Ugi Utilities 10-Q 6 Aug 19 2019 Q3 Quarterly report Financial data

Cover Page

Cover Page - shares	9 Months Ended
	Jun. 30, 2019	Jul. 31, 2019
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	1-1398
Entity Registrant Name	UGI UTILITIES, INC.
Entity Incorporation, State or Country Code	PA
Entity Tax Identification Number	23-1174060
Entity Address, Address Line One	One UGI Drive
Entity Address, City or Town	Denver
Entity Address, State or Province	PA
Entity Address, Postal Zip Code	17517
City Area Code	610
Local Phone Number	796-3400
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		26,781,785
Entity Central Index Key	0000100548
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--09-30

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands	Jun. 30, 2019	Sep. 30, 2018	Jun. 30, 2018
Current assets:
Cash and cash equivalents	$ 3,057	$ 10,314	$ 23,181
Restricted cash	4,255	1,190	805
Accounts receivable (less allowances for doubtful accounts of $15,967, $9,760 and $16,261, respectively)	94,106	71,507	107,966
Accounts receivable — related parties	437	2,273	1,682
Accrued utility revenues	14,575	13,977	14,425
Inventories	32,263	52,413	34,663
Prepaid income taxes	127	53,857	41
Regulatory assets	3,549	7,475	2,180
Derivative instruments	851	3,004	1,874
Prepaid expenses	6,754	9,006	10,224
Other current assets	6,702	8,003	8,832
Total current assets	166,676	233,019	205,873
Property, plant and equipment, at cost (less accumulated depreciation of $1,115,273, $1,074,521 and $1,069,070, respectively)	2,709,194	2,541,768	2,430,893
Goodwill	182,145	182,145	182,145
Regulatory assets	297,128	293,527	357,881
Other assets	20,479	16,117	17,233
Total assets	3,375,622	3,266,576	3,194,025
Current liabilities:
Current maturities of long-term debt	8,494	9,001	9,474
Short-term borrowings	76,000	189,500	118,500
Accounts payable	44,665	87,861	56,297
Accounts payable — related parties	7,203	9,585	14,385
Regulatory liabilities	51,777	40,131	49,664
Other current liabilities	116,695	114,256	119,196
Total current liabilities	304,834	450,334	367,516
Long-term debt	972,716	828,995	830,982
Deferred income taxes	421,855	400,939	336,035
Pension and postretirement benefit obligations	71,946	81,590	133,235
Regulatory liabilities	324,393	350,044	362,787
Other noncurrent liabilities	66,855	61,386	63,665
Total liabilities	2,162,599	2,173,288	2,094,220
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	705,724	579,778	590,321
Accumulated other comprehensive loss	(26,540)	(20,329)	(24,355)
Total common stockholder’s equity	1,213,023	1,093,288	1,099,805
Total liabilities and stockholder’s equity	$ 3,375,622	$ 3,266,576	$ 3,194,025

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2019	Sep. 30, 2018	Jun. 30, 2018
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 15,967	$ 9,760	$ 16,261
Accumulated depreciation and amortization	$ 1,115,273	$ 1,074,521	$ 1,069,070
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		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Income Statement [Abstract]
Revenues	$ 163,893	$ 159,934	$ 916,210	$ 966,300
Costs and expenses:
Cost of sales — gas and purchased power (excluding depreciation shown below)	61,021	72,537	438,516	481,613
Operating and administrative expenses	56,525	57,656	179,397	175,475
Operating and administrative expenses — related parties	2,861	4,325	11,571	10,780
Depreciation	23,141	21,414	67,956	62,926
Other operating expense (income), net	20	(481)	1,505	(1,618)
Total costs and expenses	143,568	155,451	698,945	729,176
Operating income	20,325	4,483	217,265	237,124
Pension and other postretirement plans non-service income	440	(569)	1,247	(1,788)
Interest expense	(12,325)	(10,003)	(36,294)	(32,033)
Income (loss) before income taxes	8,440	(6,089)	182,218	203,303
Income tax (expense) benefit	(1,767)	3,066	(42,797)	(48,839)
Net income (loss)	$ 6,673	$ (3,023)	$ 139,421	$ 154,464

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 6,673	$ (3,023)	$ 139,421	$ 154,464
Other comprehensive income (loss):
Net losses on derivative instruments (net of tax of $486, $0, $1,225 and $0, respectively)	(1,197)	0	(3,016)	0
Reclassifications of net losses on derivative instruments (net of tax of $(252), $(279), $(755) and $(838), respectively)	620	592	1,859	1,776
Reclassifications of benefit plan actuarial losses and net prior service benefits (net of tax of $(53), $(104), $(161) and $(312), respectively)	132	220	397	660
Other comprehensive (loss) income	(445)	812	(760)	2,436
Comprehensive income (loss)	$ 6,228	$ (2,211)	$ 138,661	$ 156,900

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Statement of Comprehensive Income [Abstract]
Net losses on derivative instruments, tax	$ 486	$ 0	$ 1,225	$ 0
Reclassifications of net losses on derivative instruments, tax	(252)	(279)	(755)	(838)
Benefit plans reclassifications of actuarial losses and prior service costs, tax	$ (53)	$ (104)	$ (161)	$ (312)

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 139,421	$ 154,464
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	67,956	62,926
Deferred income tax expense (benefit), net	10,455	(6,024)
Provision for uncollectible accounts	13,297	16,462
Regulatory liability arising from tax reform	0	24,098
Other, net	2,799	(1,635)
Net change in:
Accounts receivable and accrued utility revenues	(34,658)	(70,726)
Inventories	20,150	18,646
Deferred fuel and power costs, net of changes in unsettled derivatives	(19,311)	39,657
Accounts payable	(9,981)	3,655
Other current assets	61,210	(2,650)
Other current liabilities	3,399	16,725
Net cash provided by operating activities	254,737	255,598
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(267,403)	(217,901)
Net costs of property, plant and equipment disposals	(4,487)	(5,682)
Net cash used by investing activities	(271,890)	(223,583)
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of dividends	(15,000)	(45,000)
Decrease in short-term borrowings	(113,500)	(51,500)
Issuances of long-term debt, net of issuance costs	149,211	124,404
Repayments of long-term debt	(7,018)	(44,182)
Other, net	(732)	0
Net cash provided (used) by financing activities	12,961	(16,278)
CASH AND CASH EQUIVALENTS
Cash, cash equivalents, and restricted cash, period end	7,312	23,986
Cash, cash equivalents, and restricted cash, period beginning	11,504	8,249
Cash, cash equivalents and restricted cash (decrease) increase	$ (4,192)	$ 15,737

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]
Reclassification of stranded income tax effects related to TCJA			0		0
Net income	$ 154,464		154,464
Cash dividends on common stock			(45,000)
Net losses on derivative instruments	0				0
Reclassifications of net losses on derivative instruments	1,776				1,776
Reclassifications of benefit plans actuarial losses and net prior service credits	660				660
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	608,344	473,580	(25,167)
Balance, beginning of period at Mar. 31, 2018		60,259	608,344	473,580	(25,167)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Reclassification of stranded income tax effects related to TCJA			0		0
Net income	(3,023)		(3,023)
Cash dividends on common stock			(15,000)
Net losses on derivative instruments	0				0
Reclassifications of net losses on derivative instruments	592				592
Reclassifications of benefit plans actuarial losses and net prior service credits	220				220
Balance, end of period		60,259	608,344	473,580	(25,167)
Balance, end of period	$ 1,099,805	60,259	590,321	473,580	(24,355)
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]
Reclassification of stranded income tax effects related to TCJA			5,451		(5,451)
Net income	$ 139,421		139,421
Cash dividends on common stock			(15,000)
Net losses on derivative instruments	(3,016)				(3,016)
Reclassifications of net losses on derivative instruments	1,859				1,859
Reclassifications of benefit plans actuarial losses and net prior service credits	397				397
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	704,051	473,580	(26,095)
Balance, beginning of period at Mar. 31, 2019		60,259	704,051	473,580	(26,095)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Reclassification of stranded income tax effects related to TCJA			0		0
Net income	6,673		6,673
Cash dividends on common stock			(5,000)
Net losses on derivative instruments	(1,197)				(1,197)
Reclassifications of net losses on derivative instruments	620				620
Reclassifications of benefit plans actuarial losses and net prior service credits	132				132
Balance, end of period		60,259	704,051	473,580	(26,095)
Balance, end of period	$ 1,213,023	$ 60,259	$ 705,724	$ 473,580	$ (26,540)
Common stock, par value (in usd per share)	$ 2.25

Nature of Operations

Nature of Operations	9 Months Ended
	Jun. 30, 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	9 Months Ended
	Jun. 30, 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 footnote disclosures from the annual financial statements. 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 nine months ended June 30, 2019 , was approximately $7,000 and $39,000 , 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 nine months ended June 30, 2018 , increasing net cash used by investing activities by $2,241 . 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 June 30, 2019 June 30, 2018 September 30, 2018 September 30, 2017 Cash and cash equivalents $ 3,057 $ 23,181 $ 10,314 $ 5,203 Restricted cash 4,255 805 1,190 3,046 Cash, cash equivalents and restricted cash $ 7,312 $ 23,986 $ 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 because it is probable such gains or losses will be recoverable from or refundable to customers. 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 nine months ended June 30, 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 nine months ended June 30, 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	9 Months Ended
	Jun. 30, 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 nine months ended June 30, 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 nine months ended June 30, 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 $440 and $1,247 , respectively, for the three and nine months ended June 30, 2019 and $(569) and $(1,788) , respectively, for the three and nine months ended June 30, 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 expects to adopt the new guidance in the fourth quarter of Fiscal 2019. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. 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 expects to adopt the new guidance in the fourth quarter of Fiscal 2019. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. 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 expects to adopt the new guidance in the first quarter of Fiscal 2020. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. Credit Losses. In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments. ” This ASU requires entities to estimate lifetime expected credit losses for financial instruments not measured at fair value through net income, including trade and other receivables, net investments in leases, financial receivables, debt securities, and other financial instruments, which may result in earlier recognition of credit losses. Further, the new current expected credit loss model may affect how entities estimate their allowance for loss for receivables that are current with respect to their payment terms. ASU 2016-13 is effective for the Company for interim and annual periods beginning October 1, 2020 (Fiscal 2021). Early adoption is permitted. 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)	9 Months Ended
	Jun. 30, 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 June 30, 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 $6,915 and $5,897 at June 30, 2019 and October 1, 2018, respectively, and are included in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets. Revenue recognized for the nine months ended June 30, 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 nine months ended June 30, 2019 : Three Months Ended June 30, 2019 Nine Months Ended June 30, 2019 Total Gas Utility Electric Utility Total Gas Utility Electric Utility Revenues from contracts with customers: Core Market: Residential $ 78,103 $ 66,390 $ 11,713 $ 494,110 $ 445,675 $ 48,435 Commercial & industrial 34,274 28,717 5,557 202,534 184,504 18,030 Large delivery service 27,857 27,857 — 111,442 111,442 — Off-system sales and capacity releases 14,115 14,115 — 98,649 98,649 — Other (a) 8,992 6,810 2,182 7,717 970 6,747 Total revenues from contracts with customers 163,341 143,889 19,452 914,452 841,240 73,212 Other revenues (b) 552 552 — 1,758 1,758 — Total revenues $ 163,893 $ 144,441 $ 19,452 $ 916,210 $ 842,998 $ 73,212 (a) Gas Utility includes an unallocated negative surcharge revenue increase (reduction) of $3,299 and $(11,325) for the three and nine months ended June 30, 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 June 30, 2019 , the Company expects to record approximately $193,000 of revenues related to the minimum future performance obligations over the remaining terms of the related contracts.

Inventories

Inventories	9 Months Ended
	Jun. 30, 2019
Inventory Disclosure [Abstract]
Inventories	Note 5 — Inventories Inventories comprise the following: June 30, 2019 September 30, 2018 June 30, 2018 Gas Utility natural gas $ 15,465 $ 37,287 $ 18,608 Materials, supplies and other 16,798 15,126 16,055 Total inventories $ 32,263 $ 52,413 $ 34,663 At June 30, 2019 , UGI Utilities was party to four principal SCAAs with terms of up to three years . All four of the SCAAs were with Energy Services (see Note 14 ). Pursuant to the SCAAs, UGI Utilities has, among other things, released certain natural gas storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated natural gas 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 June 30, 2019 , September 30, 2018 and June 30, 2018 , comprising 3.3 bcf, 9.0 bcf and 4.7 bcf of natural gas, were $8,234 , $23,136 and $11,944 , respectively. At June 30, 2019 , September 30, 2018 and June 30, 2018 , UGI Utilities held a total of $7,640 , $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)	9 Months Ended
	Jun. 30, 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 nine months ended June 30, 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 nine months ended June 30, 2018, the amount of the reduction in deferred income taxes that reduced income tax expense totaled $9,254 . 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 nine months ended June 30, 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 nine months ended June 30, 2019 were based upon a federal income tax rate of 21% , and our annual effective tax rates used for the three and nine months ended June 30, 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	9 Months Ended
	Jun. 30, 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: June 30, 2019 September 30, 2018 June 30, 2018 Regulatory assets: Income taxes recoverable $ 123,901 $ 110,129 $ 130,024 Underfunded pension and postretirement plans 81,791 87,106 132,239 Environmental costs 56,561 58,836 59,808 Removal costs, net 29,339 32,025 30,987 Other 9,085 12,906 7,003 Total regulatory assets $ 300,677 $ 301,002 $ 360,061 Regulatory liabilities: Postretirement benefits $ 16,481 $ 17,781 $ 16,895 Deferred fuel and power refunds 12,416 36,723 44,500 State tax benefits — distribution system repairs 25,176 22,611 20,677 PAPUC temporary rates order 25,414 24,430 24,098 Excess federal deferred income taxes 282,735 285,221 301,151 Other 13,948 3,409 5,130 Total regulatory liabilities $ 376,170 $ 390,175 $ 412,451 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 (losses) gains on such contracts at June 30, 2019 , September 30, 2018 , and June 30, 2018 , were $(2,141) , $2,856 and $1,863 , 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 to credit customers any tax savings as a result of TCJA 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 Gas Utility’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 Gas Utility’s base rate proceeding filed January 28, 2019 (see “ Base Rate Filings ” below). In its initial filing, Gas Utility 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 applied. 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, Gas Utility 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, Gas Utility 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. Gas Utility 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. On July 22, 2019, a Joint Petition for Approval of Settlement of all issues supported by all active parties was filed with the PAPUC. The Joint Petition is subject to receipt of a recommended decision by a PAPUC administrative law judge and an order of the PAPUC approving the settlement. Unless the PAPUC issues a final order prior to the end of the statutory suspension period, October 28, 2019, the initial proposed rate increase will become effective the next day, subject to refund and a subsequent PAPUC order. 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 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, 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	9 Months Ended
	Jun. 30, 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. On June 27, 2019, UGI Utilities entered into the UGI Utilities 2019 Credit Agreement with a group of banks providing for borrowings up to $350,000 (including a $100,000 sublimit for letters of credit). The Company may request an increase in the amount of loan commitments under the UGI Utilities 2019 Credit Agreement to a maximum aggregate amount of $150,000 . Concurrently with entering into the UGI Utilities 2019 Credit Agreement, the Company terminated its existing $450,000 revolving credit agreement dated March 27, 2015. Under the UGI Utilities 2019 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2019 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.0. The UGI Utilities 2019 Credit Agreement is currently scheduled to expire in June 2020, but will be extended to June 2024 if on or before June 25, 2020, UGI Utilities satisfies certain requirements relating to approval by the PAPUC. UGI Utilities is currently seeking such PAPUC approval.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Jun. 30, 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 June 30, 2019 , September 30, 2018 and June 30, 2018 , our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $47,560 , $50,970 , and $52,231 , 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 June 30, 2019 , September 30, 2018 and June 30, 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. Prior to the tolling of the statute of limitations on July 2, 2019, the Company received lawsuits alleging that the Company and other unrelated parties are responsible for the value of property damage resulting from the explosion. The Company also resolved a number of claims through settlement. 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	9 Months Ended
	Jun. 30, 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. The service cost component of our pension and other postretirement plans, net of amounts capitalized, are reflected in “ Operating and administrative expenses ” on the Condensed Consolidated Statements of Income. The non-service cost component, net of amounts capitalized, are reflected in “ Pension and other postretirement plans non-service income (expense) ” on the Condensed Consolidated Statements of Income. Net periodic pension expense and other postretirement benefit costs include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended June 30, 2019 2018 2019 2018 Service cost $ 1,637 $ 1,882 $ 31 $ 66 Interest cost 6,050 5,766 109 111 Expected return on assets (8,140 ) (7,776 ) (185 ) (178 ) Amortization of: Prior service cost (benefit) 63 61 (109 ) (110 ) Actuarial loss 1,721 2,984 17 23 Net benefit cost (benefit) 1,331 2,917 (137 ) (88 ) Change in associated regulatory liabilities — — (343 ) (122 ) Net benefit cost (benefit) after change in regulatory liabilities $ 1,331 $ 2,917 $ (480 ) $ (210 ) Pension Benefits Other Postretirement Benefits Nine Months Ended June 30, 2019 2018 2019 2018 Service cost $ 4,912 $ 5,644 $ 94 $ 200 Interest cost 18,151 17,300 327 335 Expected return on assets (24,420 ) (23,330 ) (554 ) (532 ) Amortization of: Prior service cost (benefit) 188 187 (327 ) (330 ) Actuarial loss 5,162 8,952 51 71 Net benefit cost (benefit) 3,993 8,753 (409 ) (256 ) Change in associated regulatory liabilities — — (1,028 ) (368 ) Net benefit cost (benefit) after change in regulatory liabilities $ 3,993 $ 8,753 $ (1,437 ) $ (624 ) 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 nine months ended June 30, 2019 and 2018 , the Company made cash contributions to the Pension Plan of $8,234 and $10,079 , respectively. The Company expects to make additional cash contributions of approximately $3,000 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 nine months ended June 30, 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	9 Months Ended
	Jun. 30, 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 June 30, 2019: Assets: Commodity contracts $ 944 $ — $ — $ 944 Liabilities: Commodity contracts $ (3,116 ) $ — $ — $ (3,116 ) Interest rate contracts $ — $ (4,211 ) $ — $ (4,211 ) September 30, 2018: Assets: Commodity contracts $ 3,154 $ — $ — $ 3,154 Interest rate contracts $ — $ 30 $ — $ 30 Liabilities: Commodity contracts $ (146 ) $ — $ — $ (146 ) June 30, 2018: Assets: Commodity contracts $ 2,097 $ — $ — $ 2,097 Liabilities: Commodity contracts $ (101 ) $ — $ — $ (101 ) 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 June 30, 2019 , September 30, 2018 and June 30, 2018 were as follows: June 30, 2019 September 30, 2018 June 30, 2018 Carrying amount $ 985,876 $ 842,130 $ 844,672 Estimated fair value $ 1,050,749 $ 826,470 $ 858,960

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	9 Months Ended
	Jun. 30, 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 June 30, 2019 , September 30, 2018 and June 30, 2018 , the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 16.5 million dekatherms, 23.2 million dekatherms and 16.8 million dekatherms, respectively. At June 30, 2019 , the maximum period over which Gas Utility is economically hedging natural gas market price risk is 15 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 June 30, 2019 , September 30, 2018 and June 30, 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 June 30, 2019 , September 30, 2018 and June 30, 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 June 30, 2019 , September 30, 2018 and June 30, 2018 , we had no unsettled IRPAs. At June 30, 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 approximately $3,500 . Derivative Instrument Credit Risk Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2019 , September 30, 2018 and June 30, 2018 , restricted cash in brokerage accounts totaled $4,255 , $1,190 and $805 , 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: June 30, 2019 September 30, 2018 June 30, 2018 Derivative assets: Derivatives designated as hedging instruments: Interest rate contracts $ — $ 30 $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts 944 3,002 1,963 Derivatives not designated as hedging instruments: Commodity contracts — 152 134 Total derivative assets — gross 944 3,184 2,097 Gross amounts offset in the balance sheet (19 ) (146 ) (101 ) Total derivative assets — net (a) $ 925 $ 3,038 $ 1,996 Derivative liabilities: Derivatives designated as hedging instruments: Interest rate contracts $ (4,211 ) $ — $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts (3,085 ) (146 ) (101 ) Derivatives not designated as hedging instruments: Commodity contracts (31 ) — — Total derivative liabilities — gross (7,327 ) (146 ) (101 ) Gross amounts offset in the balance sheet 19 146 101 Total derivative liabilities — net (a) $ (7,308 ) $ — $ — (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 nine months ended June 30, 2019 and 2018 : Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Three Months Ended June 30, 2019 2018 2019 2018 Cash Flow Hedges: Interest rate contracts $ (1,683 ) $ — $ (872 ) $ (871 ) Interest expense Gain Recognized in Income Location of Gain Recognized in Income Three Months Ended June 30, 2019 2018 Derivatives Not Subject to PGC and DS Mechanisms: Commodity contracts $ 10 $ 37 Operating and administrative expenses Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Nine Months Ended June 30, 2019 2018 2019 2018 Cash Flow Hedges: Interest rate contracts $ (4,241 ) $ — $ (2,614 ) $ (2,614 ) Interest expense (Loss) Gain Recognized in Income Location of (Loss) Gain Recognized in Income Nine Months Ended June 30, 2019 2018 Derivatives Not Subject to PGC and DS Mechanisms: Commodity contracts $ (257 ) $ 198 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	9 Months Ended
	Jun. 30, 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 nine months ended June 30, 2019 and 2018 : Three Months Ended June 30, 2019 Postretirement Benefit Plans Derivative Instruments Total AOCI — March 31, 2019 $ (6,367 ) $ (19,728 ) $ (26,095 ) Net losses on interest rate contract — (1,197 ) (1,197 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 132 — 132 Reclassifications of net losses on IRPAs — 620 620 AOCI — June 30, 2019 $ (6,235 ) $ (20,305 ) $ (26,540 ) Three Months Ended June 30, 2018 Postretirement Benefit Plans Derivative Instruments Total AOCI — March 31, 2018 $ (8,555 ) $ (16,612 ) $ (25,167 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 220 — 220 Reclassifications of net losses on IRPAs — 592 592 AOCI — June 30, 2018 $ (8,335 ) $ (16,020 ) $ (24,355 ) Nine Months Ended June 30, 2019 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2018 $ (4,920 ) $ (15,409 ) $ (20,329 ) Net losses on interest rate contract — (3,016 ) (3,016 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 397 — 397 Reclassifications of net losses on IRPAs — 1,859 1,859 Reclassification of stranded income tax effects related to TCJA (1,712 ) (3,739 ) (5,451 ) AOCI — June 30, 2019 $ (6,235 ) $ (20,305 ) $ (26,540 ) Nine Months Ended June 30, 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 660 — 660 Reclassifications of net losses on IRPAs — 1,776 1,776 AOCI — June 30, 2018 $ (8,335 ) $ (16,020 ) $ (24,355 )

Related Party Transactions

Related Party Transactions	9 Months Ended
	Jun. 30, 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 $1,536 and $1,665 during the three months ended June 30, 2019 and 2018 , respectively, and $4,228 and $4,070 during the nine months ended June 30, 2019 and 2018 , respectively. UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years . At June 30, 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 natural gas 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 natural gas 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 $7,045 and $8,114 during the three months ended June 30, 2019 and 2018 , respectively, and $10,314 and $11,394 during the nine months ended June 30, 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 $784 and $701 during the three months ended June 30, 2019 and 2018 , respectively, and $2,303 and $2,127 during the nine months ended June 30, 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 June 30, 2019 was $7,640 and at September 30, 2018 and June 30, 2018 , was $11,040 . UGI Utilities reflects the historical cost of the natural 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 June 30, 2019 , September 30, 2018 and June 30, 2018 , the carrying values of these gas storage inventories, comprising approximately 3.3 bcf, 6.7 bcf and 3.6 bcf of natural gas, were $8,234 , $17,701 and $9,294 , 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 June 30, 2019 and 2018 totaled $3,222 and $5,828 , respectively, and during the nine months ended June 30, 2019 and 2018 totaled $93,579 and $87,782 , respectively. From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During the three months ended June 30, 2019 and 2018 , revenues associated with such sales to Energy Services totaled $10,041 and $11,582 , respectively. During the nine months ended June 30, 2019 and 2018 , revenues associated with such sales to Energy Services totaled $57,467 and $93,974 , 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 June 30, 2019 and 2018 , such purchases totaled $16,568 and $19,429 , respectively. During the nine months ended June 30, 2019 and 2018 , such purchases totaled $107,245 and $140,455 , respectively.

Segment Information

Segment Information	9 Months Ended
	Jun. 30, 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 June 30, 2019 Total Gas Utility Electric Utility Revenues $ 163,893 $ 144,441 $ 19,452 Cost of sales $ 61,021 $ 51,626 $ 9,395 Depreciation $ 23,141 $ 21,612 $ 1,529 Operating income $ 20,325 $ 18,592 $ 1,733 Pension and other postretirement plans non-service income $ 440 $ 387 $ 53 Interest expense $ (12,325 ) $ (11,522 ) $ (803 ) Income before income taxes $ 8,440 $ 7,457 $ 983 Capital expenditures (including the effects of accruals) $ 84,451 $ 79,272 $ 5,179 Reportable Segments Three Months Ended June 30, 2018 Total Gas Utility Electric Utility Revenues $ 159,934 $ 138,597 $ 21,337 Cost of sales $ 72,537 $ 60,837 $ 11,700 Depreciation $ 21,414 $ 20,011 $ 1,403 Operating income (a) $ 4,483 $ 3,126 $ 1,357 Pension and other postretirement plans non-service expense (a) $ (569 ) $ (498 ) $ (71 ) Interest expense $ (10,003 ) $ (9,829 ) $ (174 ) (Loss) income before income taxes $ (6,089 ) $ (7,201 ) $ 1,112 Capital expenditures (including the effects of accruals) $ 79,704 $ 76,546 $ 3,158 Reportable Segments Nine Months Ended June 30, 2019 Total Gas Utility Electric Utility Revenues $ 916,210 $ 842,998 $ 73,212 Cost of sales $ 438,516 $ 398,910 $ 39,606 Depreciation $ 67,956 $ 63,554 $ 4,402 Operating income $ 217,265 $ 208,756 $ 8,509 Pension and other postretirement plans non-service income $ 1,247 $ 1,094 $ 153 Interest expense $ (36,294 ) $ (34,362 ) $ (1,932 ) Income before income taxes $ 182,218 $ 175,488 $ 6,730 Capital expenditures (including the effects of accruals) $ 232,569 $ 221,112 $ 11,457 As of June 30, 2019 Total assets $ 3,375,622 $ 3,191,316 $ 184,306 Goodwill $ 182,145 $ 182,145 $ — Reportable Segments Nine Months Ended June 30, 2018 Total Gas Utility Electric Utility Revenues $ 966,300 $ 894,535 $ 71,765 Cost of sales $ 481,613 $ 440,726 $ 40,887 Depreciation $ 62,926 $ 58,787 $ 4,139 Operating income (a) $ 237,124 $ 232,049 $ 5,075 Pension and other postretirement plans non-service expense (a) $ (1,788 ) $ (1,565 ) $ (223 ) Interest expense $ (32,033 ) $ (31,221 ) $ (812 ) Income before income taxes $ 203,303 $ 199,263 $ 4,040 Capital expenditures (including the effects of accruals) $ 206,492 $ 196,751 $ 9,741 As of June 30, 2018 Total assets $ 3,194,025 $ 3,008,441 $ 185,584 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)	9 Months Ended
	Jun. 30, 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.
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 because it is probable such gains or losses will be recoverable from or refundable to customers. 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 nine months ended June 30, 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.
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 nine months ended June 30, 2019 , was approximately $7,000 and $39,000 , respectively, with no impact on net income.
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 expects to adopt the new guidance in the fourth quarter of Fiscal 2019. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. 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 expects to adopt the new guidance in the fourth quarter of Fiscal 2019. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. 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 expects to adopt the new guidance in the first quarter of Fiscal 2020. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. Credit Losses. In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments. ” This ASU requires entities to estimate lifetime expected credit losses for financial instruments not measured at fair value through net income, including trade and other receivables, net investments in leases, financial receivables, debt securities, and other financial instruments, which may result in earlier recognition of credit losses. Further, the new current expected credit loss model may affect how entities estimate their allowance for loss for receivables that are current with respect to their payment terms. ASU 2016-13 is effective for the Company for interim and annual periods beginning October 1, 2020 (Fiscal 2021). Early adoption is permitted. 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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)	9 Months Ended
	Jun. 30, 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 June 30, 2019 June 30, 2018 September 30, 2018 September 30, 2017 Cash and cash equivalents $ 3,057 $ 23,181 $ 10,314 $ 5,203 Restricted cash 4,255 805 1,190 3,046 Cash, cash equivalents and restricted cash $ 7,312 $ 23,986 $ 11,504 $ 8,249

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	9 Months Ended
	Jun. 30, 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 nine months ended June 30, 2019 : Three Months Ended June 30, 2019 Nine Months Ended June 30, 2019 Total Gas Utility Electric Utility Total Gas Utility Electric Utility Revenues from contracts with customers: Core Market: Residential $ 78,103 $ 66,390 $ 11,713 $ 494,110 $ 445,675 $ 48,435 Commercial & industrial 34,274 28,717 5,557 202,534 184,504 18,030 Large delivery service 27,857 27,857 — 111,442 111,442 — Off-system sales and capacity releases 14,115 14,115 — 98,649 98,649 — Other (a) 8,992 6,810 2,182 7,717 970 6,747 Total revenues from contracts with customers 163,341 143,889 19,452 914,452 841,240 73,212 Other revenues (b) 552 552 — 1,758 1,758 — Total revenues $ 163,893 $ 144,441 $ 19,452 $ 916,210 $ 842,998 $ 73,212

Inventories (Tables)

Inventories (Tables)	9 Months Ended
	Jun. 30, 2019
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories comprise the following: June 30, 2019 September 30, 2018 June 30, 2018 Gas Utility natural gas $ 15,465 $ 37,287 $ 18,608 Materials, supplies and other 16,798 15,126 16,055 Total inventories $ 32,263 $ 52,413 $ 34,663

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities and Regulatory Matters (Tables)	9 Months Ended
	Jun. 30, 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: June 30, 2019 September 30, 2018 June 30, 2018 Regulatory assets: Income taxes recoverable $ 123,901 $ 110,129 $ 130,024 Underfunded pension and postretirement plans 81,791 87,106 132,239 Environmental costs 56,561 58,836 59,808 Removal costs, net 29,339 32,025 30,987 Other 9,085 12,906 7,003 Total regulatory assets $ 300,677 $ 301,002 $ 360,061 Regulatory liabilities: Postretirement benefits $ 16,481 $ 17,781 $ 16,895 Deferred fuel and power refunds 12,416 36,723 44,500 State tax benefits — distribution system repairs 25,176 22,611 20,677 PAPUC temporary rates order 25,414 24,430 24,098 Excess federal deferred income taxes 282,735 285,221 301,151 Other 13,948 3,409 5,130 Total regulatory liabilities $ 376,170 $ 390,175 $ 412,451
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: June 30, 2019 September 30, 2018 June 30, 2018 Regulatory assets: Income taxes recoverable $ 123,901 $ 110,129 $ 130,024 Underfunded pension and postretirement plans 81,791 87,106 132,239 Environmental costs 56,561 58,836 59,808 Removal costs, net 29,339 32,025 30,987 Other 9,085 12,906 7,003 Total regulatory assets $ 300,677 $ 301,002 $ 360,061 Regulatory liabilities: Postretirement benefits $ 16,481 $ 17,781 $ 16,895 Deferred fuel and power refunds 12,416 36,723 44,500 State tax benefits — distribution system repairs 25,176 22,611 20,677 PAPUC temporary rates order 25,414 24,430 24,098 Excess federal deferred income taxes 282,735 285,221 301,151 Other 13,948 3,409 5,130 Total regulatory liabilities $ 376,170 $ 390,175 $ 412,451

Defined Benefit Pension and O_2

Defined Benefit Pension and Other Postretirement Plans (Tables)	9 Months Ended
	Jun. 30, 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 June 30, 2019 2018 2019 2018 Service cost $ 1,637 $ 1,882 $ 31 $ 66 Interest cost 6,050 5,766 109 111 Expected return on assets (8,140 ) (7,776 ) (185 ) (178 ) Amortization of: Prior service cost (benefit) 63 61 (109 ) (110 ) Actuarial loss 1,721 2,984 17 23 Net benefit cost (benefit) 1,331 2,917 (137 ) (88 ) Change in associated regulatory liabilities — — (343 ) (122 ) Net benefit cost (benefit) after change in regulatory liabilities $ 1,331 $ 2,917 $ (480 ) $ (210 ) Pension Benefits Other Postretirement Benefits Nine Months Ended June 30, 2019 2018 2019 2018 Service cost $ 4,912 $ 5,644 $ 94 $ 200 Interest cost 18,151 17,300 327 335 Expected return on assets (24,420 ) (23,330 ) (554 ) (532 ) Amortization of: Prior service cost (benefit) 188 187 (327 ) (330 ) Actuarial loss 5,162 8,952 51 71 Net benefit cost (benefit) 3,993 8,753 (409 ) (256 ) Change in associated regulatory liabilities — — (1,028 ) (368 ) Net benefit cost (benefit) after change in regulatory liabilities $ 3,993 $ 8,753 $ (1,437 ) $ (624 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Jun. 30, 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 June 30, 2019: Assets: Commodity contracts $ 944 $ — $ — $ 944 Liabilities: Commodity contracts $ (3,116 ) $ — $ — $ (3,116 ) Interest rate contracts $ — $ (4,211 ) $ — $ (4,211 ) September 30, 2018: Assets: Commodity contracts $ 3,154 $ — $ — $ 3,154 Interest rate contracts $ — $ 30 $ — $ 30 Liabilities: Commodity contracts $ (146 ) $ — $ — $ (146 ) June 30, 2018: Assets: Commodity contracts $ 2,097 $ — $ — $ 2,097 Liabilities: Commodity contracts $ (101 ) $ — $ — $ (101 )
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 June 30, 2019 , September 30, 2018 and June 30, 2018 were as follows: June 30, 2019 September 30, 2018 June 30, 2018 Carrying amount $ 985,876 $ 842,130 $ 844,672 Estimated fair value $ 1,050,749 $ 826,470 $ 858,960

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Jun. 30, 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: June 30, 2019 September 30, 2018 June 30, 2018 Derivative assets: Derivatives designated as hedging instruments: Interest rate contracts $ — $ 30 $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts 944 3,002 1,963 Derivatives not designated as hedging instruments: Commodity contracts — 152 134 Total derivative assets — gross 944 3,184 2,097 Gross amounts offset in the balance sheet (19 ) (146 ) (101 ) Total derivative assets — net (a) $ 925 $ 3,038 $ 1,996 Derivative liabilities: Derivatives designated as hedging instruments: Interest rate contracts $ (4,211 ) $ — $ — Derivatives subject to PGC and DS mechanisms: Commodity contracts (3,085 ) (146 ) (101 ) Derivatives not designated as hedging instruments: Commodity contracts (31 ) — — Total derivative liabilities — gross (7,327 ) (146 ) (101 ) Gross amounts offset in the balance sheet 19 146 101 Total derivative liabilities — net (a) $ (7,308 ) $ — $ — (a) Derivative assets and liabilities with maturities greater than one year are recorded in “ Other assets ” and “ Other noncurrent liabilities
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 nine months ended June 30, 2019 and 2018 : Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Three Months Ended June 30, 2019 2018 2019 2018 Cash Flow Hedges: Interest rate contracts $ (1,683 ) $ — $ (872 ) $ (871 ) Interest expense Gain Recognized in Income Location of Gain Recognized in Income Three Months Ended June 30, 2019 2018 Derivatives Not Subject to PGC and DS Mechanisms: Commodity contracts $ 10 $ 37 Operating and administrative expenses Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Nine Months Ended June 30, 2019 2018 2019 2018 Cash Flow Hedges: Interest rate contracts $ (4,241 ) $ — $ (2,614 ) $ (2,614 ) Interest expense (Loss) Gain Recognized in Income Location of (Loss) Gain Recognized in Income Nine Months Ended June 30, 2019 2018 Derivatives Not Subject to PGC and DS Mechanisms: Commodity contracts $ (257 ) $ 198 Operating and administrative expenses

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Tables)	9 Months Ended
	Jun. 30, 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 nine months ended June 30, 2019 and 2018 : Three Months Ended June 30, 2019 Postretirement Benefit Plans Derivative Instruments Total AOCI — March 31, 2019 $ (6,367 ) $ (19,728 ) $ (26,095 ) Net losses on interest rate contract — (1,197 ) (1,197 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 132 — 132 Reclassifications of net losses on IRPAs — 620 620 AOCI — June 30, 2019 $ (6,235 ) $ (20,305 ) $ (26,540 ) Three Months Ended June 30, 2018 Postretirement Benefit Plans Derivative Instruments Total AOCI — March 31, 2018 $ (8,555 ) $ (16,612 ) $ (25,167 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 220 — 220 Reclassifications of net losses on IRPAs — 592 592 AOCI — June 30, 2018 $ (8,335 ) $ (16,020 ) $ (24,355 ) Nine Months Ended June 30, 2019 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2018 $ (4,920 ) $ (15,409 ) $ (20,329 ) Net losses on interest rate contract — (3,016 ) (3,016 ) Reclassifications of benefit plan actuarial losses and net prior service benefits 397 — 397 Reclassifications of net losses on IRPAs — 1,859 1,859 Reclassification of stranded income tax effects related to TCJA (1,712 ) (3,739 ) (5,451 ) AOCI — June 30, 2019 $ (6,235 ) $ (20,305 ) $ (26,540 ) Nine Months Ended June 30, 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 660 — 660 Reclassifications of net losses on IRPAs — 1,776 1,776 AOCI — June 30, 2018 $ (8,335 ) $ (16,020 ) $ (24,355 )

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Jun. 30, 2019
Segment Reporting [Abstract]
Schedule of Segment Information	Reportable Segments Three Months Ended June 30, 2019 Total Gas Utility Electric Utility Revenues $ 163,893 $ 144,441 $ 19,452 Cost of sales $ 61,021 $ 51,626 $ 9,395 Depreciation $ 23,141 $ 21,612 $ 1,529 Operating income $ 20,325 $ 18,592 $ 1,733 Pension and other postretirement plans non-service income $ 440 $ 387 $ 53 Interest expense $ (12,325 ) $ (11,522 ) $ (803 ) Income before income taxes $ 8,440 $ 7,457 $ 983 Capital expenditures (including the effects of accruals) $ 84,451 $ 79,272 $ 5,179 Reportable Segments Three Months Ended June 30, 2018 Total Gas Utility Electric Utility Revenues $ 159,934 $ 138,597 $ 21,337 Cost of sales $ 72,537 $ 60,837 $ 11,700 Depreciation $ 21,414 $ 20,011 $ 1,403 Operating income (a) $ 4,483 $ 3,126 $ 1,357 Pension and other postretirement plans non-service expense (a) $ (569 ) $ (498 ) $ (71 ) Interest expense $ (10,003 ) $ (9,829 ) $ (174 ) (Loss) income before income taxes $ (6,089 ) $ (7,201 ) $ 1,112 Capital expenditures (including the effects of accruals) $ 79,704 $ 76,546 $ 3,158 Reportable Segments Nine Months Ended June 30, 2019 Total Gas Utility Electric Utility Revenues $ 916,210 $ 842,998 $ 73,212 Cost of sales $ 438,516 $ 398,910 $ 39,606 Depreciation $ 67,956 $ 63,554 $ 4,402 Operating income $ 217,265 $ 208,756 $ 8,509 Pension and other postretirement plans non-service income $ 1,247 $ 1,094 $ 153 Interest expense $ (36,294 ) $ (34,362 ) $ (1,932 ) Income before income taxes $ 182,218 $ 175,488 $ 6,730 Capital expenditures (including the effects of accruals) $ 232,569 $ 221,112 $ 11,457 As of June 30, 2019 Total assets $ 3,375,622 $ 3,191,316 $ 184,306 Goodwill $ 182,145 $ 182,145 $ — Reportable Segments Nine Months Ended June 30, 2018 Total Gas Utility Electric Utility Revenues $ 966,300 $ 894,535 $ 71,765 Cost of sales $ 481,613 $ 440,726 $ 40,887 Depreciation $ 62,926 $ 58,787 $ 4,139 Operating income (a) $ 237,124 $ 232,049 $ 5,075 Pension and other postretirement plans non-service expense (a) $ (1,788 ) $ (1,565 ) $ (223 ) Interest expense $ (32,033 ) $ (31,221 ) $ (812 ) Income before income taxes $ 203,303 $ 199,263 $ 4,040 Capital expenditures (including the effects of accruals) $ 206,492 $ 196,751 $ 9,741 As of June 30, 2018 Total assets $ 3,194,025 $ 3,008,441 $ 185,584 Goodwill $ 182,145 $ 182,145 $ —

Nature of Operations (Details)

Nature of Operations (Details)	9 Months Ended
	Jun. 30, 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	Jun. 30, 2019	Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017
Accounting Policies [Abstract]
Cash and cash equivalents	$ 3,057	$ 10,314	$ 23,181	$ 5,203
Restricted cash	4,255	1,190	805	3,046
Cash, cash equivalents and restricted cash	$ 7,312	$ 11,504	$ 23,986	$ 8,249

Summary of Significant Accoun_5

Summary of Significant Accounting Policies Narrative (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Jun. 30, 2019	Jun. 30, 2019	Jun. 30, 2018	Oct. 01, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenue from contracts with customers	$ 163,341	$ 914,452
Scenario, Previously Reported
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase (decrease) in restricted cash			$ 2,241
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	$ 7,000	$ 39,000

Accounting Changes Accounting C

Accounting Changes Accounting Changes (Details) - USD ($) $ in Thousands	Oct. 01, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Accounting Standards Update 2018-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of stranded income tax effects related to TCJA	$ 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		$ 440	$ (569)	$ 1,247	$ (1,788)

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Oct. 01, 2018
Disaggregation of Revenue [Line Items]
Contract with customer, liability, current	$ 6,915	$ 5,897
Fixed-price Contract
Disaggregation of Revenue [Line Items]
Revenue, remaining performance obligation	$ 193,000

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		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 163,341		$ 914,452
Other revenue, net	552		1,758
Revenues	163,893	$ 159,934	916,210	$ 966,300
Public Utilities, Negative Surcharge In Revenue	3,299		(11,325)
Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	78,103		494,110
Commercial & industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	34,274		202,534
Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	27,857		111,442
Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	14,115		98,649
Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	8,992		7,717
Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	19,452		73,212
Other revenue, net	0		0
Revenues	19,452		73,212
Electric Utilities | Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	11,713		48,435
Electric Utilities | Commercial & industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	5,557		18,030
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	2,182		6,747
Gas Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	143,889		841,240
Other revenue, net	552		1,758
Revenues	144,441	$ 138,597	842,998	$ 894,535
Gas Utility | Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	66,390		445,675
Gas Utility | Commercial & industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	28,717		184,504
Gas Utility | Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	27,857		111,442
Gas Utility | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	14,115		98,649
Gas Utility | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 6,810		$ 970

Inventories - Schedule of Inven

Inventories - Schedule of Inventories (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Sep. 30, 2018	Jun. 30, 2018
Public Utilities, Inventory
Total inventories	$ 32,263	$ 52,413	$ 34,663
Gas Utility natural gas
Public Utilities, Inventory
Total inventories	15,465	37,287	18,608
Materials, supplies and other
Public Utilities, Inventory
Total inventories	$ 16,798	$ 15,126	$ 16,055

Inventories - Narrative (Detail

Inventories - Narrative (Details) $ in Thousands	9 Months Ended
	Jun. 30, 2019USD ($)agreementBcf	Sep. 30, 2018USD ($)Bcf	Jun. 30, 2018USD ($)Bcf
Public Utilities, Inventory
Number of storage agreements | agreement	4
Number of storage agreements with Energy Services | agreement	4
Volume of gas storage inventories released under SCAAs with non-affiliates (in bcf) | Bcf	3.3	9	4.7
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $	$ 8,234	$ 23,136	$ 11,944
Security deposit liability | $	$ 7,640	$ 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	Jun. 30, 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			$ 9,254
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	Jun. 30, 2019	Sep. 30, 2018	Jun. 30, 2018
Regulatory Assets
Regulatory assets	$ 300,677	$ 301,002	$ 360,061
Regulatory Liabilities
Regulatory liabilities	376,170	390,175	412,451
Income taxes recoverable
Regulatory Assets
Regulatory assets	123,901	110,129	130,024
Underfunded pension and postretirement plans
Regulatory Assets
Regulatory assets	81,791	87,106	132,239
Environmental costs
Regulatory Assets
Regulatory assets	56,561	58,836	59,808
Removal costs, net
Regulatory Assets
Regulatory assets	29,339	32,025	30,987
Other
Regulatory Assets
Regulatory assets	9,085	12,906	7,003
Postretirement benefits
Regulatory Liabilities
Regulatory liabilities	16,481	17,781	16,895
Deferred fuel and power refunds
Regulatory Liabilities
Regulatory liabilities	12,416	36,723	44,500
State tax benefits — distribution system repairs
Regulatory Liabilities
Regulatory liabilities	25,176	22,611	20,677
PAPUC temporary rates order
Regulatory Liabilities
Regulatory liabilities	25,414	24,430	24,098
Excess federal deferred income taxes
Regulatory Liabilities
Regulatory liabilities	282,735	285,221	301,151
Other
Regulatory Liabilities
Regulatory liabilities	$ 13,948	$ 3,409	$ 5,130

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

Jun. 30, 2018

Jun. 30, 2019

Sep. 30, 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 | 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)

$ 1,863

$ 1,863

$ (2,141)

$ 2,856

Debt (Details)

Debt (Details)	Jun. 27, 2019USD ($)	Jun. 26, 2019USD ($)	Feb. 01, 2019USD ($)
2019 Credit Agreement
Debt Instrument [Line Items]
Debt instrument, covenant terms, consolidated debt to consolidated total capital ratio	0.65
Line of Credit | 2019 Credit Agreement
Debt Instrument [Line Items]
Credit limit	$ 350,000,000
Additional borrowing amount	$ 150,000,000
UGI Utilities | Senior Notes | 4.55% Senior Notes due February 2049
Debt Instrument [Line Items]
Aggregate principal amount			$ 150,000,000
Debt instrument, interest rate, stated percentage			4.55%
Debt instrument, covenant terms, consolidated debt to consolidated total capital ratio			0.65
Minimum | Line of Credit | 2019 Credit Agreement
Debt Instrument [Line Items]
Margin on borrowing	0.00%
Maximum | Line of Credit | 2019 Credit Agreement
Debt Instrument [Line Items]
Margin on borrowing	1.75%
Letter of Credit | Line of Credit | 2019 Credit Agreement
Debt Instrument [Line Items]
Credit limit	$ 100,000,000
Revolving Credit Facility | Line of Credit | UGI Utilities International Credit Agreement
Debt Instrument [Line Items]
Credit limit		$ 450,000,000

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Thousands	Jul. 02, 2017USD ($)	Jun. 30, 2019USD ($)subsidiary	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)
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		$ 47,560	$ 50,970	$ 52,231
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		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 1,637	$ 1,882	$ 4,912	$ 5,644
Interest cost	6,050	5,766	18,151	17,300
Expected return on assets	(8,140)	(7,776)	(24,420)	(23,330)
Amortization of:
Prior service cost (benefit)	63	61	188	187
Actuarial loss	1,721	2,984	5,162	8,952
Net benefit cost (benefit)	1,331	2,917	3,993	8,753
Change in associated regulatory liabilities	0	0	0	0
Net benefit cost (benefit) after change in regulatory liabilities	1,331	2,917	3,993	8,753
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	31	66	94	200
Interest cost	109	111	327	335
Expected return on assets	(185)	(178)	(554)	(532)
Amortization of:
Prior service cost (benefit)	(109)	(110)	(327)	(330)
Actuarial loss	17	23	51	71
Net benefit cost (benefit)	(137)	(88)	(409)	(256)
Change in associated regulatory liabilities	(343)	(122)	(1,028)	(368)
Net benefit cost (benefit) after change in regulatory liabilities	$ (480)	$ (210)	$ (1,437)	$ (624)

Defined Benefit Pension and O_4

Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) - USD ($)	9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Pension Benefits
Defined Benefit Plan Disclosure
Contribution made to Pension Plan	$ 8,234,000	$ 10,079,000
Expected contribution to pensions plans in the remainder of current fiscal year	3,000,000
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	Jun. 30, 2019	Sep. 30, 2018	Jun. 30, 2018
Commodity contracts
Assets:
Derivative assets	$ 944	$ 3,154	$ 2,097
Liabilities:
Derivative liabilities	(3,116)	(146)	(101)
Interest rate contracts
Assets:
Derivative Asset		30
Liabilities:
Derivative liabilities	(4,211)
Level 1 | Commodity contracts
Assets:
Derivative assets	944	3,154	2,097
Liabilities:
Derivative liabilities	(3,116)	(146)	(101)
Level 1 | Interest rate contracts
Assets:
Derivative Asset		0
Liabilities:
Derivative liabilities	0
Level 2 | Commodity contracts
Assets:
Derivative assets	0	0	0
Liabilities:
Derivative liabilities	0	0	0
Level 2 | Interest rate contracts
Assets:
Derivative Asset		30
Liabilities:
Derivative liabilities	(4,211)
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	Jun. 30, 2019	Sep. 30, 2018	Jun. 30, 2018
Carrying amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 985,876	$ 842,130	$ 844,672
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 1,050,749	$ 826,470	$ 858,960

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Narrative (Details) $ in Thousands, MMBTU in Millions	9 Months Ended
	Jun. 30, 2019USD ($)MMBTU	Sep. 30, 2018USD ($)MMBTU	Jun. 30, 2018USD ($)MMBTU	Sep. 30, 2017USD ($)
Derivative
Restricted cash	$ 4,255	$ 1,190	$ 805	$ 3,046
IRPAs
Derivative
Derivative, notional amount	0	$ 0	$ 0
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	$ 3,500
Gas Utility
Derivative
Notional amount (energy measure) (in mmbtu) | MMBTU	16.5	23.2	16.8
Maximum length of time hedged in price risk cash flow hedges (in months)	15 months
Electric Utility | Electric Utility Electric Transmission Congestion
Derivative
Derivative, notional amount	$ 114,063
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	Jun. 30, 2019	Sep. 30, 2018	Jun. 30, 2018
Derivative assets
Derivative assets:
Derivative assets	$ 944	$ 3,184	$ 2,097
Gross amounts offset in the balance sheet	(19)	(146)	(101)
Total derivative assets — net (a)	925	3,038	1,996
Derivative assets | Derivatives subject to PGC and DS mechanisms:
Derivative assets:
Derivative assets	944	3,002	1,963
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	134
Derivative liabilities
Derivative liabilities:
Derivative liabilities	(7,327)	(146)	(101)
Gross amounts offset in the balance sheet	19	146	101
Total derivative liabilities — net (a)	(7,308)	0	0
Derivative liabilities | Derivatives subject to PGC and DS mechanisms:
Derivative liabilities:
Derivative liabilities	(3,085)	(146)	(101)
Derivative liabilities | Designated as Hedging Instrument | Interest rate contracts
Derivative liabilities:
Derivative liabilities	(4,211)	0	0
Derivative liabilities | Not designated as hedging instruments | Commodity contracts
Derivative liabilities:
Derivative liabilities	$ (31)	$ 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		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivatives Not Subject to PGC and DS Mechanisms: | Operating and administrative expenses
Derivative Instruments, Gain (Loss)
Location of (Loss) Gain Recognized in Income	$ 10	$ 37
Not designated as hedging instruments | Commodity contracts | Operating and administrative expenses
Derivative Instruments, Gain (Loss)
Location of (Loss) Gain Recognized in Income			$ (257)	$ 198
Cash Flow Hedges | Interest rate contracts
Derivative Instruments, Gain (Loss)
Loss Recognized in AOCI	(1,683)	0	(4,241)	0
Cash Flow Hedges | Interest rate contracts | Interest expense
Derivative Instruments, Gain (Loss)
Location of Loss Reclassified from AOCI into Income	$ (872)	$ (871)	$ (2,614)	$ (2,614)

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance			$ 1,093,288
Reclassifications, net of tax	$ 132	$ 220	397	$ 660
AOCI, net of tax - end balance	1,213,023	1,099,805	1,213,023	1,099,805
IRPAs
Accumulated Other Comprehensive Income (Loss)
Other comprehensive income (loss), before reclassifications, net of tax	(1,197)		(3,016)
Reclassifications, net of tax	620	592	1,859	1,776
Reclassification of stranded income tax effects related to TCJA			(5,451)
Postretirement Benefit Plans
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(6,367)	(8,555)	(4,920)	(8,995)
Reclassifications, net of tax	132	220	397	660
AOCI, net of tax - end balance	(6,235)	(8,335)	(6,235)	(8,335)
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
Reclassification of stranded income tax effects related to TCJA			(1,712)
Derivative Instruments
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(19,728)	(16,612)	(15,409)	(17,796)
Reclassifications, net of tax	0	0	0	0
AOCI, net of tax - end balance	(20,305)	(16,020)	(20,305)	(16,020)
Derivative Instruments | IRPAs
Accumulated Other Comprehensive Income (Loss)
Other comprehensive income (loss), before reclassifications, net of tax	(1,197)		(3,016)
Reclassifications, net of tax	620	592	1,859	1,776
Reclassification of stranded income tax effects related to TCJA			(3,739)
Total
Accumulated Other Comprehensive Income (Loss)
AOCI, net of tax - beginning balance	(26,095)	(25,167)	(20,329)	(26,791)
AOCI, net of tax - end balance	$ (26,540)	$ (24,355)	$ (26,540)	$ (24,355)

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2019USD ($)Bcf	Jun. 30, 2018USD ($)Bcf	Jun. 30, 2019USD ($)Bcf	Jun. 30, 2018USD ($)Bcf	Sep. 30, 2018USD ($)Bcf
Related Party Transaction
Related party costs incurred	$ 2,861	$ 4,325	$ 11,571	$ 10,780
UGI and Subsidiaries | Administrative Services
Related Party Transaction
Amount of related party transaction	$ 1,536	$ 1,665	$ 4,228	$ 4,070
Energy Services
Related Party Transaction
Volume of gas storage inventory (in bcf of natural gas) | Bcf	3.3	3.6	3.3	3.6	6.7
Natural gas storage inventory, related parties, current	$ 8,234	$ 9,294	$ 8,234	$ 9,294	$ 17,701
Revenue from related parties	10,041	11,582	$ 57,467	93,974
Term of agreements (in years)			1 year
Purchases from related party	16,568	19,429	$ 107,245	140,455
Energy Services | SCAAs
Related Party Transaction
Amount of related party transaction	784	701	$ 2,303	2,127
SCAA contract term (in years)			3 years
Related party costs incurred	7,045	8,114	$ 10,314	11,394
Related party security deposits	7,640	11,040	7,640	11,040	$ 13,840
Energy Services | Exclusive of Transactions Pursuant SCAAs
Related Party Transaction
Related party costs incurred	$ 3,222	$ 5,828	$ 93,579	$ 87,782

Segment Information - Narrative

Segment Information - Narrative (Details)	9 Months Ended
	Jun. 30, 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		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Sep. 30, 2018
Segment Reporting Information
Revenues	$ 163,893	$ 159,934	$ 916,210	$ 966,300
Cost of sales	61,021	72,537	438,516	481,613
Depreciation	23,141	21,414	67,956	62,926
Operating income	20,325	4,483	217,265	237,124
Pension and other postretirement plans non-service income	440	(569)	1,247	(1,788)
Interest expense	(12,325)	(10,003)	(36,294)	(32,033)
Income (loss) before income taxes	8,440	(6,089)	182,218	203,303
Capital expenditures (including the effects of accruals)	84,451	79,704	232,569	206,492
Total assets	3,375,622	3,194,025	3,375,622	3,194,025	$ 3,266,576
Goodwill	182,145	182,145	182,145	182,145	$ 182,145
Gas Utility
Segment Reporting Information
Revenues	144,441	138,597	842,998	894,535
Cost of sales	51,626	60,837	398,910	440,726
Depreciation	21,612	20,011	63,554	58,787
Operating income	18,592	3,126	208,756	232,049
Pension and other postretirement plans non-service income	387	(498)	1,094	(1,565)
Interest expense	(11,522)	(9,829)	(34,362)	(31,221)
Income (loss) before income taxes	7,457	(7,201)	175,488	199,263
Capital expenditures (including the effects of accruals)	79,272	76,546	221,112	196,751
Total assets	3,191,316	3,008,441	3,191,316	3,008,441
Goodwill	182,145	182,145	182,145	182,145
Electric Utility
Segment Reporting Information
Revenues	19,452	21,337	73,212	71,765
Cost of sales	9,395	11,700	39,606	40,887
Depreciation	1,529	1,403	4,402	4,139
Operating income	1,733	1,357	8,509	5,075
Pension and other postretirement plans non-service income	53	(71)	153	(223)
Interest expense	(803)	(174)	(1,932)	(812)
Income (loss) before income taxes	983	1,112	6,730	4,040
Capital expenditures (including the effects of accruals)	5,179	3,158	11,457	9,741
Total assets	184,306	185,584	184,306	185,584
Goodwill	$ 0	$ 0	$ 0	$ 0