,285 $ 36,722 Commercial & industrial 100,686 94,412 6,274 168,260 155,787 12,473 Large delivery service 44,038 44,038 — 83,585 83,585 — Off-system sales and capacity releases 46,403 46,403 — 84,534 84,534 — Other (a) (2,446 ) (4,761 ) 2,315 (1,275 ) (5,840 ) 4,565 Total revenues from contracts with customers 428,997 400,820 28,177 751,111 697,351 53,760 Other revenues (b) 595 595 — 1,206 1,206 — Total revenues $ 429,592 $ 401,415 $ 28,177 $ 752,317 $ 698,557 $ 53,760

Inventories (Tables)

Inventories (Tables)	6 Months Ended
	Mar. 31, 2019
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories comprise the following: March 31, 2019 September 30, 2018 March 31, 2018 Gas Utility natural gas $ 3,396 $ 37,287 $ 3,459 Materials, supplies and other 16,546 15,126 16,258 Total inventories $ 19,942 $ 52,413 $ 19,717

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities and Regulatory Matters (Tables)	6 Months Ended
	Mar. 31, 2019
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 on the Condensed Consolidated Balance Sheets: March 31, 2019 September 30, 2018 March 31, 2018 Regulatory assets: Income taxes recoverable $ 120,279 $ 110,129 $ 128,267 Underfunded pension and postretirement plans 83,563 87,106 135,263 Environmental costs 58,758 58,836 59,788 Removal costs, net 30,055 32,025 30,478 Other 6,714 12,906 7,842 Total regulatory assets $ 299,369 $ 301,002 $ 361,638 Regulatory liabilities: Postretirement benefits $ 16,914 $ 17,781 $ 17,105 Deferred fuel and power refunds 17,731 36,723 35,278 State tax benefits — distribution system repairs 24,294 22,611 19,888 PAPUC temporary rates order 25,098 24,430 — Excess federal deferred income taxes 276,659 285,221 301,151 Other 18,828 3,409 7,299 Total regulatory liabilities $ 379,524 $ 390,175 $ 380,721
Schedule of Regulatory Liabilities Associated with Gas Utility and Electric Utility	The following regulatory assets and liabilities associated with UGI Utilities are included on the Condensed Consolidated Balance Sheets: March 31, 2019 September 30, 2018 March 31, 2018 Regulatory assets: Income taxes recoverable $ 120,279 $ 110,129 $ 128,267 Underfunded pension and postretirement plans 83,563 87,106 135,263 Environmental costs 58,758 58,836 59,788 Removal costs, net 30,055 32,025 30,478 Other 6,714 12,906 7,842 Total regulatory assets $ 299,369 $ 301,002 $ 361,638 Regulatory liabilities: Postretirement benefits $ 16,914 $ 17,781 $ 17,105 Deferred fuel and power refunds 17,731 36,723 35,278 State tax benefits — distribution system repairs 24,294 22,611 19,888 PAPUC temporary rates order 25,098 24,430 — Excess federal deferred income taxes 276,659 285,221 301,151 Other 18,828 3,409 7,299 Total regulatory liabilities $ 379,524 $ 390,175 $ 380,721

Defined Benefit Pension and O_2

Defined Benefit Pension and Other Postretirement Plans (Tables)	6 Months Ended
	Mar. 31, 2019
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 March 31, 2019 2018 2019 2018 Service cost $ 1,638 $ 1,881 $ 32 $ 67 Interest cost 6,051 5,767 109 112 Expected return on assets (8,140 ) (7,777 ) (184 ) (177 ) Amortization of: Prior service cost (benefit) 62 63 (109 ) (110 ) Actuarial loss 1,721 2,984 17 24 Net benefit cost (benefit) 1,332 2,918 (135 ) (84 ) Change in associated regulatory liabilities — — (342 ) (123 ) Net benefit cost (benefit) after change in regulatory liabilities $ 1,332 $ 2,918 $ (477 ) $ (207 ) Pension Benefits Other Postretirement Benefits Six Months Ended March 31, 2019 2018 2019 2018 Service cost $ 3,275 $ 3,762 $ 63 $ 134 Interest cost 12,101 11,534 218 224 Expected return on assets (16,280 ) (15,554 ) (369 ) (354 ) Amortization of: Prior service cost (benefit) 125 126 (218 ) (220 ) Actuarial loss 3,441 5,968 34 48 Net benefit cost (benefit) 2,662 5,836 (272 ) (168 ) Change in associated regulatory liabilities — — (685 ) (246 ) Net benefit cost (benefit) after change in regulatory liabilities $ 2,662 $ 5,836 $ (957 ) $ (414 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Mar. 31, 2019
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: Asset (Liability) Level 1 Level 2 Level 3 Total March 31, 2019: Assets: Commodity contracts $ 1,258 $ — $ — $ 1,258 Liabilities: Commodity contracts $ (251 ) $ — $ — $ (251 ) Interest rate contracts $ — $ (2,528 ) $ — $ (2,528 ) September 30, 2018: Assets: Commodity contracts $ 3,154 $ — $ — $ 3,154 Interest rate contracts $ — $ 30 $ — $ 30 Liabilities: Commodity contracts $ (146 ) $ — $ — $ (146 ) March 31, 2018: Assets: Commodity contracts $ 1,042 $ 9 $ — $ 1,051 Liabilities: Commodity contracts $ (582 ) $ (7 ) $ — $ (589 )
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 March 31, 2019 , September 30, 2018 and March 31, 2018 were as follows: March 31, 2019 September 30, 2018 March 31, 2018 Carrying amount $ 988,080 $ 842,130 $ 838,437 Estimated fair value $ 1,005,920 $ 826,470 $ 871,853

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	6 Months Ended
	Mar. 31, 2019
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: March 31, 2019 September 30, 2018 March 31, 2018 Derivative assets: Derivatives designated as hedging instruments: Interest rate contracts $ — $ 30 $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts 1,258 3,002 860 Derivatives not designated as hedging instruments: Commodity contracts — 152 191 Total derivative assets — gross 1,258 3,184 1,051 Gross amounts offset in the balance sheet (211 ) (146 ) (37 ) Total derivative assets — net (a) $ 1,047 $ 3,038 $ 1,014 Derivative liabilities: Derivatives designated as hedging instruments: Interest rate contracts $ (2,528 ) $ — $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts (211 ) (146 ) (589 ) Derivatives not designated as hedging instruments: Commodity contracts (40 ) — — Total derivative liabilities — gross (2,779 ) (146 ) (589 ) Gross amounts offset in the balance sheet 211 146 37 Total derivative liabilities — net (a) $ (2,568 ) $ — $ (552 ) (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.
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 and six months ended March 31, 2019 and 2018 : Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Three Months Ended March 31, 2019 2018 2019 2018 Cash Flow Hedges: Interest rate contracts $ (873 ) $ — $ (870 ) $ (872 ) Interest expense Gain Recognized in Income Location of Gain Recognized in Income Three Months Ended March 31, 2019 2018 Derivatives Not Subject to PGC and DS Mechanisms: Commodity contracts $ 129 $ 12 Operating and administrative expenses Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Six Months Ended March 31, 2019 2018 2019 2018 Cash Flow Hedges: Interest rate contracts $ (2,558 ) $ — $ (1,742 ) $ (1,743 ) Interest expense (Loss) Gain Recognized in Income Location of (Loss) Gain Recognized in Income Six Months Ended March 31, 2019 2018 Derivatives Not Subject to PGC and DS Mechanisms: Commodity contracts $ (267 ) $ 161 Operating and administrative expenses

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Tables)	6 Months Ended
	Mar. 31, 2019
Equity [Abstract]
Schedule of Changes in Accumulated Other Comprehensive Income	The tables below present changes in AOCI, net of tax, during the three and six months ended March 31, 2019 and 2018 : Three Months Ended March 31, 2019 Postretirement Benefit Plans Derivative Instruments Total AOCI — December 31, 2018 $ (6,500 ) $ (19,726 ) $ (26,226 ) Net losses on interest rate contract — (621 ) (621 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 133 — 133 Reclassifications of net losses on IRPAs — 619 619 AOCI — March 31, 2019 $ (6,367 ) $ (19,728 ) $ (26,095 ) Three Months Ended March 31, 2018 Postretirement Benefit Plans Derivative Instruments Total AOCI — December 31, 2017 $ (8,775 ) $ (17,204 ) $ (25,979 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 220 — 220 Reclassifications of net losses on IRPAs — 592 592 AOCI — March 31, 2018 $ (8,555 ) $ (16,612 ) $ (25,167 ) Six Months Ended March 31, 2019 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2018 $ (4,920 ) $ (15,409 ) $ (20,329 ) Net losses on interest rate contract — (1,819 ) (1,819 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 265 — 265 Reclassifications of net losses on IRPAs — 1,239 1,239 Reclassification of stranded income tax effects related to TCJA (1,712 ) (3,739 ) (5,451 ) AOCI — March 31, 2019 $ (6,367 ) $ (19,728 ) $ (26,095 ) Six Months Ended March 31, 2018 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2017 $ (8,995 ) $ (17,796 ) $ (26,791 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 440 — 440 Reclassifications of net losses on IRPAs — 1,184 1,184 AOCI — March 31, 2018 $ (8,555 ) $ (16,612 ) $ (25,167 )

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Mar. 31, 2019
Segment Reporting [Abstract]
Schedule of Segment Information	Reportable Segments Three Months Ended March 31, 2019 Total Gas Utility Electric Utility Revenues $ 429,592 $ 401,415 $ 28,177 Cost of sales $ 217,976 $ 202,164 $ 15,812 Depreciation $ 22,341 $ 20,902 $ 1,439 Operating income $ 119,866 $ 116,580 $ 3,286 Pension and other postretirement plans non-service income $ 395 $ 346 $ 49 Interest expense $ (12,231 ) $ (11,622 ) $ (609 ) Income before income taxes $ 108,030 $ 105,304 $ 2,726 Capital expenditures (including the effects of accruals) $ 70,799 $ 66,766 $ 4,033 Reportable Segments Three Months Ended March 31, 2018 Total Gas Utility Electric Utility Revenues $ 483,261 $ 455,973 $ 27,288 Cost of sales $ 257,302 $ 241,031 $ 16,271 Depreciation $ 21,158 $ 19,776 $ 1,382 Operating income (a) $ 135,771 $ 134,738 $ 1,033 Pension and other postretirement plans non-service expense (a) $ (644 ) $ (563 ) $ (81 ) Interest expense $ (11,091 ) $ (10,866 ) $ (225 ) Income before income taxes $ 124,036 $ 123,309 $ 727 Capital expenditures (including the effects of accruals) $ 55,089 $ 51,363 $ 3,726 Reportable Segments Six Months Ended March 31, 2019 Total Gas Utility Electric Utility Revenues $ 752,317 $ 698,557 $ 53,760 Cost of sales $ 377,495 $ 347,284 $ 30,211 Depreciation $ 44,815 $ 41,942 $ 2,873 Operating income $ 196,940 $ 190,164 $ 6,776 Pension and other postretirement plans non-service income $ 807 $ 707 $ 100 Interest expense $ (23,969 ) $ (22,840 ) $ (1,129 ) Income before income taxes $ 173,778 $ 168,031 $ 5,747 Capital expenditures (including the effects of accruals) $ 148,118 $ 141,840 $ 6,278 As of March 31, 2019 Total assets $ 3,438,437 $ 3,252,092 $ 186,345 Goodwill $ 182,145 $ 182,145 $ — Reportable Segments Six Months Ended March 31, 2018 Total Gas Utility Electric Utility Revenues $ 806,366 $ 755,938 $ 50,428 Cost of sales $ 409,076 $ 379,889 $ 29,187 Depreciation $ 41,512 $ 38,776 $ 2,736 Operating income (a) $ 232,641 $ 228,923 $ 3,718 Pension and other postretirement plans non-service expense (a) $ (1,219 ) $ (1,067 ) $ (152 ) Interest expense $ (22,030 ) $ (21,392 ) $ (638 ) Income before income taxes $ 209,392 $ 206,464 $ 2,928 Capital expenditures (including the effects of accruals) $ 126,788 $ 120,205 $ 6,583 As of March 31, 2018 Total assets $ 3,204,045 $ 3,033,352 $ 170,693 Goodwill $ 182,145 $ 182,145 $ —

Nature of Operations (Details)

Nature of Operations (Details)	6 Months Ended
	Mar. 31, 2019county
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of counties of operation	1

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018	Sep. 30, 2017
Accounting Policies [Abstract]
Cash and cash equivalents	$ 41,421	$ 10,314	$ 4,710	$ 5,203
Restricted cash	837	1,190	1,572	3,046
Cash, cash equivalents and restricted cash	$ 42,258	$ 11,504	$ 6,282	$ 8,249

Summary of Significant Accoun_5

Summary of Significant Accounting Policies Narrative (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Mar. 31, 2019	Mar. 31, 2019	Mar. 31, 2018	Oct. 01, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenue from contracts with customers	$ 428,997	$ 751,111
Scenario, Previously Reported
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase (decrease) in restricted cash			$ 1,474
Accounting Standards Update 2014-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of change in accounting for employee share-based payments				$ 3,926
Revenue from contracts with customers	$ 17,000	$ 32,000

Accounting Changes Accounting C

Accounting Changes Accounting Changes (Details) - USD ($) $ in Thousands	Oct. 01, 2018	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Accounting Standards Update 2018-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Tax cuts and jobs act of 2017, reclassification from AOCI to retained earnings, tax effect	$ 5,451
Accounting Standards Update 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net periodic benefits expense (reversal of expense) excluding service cost component		$ 395	$ (644)	$ 807	$ (1,219)

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Oct. 01, 2018
Disaggregation of Revenue [Line Items]
Contract with customer, liability, current	$ 6,481	$ 5,897
Fixed-price Contract
Disaggregation of Revenue [Line Items]
Revenue, remaining performance obligation	$ 195,000

Revenue from Contracts with C_4

Revenue from Contracts with Customers Schedule of Summary Of Disaggregation Of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 428,997		$ 751,111
Other revenue, net	595		1,206
Revenues	429,592	$ 483,261	752,317	$ 806,366
Public Utilities, Negative Surcharge In Revenue	(10,496)		(14,624)
Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	240,316		416,007
Commercial & industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	100,686		168,260
Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	44,038		83,585
Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	46,403		84,534
Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(2,446)		(1,275)
Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	28,177		53,760
Other revenue, net	0		0
Revenues	28,177		53,760
Electric Utilities | Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	19,588		36,722
Electric Utilities | Commercial & industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	6,274		12,473
Electric Utilities | Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Electric Utilities | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Electric Utilities | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,315		4,565
Gas Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	400,820		697,351
Other revenue, net	595		1,206
Revenues	401,415	$ 455,973	698,557	$ 755,938
Gas Utility | Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	220,728		379,285
Gas Utility | Commercial & industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	94,412		155,787
Gas Utility | Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	44,038		83,585
Gas Utility | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	46,403		84,534
Gas Utility | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ (4,761)		$ (5,840)

Inventories - Schedule of Inven

Inventories - Schedule of Inventories (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018
Public Utilities, Inventory
Total inventories	$ 19,942	$ 52,413	$ 19,717
Gas Utility natural gas
Public Utilities, Inventory
Total inventories	3,396	37,287	3,459
Materials, supplies and other
Public Utilities, Inventory
Total inventories	$ 16,546	$ 15,126	$ 16,258

Inventories - Narrative (Detail

Inventories - Narrative (Details) $ in Thousands	6 Months Ended
	Mar. 31, 2019USD ($)agreementBcf	Sep. 30, 2018USD ($)Bcf	Mar. 31, 2018USD ($)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	0.8	9	0.9
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $	$ 2,075	$ 23,136	$ 2,532
Security deposit liability | $	$ 11,840	$ 13,840	$ 13,840
Maximum
Public Utilities, Inventory
Term of agreements (in years)	3 years

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2017	Mar. 31, 2018	Sep. 30, 2018
Operating Loss Carryforwards [Line Items]
Federal statutory income tax rate				24.50%
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	$ 216,098
Increase in regulatory liabilities, excess deferred income taxes	$ 87,803

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities and Regulatory Matters - Schedule of Regulatory Assets and Liabilities Associated With Gas Utility and Electric Utility (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018
Regulatory Assets
Regulatory assets	$ 299,369	$ 301,002	$ 361,638
Regulatory Liabilities
Regulatory liabilities	379,524	390,175	380,721
Income taxes recoverable
Regulatory Assets
Regulatory assets	120,279	110,129	128,267
Underfunded pension and postretirement plans
Regulatory Assets
Regulatory assets	83,563	87,106	135,263
Environmental costs
Regulatory Assets
Regulatory assets	58,758	58,836	59,788
Removal costs, net
Regulatory Assets
Regulatory assets	30,055	32,025	30,478
Other
Regulatory Assets
Regulatory assets	6,714	12,906	7,842
Postretirement benefits
Regulatory Liabilities
Regulatory liabilities	16,914	17,781	17,105
Deferred fuel and power refunds
Regulatory Liabilities
Regulatory liabilities	17,731	36,723	35,278
State tax benefits — distribution system repairs
Regulatory Liabilities
Regulatory liabilities	24,294	22,611	19,888
PAPUC temporary rates order
Regulatory Liabilities
Regulatory liabilities	25,098	24,430	0
Excess federal deferred income taxes
Regulatory Liabilities
Regulatory liabilities	276,659	285,221	301,151
Other
Regulatory Liabilities
Regulatory liabilities	$ 18,828	$ 3,409	$ 7,299

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) - USD ($) $ in Thousands

Jan. 28, 2019

Oct. 27, 2018

Oct. 25, 2018

Jun. 30, 2018

May 17, 2018

Jan. 26, 2018

Jul. 02, 2017

Jun. 30, 2017

Jan. 19, 2017

Apr. 01, 2016

Jun. 30, 2018

Mar. 31, 2019

Sep. 30, 2018

Mar. 31, 2018

Regulatory Assets

Proposed negative surcharge in customer distribution service bills, percentage

4.50%

4.50%

Public Utilities, Tax Benefits Received

$ 24,029

Public utilities, civil penalties

$ 2,100

UGI South

Regulatory Assets

PUC termporary rates order, percent of reduction in base revenues

4.71%

UGI North

Regulatory Assets

PUC termporary rates order, percent of reduction in base revenues

2.87%

UGI Central

Regulatory Assets

PUC termporary rates order, percent of reduction in base revenues

6.34%

UGI Utilities

Regulatory Assets

Public utilities, civil penalties

$ 2,100

Pennsylvania Public Utilities Commission

Regulatory Assets

Requested operating revenue increase

$ 9,200

Pennsylvania Public Utilities Commission | UGI Gas

Regulatory Assets

Proposed negative surcharge in customer distribution service bills, percentage

4.50%

Public Utilities, Tax Benefits Received

$ 24,029

Pennsylvania PUC | CPG | Maximum

Regulatory Assets

Distribution system improvement charge, percent of amount billed to customers

0.00%

Pennsylvania PUC | UGI Gas

Regulatory Assets

Requested operating revenue increase

$ 71,090

Pennsylvania PUC | Electric Utilities

Regulatory Assets

Requested operating revenue increase

$ 3,201

$ 7,700

$ 21,700

Tax Cuts And Jobs Act Of 2017, Customer Billing Credit

$ 210

Increase in annual base distribution rate

$ 11,250

Gas Utility

Regulatory Assets

Fair value of unrealized gains (losses)

$ 1,047

$ 2,856

$ 269

Debt (Details)

Debt (Details) - UGI Utilities - Senior Notes - 4.55% Senior Notes due February 2049	Feb. 01, 2019USD ($)
Debt Instrument [Line Items]
Aggregate principal amount	$ 150,000
Debt instrument, interest rate, stated percentage	4.55%
Debt instrument, covenant terms, consolidated debt to consolidated total capital ratio	0.65

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Thousands	Jul. 02, 2017USD ($)	Mar. 31, 2019USD ($)subsidiary	Sep. 30, 2018USD ($)	Mar. 31, 2018USD ($)
Loss Contingencies [Line Items]
Public utilities, civil penalties	$ 2,100
PNG MGP | Environmental Issue
Loss Contingencies [Line Items]
Environmental expenditures cap during year		$ 5,350
CPG, PNG and UGI Gas COAs
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies		$ 50,844	$ 50,970	$ 51,941
PNG and CPG
Loss Contingencies [Line Items]
Number of subsidiaries acquired with similar histories | subsidiary		2

Defined Benefit Pension and O_3

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		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 1,638	$ 1,881	$ 3,275	$ 3,762
Interest cost	6,051	5,767	12,101	11,534
Expected return on assets	(8,140)	(7,777)	(16,280)	(15,554)
Amortization of:
Prior service cost (benefit)	62	63	125	126
Actuarial loss	1,721	2,984	3,441	5,968
Net benefit cost (benefit)	1,332	2,918	2,662	5,836
Change in associated regulatory liabilities	0	0	0	0
Net benefit cost (benefit) after change in regulatory liabilities	1,332	2,918	2,662	5,836
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	32	67	63	134
Interest cost	109	112	218	224
Expected return on assets	(184)	(177)	(369)	(354)
Amortization of:
Prior service cost (benefit)	(109)	(110)	(218)	(220)
Actuarial loss	17	24	34	48
Net benefit cost (benefit)	(135)	(84)	(272)	(168)
Change in associated regulatory liabilities	(342)	(123)	(685)	(246)
Net benefit cost (benefit) after change in regulatory liabilities	$ (477)	$ (207)	$ (957)	$ (414)

Defined Benefit Pension and O_4

Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) - USD ($)	6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure
Contribution made to Pension Plan	$ 5,000,000	$ 6,720,000
Expected contribution to pensions plans in the remainder of current fiscal year	6,500,000
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 - USD ($) $ in Thousands	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018
Commodity contracts
Assets:
Derivative assets	$ 1,258	$ 3,154	$ 1,051
Liabilities:
Derivative liabilities	(251)	(146)	(589)
Interest rate contracts
Assets:
Derivative Asset		30
Liabilities:
Derivative liabilities	(2,528)
Level 1 | Commodity contracts
Assets:
Derivative assets	1,258	3,154	1,042
Liabilities:
Derivative liabilities	(251)	(146)	(582)
Level 1 | Interest rate contracts
Assets:
Derivative Asset		0
Liabilities:
Derivative liabilities	0
Level 2 | Commodity contracts
Assets:
Derivative assets	0	0	9
Liabilities:
Derivative liabilities	0	0	(7)
Level 2 | Interest rate contracts
Assets:
Derivative Asset		30
Liabilities:
Derivative liabilities	(2,528)
Level 3 | Commodity contracts
Assets:
Derivative assets	0	0	0
Liabilities:
Derivative liabilities	0	0	$ 0
Level 3 | Interest rate contracts
Assets:
Derivative Asset		$ 0
Liabilities:
Derivative liabilities	$ 0

Fair Value Measurements - Long-

Fair Value Measurements - Long-term Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018
Carrying amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 988,080	$ 842,130	$ 838,437
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 1,005,920	$ 826,470	$ 871,853

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Narrative (Details) MMBTU in Millions	6 Months Ended
	Mar. 31, 2019USD ($)MMBTU	Sep. 30, 2018USD ($)MMBTU	Mar. 31, 2018USD ($)MMBTU
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	11.6	23.2	12.7
Maximum length of time hedged in price risk cash flow hedges (in months)	12 months
Electric Utility | Electric Utility Electric Transmission Congestion
Derivative
Notional amount (energy measure) (in mmbtu)	114,063,000
Unsecured Debt | Maximum
Derivative
Derivative, fixed interest rate	3.00%

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities - Balance Sheet Location and Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018
Derivative assets
Derivative assets:
Derivative assets	$ 1,258	$ 3,184	$ 1,051
Gross amounts offset in the balance sheet	(211)	(146)	(37)
Total derivative assets — net (a)	1,047	3,038	1,014
Derivative assets | Derivatives subject to PGC and DS mechanisms:
Derivative assets:
Derivative assets	1,258	3,002	860
Derivative assets | Designated as Hedging Instrument | Interest rate contracts
Derivative assets:
Derivative assets	0	30	0
Derivative assets | Not designated as hedging instruments | Commodity contracts
Derivative assets:
Derivative assets	0	152	191
Derivative liabilities
Derivative liabilities:
Derivative liabilities	(2,779)	(146)	(589)
Gross amounts offset in the balance sheet	211	146	37
Total derivative liabilities — net (a)	(2,568)	0	(552)
Derivative liabilities | Derivatives subject to PGC and DS mechanisms:
Derivative liabilities:
Derivative liabilities	(211)	(146)	(589)
Derivative liabilities | Designated as Hedging Instrument | Interest rate contracts
Derivative liabilities:
Derivative liabilities	(2,528)	0	0
Derivative liabilities | Not designated as hedging instruments | Commodity contracts
Derivative liabilities:
Derivative liabilities	$ (40)	$ 0	$ 0

Derivative Instruments and He_5

Derivative Instruments and Hedging Activities - Effects of Derivatives on Statements of Income and AOCI (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Derivatives Not Subject to PGC and DS Mechanisms: | Operating and administrative expenses
Derivative Instruments, Gain (Loss)
Location of (Loss) Gain Recognized in Income	$ 129	$ 12
Not designated as hedging instruments | Commodity contracts | Operating and administrative expenses
Derivative Instruments, Gain (Loss)
Location of (Loss) Gain Recognized in Income			$ (267)	$ 161
Cash Flow Hedges | Interest rate contracts
Derivative Instruments, Gain (Loss)
Loss Recognized in AOCI	(873)	0	(2,558)	0
Cash Flow Hedges | Interest rate contracts | Interest expense
Derivative Instruments, Gain (Loss)
Location of Loss Reclassified from AOCI into Income	$ (870)	$ (872)	$ (1,742)	$ (1,743)

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance			$ 1,093,288
Reclassifications, net of tax	$ 133	$ 220	265	$ 440
AOCI, net of tax - end balance	1,211,795	1,117,016	1,211,795	1,117,016
IRPAs
Accumulated Other Comprehensive Income (Loss)
Other comprehensive income (loss), before reclassifications, net of tax	(621)		(1,819)
Reclassifications, net of tax	619	592	1,239	1,184
Tax cuts and jobs act of 2017, reclassification from AOCI to retained earnings, tax effect			(5,451)
Postretirement Benefit Plans
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(6,500)	(8,775)	(4,920)	(8,995)
Reclassifications, net of tax	133	220	265	440
AOCI, net of tax - end balance	(6,367)	(8,555)	(6,367)	(8,555)
Postretirement Benefit Plans | IRPAs
Accumulated Other Comprehensive Income (Loss)
Other comprehensive income (loss), before reclassifications, net of tax	0		0
Reclassifications, net of tax	0	0	0	0
Tax cuts and jobs act of 2017, reclassification from AOCI to retained earnings, tax effect			(1,712)
Derivative Instruments
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(19,726)	(17,204)	(15,409)	(17,796)
Reclassifications, net of tax	0	0	0	0
AOCI, net of tax - end balance	(19,728)	(16,612)	(19,728)	(16,612)
Derivative Instruments | IRPAs
Accumulated Other Comprehensive Income (Loss)
Other comprehensive income (loss), before reclassifications, net of tax	(621)		(1,819)
Reclassifications, net of tax	619	592	1,239	1,184
Tax cuts and jobs act of 2017, reclassification from AOCI to retained earnings, tax effect			(3,739)
Total
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(26,226)	(25,979)	(20,329)	(26,791)
AOCI, net of tax - end balance	$ (26,095)	$ (25,167)	$ (26,095)	$ (25,167)

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2019USD ($)Bcf	Mar. 31, 2018USD ($)Bcf	Mar. 31, 2019USD ($)Bcf	Mar. 31, 2018USD ($)Bcf	Sep. 30, 2018USD ($)Bcf
Related Party Transaction
Related party costs incurred	$ 5,198	$ 3,766	$ 8,710	$ 6,455
UGI and Subsidiaries | Administrative Services
Related Party Transaction
Amount of related party transaction	$ 1,510	$ 1,359	$ 2,692	$ 2,405
Energy Services
Related Party Transaction
Volume of gas storage inventory (in bcf of natural gas) | Bcf	0.8	0.9	0.8	0.9	6.7
Natural gas storage inventory, related parties, current	$ 2,075	$ 2,532	$ 2,075	$ 2,532	$ 17,701
Revenue from related parties	24,564	61,245	$ 47,426	82,392
Term of agreements (in years)			1 year
Purchases from related party	46,295	83,429	$ 90,677	121,026
Energy Services | SCAAs
Related Party Transaction
Amount of related party transaction	776	708	$ 1,519	1,426
SCAA contract term (in years)			3 years
Related party costs incurred	168	179	$ 3,269	3,280
Related party security deposits	9,040	11,040	9,040	11,040	$ 11,040
Energy Services | Exclusive of Transactions Pursuant SCAAs
Related Party Transaction
Related party costs incurred	$ 54,120	$ 47,366	$ 90,357	$ 81,954

Segment Information - Narrative

Segment Information - Narrative (Details)	6 Months Ended
	Mar. 31, 2019countysegment
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		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018	Sep. 30, 2018
Segment Reporting Information
Revenues	$ 429,592	$ 483,261	$ 752,317	$ 806,366
Cost of sales	217,976	257,302	377,495	409,076
Depreciation	22,341	21,158	44,815	41,512
Operating income	119,866	135,771	196,940	232,641
Pension and other postretirement plans non-service income	395	(644)	807	(1,219)
Interest expense	(12,231)	(11,091)	(23,969)	(22,030)
Income before income taxes	108,030	124,036	173,778	209,392
Capital expenditures (including the effects of accruals)	70,799	55,089	148,118	126,788
Total assets	3,438,437	3,204,045	3,438,437	3,204,045	$ 3,266,576
Goodwill	182,145	182,145	182,145	182,145	$ 182,145
Gas Utility
Segment Reporting Information
Revenues	401,415	455,973	698,557	755,938
Cost of sales	202,164	241,031	347,284	379,889
Depreciation	20,902	19,776	41,942	38,776
Operating income	116,580	134,738	190,164	228,923
Pension and other postretirement plans non-service income	346	(563)	707	(1,067)
Interest expense	(11,622)	(10,866)	(22,840)	(21,392)
Income before income taxes	105,304	123,309	168,031	206,464
Capital expenditures (including the effects of accruals)	66,766	51,363	141,840	120,205
Total assets	3,252,092	3,033,352	3,252,092	3,033,352
Goodwill	182,145	182,145	182,145	182,145
Electric Utility
Segment Reporting Information
Revenues	28,177	27,288	53,760	50,428
Cost of sales	15,812	16,271	30,211	29,187
Depreciation	1,439	1,382	2,873	2,736
Operating income	3,286	1,033	6,776	3,718
Pension and other postretirement plans non-service income	49	(81)	100	(152)
Interest expense	(609)	(225)	(1,129)	(638)
Income before income taxes	2,726	727	5,747	2,928
Capital expenditures (including the effects of accruals)	4,033	3,726	6,278	6,583
Total assets	186,345	170,693	186,345	170,693
Goodwill	$ 0	$ 0	$ 0	$ 0