Ugi Utilities 10-K 21 Nov 17 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2017	Nov. 14, 2017	Mar. 31, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	100,548
Document Type	10-K
Document Period End Date	Sep. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		26,781,785
Entity Public Float			$ 0

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Current assets:
Cash and cash equivalents	$ 5,203	$ 2,819
Restricted cash	3,046	583
Accounts receivable (less allowances for doubtful accounts of $4,052 and $3,946, respectively)	53,720	44,692
Accounts receivable — related parties	2,807	398
Accrued utility revenues	13,296	12,753
Inventories	53,309	42,340
Prepaid income taxes	7,711	1,956
Regulatory assets	8,338	3,208
Derivative instruments	1,354	4,263
Prepaid expenses	8,450	10,499
Other current assets	7,956	11,510
Total current assets	165,190	135,021
Property, plant and equipment	3,285,329	2,998,915
Less accumulated depreciation and amortization	(1,010,781)	(975,374)
Net property, plant and equipment	2,274,548	2,023,541
Goodwill	182,145	182,145
Regulatory assets	360,591	391,933
Other assets	11,541	10,451
Total assets	2,994,015	2,743,091
Current liabilities:
Current maturities of long-term debt	39,996	19,986
Short-term borrowings	170,000	112,500
Accounts payable — trade	71,559	65,180
Accounts payable — related parties	6,890	3,995
Employee compensation and benefits accrued	21,851	16,323
Interest accrued	16,200	7,605
Customer deposits and advances	35,278	41,391
Derivative instruments	1,071	310
Regulatory liability — deferred fuel and power refunds	10,621	22,299
Other current liabilities	40,016	44,321
Total current liabilities	413,482	333,910
Long-term debt	711,105	651,455
Deferred income taxes	635,465	550,229
Deferred investment tax credits	2,950	3,268
Pension and other postretirement benefit obligations	143,674	184,516
Other noncurrent liabilities	99,434	94,976
Total liabilities	2,006,110	1,818,354
Commitments and contingencies (Note 12)
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
Additional paid-in capital	473,580	473,580
Retained earnings	480,857	422,516
Accumulated other comprehensive loss	(26,791)	(31,618)
Total common stockholder’s equity	987,905	924,737
Total liabilities and stockholder’s equity	$ 2,994,015	$ 2,743,091

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Current assets:
Allowance for doubtful accounts	$ 4,052	$ 3,946
Common stockholder’s equity:
Common stock, par value (in usd per share)	$ 2.25	$ 2.25
Common stock, shares authorized (in shares)	40,000,000	40,000,000
Common stock, shares issued (in shares)	26,781,785	26,781,785
Common stock, shares outstanding (in shares)	26,781,785	26,781,785

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Income Statement [Abstract]
Revenues	$ 887,588	$ 768,484	$ 1,041,581
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	367,279	289,786	510,784
Operating and administrative expenses	199,997	180,842	206,319
Operating and administrative expenses — related parties	12,354	11,863	11,956
Taxes other than income taxes	15,648	15,789	16,134
Depreciation	69,778	64,260	59,841
Amortization	2,554	3,043	3,749
Other operating (income) expense, net	(8,329)	2,000	(8,869)
Costs and expenses	659,281	567,583	799,914
Operating income	228,307	200,901	241,667
Interest expense	40,212	37,630	41,128
Income before income taxes	188,095	163,271	200,539
Income taxes	72,054	65,898	79,484
Net income	$ 116,041	$ 97,373	$ 121,055

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net income	$ 116,041	$ 97,373	$ 121,055
Net losses on derivative instruments (net of tax of $0, $12,016 and $2,911, respectively)	0	(16,942)	(4,105)
Reclassifications of net losses on derivative instruments (net of tax of $(1,409), $(1,112) and $(1,109), respectively)	1,988	1,568	1,565
Benefit plans, principally actuarial gains (losses) (net of tax of $(1,336), $2,267 and $2,469, respectively)	1,883	(3,197)	(3,482)
Reclassifications of benefit plans actuarial losses and net prior service credits (net of tax of $(678), $(454) and $(367), respectively)	956	639	517
Other comprehensive income (loss)	4,827	(17,932)	(5,505)
Comprehensive income	$ 120,868	$ 79,441	$ 115,550

Consolidated Statements of Com6

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Tax on (loss) gain on derivative instruments	$ 0	$ 12,016	$ 2,911
Tax on reclassifications of net losses (gains) on derivative instruments	(1,409)	(1,112)	(1,109)
Tax on benefit plans	(1,336)	2,267	2,469
Tax on reclassification of benefits plans actuarial losses and prior service cost	$ (678)	$ (454)	$ (367)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 116,041	$ 97,373	$ 121,055
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	72,332	67,303	63,590
Deferred income taxes, net	78,568	76,938	29,356
Pension contributions, net of pension cost	4,017	1,580	(1,415)
Settlement of interest rate protection agreements	0	(35,975)	0
Provision for uncollectible accounts	8,030	7,760	13,498
Other, net	9,664	(10,112)	3,228
Net change in:
Accounts receivable and accrued utility revenues	(25,253)	1,120	7,297
Inventories	(10,969)	9,376	43,503
Deferred fuel costs, net of changes in unsettled derivatives	(15,385)	(22,740)	51,778
Accounts payable	2,107	(3,053)	(7,649)
Other current assets	(2,108)	(70)	(9,723)
Other current liabilities	6,550	15,870	(7,808)
Net cash provided by operating activities	243,594	205,370	306,710
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(305,311)	(250,584)	(203,192)
Net costs of property, plant and equipment disposals	(12,735)	(7,940)	(10,443)
(Increase) decrease in restricted cash	(2,463)	6,019	(3,010)
Net cash used by investing activities	(320,509)	(252,505)	(216,645)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(57,700)	(47,000)	(65,600)
Increase (decrease) in short-term borrowings	57,500	40,800	(14,600)
Issuances of long-term debt, net of issuance costs	99,499	298,379	0
Repayments of long-term debt	(20,000)	(247,000)	(20,000)
Excess tax benefits from equity-based payment arrangements	0	1,676	833
Net cash provided (used) by financing activities	79,299	46,855	(99,367)
Cash and cash equivalents increase (decrease)	2,384	(280)	(9,302)
CASH AND CASH EQUIVALENTS:
End of year	5,203	2,819	3,099
Beginning of year	2,819	3,099	12,401
Increase (decrease)	2,384	(280)	(9,302)
Cash paid (received) for:
Interest	29,449	36,155	38,405
Income taxes	$ 2,080	$ (19,758)	$ 54,427

Consolidated Statements of Stoc

Consolidated Statements of Stockholder's Equity - USD ($) $ in Thousands	Total	Common stock, without par value	Retained earnings	Additional paid-in capital	Accumulated other comprehensive income (loss)
Balance, beginning of year at Sep. 30, 2014		$ 60,259	$ 316,688	$ 471,071	$ (8,181)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 121,055		121,055
Cash dividends — Common Stock			(65,600)
Excess tax benefits on equity-based compensation				833
Net losses on derivative instruments	(4,105)				(4,105)
Reclassifications of net losses on derivative instruments	1,565				1,565
Benefit plans, principally actuarial gains (losses)					(3,482)
Reclassifications of benefit plans actuarial losses and net prior service credits	517				517
Balance, end of year at Sep. 30, 2015	890,620	60,259	372,143	471,904	(13,686)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	97,373		97,373
Cash dividends — Common Stock			(47,000)
Excess tax benefits on equity-based compensation				1,676
Net losses on derivative instruments	(16,942)				(16,942)
Reclassifications of net losses on derivative instruments	1,568				1,568
Benefit plans, principally actuarial gains (losses)					(3,197)
Reclassifications of benefit plans actuarial losses and net prior service credits	639				639
Balance, end of year at Sep. 30, 2016	924,737	60,259	422,516	473,580	(31,618)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	116,041		116,041
Cash dividends — Common Stock			(57,700)
Excess tax benefits on equity-based compensation				0
Net losses on derivative instruments	0				0
Reclassifications of net losses on derivative instruments	1,988				1,988
Benefit plans, principally actuarial gains (losses)					1,883
Reclassifications of benefit plans actuarial losses and net prior service credits	956				956
Balance, end of year at Sep. 30, 2017	$ 987,905	$ 60,259	$ 480,857	$ 473,580	$ (26,791)

Nature of Operations

Nature of Operations	12 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations	NATURE OF OPERATIONS UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”), own and operate natural gas distribution utilities in eastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.” Prior to June 1, 2015, PNG also had a heating, ventilation and air-conditioning service business which operated principally in the PNG service territory (“PNG HVAC Business”). The assets of the PNG HVAC Business principally comprising customer contracts were sold on June 1, 2015. The term “UGI Utilities” is used herein as an abbreviated reference to UGI Utilities, Inc., or collectively to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions. Certain prior-year amounts have been reclassified to conform to the current-year presentation. Principles of Consolidation Our consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or “the Company”). We eliminate intercompany accounts when we consolidate. Effects of Regulation UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator. For additional information regarding the effects of rate regulation on our utility operations, see Note 4 . Fair Value Measurements The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements performed on a recurring basis principally relate to derivative instruments. GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: • Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. • Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. • Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments. Derivative Instruments Derivative instruments are reported on the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or is designated and qualifies for hedge accounting. Gains and losses on substantially all of the derivative instruments used by UGI Utilities (for which NPNS has not been elected) to hedge commodity prices are included in regulatory assets and liabilities in accordance with GAAP regarding accounting for rate-regulated entities. Certain of our derivative instruments are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative financial instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Certain other commodity derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments are included in cash flows from operating activities. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 14 . Revenue Recognition UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service rendered and commodities delivered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered. We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice. Accounts Receivable Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible. Income Taxes We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse. We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is consistent with income taxes calculated on a separate return basis. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. Cash and Cash Equivalents For cash flow purposes, cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities of three months or less when purchased. Restricted Cash Restricted cash represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. Inventories Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for substantially all of our inventory. Property, Plant and Equipment and Related Depreciation We record property, plant and equipment at original cost. Capitalized costs include labor, materials and other direct and indirect costs, and allowance for funds used during construction (“AFUDC”). The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition. We record depreciation expense for Utilities’ plant and equipment on a straight-line basis based upon projected service lives of the various classes of its depreciable property. The estimated useful lives of the classes of depreciable property are reviewed by a third party and adjusted, if necessary, as part of periodic service life studies required by the PUC. The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2017 , 2016 and 2015 were as follows: 2017 2016 2015 Gas Utility 2.2 % 2.2 % 2.2 % Electric Utility 2.4 % 2.5 % 2.5 % When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over five years , consistent with prior ratemaking treatment (See Note 4 ). We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. Information technology costs associated with major system installations, conversions and improvements, such as software training, data conversion, business process reengineering costs and preliminary project stage costs are deferred as a regulatory asset if the Company expects to recover these costs in future rates, and the deferral is reported as a component of property, plant and equipment. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use. No depreciation expense is included in cost of sales in the Consolidated Statements of Income. Goodwill Our goodwill is the result of Gas Utility business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance simplifying the test for goodwill impairment. The adoption of the new guidance did not impact the consolidated financial statements (see Note 3). We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value. From time to time, we may assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. From time to time, we may bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit. No provisions for goodwill impairments were recorded during Fiscal 2017 , Fiscal 2016 or Fiscal 2015 . Impairment of Long-Lived Assets We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No provisions for impairments were recorded during Fiscal 2017 , Fiscal 2016 or Fiscal 2015 . Employee Retirement Plans We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 9 ). Equity-Based Compensation All of our equity-based compensation, principally comprising UGI stock options and grants of UGI stock-based equity instruments (“UGI Units”), is measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, equity-based compensation costs are measured based upon the fair value of the award on the date of grant or the fair value of the award as of the end of each reporting period. In Fiscal 2017, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. (see Note 3). For additional information on our equity-based compensation plans and related disclosures, see Note 11 . Environmental Matters We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites. Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see Note 12 .

Accounting Changes

Accounting Changes	12 Months Ended
	Sep. 30, 2017
Accounting Changes and Error Corrections [Abstract]
Accounting Changes	ACCOUNTING CHANGES Adoption of New Accounting Standard Cash Flow Classification. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance on the classification of certain cash receipts and payments in the statement of cash flows. The guidance is generally required to be applied retrospectively. The adoption of the new guidance did not impact our consolidated financial statements. Goodwill Impairment. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance regarding the test for goodwill impairment. Under the new accounting guidance, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements. Employee Share-based Payments. Effective October 1, 2016, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. The adoption of the new accounting guidance did not have a material impact on our financial statements. Accounting Standards Not Yet Adopted Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue. The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities and Regulatory Matters	12 Months Ended
	Sep. 30, 2017
Regulated Operations [Abstract]
Regulatory Assets and Liabilities and Regulatory Matters	REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS The following regulatory assets and liabilities are included in our Consolidated Balance Sheets at September 30: 2017 2016 Regulatory assets: Income taxes recoverable $ 121,421 $ 115,643 Underfunded pension and postretirement plans 141,310 183,129 Environmental costs 61,566 59,397 Deferred fuel and power costs 7,685 151 Removal costs, net 30,996 27,956 Other 5,951 8,865 Total regulatory assets $ 368,929 $ 395,141 Regulatory liabilities (a): Postretirement benefits overcollections $ 17,493 $ 17,519 Deferred fuel and power refunds 10,621 22,299 State income tax benefits — distribution system repairs 18,430 15,086 Other 2,686 665 Total regulatory liabilities $ 49,230 $ 55,569 (a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Consolidated Balance Sheets. Other than removal costs, UGI Utilities currently does not recover a rate of return on the regulatory assets included in the table above. Income taxes recoverable . This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of the tax benefit on accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. UGI Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 65 years . Underfunded pension and other postretirement plans . This regulatory asset represents the portion of net actuarial losses and prior service costs (credits) associated with pension and other postretirement benefits which are probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants. Environmental costs . Environmental costs principally represent estimated probable future environmental remediation and investigation costs that UGI Gas, CPG and PNG expect to incur, primarily at Manufactured Gas Plant (“MGP”) sites in Pennsylvania, in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (“DEP”). Pursuant to base rate orders, UGI Gas, PNG and CPG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2017 , the period over which UGI Gas, PNG and CPG expect to recover these costs will depend upon future remediation activity. For additional information on environmental costs, see Note 12 . Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. As required by PUC ratemaking, removal costs include actual costs incurred associated with asset retirement obligations. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over five years . Postretirement benefit overcollections . This regulatory liability represents the difference between amounts recovered through rates by UGI Gas and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With respect to UGI Gas, postretirement benefit overcollections are generally being refunded to customers over a ten -year period beginning October 19, 2016, the date UGI Gas’ Joint Petition pursuant to its January 19, 2016 base rate filing became effective (see “Base Rate Filings” below). With respect to Electric Utility, the excess of the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits is being deferred for future rate refund to customers. Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability. Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains on such contracts at September 30, 2017 and 2016 , were $ 146 and $ 4,263 , respectively. In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at September 30, 2017 and 2016 , were not material. State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal benefit, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets. Other . Other regulatory assets and liabilities comprise a number of deferred items including, among others, a portion of preliminary stage information technology costs, energy efficiency conservation costs and rate case expenses. Other Regulatory Matters Base Rate Filings. On January 19, 2017, PNG filed a rate request with the PUC 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 PUC providing for an $11,250 PNG annual base distribution rate increase. On August 31, 2017, the PUC approved the Joint Petition and the increase became effective October 20, 2017. On January 19, 2016, UGI Utilities filed a rate request with the PUC to increase UGI Gas’s annual base operating revenues for residential, commercial and industrial customers by $58,600 . The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2016, a Joint Petition for Approval of Settlement of all issues providing for a $27,000 UGI Gas annual base distribution rate increase, to be effective October 19, 2016, was filed with the PUC (“Joint Petition”). On October 14, 2016, the PUC approved the Joint Petition with a minor modification which had no effect on the $27,000 base distribution rate increase. The increase became effective on October 19, 2016. Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at 5% of distribution charges billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero , in 2014. PNG and CPG began charging a DSIC at a rate other than zero , beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from 5% to 10% of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018. On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case. Preliminary Stage Information Technology Costs. During Fiscal 2016, we determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during Fiscal 2016, we capitalized $5,830 of such project costs ( $5,375 of which had been expensed prior to Fiscal 2016) and recorded associated increases to utility property, plant and equipment ( $2,755 ) and regulatory assets ( $3,075 ). Subsequent to this determination, we continue to capitalize such preliminary stage project costs in accordance with GAAP related to regulated entities.

Inventories

Inventories	12 Months Ended
	Sep. 30, 2017
Inventory Disclosure [Abstract]
Inventories	INVENTORIES Inventories comprise the following at September 30: 2017 2016 Gas Utility natural gas $ 39,486 $ 29,223 Materials, supplies and other 13,823 13,117 Total inventories $ 53,309 $ 42,340 At September 30, 2017 , UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) having terms ranging from one to three years. Four of the SCAAs were with UGI Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 18 ), and one of the SCAAs was with a non-affiliate. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above. The carrying values of gas storage inventories released under the SCAAs at September 30, 2017 and 2016 , comprising 9.1 billion cubic feet (“bcf”) and 8.1 bcf of natural gas, were $26,064 and $18,773 , respectively. At September 30, 2017 and 2016 , UGI Utilities held a total of $15,040 and $19,100 , respectively, of security deposits received from its SCAA counterparties. These amounts are included in “ Other current liabilities ” on the Consolidated Balance Sheets. For additional information related to the SCAAs with Energy Services, see Note 18 .

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Sep. 30, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment comprise the following categories at September 30: 2017 2016 Distribution $ 2,835,339 $ 2,634,191 Transmission 96,430 93,454 Construction in process 112,563 103,929 General and other 240,997 167,341 Total property, plant and equipment $ 3,285,329 $ 2,998,915

Debt

Debt	12 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Debt	DEBT Long-term debt comprises the following at September 30: 2017 2016 Senior Notes: 4.12%, due September 2046 $ 200,000 $ 200,000 4.98%, due March 2044 175,000 175,000 4.12%, due October 2046 100,000 — 6.21%, due September 2036 100,000 100,000 2.95%, due June 2026 100,000 100,000 Medium-Term Notes: 6.17%, due June 2017 — 20,000 7.25%, due November 2017 20,000 20,000 5.67%, due January 2018 20,000 20,000 6.50%, due August 2033 20,000 20,000 6.13%, due October 2034 20,000 20,000 Total long-term debt 755,000 675,000 Less: unamortized debt issuance costs (3,899 ) (3,559 ) Less: current maturities (39,996 ) (19,986 ) Total long-term debt due after one year $ 711,105 $ 651,455 Principal payments on long-term debt during the next five fiscal years is as follows: $ 40,000 is due in Fiscal 2018 ; $ 0 is due in Fiscal 2019 through Fiscal 2022 . Pursuant to a note purchase agreement, in October 2016, UGI Utilities issued $100,000 aggregate principal amount of 4.12% Senior Notes due October 2046 (the “ 4.12% Senior Notes”). The net proceeds of the issuance of the 4.12% Senior Notes were used (1) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and information technology initiatives and (2) for general corporate purposes. The 4.12% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. On October 31, 2017, UGI Utilities entered into a $125,000 unsecured term loan (the “Term Loan”) with a group of banks which initially matures on October 30, 2018. Such maturity will be automatically extended to October 30, 2022 once UGI Utilities delivers to the agent a copy of the securities certificate registered with the PUC authorizing UGI Utilities’ incurring indebtedness with such maturity date. Proceeds from the Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Term Loan is payable in equal quarterly installments of $1,563 with the balance of the principal being due and payable in full on the maturity date. Under the term loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The Term Loan requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. UGI Utilities has an unsecured credit agreement (the “Credit Agreement”) with a group of banks providing for borrowings of up to $300,000 (including a $100,000 sublimit for letters of credit) which expires in March 2020. Under the 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. UGI Utilities had borrowings outstanding under the credit agreements, which we classify as “ Short-term borrowings ” on the Consolidated Balance Sheets, totaling $170,000 and $112,500 at September 30, 2017 and 2016 , respectively. The weighted-average interest rates on the credit agreement borrowings at September 30, 2017 and 2016 were 2.11% and 1.42% , respectively. Issued and outstanding letters of credit, which reduce available borrowings under the credit agreements, totaled $2,009 and $2,009 at September 30, 2017 and 2016 , respectively. Restrictive Covenants. Certain of UGI Utilities 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. These Senior Notes also contain restrictive and financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00 . The UGI Utilities Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.

Income Taxes

Income Taxes	12 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES The provisions for income taxes consist of the following: 2017 2016 2015 Current expense (benefit): Federal $ (12,253 ) $ (17,845 ) $ 34,990 State 5,739 6,805 15,138 Total current (benefit) expense (6,514 ) (11,040 ) 50,128 Deferred expense (benefit): Federal 70,293 71,005 28,877 State 8,593 6,262 815 Investment tax credit amortization (318 ) (329 ) (336 ) Total income tax expense $ 72,054 $ 65,898 $ 79,484 A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows: 2017 2016 2015 U.S. federal statutory tax rate 35.0 % 35.0 % 35.0 % Difference in tax rate due to: State income taxes, net of federal benefit 5.0 5.2 5.1 Excess tax benefits on share-based payments (0.9 ) — — Other, net (0.8 ) 0.2 (0.5 ) Effective tax rate 38.3 % 40.4 % 39.6 % Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , the beneficial effects of state tax flow through of accelerated depreciation reduced tax expense by $2,537 , $1,344 and $1,539 , respectively. Deferred tax liabilities (assets) comprise the following at September 30: 2017 2016 Excess book basis over tax basis of property, plant and equipment $ 564,327 $ 491,038 Goodwill 49,588 45,070 Derivative financial instruments — 948 Regulatory assets 136,093 149,660 Other 3,140 2,910 Gross deferred tax liabilities 753,148 689,626 Pension plan liabilities (57,011 ) (74,129 ) Allowance for doubtful accounts (1,681 ) (1,637 ) Deferred investment tax credits (1,224 ) (1,356 ) Employee-related expenses (6,793 ) (5,247 ) Regulatory liabilities (12,780 ) (16,798 ) Environmental liabilities (22,224 ) (22,757 ) Derivative financial instruments (354 ) — Other (15,616 ) (17,473 ) Gross deferred tax assets (117,683 ) (139,397 ) Net deferred tax liabilities $ 635,465 $ 550,229 We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. UGI’s federal income tax returns are settled through the tax year 2013. We file separate company income tax returns in various other states but are subject to state income tax principally in Pennsylvania. Pennsylvania income tax returns are generally subject to examination for a period of three years after the filing of the respective returns. During Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , interest (income) expense of $(73) , $204 and $0 , respectively, was recognized in income taxes in the Consolidated Statements of Income. As of September 30, 2017 , we have unrecognized income tax benefits totaling $1,829 including related accrued interest of $132 . If these unrecognized tax benefits were subsequently recognized, $940 would be recorded as a benefit to income taxes on the Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. There is no material change expected in unrecognized tax benefits and related interest in the next twelve months. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: 2017 2016 2015 Unrecognized tax benefits – beginning of year $ 2,055 $ — $ — Additions for tax positions taken in prior years 604 2,055 — Additions for tax positions of the current year — — — Settlements with tax authorities/statute lapses (830 ) — — Unrecognized tax benefits – end of year $ 1,829 $ 2,055 $ —

Employee Retirement Plans

Employee Retirement Plans	12 Months Ended
	Sep. 30, 2017
Defined Benefit Plan [Abstract]
Employee Retirement Plans	EMPLOYEE RETIREMENT PLANS Defined Benefit Pension and Other Postretirement Plans. We sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plan”). Pension Plan benefits are based on years of service, age and employee compensation. We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all active and retired employees (“Other Postretirement Plans”). The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plan, the accumulated benefit obligations (“ABOs”) of the Other Postretirement Plans, plan assets and the funded status of the Pension Plan and Other Postretirement Plans as of September 30, 2017 and 2016 . ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect future compensation. Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Change in benefit obligations: Benefit obligations — beginning of year $ 645,444 $ 563,621 $ 12,075 $ 10,676 Service cost 9,038 7,772 303 198 Interest cost 24,394 25,733 460 483 Actuarial (gain) loss (14,575 ) 72,418 (512 ) 1,117 Benefits paid (25,056 ) (24,100 ) (422 ) (399 ) Benefit obligations — end of year $ 639,245 $ 645,444 $ 11,904 $ 12,075 Change in plan assets: Fair value of plan assets — beginning of year $ 463,432 $ 430,789 $ 13,715 $ 12,523 Actual gain on assets 48,309 46,874 1,333 1,347 Employer contributions 11,395 9,869 85 98 Benefits paid (25,056 ) (24,100 ) (362 ) (253 ) Fair value of plan assets — end of year $ 498,080 $ 463,432 $ 14,771 $ 13,715 Funded status of the plans — end of year $ (141,165 ) $ (182,012 ) $ 2,867 $ 1,640 Assets (liabilities) recorded in the balance sheet: Assets in excess of liabilities – included in other noncurrent assets $ — $ — $ 5,382 $ 4,139 Unfunded liabilities – included in other noncurrent liabilities (141,165 ) (182,012 ) (2,514 ) (2,499 ) Net amount recognized $ (141,165 ) $ (182,012 ) $ 2,868 $ 1,640 Amounts recorded in stockholder’s equity (pre-tax): Prior service cost (credit) $ 105 $ 138 $ (23 ) $ (35 ) Net actuarial loss (gain) 15,106 19,866 (46 ) (1 ) Total $ 15,211 $ 20,004 $ (69 ) $ (36 ) Amounts recorded in regulatory assets and liabilities (pre-tax): Prior service cost (credit) $ 970 $ 1,262 $ (1,605 ) $ (2,247 ) Net actuarial loss 139,505 180,964 1,192 2,425 Total $ 140,475 $ 182,226 $ (413 ) $ 178 In Fiscal 2018 , we estimate that we will amortize approximately $12,000 of net actuarial losses, primarily associated with Pension Plan, and $250 of prior service credits from stockholder’s equity and regulatory assets. Actuarial assumptions are described below. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the Company’s postretirement plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the benefit payments. The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below). Pension Benefits Other Postretirement Benefits Weighted-average assumptions: 2017 2016 2015 2017 2016 2015 Discount rate – benefit obligations 4.00 % 3.80 % 4.60 % 4.00 % 3.80 % 4.70 % Discount rate – benefit cost 3.80 % 4.60 % 4.60 % 3.80 % 4.70 % 4.60 % Expected return on plan assets 7.50 % 7.55 % 7.75 % 5.00 % 5.00 % 5.00 % Rate of increase in salary levels 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % The ABOs for the Pension Plan were $605,237 and $601,255 as of September 30, 2017 and 2016 , respectively. Included in the end of year Pension Plan PBOs above are $62,458 at September 30, 2017 , and $63,847 at September 30, 2016 , relating to employees of UGI and certain of its other subsidiaries. Included in the end of year Other Postretirement Plans ABOs above are $996 at September 30, 2017 , and $951 at September 30, 2016 , relating to employees of UGI and certain of its other subsidiaries. Net periodic pension and other postretirement benefit costs relating to the Company’s employees include the following components: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Service cost $ 8,091 $ 6,927 $ 6,962 $ 273 $ 183 $ 202 Interest cost 22,157 23,270 22,511 431 465 479 Expected return on assets (29,986 ) (28,668 ) (28,898 ) (656 ) (596 ) (612 ) Amortization of: Prior service cost (benefit) 325 348 348 (641 ) (641 ) (641 ) Actuarial loss 14,825 9,571 8,793 108 98 122 Net benefit cost (income) 15,412 11,448 9,716 (485 ) (491 ) (450 ) Change in associated regulatory liabilities — — — (490 ) 971 3,740 Net benefit cost after change in regulatory liabilities $ 15,412 $ 11,448 $ 9,716 $ (975 ) $ 480 $ 3,290 Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Corporation Common Stock and smallcap common stocks (prior to their liquidation during Fiscal 2017). 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 Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , we made contributions to the Pension Plan of $11,395 , $9,869 and $11,131 , respectively. The minimum required contributions in Fiscal 2018 are not expected to be material. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and the amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. The required contributions to the VEBA during Fiscal 2018 , if any, are not expected to be material. Expected payments for pension and other postretirement welfare benefits are as follows: Pension Benefits Other Postretirement Benefits Fiscal 2018 $ 27,176 $ 566 Fiscal 2019 28,471 566 Fiscal 2020 29,812 552 Fiscal 2021 31,084 537 Fiscal 2022 32,323 540 Fiscal 2023 - 2027 179,945 2,710 The assumed health care cost trend rates at September 30 are as follows: 2017 2016 Health care cost trend rate assumed for next year 7.00 % 7.25 % Rate to which the cost trend rate is assumed to decline (ultimate trend rate) 5.0 % 5.0 % Fiscal year that the rate reaches the ultimate trend rate 2026 2026 A one percentage point change in these assumed health care cost trend rates would not have had a material impact on Fiscal 2017 other postretirement benefit cost or the September 30, 2017 , other postretirement benefit ABO. We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement income plans. At September 30, 2017 and 2016 , the PBOs of these plans were $4,222 and $3,628 , respectively. We recorded expense for these plans of $605 in Fiscal 2017 , $353 in Fiscal 2016 and $445 in Fiscal 2015 . Pension Plan and VEBA Assets. The assets of the Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks (prior to their liquidation in Fiscal 2017) and UGI Common Stock. The targets, target ranges and actual allocations for the Pension Plan and VEBA trust assets at September 30 are as follows: Actual Target Asset Permitted Pension Plan: 2017 2016 Allocation Range Equity investments: Domestic 55.2 % 54.1 % 52.5% 40.0% – 65.0% International 12.4 % 10.2 % 12.5% 7.5% – 17.5% Total 67.6 % 64.3 % 65.0% 60.0% – 70.0% Fixed income funds & cash equivalents 32.4 % 35.7 % 35.0% 30.0% – 40.0% Total 100.0 % 100.0 % 100.0% Actual Target Asset Permitted VEBA: 2017 2016 Allocation Range Domestic equity investments 63.1 % 69.9 % 65.0% 60.0% – 70.0% Fixed income funds & cash equivalents 36.9 % 30.1 % 35.0% 30.0% – 40.0% Total 100.0 % 100.0 % 100.0% Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds, and a separately managed account comprising small-cap common stocks (prior to their liquidation in Fiscal 2017). Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 7.7% and 8.0% of Pension Plan assets at September 30, 2017 and 2016 , respectively. The fair values of the Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee. The fair values of the Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2 , as of September 30, 2017 and 2016 are as follows: Pension Plan Level 1 Level 2 Level 3 Other (a) Total September 30, 2017: Domestic equity investments: S&P 500 Index equity mutual funds $ 171,600 $ — $ — $ — $ 171,600 Small and midcap equity mutual funds 65,167 — — — 65,167 UGI Corporation Common Stock 38,137 — — — 38,137 Total domestic equity investments 274,904 — — — 274,904 International index equity mutual funds 61,613 — — — 61,613 Fixed income investments: Bond index mutual funds 156,228 — — — 156,228 Cash equivalents — — — 5,332 5,332 Total fixed income investments 156,228 — — 5,332 161,560 Total $ 492,745 $ — $ — $ 5,332 $ 498,077 September 30, 2016: Equity investments: S&P 500 Index equity mutual funds $ 158,906 $ — $ — $ — $ 158,906 Small and midcap equity mutual funds 43,170 — — — 43,170 Smallcap common stocks 11,414 — — — 11,414 UGI Corporation Common Stock 37,013 — — — 37,013 Total domestic equity investments 250,503 — — — 250,503 International index equity mutual funds 47,324 — — — 47,324 Fixed income investments: Bond index mutual funds 147,794 — — — 147,794 Cash equivalents — — — 17,811 17,811 Total fixed income investments 147,794 — — 17,811 165,605 Total $ 445,621 $ — $ — $ 17,811 $ 463,432 VEBA Level 1 Level 2 Level 3 Other (a) Total September 30, 2017: S&P 500 Index equity mutual fund $ 9,318 $ — $ — $ — $ 9,318 Bond index mutual fund 5,044 — — — 5,044 Cash equivalents — — — 409 409 Total $ 14,362 $ — $ — $ 409 $ 14,771 September 30, 2016: S&P 500 Index equity mutual fund $ 9,583 $ — $ — $ — $ 9,583 Bond index mutual fund 4,019 — — — 4,019 Cash equivalents — — — 113 113 Total $ 13,602 $ — $ — $ 113 $ 13,715 (a) Assets measured at net asset value (“NAV”) and therefore excluded from the fair value hierarchy. The expected long-term rates of return on Pension Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption. Defined Contribution Plan. We sponsor a 401(k) savings plan for eligible employees (“Utilities Savings Plan”). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. The Utilities Savings Plan provides for employer matching contributions. Those employees hired after December 31, 2008, who are not eligible to participate in the Pension Plan, receive employer matching contributions at a higher rate. The cost of benefits under the Utilities Savings Plan totaled $2,829 in Fiscal 2017 , $2,409 in Fiscal 2016 and $2,162 in Fiscal 2015 . We also sponsor a nonqualified supplemental defined contribution executive retirement plan. This plan generally provides supplemental benefits to certain executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal Revenue Code. Costs associated with this plan were not material in Fiscal 2017 , Fiscal 2016 and Fiscal 2015 .

Series Preferred Stock

Series Preferred Stock	12 Months Ended
	Sep. 30, 2017
Equity [Abstract]
Series Preferred Stock	SERIES PREFERRED STOCK We have 2,000,000 shares of Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of Series Preferred Stock outstanding at September 30, 2017 or 2016 .

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Based Compensation	EQUITY-BASED COMPENSATION Under UGI Corporation’s 2013 Omnibus Incentive Compensation Plan (the “2013 OICP”) and prior UGI equity compensation plans, certain key employees of UGI Utilities may be granted stock options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”) and other equity-based awards. The exercise price for UGI stock options may not be less than the fair market value on the grant date. Awards granted under the 2013 OICP and the prior plans may vest immediately or ratably over a period of years (generally three -year periods), and stock options for UGI Common Stock can be exercised no later than ten years from the grant date. In addition, the 2013 OICP and the prior UGI equity compensation plans provide that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements. UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. With respect to UGI Performance Units awards, the actual number of UGI shares actually issued (or their cash equivalent) at the end of the performance period and the actual amount of dividend equivalents paid, may range from 0% to 200% of the target award based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to the Russell Midcap Utility Index, excluding telecommunication companies (“UGI comparator group”). Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest. We use a Black-Scholes option-pricing model to estimate the fair value of UGI stock options. We use a Monte Carlo valuation approach to estimate the fair value of UGI Performance Unit awards. We recorded total net pre-tax equity-based compensation expense associated with both UGI Units and UGI stock options of $1,461 ( $855 after-tax) during Fiscal 2017 ; $1,924 ( $1,126 after-tax) during Fiscal 2016 ; and $1,847 ( $1,081 after-tax) during Fiscal 2015 . As of September 30, 2017 , there was $1,167 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 1.9 years. As of September 30, 2017 , there was a total of $1,029 of unrecognized compensation expense associated with 45,588 UGI Unit awards that is expected to be recognized over a weighted average period of 1.8 years. At September 30, 2017 and 2016 , total liabilities of $533 and $1,304 , respectively, associated with UGI Unit awards are reflected in other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheets. The following table summarizes UGI Unit award activity for Fiscal 2017 : Total Vested Non-Vested Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) September 30, 2016 57,783 $ 34.66 10,316 $ 34.31 47,467 $ 34.74 Granted 16,425 $ 51.42 367 $ 51.42 16,058 $ 51.42 Vested — $ — 16,003 $ 33.10 (16,003 ) $ 33.10 Forfeitures & transfers (1,934 ) $ 34.74 — $ — (1,934 ) $ 34.74 Unit awards paid (20,050 ) $ 32.59 (20,050 ) $ 32.59 — $ — September 30, 2017 52,224 $ 40.72 6,636 $ 37.53 45,588 $ 41.19

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Commitments We lease various buildings and vehicles, computer and office equipment and other facilities under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $7,276 in Fiscal 2017 , $7,669 in Fiscal 2016 and $7,956 in Fiscal 2015 . Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year for the fiscal years ending September 30 are as follows: 2018 — $7,545 ; 2019 — $5,961 ; 2020 — $4,355 ; 2021 — $2,665 ; 2022 — $793 ; after 2022 — $182 . Contingencies Environmental Matters From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility. UGI Utilities also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into a consent order and agreement (“COA”) with the DEP to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2,500 , $1,750 and $1,100 , for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively. At September 30, 2017 and 2016 , our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $54,250 and $55,063 , respectively. UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable. (See Note 4 ). UGI Utilities does not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Utilities, CPG and PNG receive ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law, UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by a former subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At September 30, 2017 and 2016 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material. Other Matters Manor Township, Pennsylvania Natural Gas Explosion. On July 2, 2017, an explosion occurred in Manor Township, Pennsylvania which resulted in the death of a Company employee, significant injuries to two other Company employees and an employee of the local sewer authority, and significant property damage. The National Transportation Safety Board (“NTSB”), the Occupational Safety and Health Administration (“OSHA”) and the PUC are investigating the Manor Township incident. The NTSB investigative team includes representatives from the Company, the PUC, the local fire department and the Pipeline and Hazardous Materials Safety Administration and the Company is cooperating with the investigation. Other parties may be invited to participate by the NTSB. While the investigation into this incident is still underway and the cause of the explosion has not been determined, the Company has received claims as a result of the explosion and may become involved in lawsuits relative to the incident. The Company maintains workers’ compensation insurance and liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of the Company’s deductible, are expected to be recovered through the Company’s insurance. Although the Company cannot predict the result of these pending or future claims, we believe that claims and expenses associated with the explosion will not have a material impact on our consolidated financial statements. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial statements.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Derivative Instruments The following table presents, on a gross basis, our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2 , as of September 30, 2017 and 2016 : Asset (Liability) Level 1 Level 2 Level 3 Total September 30, 2017 Derivative instruments: Assets: Commodity contracts $ 1,735 $ 72 $ — $ 1,807 Liabilities: Commodity contracts $ (1,447 ) $ (73 ) $ — $ (1,520 ) September 30, 2016 Derivative instruments: Assets: Commodity contracts $ 4,506 $ 4 $ — $ 4,510 Liabilities: Commodity contracts $ (263 ) $ (294 ) $ — $ (557 ) The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments, which are designated as Level 2, are generally based upon recent market transactions and related market indicators. There were no transfers between Level 1 and Level 2 during the periods presented. Other Financial Instruments The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt (Level 2). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2017 and 2016 , were as follows: 2017 2016 Carrying amount $ 755,000 $ 675,000 Estimated fair value $ 791,378 $ 770,781

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	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 of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 2017 and 2016 , the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 14.8 million dekatherms and 18.4 million dekatherms, respectively. At September 30, 2017 , the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 months. Gains and losses on natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the 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 4 ). 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 September 30, 2017 and 2016 , all Electric Utility forward electricity purchase contracts were subject to the NPNS exception under GAAP. In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 4 ). At September 30, 2017 and 2016 , the total volumes associated with FTRs totaled 101.2 million kilowatt hours and 58.3 million kilowatt hours, respectively. At September 30, 2017 , the maximum period over which we are economically hedging electricity congestion is 8 months. In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. At September 30, 2017 and 2016 , the total volumes associated with gasoline futures contracts were not material. Interest Rate Risk Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. On March 31, 2016, concurrent with the pricing of UGI Utilities’ Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities settled all of its then-existing IRPA contracts associated with such debt at a loss of $35,975 . Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs was recorded in AOCI and is being recognized in interest expense as the associated future interest expense impacts earnings. At September 30, 2017 and 2016 , we had no unsettled IRPAs. At September 30, 2017 , the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,485 . Derivative Instrument Credit Risk Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2017 and 2016 , restricted cash in brokerage accounts totaled $3,046 and $583 , respectively. Offsetting Derivative Assets and Liabilities Derivative assets and liabilities are presented net by counterparty on the 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 Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements. Fair Value of Derivative Instruments The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of September 30, 2017 and 2016 : 2017 2016 Derivative assets: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ 1,665 $ 4,472 Derivatives not subject to PGC and DS mechanisms: Commodity contracts 142 38 Total derivative assets – gross 1,807 4,510 Gross amounts offset in the balance sheet (450 ) (247 ) Total derivative assets – net (a) $ 1,357 $ 4,263 Derivative liabilities: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ (1,520 ) $ (499 ) Derivatives not subject to PGC and DS mechanisms: Commodity contracts — (58 ) Total derivative liabilities – gross (1,520 ) (557 ) Gross amounts offset in the balance sheet 450 247 Total derivative liabilities – net (a) $ (1,070 ) $ (310 ) (a) Derivative assets and liabilities with maturities greater than one year are recorded in “ Other assets ” and “ Other noncurrent liabilities ” on the Consolidated Balance Sheets. Effect of Derivative Instruments The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Consolidated Statements of Income and changes in AOCI for Fiscal 2017 , Fiscal 2016 and Fiscal 2015 : Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of 2017 2016 2015 2017 2016 2015 Loss Reclassified from AOCI into Income Cash Flow Hedges: Interest rate contracts $ — $ (28,958 ) $ (7,016 ) $ (3,397 ) $ (2,680 ) $ (2,674 ) Interest expense Gain (Loss) Recognized in Income Location of Gain (Loss) 2017 2016 2015 Recognized in Income Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ 174 $ (88 ) $ (761 ) Operating and administrative expenses/other operating income, net 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 under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Sep. 30, 2017
Equity [Abstract]
Accumulated Other Comprehensive Income	ACCUMULATED OTHER COMPREHENSIVE INCOME Other comprehensive income (loss) principally reflects losses on IRPAs qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income. Changes in AOCI, net of tax, during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 are as follows: Postretirement Benefit Plans Derivative Instruments Total AOCI - September 30, 2014 $ (6,311 ) $ (1,870 ) $ (8,181 ) Reclassifications of benefit plans actuarial losses and net prior service credits 517 — 517 Reclassifications of net losses on IRPAs — 1,565 1,565 Net losses on IRPAs — (4,105 ) (4,105 ) Benefit plans, principally actuarial losses (3,482 ) — (3,482 ) AOCI - September 30, 2015 $ (9,276 ) $ (4,410 ) $ (13,686 ) Reclassifications of benefit plans actuarial losses and net prior service credits 639 — 639 Reclassifications of net losses on IRPAs — 1,568 1,568 Net losses on IRPAs — (16,942 ) (16,942 ) Benefit plans, principally actuarial losses (3,197 ) — (3,197 ) AOCI - September 30, 2016 $ (11,834 ) $ (19,784 ) $ (31,618 ) Reclassifications of benefit plans actuarial losses and net prior service credits 956 — 956 Reclassifications of net losses on IRPAs — 1,988 1,988 Benefit plans, principally actuarial gains 1,883 — 1,883 AOCI - September 30, 2017 $ (8,995 ) $ (17,796 ) $ (26,791 ) Reclassifications of net losses on IRPAs are reflected in interest expense on the Consolidated Statements of Income.

Segment Information

Segment Information	12 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Segment Information	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 . We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes. No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States, and all of our reportable segments’ long-lived assets are located in the United States. Financial information by business segment follows: Total Gas Utility Electric Utility Other 2017 Revenues $ 887,588 $ 799,054 $ 88,534 Cost of sales $ 367,279 $ 318,210 $ 49,069 Depreciation and amortization $ 72,332 $ 67,357 $ 4,975 Operating income $ 228,307 $ 219,561 $ 8,746 Interest expense $ 40,212 $ 38,218 $ 1,994 Income before income taxes $ 188,095 $ 181,343 $ 6,752 Total assets $ 2,994,015 $ 2,833,423 $ 160,592 Goodwill $ 182,145 $ 182,145 $ — Capital expenditures (including the effects of accruals) $ 317,722 $ 306,243 $ 11,479 2016 Revenues $ 768,484 $ 677,387 $ 91,097 Cost of sales $ 289,786 $ 239,163 $ 50,623 Depreciation and amortization $ 67,303 $ 62,451 $ 4,852 Operating income $ 200,901 $ 189,412 $ 11,489 Interest expense $ 37,630 $ 35,786 $ 1,844 Income before income taxes $ 163,271 $ 153,626 $ 9,645 Total assets $ 2,743,091 $ 2,570,297 $ 172,794 Goodwill $ 182,145 $ 182,145 $ — Capital expenditures (including the effects of accruals) $ 262,503 $ 251,261 $ 11,242 2015 Revenues $ 1,041,581 $ 933,080 $ 107,577 $ 924 Cost of sales $ 510,784 $ 448,617 $ 62,167 $ — Depreciation and amortization $ 63,590 $ 58,974 $ 4,616 $ — Operating income $ 241,667 $ 226,485 $ 14,153 $ 1,029 Interest expense $ 41,128 $ 39,112 $ 2,016 $ — Income before income taxes $ 200,539 $ 187,373 $ 12,137 $ 1,029 Total assets $ 2,505,984 $ 2,360,156 $ 145,828 $ — Goodwill $ 182,145 $ 182,145 $ — $ — Capital expenditures (including the effects of accruals) $ 197,684 $ 189,671 $ 8,013 $ —

Other Operating Income (Expense

Other Operating Income (Expense), Net	12 Months Ended
	Sep. 30, 2017
Component of Operating Income [Abstract]
Other Operating Income (Expense), Net	OTHER OPERATING INCOME (EXPENSE), NET Other operating income (expense), net, comprises the following: 2017 2016 2015 Non-tariff service income $ 1,491 $ 2,633 $ 4,760 Environmental matters 6,155 (2,918 ) 1,152 Construction service income — — 2,175 Sale of HVAC Business — — 1,065 Net interest on PGC overcollection (130 ) (1,740 ) (606 ) Other, net 813 25 323 Total other operating income (expense), net $ 8,329 $ (2,000 ) $ 8,869

Related Party Transactions

Related Party Transactions	12 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as “ Operating and administrative expenses — related parties ” in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 totaled $4,346 , $5,069 and $3,168 , respectively. From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years . At September 30, 2017 , UGI Utilities was a party to four SCAAs with Energy Services, and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 totaling $21,424 , $12,739 and $16,849 , respectively. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. During Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , these payments totaled $2,747 , $2,002 and $2,339 , respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. At September 30, 2017 and 2016 , the amounts of such security deposits, which are included in “ Other current liabilities ” on the Consolidated Balance Sheets, were $11,040 and $8,100 , respectively. UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “ Inventories .” At September 30, 2017 and 2016 , the carrying values of these gas storage inventories, comprising approximately 6.8 bcf and 4.6 bcf of natural gas, were $19,323 and $11,148 , 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 Fiscal 2017 , Fiscal 2016 and Fiscal 2015 totaled $76,010 , $63,331 and $47,794 , respectively. From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , revenues associated with such sales to Energy Services totaled $50,948 , $30,743 and $79,182 , respectively. Also from time to time, UGI Utilities purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one -year agreements. During Fiscal 2017 , Fiscal 2016 and Fiscal 2015 , such purchases totaled $84,402 , $35,067 and $85,383 , respectively.

Quarterly Data (unaudited)

Quarterly Data (unaudited)	12 Months Ended
	Sep. 30, 2017
Quarterly Financial Data [Abstract]
Quarterly Data (unaudited)	QUARTERLY DATA (unaudited) The following quarterly information includes all adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of the Company’s businesses. December 31, March 31, June 30, September 30, 2016 2015 2017 2016 2017 2016 2017 2016 Revenues $ 261,413 $ 197,982 $ 359,940 $ 322,047 $ 146,692 $ 140,283 $ 119,543 $ 108,172 Operating income $ 82,236 $ 48,296 $ 116,408 $ 114,481 $ 27,671 $ 29,815 $ 1,992 $ 8,309 Net income (loss) $ 44,265 $ 23,351 $ 65,125 $ 63,294 $ 10,697 $ 12,603 $ (4,046 ) $ (1,875 )

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Sep. 30, 2017
Valuation and Qualifying Accounts [Abstract]
Schedule II - Valuation and Qualifying Accounts	SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (Thousands of dollars) Balance at beginning of year Charged to costs and expenses Other Balance at end of year September 30, 2017 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 3,946 $ 8,030 $ (7,924 ) (1) $ 4,052 September 30, 2016 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 5,599 $ 7,760 $ (9,413 ) (1) $ 3,946 September 30, 2015 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 6,992 $ 13,498 $ (14,891 ) (1) $ 5,599 (1) Uncollectible accounts written off, net of recoveries

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions. Certain prior-year amounts have been reclassified to conform to the current-year presentation.
Principles of Consolidation	Principles of Consolidation Our consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or “the Company”). We eliminate intercompany accounts when we consolidate.
Effects of Regulation	Effects of Regulation UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator.
Fair Value Measurements	Fair Value Measurements The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements performed on a recurring basis principally relate to derivative instruments. GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: • Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. • Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. • Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.
Derivative Instruments	Derivative Instruments Derivative instruments are reported on the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or is designated and qualifies for hedge accounting. Gains and losses on substantially all of the derivative instruments used by UGI Utilities (for which NPNS has not been elected) to hedge commodity prices are included in regulatory assets and liabilities in accordance with GAAP regarding accounting for rate-regulated entities. Certain of our derivative instruments are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative financial instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. 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.
Revenue Recognition	Revenue Recognition UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service rendered and commodities delivered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered. We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.
Accounts Receivable	Accounts Receivable Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.
Income Taxes	Income Taxes We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse. We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is consistent with income taxes calculated on a separate return basis. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income.
Cash and Cash Equivalents	Cash and Cash Equivalents For cash flow purposes, cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities of three months or less when purchased.
Restricted Cash	Restricted Cash Restricted cash represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
Inventories	Inventories Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for substantially all of our inventory.
Property, Plant and Equipment and Related Depreciation	Property, Plant and Equipment and Related Depreciation We record property, plant and equipment at original cost. Capitalized costs include labor, materials and other direct and indirect costs, and allowance for funds used during construction (“AFUDC”). The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition. We record depreciation expense for Utilities’ plant and equipment on a straight-line basis based upon projected service lives of the various classes of its depreciable property. The estimated useful lives of the classes of depreciable property are reviewed by a third party and adjusted, if necessary, as part of periodic service life studies required by the PUC. The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2017 , 2016 and 2015 were as follows: 2017 2016 2015 Gas Utility 2.2 % 2.2 % 2.2 % Electric Utility 2.4 % 2.5 % 2.5 % When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over five years , consistent with prior ratemaking treatment (See Note 4 ). We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. Information technology costs associated with major system installations, conversions and improvements, such as software training, data conversion, business process reengineering costs and preliminary project stage costs are deferred as a regulatory asset if the Company expects to recover these costs in future rates, and the deferral is reported as a component of property, plant and equipment. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.
Goodwill	Goodwill Our goodwill is the result of Gas Utility business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance simplifying the test for goodwill impairment. The adoption of the new guidance did not impact the consolidated financial statements (see Note 3). We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value. From time to time, we may assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. From time to time, we may bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets.
Employee Retirement Plans	Employee Retirement Plans We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value
Equity-Based Compensation	Equity-Based Compensation All of our equity-based compensation, principally comprising UGI stock options and grants of UGI stock-based equity instruments (“UGI Units”), is measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, equity-based compensation costs are measured based upon the fair value of the award on the date of grant or the fair value of the award as of the end of each reporting period. In Fiscal 2017, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows.
Environmental Matters	Environmental Matters We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites. Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.
Adoption of New Accounting Standard and Accounting Standards Not Yet Adopted	Adoption of New Accounting Standard Cash Flow Classification. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance on the classification of certain cash receipts and payments in the statement of cash flows. The guidance is generally required to be applied retrospectively. The adoption of the new guidance did not impact our consolidated financial statements. Goodwill Impairment. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance regarding the test for goodwill impairment. Under the new accounting guidance, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements. Employee Share-based Payments. Effective October 1, 2016, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. The adoption of the new accounting guidance did not have a material impact on our financial statements. Accounting Standards Not Yet Adopted Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue. The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.

Regulatory Assets and Liabili30

Regulatory Assets and Liabilities and Regulatory Matters (Tables)	12 Months Ended
	Sep. 30, 2017
Regulated Operations [Abstract]
Schedule of Regulatory Assets	The following regulatory assets and liabilities are included in our Consolidated Balance Sheets at September 30: 2017 2016 Regulatory assets: Income taxes recoverable $ 121,421 $ 115,643 Underfunded pension and postretirement plans 141,310 183,129 Environmental costs 61,566 59,397 Deferred fuel and power costs 7,685 151 Removal costs, net 30,996 27,956 Other 5,951 8,865 Total regulatory assets $ 368,929 $ 395,141 Regulatory liabilities (a): Postretirement benefits overcollections $ 17,493 $ 17,519 Deferred fuel and power refunds 10,621 22,299 State income tax benefits — distribution system repairs 18,430 15,086 Other 2,686 665 Total regulatory liabilities $ 49,230 $ 55,569 (a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Consolidated Balance Sheets.
Schedule of Regulatory Liabilities	The following regulatory assets and liabilities are included in our Consolidated Balance Sheets at September 30: 2017 2016 Regulatory assets: Income taxes recoverable $ 121,421 $ 115,643 Underfunded pension and postretirement plans 141,310 183,129 Environmental costs 61,566 59,397 Deferred fuel and power costs 7,685 151 Removal costs, net 30,996 27,956 Other 5,951 8,865 Total regulatory assets $ 368,929 $ 395,141 Regulatory liabilities (a): Postretirement benefits overcollections $ 17,493 $ 17,519 Deferred fuel and power refunds 10,621 22,299 State income tax benefits — distribution system repairs 18,430 15,086 Other 2,686 665 Total regulatory liabilities $ 49,230 $ 55,569 (a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Consolidated Balance Sheets.

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Sep. 30, 2017
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories comprise the following at September 30: 2017 2016 Gas Utility natural gas $ 39,486 $ 29,223 Materials, supplies and other 13,823 13,117 Total inventories $ 53,309 $ 42,340

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Sep. 30, 2017
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Property, plant and equipment comprise the following categories at September 30: 2017 2016 Distribution $ 2,835,339 $ 2,634,191 Transmission 96,430 93,454 Construction in process 112,563 103,929 General and other 240,997 167,341 Total property, plant and equipment $ 3,285,329 $ 2,998,915

Debt (Tables)

Debt (Tables)	12 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Composition of Long-term Debt	Long-term debt comprises the following at September 30: 2017 2016 Senior Notes: 4.12%, due September 2046 $ 200,000 $ 200,000 4.98%, due March 2044 175,000 175,000 4.12%, due October 2046 100,000 — 6.21%, due September 2036 100,000 100,000 2.95%, due June 2026 100,000 100,000 Medium-Term Notes: 6.17%, due June 2017 — 20,000 7.25%, due November 2017 20,000 20,000 5.67%, due January 2018 20,000 20,000 6.50%, due August 2033 20,000 20,000 6.13%, due October 2034 20,000 20,000 Total long-term debt 755,000 675,000 Less: unamortized debt issuance costs (3,899 ) (3,559 ) Less: current maturities (39,996 ) (19,986 ) Total long-term debt due after one year $ 711,105 $ 651,455

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Provisions for Income Taxes	The provisions for income taxes consist of the following: 2017 2016 2015 Current expense (benefit): Federal $ (12,253 ) $ (17,845 ) $ 34,990 State 5,739 6,805 15,138 Total current (benefit) expense (6,514 ) (11,040 ) 50,128 Deferred expense (benefit): Federal 70,293 71,005 28,877 State 8,593 6,262 815 Investment tax credit amortization (318 ) (329 ) (336 ) Total income tax expense $ 72,054 $ 65,898 $ 79,484
Reconciliation from US Federal Statutory Tax Rate to Effective Tax Rate	A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows: 2017 2016 2015 U.S. federal statutory tax rate 35.0 % 35.0 % 35.0 % Difference in tax rate due to: State income taxes, net of federal benefit 5.0 5.2 5.1 Excess tax benefits on share-based payments (0.9 ) — — Other, net (0.8 ) 0.2 (0.5 ) Effective tax rate 38.3 % 40.4 % 39.6 %
Deferred Tax Liabilities (Assets)	Deferred tax liabilities (assets) comprise the following at September 30: 2017 2016 Excess book basis over tax basis of property, plant and equipment $ 564,327 $ 491,038 Goodwill 49,588 45,070 Derivative financial instruments — 948 Regulatory assets 136,093 149,660 Other 3,140 2,910 Gross deferred tax liabilities 753,148 689,626 Pension plan liabilities (57,011 ) (74,129 ) Allowance for doubtful accounts (1,681 ) (1,637 ) Deferred investment tax credits (1,224 ) (1,356 ) Employee-related expenses (6,793 ) (5,247 ) Regulatory liabilities (12,780 ) (16,798 ) Environmental liabilities (22,224 ) (22,757 ) Derivative financial instruments (354 ) — Other (15,616 ) (17,473 ) Gross deferred tax assets (117,683 ) (139,397 ) Net deferred tax liabilities $ 635,465 $ 550,229
Reconciliation of Unrecognized Tax Benefits	A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: 2017 2016 2015 Unrecognized tax benefits – beginning of year $ 2,055 $ — $ — Additions for tax positions taken in prior years 604 2,055 — Additions for tax positions of the current year — — — Settlements with tax authorities/statute lapses (830 ) — — Unrecognized tax benefits – end of year $ 1,829 $ 2,055 $ —

Employee Retirement Plans (Tabl

Employee Retirement Plans (Tables)	12 Months Ended
	Sep. 30, 2017
Defined Benefit Plan [Abstract]
Change in Pension Benefits and Other Postretirement Benefit Obligations, Plan Assets, and Funded Status	The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plan, the accumulated benefit obligations (“ABOs”) of the Other Postretirement Plans, plan assets and the funded status of the Pension Plan and Other Postretirement Plans as of September 30, 2017 and 2016 . ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect future compensation. Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Change in benefit obligations: Benefit obligations — beginning of year $ 645,444 $ 563,621 $ 12,075 $ 10,676 Service cost 9,038 7,772 303 198 Interest cost 24,394 25,733 460 483 Actuarial (gain) loss (14,575 ) 72,418 (512 ) 1,117 Benefits paid (25,056 ) (24,100 ) (422 ) (399 ) Benefit obligations — end of year $ 639,245 $ 645,444 $ 11,904 $ 12,075 Change in plan assets: Fair value of plan assets — beginning of year $ 463,432 $ 430,789 $ 13,715 $ 12,523 Actual gain on assets 48,309 46,874 1,333 1,347 Employer contributions 11,395 9,869 85 98 Benefits paid (25,056 ) (24,100 ) (362 ) (253 ) Fair value of plan assets — end of year $ 498,080 $ 463,432 $ 14,771 $ 13,715 Funded status of the plans — end of year $ (141,165 ) $ (182,012 ) $ 2,867 $ 1,640 Assets (liabilities) recorded in the balance sheet: Assets in excess of liabilities – included in other noncurrent assets $ — $ — $ 5,382 $ 4,139 Unfunded liabilities – included in other noncurrent liabilities (141,165 ) (182,012 ) (2,514 ) (2,499 ) Net amount recognized $ (141,165 ) $ (182,012 ) $ 2,868 $ 1,640 Amounts recorded in stockholder’s equity (pre-tax): Prior service cost (credit) $ 105 $ 138 $ (23 ) $ (35 ) Net actuarial loss (gain) 15,106 19,866 (46 ) (1 ) Total $ 15,211 $ 20,004 $ (69 ) $ (36 ) Amounts recorded in regulatory assets and liabilities (pre-tax): Prior service cost (credit) $ 970 $ 1,262 $ (1,605 ) $ (2,247 ) Net actuarial loss 139,505 180,964 1,192 2,425 Total $ 140,475 $ 182,226 $ (413 ) $ 178
Actuarial Assumptions for Domestic Plans	The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below). Pension Benefits Other Postretirement Benefits Weighted-average assumptions: 2017 2016 2015 2017 2016 2015 Discount rate – benefit obligations 4.00 % 3.80 % 4.60 % 4.00 % 3.80 % 4.70 % Discount rate – benefit cost 3.80 % 4.60 % 4.60 % 3.80 % 4.70 % 4.60 % Expected return on plan assets 7.50 % 7.55 % 7.75 % 5.00 % 5.00 % 5.00 % Rate of increase in salary levels 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 %
Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs	Net periodic pension and other postretirement benefit costs relating to the Company’s employees include the following components: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Service cost $ 8,091 $ 6,927 $ 6,962 $ 273 $ 183 $ 202 Interest cost 22,157 23,270 22,511 431 465 479 Expected return on assets (29,986 ) (28,668 ) (28,898 ) (656 ) (596 ) (612 ) Amortization of: Prior service cost (benefit) 325 348 348 (641 ) (641 ) (641 ) Actuarial loss 14,825 9,571 8,793 108 98 122 Net benefit cost (income) 15,412 11,448 9,716 (485 ) (491 ) (450 ) Change in associated regulatory liabilities — — — (490 ) 971 3,740 Net benefit cost after change in regulatory liabilities $ 15,412 $ 11,448 $ 9,716 $ (975 ) $ 480 $ 3,290
Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits	Expected payments for pension and other postretirement welfare benefits are as follows: Pension Benefits Other Postretirement Benefits Fiscal 2018 $ 27,176 $ 566 Fiscal 2019 28,471 566 Fiscal 2020 29,812 552 Fiscal 2021 31,084 537 Fiscal 2022 32,323 540 Fiscal 2023 - 2027 179,945 2,710
Schedule of Effect of One-percentage-point Change in Assumed Health Care Cost Trend Rates	The assumed health care cost trend rates at September 30 are as follows: 2017 2016 Health care cost trend rate assumed for next year 7.00 % 7.25 % Rate to which the cost trend rate is assumed to decline (ultimate trend rate) 5.0 % 5.0 % Fiscal year that the rate reaches the ultimate trend rate 2026 2026
Allocation of Pension Plan and VEBA Trust Assets	The targets, target ranges and actual allocations for the Pension Plan and VEBA trust assets at September 30 are as follows: Actual Target Asset Permitted Pension Plan: 2017 2016 Allocation Range Equity investments: Domestic 55.2 % 54.1 % 52.5% 40.0% – 65.0% International 12.4 % 10.2 % 12.5% 7.5% – 17.5% Total 67.6 % 64.3 % 65.0% 60.0% – 70.0% Fixed income funds & cash equivalents 32.4 % 35.7 % 35.0% 30.0% – 40.0% Total 100.0 % 100.0 % 100.0% Actual Target Asset Permitted VEBA: 2017 2016 Allocation Range Domestic equity investments 63.1 % 69.9 % 65.0% 60.0% – 70.0% Fixed income funds & cash equivalents 36.9 % 30.1 % 35.0% 30.0% – 40.0% Total 100.0 % 100.0 % 100.0%
Fair Value of Pension Plan and VEBA Trust Assets	The fair values of the Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2 , as of September 30, 2017 and 2016 are as follows: Pension Plan Level 1 Level 2 Level 3 Other (a) Total September 30, 2017: Domestic equity investments: S&P 500 Index equity mutual funds $ 171,600 $ — $ — $ — $ 171,600 Small and midcap equity mutual funds 65,167 — — — 65,167 UGI Corporation Common Stock 38,137 — — — 38,137 Total domestic equity investments 274,904 — — — 274,904 International index equity mutual funds 61,613 — — — 61,613 Fixed income investments: Bond index mutual funds 156,228 — — — 156,228 Cash equivalents — — — 5,332 5,332 Total fixed income investments 156,228 — — 5,332 161,560 Total $ 492,745 $ — $ — $ 5,332 $ 498,077 September 30, 2016: Equity investments: S&P 500 Index equity mutual funds $ 158,906 $ — $ — $ — $ 158,906 Small and midcap equity mutual funds 43,170 — — — 43,170 Smallcap common stocks 11,414 — — — 11,414 UGI Corporation Common Stock 37,013 — — — 37,013 Total domestic equity investments 250,503 — — — 250,503 International index equity mutual funds 47,324 — — — 47,324 Fixed income investments: Bond index mutual funds 147,794 — — — 147,794 Cash equivalents — — — 17,811 17,811 Total fixed income investments 147,794 — — 17,811 165,605 Total $ 445,621 $ — $ — $ 17,811 $ 463,432 VEBA Level 1 Level 2 Level 3 Other (a) Total September 30, 2017: S&P 500 Index equity mutual fund $ 9,318 $ — $ — $ — $ 9,318 Bond index mutual fund 5,044 — — — 5,044 Cash equivalents — — — 409 409 Total $ 14,362 $ — $ — $ 409 $ 14,771 September 30, 2016: S&P 500 Index equity mutual fund $ 9,583 $ — $ — $ — $ 9,583 Bond index mutual fund 4,019 — — — 4,019 Cash equivalents — — — 113 113 Total $ 13,602 $ — $ — $ 113 $ 13,715 (a) Assets measured at net asset value (“NAV”) and therefore excluded from the fair value hierarchy.

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
UGI Unit Award Activity	The following table summarizes UGI Unit award activity for Fiscal 2017 : Total Vested Non-Vested Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) September 30, 2016 57,783 $ 34.66 10,316 $ 34.31 47,467 $ 34.74 Granted 16,425 $ 51.42 367 $ 51.42 16,058 $ 51.42 Vested — $ — 16,003 $ 33.10 (16,003 ) $ 33.10 Forfeitures & transfers (1,934 ) $ 34.74 — $ — (1,934 ) $ 34.74 Unit awards paid (20,050 ) $ 32.59 (20,050 ) $ 32.59 — $ — September 30, 2017 52,224 $ 40.72 6,636 $ 37.53 45,588 $ 41.19

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following table presents, on a gross basis, our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2 , as of September 30, 2017 and 2016 : Asset (Liability) Level 1 Level 2 Level 3 Total September 30, 2017 Derivative instruments: Assets: Commodity contracts $ 1,735 $ 72 $ — $ 1,807 Liabilities: Commodity contracts $ (1,447 ) $ (73 ) $ — $ (1,520 ) September 30, 2016 Derivative instruments: Assets: Commodity contracts $ 4,506 $ 4 $ — $ 4,510 Liabilities: Commodity contracts $ (263 ) $ (294 ) $ — $ (557 )
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 September 30, 2017 and 2016 , were as follows: 2017 2016 Carrying amount $ 755,000 $ 675,000 Estimated fair value $ 791,378 $ 770,781

Derivative Instruments and He38

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Assets and Liabilities Including Offsetting Amounts	The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of September 30, 2017 and 2016 : 2017 2016 Derivative assets: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ 1,665 $ 4,472 Derivatives not subject to PGC and DS mechanisms: Commodity contracts 142 38 Total derivative assets – gross 1,807 4,510 Gross amounts offset in the balance sheet (450 ) (247 ) Total derivative assets – net (a) $ 1,357 $ 4,263 Derivative liabilities: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ (1,520 ) $ (499 ) Derivatives not subject to PGC and DS mechanisms: Commodity contracts — (58 ) Total derivative liabilities – gross (1,520 ) (557 ) Gross amounts offset in the balance sheet 450 247 Total derivative liabilities – net (a) $ (1,070 ) $ (310 ) (a) Derivative assets and liabilities with maturities greater than one year are recorded in “ Other assets ” and “ Other noncurrent liabilities ” on the Consolidated Balance Sheets.
Effects of Derivative Instruments on Consolidated Statements of Income and Changes in AOCI	The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Consolidated Statements of Income and changes in AOCI for Fiscal 2017 , Fiscal 2016 and Fiscal 2015 : Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of 2017 2016 2015 2017 2016 2015 Loss Reclassified from AOCI into Income Cash Flow Hedges: Interest rate contracts $ — $ (28,958 ) $ (7,016 ) $ (3,397 ) $ (2,680 ) $ (2,674 ) Interest expense Gain (Loss) Recognized in Income Location of Gain (Loss) 2017 2016 2015 Recognized in Income Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ 174 $ (88 ) $ (761 ) Operating and administrative expenses/other operating income, net

Accumulated Other Comprehensi39

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Sep. 30, 2017
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income	Changes in AOCI, net of tax, during Fiscal 2017 , Fiscal 2016 and Fiscal 2015 are as follows: Postretirement Benefit Plans Derivative Instruments Total AOCI - September 30, 2014 $ (6,311 ) $ (1,870 ) $ (8,181 ) Reclassifications of benefit plans actuarial losses and net prior service credits 517 — 517 Reclassifications of net losses on IRPAs — 1,565 1,565 Net losses on IRPAs — (4,105 ) (4,105 ) Benefit plans, principally actuarial losses (3,482 ) — (3,482 ) AOCI - September 30, 2015 $ (9,276 ) $ (4,410 ) $ (13,686 ) Reclassifications of benefit plans actuarial losses and net prior service credits 639 — 639 Reclassifications of net losses on IRPAs — 1,568 1,568 Net losses on IRPAs — (16,942 ) (16,942 ) Benefit plans, principally actuarial losses (3,197 ) — (3,197 ) AOCI - September 30, 2016 $ (11,834 ) $ (19,784 ) $ (31,618 ) Reclassifications of benefit plans actuarial losses and net prior service credits 956 — 956 Reclassifications of net losses on IRPAs — 1,988 1,988 Benefit plans, principally actuarial gains 1,883 — 1,883 AOCI - September 30, 2017 $ (8,995 ) $ (17,796 ) $ (26,791 )

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Segment Information	Financial information by business segment follows: Total Gas Utility Electric Utility Other 2017 Revenues $ 887,588 $ 799,054 $ 88,534 Cost of sales $ 367,279 $ 318,210 $ 49,069 Depreciation and amortization $ 72,332 $ 67,357 $ 4,975 Operating income $ 228,307 $ 219,561 $ 8,746 Interest expense $ 40,212 $ 38,218 $ 1,994 Income before income taxes $ 188,095 $ 181,343 $ 6,752 Total assets $ 2,994,015 $ 2,833,423 $ 160,592 Goodwill $ 182,145 $ 182,145 $ — Capital expenditures (including the effects of accruals) $ 317,722 $ 306,243 $ 11,479 2016 Revenues $ 768,484 $ 677,387 $ 91,097 Cost of sales $ 289,786 $ 239,163 $ 50,623 Depreciation and amortization $ 67,303 $ 62,451 $ 4,852 Operating income $ 200,901 $ 189,412 $ 11,489 Interest expense $ 37,630 $ 35,786 $ 1,844 Income before income taxes $ 163,271 $ 153,626 $ 9,645 Total assets $ 2,743,091 $ 2,570,297 $ 172,794 Goodwill $ 182,145 $ 182,145 $ — Capital expenditures (including the effects of accruals) $ 262,503 $ 251,261 $ 11,242 2015 Revenues $ 1,041,581 $ 933,080 $ 107,577 $ 924 Cost of sales $ 510,784 $ 448,617 $ 62,167 $ — Depreciation and amortization $ 63,590 $ 58,974 $ 4,616 $ — Operating income $ 241,667 $ 226,485 $ 14,153 $ 1,029 Interest expense $ 41,128 $ 39,112 $ 2,016 $ — Income before income taxes $ 200,539 $ 187,373 $ 12,137 $ 1,029 Total assets $ 2,505,984 $ 2,360,156 $ 145,828 $ — Goodwill $ 182,145 $ 182,145 $ — $ — Capital expenditures (including the effects of accruals) $ 197,684 $ 189,671 $ 8,013 $ —

Other Operating Income (Expen41

Other Operating Income (Expense), Net (Tables)	12 Months Ended
	Sep. 30, 2017
Component of Operating Income [Abstract]
Schedule of Other Operating Income (Expense), Net	Other operating income (expense), net, comprises the following: 2017 2016 2015 Non-tariff service income $ 1,491 $ 2,633 $ 4,760 Environmental matters 6,155 (2,918 ) 1,152 Construction service income — — 2,175 Sale of HVAC Business — — 1,065 Net interest on PGC overcollection (130 ) (1,740 ) (606 ) Other, net 813 25 323 Total other operating income (expense), net $ 8,329 $ (2,000 ) $ 8,869

Quarterly Data (unaudited) (Tab

Quarterly Data (unaudited) (Tables)	12 Months Ended
	Sep. 30, 2017
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information	The following quarterly information includes all adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of the Company’s businesses. December 31, March 31, June 30, September 30, 2016 2015 2017 2016 2017 2016 2017 2016 Revenues $ 261,413 $ 197,982 $ 359,940 $ 322,047 $ 146,692 $ 140,283 $ 119,543 $ 108,172 Operating income $ 82,236 $ 48,296 $ 116,408 $ 114,481 $ 27,671 $ 29,815 $ 1,992 $ 8,309 Net income (loss) $ 44,265 $ 23,351 $ 65,125 $ 63,294 $ 10,697 $ 12,603 $ (4,046 ) $ (1,875 )

Nature of Operations Nature of

Nature of Operations Nature of Operations (Details)	12 Months Ended
	Sep. 30, 2017county
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of counties	1

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Property, Plant and Equipment and Related Depreciation (Details) - USD ($)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Property, Plant and Equipment
Depreciation expense	$ 0
Maximum
Property, Plant and Equipment
Useful life (in years)	15 years
Removal Costs
Property, Plant and Equipment
Amortization period	5 years
Gas Utility
Property, Plant and Equipment
Average composite depreciation rates	2.20%	2.20%	2.20%
Electric Utility
Property, Plant and Equipment
Average composite depreciation rates	2.40%	2.50%	2.50%

Summary of Significant Accoun45

Summary of Significant Accounting Policies - Goodwill (Details) - USD ($)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Accounting Policies [Abstract]
Goodwill impairments	$ 0	$ 0	$ 0

Summary of Significant Accoun46

Summary of Significant Accounting Policies - Impairment of Long-Lived Assets (Details) - USD ($)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Accounting Policies [Abstract]
Provisions for impairments	$ 0	$ 0	$ 0

Regulatory Assets and Liabili47

Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Regulatory Assets
Regulatory assets	$ 368,929	$ 395,141
Regulatory Liabilities [Line Items]
Regulatory liabilities	49,230	55,569
Postretirement benefits overcollections
Regulatory Liabilities [Line Items]
Regulatory liabilities	17,493	17,519
Deferred fuel and power refunds
Regulatory Liabilities [Line Items]
Regulatory liabilities	10,621	22,299
State income tax benefits — distribution system repairs
Regulatory Liabilities [Line Items]
Regulatory liabilities	18,430	15,086
Other
Regulatory Liabilities [Line Items]
Regulatory liabilities	2,686	665
Income taxes recoverable
Regulatory Assets
Regulatory assets	121,421	115,643
Underfunded pension and postretirement plans
Regulatory Assets
Regulatory assets	141,310	183,129
Environmental costs
Regulatory Assets
Regulatory assets	61,566	59,397
Deferred fuel and power costs
Regulatory Assets
Regulatory assets	7,685	151
Removal costs, net
Regulatory Assets
Regulatory assets	30,996	27,956
Other
Regulatory Assets
Regulatory assets	$ 5,951	$ 8,865

Regulatory Assets and Liabili48

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

Oct. 20, 2017

Jul. 01, 2017

Jan. 19, 2017

Jan. 01, 2017

Oct. 19, 2016

Oct. 14, 2016

Jun. 30, 2016

Apr. 01, 2016

Jan. 19, 2016

Apr. 01, 2015

Mar. 31, 2016

Sep. 30, 2017

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2016

Regulatory Assets

Unrealized gains (losses) on derivative financial instruments contracts

$ 146

$ 4,263

Capitalized project costs

5,830

Project costs expensed in prior periods

$ 5,375

Information Technology

Regulatory Assets

Associated increase to utility property, plant and equipment

2,755

Pennsylvania Public Utility Commission

Regulatory Assets

Requested operating revenue increase

$ 21,700

Maximum period post petition to file general rate filing

5 years

Distribution system improvement charge, percent of amount billed to customers

0.00%

Pennsylvania Public Utility Commission | PNG

Regulatory Assets

Distribution system improvement charge, percent of amount billed to customers

7.50%

0.00%

Pennsylvania Public Utility Commission | PNG | Subsequent Event

Regulatory Assets

Approved operating revenue increase

$ 11,250

Pennsylvania Public Utility Commission | UGI Gas

Regulatory Assets

Requested operating revenue increase

$ 58,600

Amount of operating revenue increase

$ 27,000

Approved operating revenue increase

$ 27,000

Pennsylvania Public Utility Commission | CPG

Regulatory Assets

Distribution system improvement charge, percent of amount billed to customers

7.50%

0.00%

Removal Costs

Regulatory Assets

Period to recover costs related to regulatory assets

5 years

Deferred Project Costs

Regulatory Assets

Associated increase to utility regulatory assets

$ 3,075

Minimum

Regulatory Assets

Average remaining depreciable lives of the associated property

1 year

Maximum

Regulatory Assets

Average remaining depreciable lives of the associated property

65 years

Maximum | Pennsylvania Public Utility Commission

Regulatory Assets

Distribution system improvement charge, percent of amount billed to customers

5.00%

5.00%

Maximum | Pennsylvania Public Utility Commission | PNG

Regulatory Assets

Distribution system improvement charge, percent of amount billed to customers

10.00%

Maximum | Pennsylvania Public Utility Commission | CPG

Regulatory Assets

Distribution system improvement charge, percent of amount billed to customers

10.00%

Maximum | Postretirement benefits overcollections

Regulatory Assets

Regulatory liability, period over which overcollections will be refunded to customers

10 years

Inventories - Schedule of Inven

Inventories - Schedule of Inventories (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Public Utilities, Inventory
Total inventories	$ 53,309	$ 42,340
Gas Utility natural gas
Public Utilities, Inventory
Total inventories	39,486	29,223
Materials, supplies and other
Public Utilities, Inventory
Total inventories	$ 13,823	$ 13,117

Inventories - Additional Inform

Inventories - Additional Information (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2017USD ($)storage_agreementagreementBcf	Sep. 30, 2016USD ($)Bcf
Public Utilities, Inventory
Number of storage agreements | storage_agreement	5
Number of storage agreements with Energy Services | agreement	4
Number of storage agreements with non-affiliates | agreement	1
Volume of gas storage inventories released under SCAAs with non-affiliates (in bcf) | Bcf	9.1	8.1
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $	$ 26,064	$ 18,773
Security deposit liability | $	$ 15,040	$ 19,100
Minimum
Public Utilities, Inventory
Storage agreement, term (in years)	1 year
Maximum
Public Utilities, Inventory
Storage agreement, term (in years)	3 years

Property, Plant and Equipment51

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Property, Plant and Equipment
Property, plant and equipment	$ 3,285,329	$ 2,998,915
Distribution
Property, Plant and Equipment
Property, plant and equipment	2,835,339	2,634,191
Transmission
Property, Plant and Equipment
Property, plant and equipment	96,430	93,454
Construction in process
Property, Plant and Equipment
Property, plant and equipment	112,563	103,929
General and other
Property, Plant and Equipment
Property, plant and equipment	$ 240,997	$ 167,341

Debt - Composition of Long Term

Debt - Composition of Long Term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Oct. 31, 2016	Sep. 30, 2016
Debt Instrument
Total long-term debt	$ 755,000		$ 675,000
Less: unamortized debt issuance costs	(3,899)		(3,559)
Less: current maturities	(39,996)		(19,986)
Total long-term debt due after one year	$ 711,105		651,455
Senior Notes | 4.12%, due September 2046
Debt Instrument
Interest rate	4.12%
Total long-term debt	$ 200,000		200,000
Senior Notes | 4.98%, due March 2044
Debt Instrument
Interest rate	4.98%
Total long-term debt	$ 175,000		175,000
Senior Notes | 4.12%, due October 2046
Debt Instrument
Interest rate	4.12%	4.12%
Total long-term debt	$ 100,000		0
Senior Notes | 6.21%, due September 2036
Debt Instrument
Interest rate	6.21%
Total long-term debt	$ 100,000		100,000
Senior Notes | 2.95%, due June 2026
Debt Instrument
Interest rate	2.95%
Total long-term debt	$ 100,000		$ 100,000
Medium-Term Notes | 6.17%, due June 2017
Debt Instrument
Interest rate			6.17%
Total long-term debt	$ 0		$ 20,000
Medium-Term Notes | 7.25%, due November 2017
Debt Instrument
Interest rate	7.25%
Total long-term debt	$ 20,000		20,000
Medium-Term Notes | 5.67%, due January 2018
Debt Instrument
Interest rate	5.67%
Total long-term debt	$ 20,000		20,000
Medium-Term Notes | 6.50%, due August 2033
Debt Instrument
Interest rate	6.50%
Total long-term debt	$ 20,000		20,000
Medium-Term Notes | 6.13%, due October 2034
Debt Instrument
Interest rate	6.13%
Total long-term debt	$ 20,000		$ 20,000

Debt - Additional Information (

Debt - Additional Information (Details)	Oct. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Oct. 31, 2016USD ($)	Sep. 30, 2016USD ($)
Debt Instrument
Due in Fiscal 2018		$ 40,000,000
Due in Fiscal 2019		0
Due in Fiscal 2020		0
Due in Fiscal 2021		0
Due in Fiscal 2022		0
Short-term borrowings		170,000,000		$ 112,500,000
UGI Utilities 2015 Credit Agreement
Debt Instrument
Short-term borrowings		$ 170,000,000		$ 112,500,000
Weighted average interest rate at period end		2.11%		1.42%
UGI Utilities 2015 Credit Agreement | Line of Credit
Debt Instrument
Credit agreement		$ 300,000,000
Issued and outstanding letters of credit		2,009,000		$ 2,009,000
UGI Utilities 2015 Credit Agreement | Letter of Credit
Debt Instrument
Credit agreement		$ 100,000,000
UGI Utilities 2015 Credit Agreement | Minimum | Line of Credit
Debt Instrument
Margin on term loan base rate borrowings (as a percent)		0.00%
UGI Utilities 2015 Credit Agreement | Maximum | Line of Credit
Debt Instrument
Margin on term loan base rate borrowings (as a percent)		1.75%
Senior Notes
Debt Instrument
Debt to capital ratio		0.65
Senior Notes | 4.12% Senior Notes, due September 2046
Debt Instrument
Interest rate		4.12%
Senior Notes | 4.12%, due October 2046
Debt Instrument
Aggregate principal amount			$ 100,000,000
Interest rate		4.12%	4.12%
Unsecured Debt [Member] | Subsequent Event
Debt Instrument
Aggregate principal amount	$ 125,000,000
Principal repayment in equal quarterly installments	$ 1,563,000
Unsecured Debt [Member] | Subsequent Event | Minimum
Debt Instrument
Margin on term loan base rate borrowings (as a percent)	0.00%
Unsecured Debt [Member] | Subsequent Event | Maximum
Debt Instrument
Margin on term loan base rate borrowings (as a percent)	1.875%

Income Taxes - Provisions for I

Income Taxes - Provisions for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Current expense (benefit):
Federal	$ (12,253)	$ (17,845)	$ 34,990
State	5,739	6,805	15,138
Total current (benefit) expense	(6,514)	(11,040)	50,128
Deferred expense (benefit):
Federal	70,293	71,005	28,877
State	8,593	6,262	815
Investment tax credit amortization	(318)	(329)	(336)
Total income tax expense	$ 72,054	$ 65,898	$ 79,484

Income Taxes - Reconciliation f

Income Taxes - Reconciliation from US Federal Statutory Tax Rate to Effective Tax Rate (Details)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Income Tax Disclosure [Abstract]
U.S. federal statutory tax rate	35.00%	35.00%	35.00%
Difference in tax rate due to:
State income taxes, net of federal benefit	5.00%	5.20%	5.10%
Excess tax benefits on share-based payments	(0.90%)	0.00%	0.00%
Other, net	(0.80%)	0.20%	(0.50%)
Effective tax rate	38.30%	40.40%	39.60%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Income Taxes
Interest (income) expense	$ (73)	$ 204	$ 0
Unrecognized tax benefits	1,829	2,055	0	$ 0
Accrued interest	132
Unrecognized tax benefits if recognized would impact the reported effective tax rate	940
State and Local Jurisdiction
Income Taxes
Decrease in income tax expense due to state tax flow through of accelerated depreciation	$ 2,537	$ 1,344	$ 1,539

Income Taxes - Deferred Tax Lia

Income Taxes - Deferred Tax Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Excess book basis over tax basis of property, plant and equipment	$ 564,327	$ 491,038
Goodwill	49,588	45,070
Derivative financial instruments	0	948
Regulatory assets	136,093	149,660
Other	3,140	2,910
Gross deferred tax liabilities	753,148	689,626
Pension plan liabilities	(57,011)	(74,129)
Allowance for doubtful accounts	(1,681)	(1,637)
Deferred investment tax credits	(1,224)	(1,356)
Employee-related expenses	(6,793)	(5,247)
Regulatory liabilities	(12,780)	(16,798)
Environmental liabilities	(22,224)	(22,757)
Derivative financial instruments	(354)	0
Other	(15,616)	(17,473)
Gross deferred tax assets	(117,683)	(139,397)
Net deferred tax liabilities	$ 635,465	$ 550,229

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Reconciliation of Unrecognized Tax Benefits
Unrecognized tax benefits – beginning of year	$ 2,055	$ 0	$ 0
Additions for tax positions taken in prior years	604	2,055	0
Additions for tax positions of the current year	0	0	0
Settlements with tax authorities/statute lapses	(830)	0	0
Unrecognized tax benefits – end of year	$ 1,829	$ 2,055	$ 0

Employee Retirement Plans - Cha

Employee Retirement Plans - Change in Pension Benefits and Other Postretirement Benefit Obligations, Plan Assets, and Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Assets (liabilities) recorded in the balance sheet:
Unfunded liabilities – included in other noncurrent liabilities	$ (143,674)	$ (184,516)
Pension Benefits
Change in benefit obligations:
Benefit obligations — beginning of year	645,444	563,621
Service cost	9,038	7,772
Interest cost	24,394	25,733
Actuarial (gain) loss	(14,575)	72,418
Benefits paid	(25,056)	(24,100)
Benefit obligations — end of year	639,245	645,444	$ 563,621
Change in plan assets:
Fair value of plan assets — beginning of year	463,432	430,789
Actual gain on assets	48,309	46,874
Employer contributions	11,395	9,869	11,131
Benefits paid	(25,056)	(24,100)
Fair value of plan assets — end of year	498,080	463,432	430,789
Funded status of the plans — end of year	(141,165)	(182,012)
Assets (liabilities) recorded in the balance sheet:
Assets in excess of liabilities – included in other noncurrent assets	0	0
Unfunded liabilities – included in other noncurrent liabilities	(141,165)	(182,012)
Net amount recognized	(141,165)	(182,012)
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	105	138
Net actuarial loss (gain)	15,106	19,866
Total	15,211	20,004
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	970	1,262
Net actuarial loss	139,505	180,964
Total	140,475	182,226
Other Postretirement Benefits
Change in benefit obligations:
Benefit obligations — beginning of year	12,075	10,676
Service cost	303	198
Interest cost	460	483
Actuarial (gain) loss	(512)	1,117
Benefits paid	(422)	(399)
Benefit obligations — end of year	11,904	12,075	10,676
Change in plan assets:
Fair value of plan assets — beginning of year	13,715	12,523
Actual gain on assets	1,333	1,347
Employer contributions	85	98
Benefits paid	(362)	(253)
Fair value of plan assets — end of year	14,771	13,715	$ 12,523
Funded status of the plans — end of year	2,867	1,640
Assets (liabilities) recorded in the balance sheet:
Assets in excess of liabilities – included in other noncurrent assets	5,382	4,139
Unfunded liabilities – included in other noncurrent liabilities	(2,514)	(2,499)
Net amount recognized	2,868	1,640
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	(23)	(35)
Net actuarial loss (gain)	(46)	(1)
Total	(69)	(36)
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	(1,605)	(2,247)
Net actuarial loss	1,192	2,425
Total	$ (413)	$ 178

Employee Retirement Plans - Add

Employee Retirement Plans - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Disclosure
Estimated amortization of net actuarial losses for Fiscal 2017	$ 12,000
Amortization of net prior service costs (credits)	$ (250)
Percentage point change in assumed health care cost trend rates	1.00%
Projected benefit obligations of unfunded and non qualified supplemental executive retirement plans	$ 4,222	$ 3,628
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans	$ 605	$ 353	$ 445
The aggregate holdings of all qualifying employer securities not to exceed the fair value of trust assets at the time of purchase	10.00%
Percentage of UGI Common Stock represented Pension Plan Assets	7.70%	8.00%
Cost of benefits under Utilities Savings Plan	$ 2,829	$ 2,409	2,162
Pension Benefits
Defined Benefit Plan Disclosure
ABO for the Pension Plans	605,237	601,255
Benefit obligations	639,245	645,444	563,621
Employer contributions	11,395	9,869	11,131
Pension Benefits | Employees of UGI and Certain of its Other Subsidiaries
Defined Benefit Plan Disclosure
Benefit obligations	62,458	63,847
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Benefit obligations	11,904	12,075	$ 10,676
Employer contributions	85	98
Other Postretirement Benefits | Employees of UGI and Certain of its Other Subsidiaries
Defined Benefit Plan Disclosure
ABO for the Pension Plans	$ 996	$ 951

Employee Retirement Plans - Act

Employee Retirement Plans - Actuarial Assumptions for Domestic Plans (Details)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits
Weighted-average assumptions:
Discount rate – benefit obligations	4.00%	3.80%	4.60%
Discount rate – benefit cost	3.80%	4.60%	4.60%
Expected return on plan assets	7.50%	7.55%	7.75%
Rate of increase in salary levels	3.25%	3.25%	3.25%
Other Postretirement Benefits
Weighted-average assumptions:
Discount rate – benefit obligations	4.00%	3.80%	4.70%
Discount rate – benefit cost	3.80%	4.70%	4.60%
Expected return on plan assets	5.00%	5.00%	5.00%
Rate of increase in salary levels	3.25%	3.25%	3.25%

Employee Retirement Plans - Com

Employee Retirement Plans - Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 9,038	$ 7,772
Interest cost	24,394	25,733
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	303	198
Interest cost	460	483
UGI Utilities Employees | Pension Benefits
Defined Benefit Plan Disclosure
Service cost	8,091	6,927	$ 6,962
Interest cost	22,157	23,270	22,511
Expected return on assets	(29,986)	(28,668)	(28,898)
Amortization of:
Prior service cost (benefit)	325	348	348
Actuarial loss	14,825	9,571	8,793
Net benefit cost (income)	15,412	11,448	9,716
Change in associated regulatory liabilities	0	0	0
Net benefit cost after change in regulatory liabilities	15,412	11,448	9,716
UGI Utilities Employees | Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	273	183	202
Interest cost	431	465	479
Expected return on assets	(656)	(596)	(612)
Amortization of:
Prior service cost (benefit)	(641)	(641)	(641)
Actuarial loss	108	98	122
Net benefit cost (income)	(485)	(491)	(450)
Change in associated regulatory liabilities	(490)	971	3,740
Net benefit cost after change in regulatory liabilities	$ (975)	$ 480	$ 3,290

Employee Retirement Plans - Exp

Employee Retirement Plans - Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits (Details) $ in Thousands	Sep. 30, 2017USD ($)
Pension Benefits
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Fiscal 2,018	$ 27,176
Fiscal 2,019	28,471
Fiscal 2,020	29,812
Fiscal 2,021	31,084
Fiscal 2,022	32,323
Fiscal 2023 - 2027	179,945
Other Postretirement Benefits
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Fiscal 2,018	566
Fiscal 2,019	566
Fiscal 2,020	552
Fiscal 2,021	537
Fiscal 2,022	540
Fiscal 2023 - 2027	$ 2,710

Employee Retirement Plans - Sch

Employee Retirement Plans - Schedule of Effect of One-percentage-point Change in Assumed Health Care Cost Trend Rates (Details)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Plan [Abstract]
Health care cost trend rate assumed for next year	7.00%	7.25%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	5.00%	5.00%
Fiscal year that the rate reaches the ultimate trend rate	2,026	2,026

Employee Retirement Plans - All

Employee Retirement Plans - Allocation of Pension Plan and VEBA Trust Assets (Details)	Sep. 30, 2017	Sep. 30, 2016
VEBA Trust
Defined Benefit Plan Disclosure
Actual pension plan	100.00%	100.00%
Target asset allocation	100.00%
VEBA Trust | Domestic
Defined Benefit Plan Disclosure
Actual pension plan	63.10%	69.90%
Target asset allocation	65.00%
VEBA Trust | Domestic | Minimum
Defined Benefit Plan Disclosure
Target asset allocation	60.00%
VEBA Trust | Domestic | Maximum
Defined Benefit Plan Disclosure
Target asset allocation	70.00%
VEBA Trust | Fixed income funds & cash equivalents
Defined Benefit Plan Disclosure
Actual pension plan	36.90%	30.10%
Target asset allocation	35.00%
VEBA Trust | Fixed income funds & cash equivalents | Minimum
Defined Benefit Plan Disclosure
Target asset allocation	30.00%
VEBA Trust | Fixed income funds & cash equivalents | Maximum
Defined Benefit Plan Disclosure
Target asset allocation	40.00%
Pension Benefits
Defined Benefit Plan Disclosure
Actual pension plan	100.00%	100.00%
Target asset allocation	100.00%
Pension Benefits | Equity investments
Defined Benefit Plan Disclosure
Actual pension plan	67.60%	64.30%
Target asset allocation	65.00%
Pension Benefits | Equity investments | Minimum
Defined Benefit Plan Disclosure
Target asset allocation	60.00%
Pension Benefits | Equity investments | Maximum
Defined Benefit Plan Disclosure
Target asset allocation	70.00%
Pension Benefits | Domestic
Defined Benefit Plan Disclosure
Actual pension plan	55.20%	54.10%
Target asset allocation	52.50%
Pension Benefits | Domestic | Minimum
Defined Benefit Plan Disclosure
Target asset allocation	40.00%
Pension Benefits | Domestic | Maximum
Defined Benefit Plan Disclosure
Target asset allocation	65.00%
Pension Benefits | International
Defined Benefit Plan Disclosure
Actual pension plan	12.40%	10.20%
Target asset allocation	12.50%
Pension Benefits | International | Minimum
Defined Benefit Plan Disclosure
Target asset allocation	7.50%
Pension Benefits | International | Maximum
Defined Benefit Plan Disclosure
Target asset allocation	17.50%
Pension Benefits | Fixed income funds & cash equivalents
Defined Benefit Plan Disclosure
Actual pension plan	32.40%	35.70%
Target asset allocation	35.00%
Pension Benefits | Fixed income funds & cash equivalents | Minimum
Defined Benefit Plan Disclosure
Target asset allocation	30.00%
Pension Benefits | Fixed income funds & cash equivalents | Maximum
Defined Benefit Plan Disclosure
Target asset allocation	40.00%

Employee Retirement Plans - Fai

Employee Retirement Plans - Fair Value of Pension Plan and VEBA Trust Assets (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
VEBA Trust
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 14,771	$ 13,715
Other	409	113
VEBA Trust | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	9,318	9,583
Other	0	0
VEBA Trust | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	5,044	4,019
Other	0	0
VEBA Trust | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	409	113
Other	409	113
VEBA Trust | Level 1
Defined Benefit Plan Disclosure
Fair value of plan assets	14,362	13,602
VEBA Trust | Level 1 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	9,318	9,583
VEBA Trust | Level 1 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	5,044	4,019
VEBA Trust | Level 1 | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA Trust | Level 2
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA Trust | Level 2 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA Trust | Level 2 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA Trust | Level 2 | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA Trust | Level 3
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA Trust | Level 3 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA Trust | Level 3 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA Trust | Level 3 | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits
Defined Benefit Plan Disclosure
Fair value of plan assets	498,080	463,432	$ 430,789
Pension Benefits | U.S. Pension Plan
Defined Benefit Plan Disclosure
Fair value of plan assets	498,077	463,432
Other	5,332	17,811
Pension Benefits | U.S. Pension Plan | Total domestic equity investments
Defined Benefit Plan Disclosure
Fair value of plan assets	274,904	250,503
Other	0	0
Pension Benefits | U.S. Pension Plan | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	171,600	158,906
Other	0	0
Pension Benefits | U.S. Pension Plan | Small and midcap equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	65,167	43,170
Other	0	0
Pension Benefits | U.S. Pension Plan | Smallcap common stocks
Defined Benefit Plan Disclosure
Fair value of plan assets		11,414
Other		0
Pension Benefits | U.S. Pension Plan | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	38,137	37,013
Other	0	0
Pension Benefits | U.S. Pension Plan | International index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	61,613	47,324
Other	0	0
Pension Benefits | U.S. Pension Plan | Total fixed income investments
Defined Benefit Plan Disclosure
Fair value of plan assets	161,560	165,605
Other	5,332	17,811
Pension Benefits | U.S. Pension Plan | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	156,228	147,794
Other	0	0
Pension Benefits | U.S. Pension Plan | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	5,332	17,811
Other	5,332	17,811
Pension Benefits | U.S. Pension Plan | Level 1
Defined Benefit Plan Disclosure
Fair value of plan assets	492,745	445,621
Pension Benefits | U.S. Pension Plan | Level 1 | Total domestic equity investments
Defined Benefit Plan Disclosure
Fair value of plan assets	274,904	250,503
Pension Benefits | U.S. Pension Plan | Level 1 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	171,600	158,906
Pension Benefits | U.S. Pension Plan | Level 1 | Small and midcap equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	65,167	43,170
Pension Benefits | U.S. Pension Plan | Level 1 | Smallcap common stocks
Defined Benefit Plan Disclosure
Fair value of plan assets		11,414
Pension Benefits | U.S. Pension Plan | Level 1 | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	38,137	37,013
Pension Benefits | U.S. Pension Plan | Level 1 | International index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	61,613	47,324
Pension Benefits | U.S. Pension Plan | Level 1 | Total fixed income investments
Defined Benefit Plan Disclosure
Fair value of plan assets	156,228	147,794
Pension Benefits | U.S. Pension Plan | Level 1 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	156,228	147,794
Pension Benefits | U.S. Pension Plan | Level 1 | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 2
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 2 | Total domestic equity investments
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 2 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 2 | Small and midcap equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 2 | Smallcap common stocks
Defined Benefit Plan Disclosure
Fair value of plan assets		0
Pension Benefits | U.S. Pension Plan | Level 2 | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 2 | International index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 2 | Total fixed income investments
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 2 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 2 | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 3
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 3 | Total domestic equity investments
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 3 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 3 | Small and midcap equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 3 | Smallcap common stocks
Defined Benefit Plan Disclosure
Fair value of plan assets		0
Pension Benefits | U.S. Pension Plan | Level 3 | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 3 | International index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 3 | Total fixed income investments
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 3 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. Pension Plan | Level 3 | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 0	$ 0

Series Preferred Stock (Details

Series Preferred Stock (Details) - shares	Sep. 30, 2017	Sep. 30, 2016
Equity [Abstract]
Preferred stock, shares authorized	2,000,000
Preferred stock, shares outstanding	0	0

Equity-Based Compensation - Add

Equity-Based Compensation - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award
Number of equity-based units for unrecognized compensation expense (in units)	52,224	57,783
Share Based Compensation Types, Excluding Stock Options | UGI Omnibus Equity Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award
Award vesting period (in years)	3 years
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award
Exercise period after grant date - no more than (in years)	10 years
Performance Unit | UGI Units and UGI Stock Options
Share-based Compensation Arrangement by Share-based Payment Award
Allocated share-based compensation expense	$ 1,461	$ 1,924	$ 1,847
Allocated share-based compensation expense, after-tax	$ 855	1,126	$ 1,081
Performance Unit | UGI Units and UGI Stock Options | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Percent of target award paid to grantee	0.00%
Performance Unit | UGI Units and UGI Stock Options | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Percent of target award paid to grantee	200.00%
Performance Unit | UGI Stock Options
Share-based Compensation Arrangement by Share-based Payment Award
Nonvested awards, total compensation cost not yet recognized	$ 1,167
Nonvested awards, total compensation cost not yet recognized, period for recognition	1 year 10 months 24 days
Performance Unit | UGI Units
Share-based Compensation Arrangement by Share-based Payment Award
Nonvested awards, total compensation cost not yet recognized	$ 1,029
Nonvested awards, total compensation cost not yet recognized, period for recognition	1 year 9 months
Number of equity-based units for unrecognized compensation expense (in units)	45,588
Performance Unit | UGI Units | Other Current Liabilities
Share-based Compensation Arrangement by Share-based Payment Award
Deferred compensation arrangements, liability, current	$ 533
Performance Unit | UGI Units | Other Noncurrent Liabilities
Share-based Compensation Arrangement by Share-based Payment Award
Deferred compensation arrangements, liability, noncurrent		$ 1,304

Equity-Based Compensation - UGI

Equity-Based Compensation - UGI Unit Award Activity (Details)	12 Months Ended
	Sep. 30, 2017$ / sharesshares
Number of UGI Units
Beginning balance (in units) | shares	57,783
Granted (in units) | shares	16,425
Vested (in units) | shares	0
Forfeitures & transfers (in units) | shares	(1,934)
Unit awards paid (in units) | shares	(20,050)
Ending balance (in units) | shares	52,224
Weighted Average Grant Date Fair Value (per Unit)
Beginning balance (in usd per share) | $ / shares	$ 34.66
Granted (in usd per share) | $ / shares	51.42
Vested (in usd per share) | $ / shares	0
Forfeitures & transfers (in usd per share) | $ / shares	34.74
Unit awards paid (in usd per share) | $ / shares	32.59
Ending balance (in usd per share) | $ / shares	$ 40.72
Vested
Number of UGI Units
Beginning balance (in units) | shares	10,316
Granted (in units) | shares	367
Vested (in units) | shares	16,003
Forfeitures & transfers (in units) | shares	0
Unit awards paid (in units) | shares	(20,050)
Ending balance (in units) | shares	6,636
Weighted Average Grant Date Fair Value (per Unit)
Beginning balance (in usd per share) | $ / shares	$ 34.31
Granted (in usd per share) | $ / shares	51.42
Vested (in usd per share) | $ / shares	33.10
Forfeitures & transfers (in usd per share) | $ / shares	0
Unit awards paid (in usd per share) | $ / shares	32.59
Ending balance (in usd per share) | $ / shares	$ 37.53
Non-Vested
Number of UGI Units
Beginning balance (in units) | shares	47,467
Granted (in units) | shares	16,058
Vested (in units) | shares	16,003
Forfeitures & transfers (in units) | shares	(1,934)
Unit awards paid (in units) | shares	0
Ending balance (in units) | shares	45,588
Weighted Average Grant Date Fair Value (per Unit)
Beginning balance (in usd per share) | $ / shares	$ 34.74
Granted (in usd per share) | $ / shares	51.42
Vested (in usd per share) | $ / shares	33.10
Forfeitures & transfers (in usd per share) | $ / shares	34.74
Unit awards paid (in usd per share) | $ / shares	0
Ending balance (in usd per share) | $ / shares	$ 41.19

Commitments and Contingencies -

Commitments and Contingencies - Commitments (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Rental expense	$ 7,276	$ 7,669	$ 7,956
2,018	7,545
2,019	5,961
2,020	4,355
2,021	2,665
2,022	793
After 2,022	$ 182

Commitments and Contingencies71

Commitments and Contingencies - Contingencies (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2017USD ($)subsidiary	Sep. 30, 2016USD ($)
CPG; PNG and UGI Gas COAs
Contingencies
Accrued liabilities for environmental investigation and remediation costs	$ 54,250	$ 55,063
Environmental Issue | UGI Utilities
Contingencies
Environmental expenditures cap during calendar year	2,500
Environmental Issue | CPG MGP
Contingencies
Environmental expenditures cap during calendar year	1,750
Environmental Issue | PNG MGP
Contingencies
Environmental expenditures cap during calendar year	$ 1,100
PNG and CPG
Contingencies
Number of subsidiaries acquired with similar histories | subsidiary	2

Fair Value Measurements - Finan

Fair Value Measurements - Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - Commodity Contracts - Fair Value - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Fair value of derivative assets, gross	$ 1,807	$ 4,510
Fair value of derivative liabilities, gross	(1,520)	(557)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Fair value of derivative assets, gross	1,735	4,506
Fair value of derivative liabilities, gross	(1,447)	(263)
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Fair value of derivative assets, gross	72	4
Fair value of derivative liabilities, gross	(73)	(294)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Fair value of derivative assets, gross	0	0
Fair value of derivative liabilities, gross	$ 0	$ 0

Fair Value Measurements - Long-

Fair Value Measurements - Long-term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Carrying amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 755,000	$ 675,000
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 791,378	$ 770,781

Derivative Instruments and He74

Derivative Instruments and Hedging Activities - Additional Information (Details) kWh in Millions, MMBTU in Millions	Mar. 31, 2016USD ($)	Sep. 30, 2017USD ($)MMBTUkWh	Sep. 30, 2016USD ($)MMBTUkWh	Sep. 30, 2015USD ($)
Derivative
Settlement of interest rate protection agreements	$ 35,975,000	$ 0	$ (35,975,000)	$ 0
Interest rate cash flow hedge loss to be reclassified during next 12 months, net		3,485,000
Restricted cash in brokerage accounts		3,046,000	583,000
Interest Rate Protection Agreements
Derivative
Underlying variable rate debt		$ 0	$ 0
Gas Utility
Derivative
Notional amount (in units) | MMBTU		14.8	18.4
Maximum length of time hedged in price risk cash flow hedges (in months)		12 months
Electric Utility | Electric Utility Electric Transmission Congestion
Derivative
Notional amount (in units) | kWh		101.2	58.3
Maximum length of time hedged in price risk cash flow hedges (in months)		8 months

Derivative Instruments and He75

Derivative Instruments and Hedging Activities - Derivative Assets and Liabilities Including Offsetting Amounts (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Derivative Instruments, Assets
Derivative assets:
Fair value of derivative assets, gross	$ 1,807	$ 4,510
Gross amounts offset in the balance sheet	(450)	(247)
Total derivative assets - net	1,357	4,263
Derivative Instruments, Assets | Commodity Contract Subject to PGC and DS Mechanisms
Derivative assets:
Fair value of derivative assets, gross	1,665	4,472
Derivative Instruments, Assets | Commodity Contract Not Subject to PGC and DS Mechanisms
Derivative assets:
Fair value of derivative assets, gross	142	38
Derivative Instruments, Liabilities
Derivative liabilities:
Fair value of derivative liabilities, gross	(1,520)	(557)
Gross amounts offset in the balance sheet	450	247
Total derivative liabilities - net	(1,070)	(310)
Derivative Instruments, Liabilities | Commodity Contract Subject to PGC and DS Mechanisms
Derivative liabilities:
Fair value of derivative liabilities, gross	(1,520)	(499)
Derivative Instruments, Liabilities | Commodity Contract Not Subject to PGC and DS Mechanisms
Derivative liabilities:
Fair value of derivative liabilities, gross	$ 0	$ (58)

Derivative Instruments and He76

Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on Consolidated Statements of Income and Changes in AOCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Gasoline contracts | Operating and administrative expenses/other operating income, net
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	$ 174	$ (88)	$ (761)
Cash Flow Hedges | Designated as Hedging Instrument | Interest rate contracts
Derivative Instruments, Gain (Loss)
Loss Recognized in AOCI	0	(28,958)	(7,016)
Cash Flow Hedges | Designated as Hedging Instrument | Interest rate contracts | Interest expense
Derivative Instruments, Gain (Loss)
Loss Reclassified from AOCI into Income	$ (3,397)	$ (2,680)	$ (2,674)

Accumulated Other Comprehensi77

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of year	$ 924,737	$ 890,620
Reclassifications, net of tax	956	639	$ 517
Net losses on derivative instruments	0	(16,942)	(4,105)
Benefit plans, principally actuarial gains	1,883	(3,197)	(3,482)
Balance, end of year	987,905	924,737	890,620
Interest Rate Protection Agreements
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassifications, net of tax	1,988	1,568	1,565
Postretirement Benefit Plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of year	(11,834)	(9,276)	(6,311)
Reclassifications, net of tax	956	639	517
Net losses on derivative instruments		0	0
Benefit plans, principally actuarial gains	1,883	(3,197)	(3,482)
Balance, end of year	(8,995)	(11,834)	(9,276)
Postretirement Benefit Plans | Interest Rate Protection Agreements
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassifications, net of tax	0	0	0
Derivative Instruments
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of year	(19,784)	(4,410)	(1,870)
Reclassifications, net of tax	0	0	0
Net losses on derivative instruments		(16,942)	(4,105)
Benefit plans, principally actuarial gains	0	0	0
Balance, end of year	(17,796)	(19,784)	(4,410)
Derivative Instruments | Interest Rate Protection Agreements
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassifications, net of tax	1,988	1,568	1,565
AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of year	(31,618)	(13,686)	(8,181)
Net losses on derivative instruments	0	(16,942)	(4,105)
Balance, end of year	$ (26,791)	$ (31,618)	$ (13,686)

Segment Information (Details)

Segment Information (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2017USD ($)countySegmentcustomer	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Measurement Disclosures
Number of reportable segments (in segments) | Segment									2
Number of counties | county									1
Revenues	$ 119,543	$ 146,692	$ 359,940	$ 261,413	$ 108,172	$ 140,283	$ 322,047	$ 197,982	$ 887,588	$ 768,484	$ 1,041,581
Cost of sales									367,279	289,786	510,784
Depreciation and amortization									72,332	67,303	63,590
Operating income	1,992	$ 27,671	$ 116,408	$ 82,236	8,309	$ 29,815	$ 114,481	$ 48,296	228,307	200,901	241,667
Interest expense									40,212	37,630	41,128
Income before income taxes									188,095	163,271	200,539
Total assets	2,994,015				2,743,091				2,994,015	2,743,091	2,505,984
Goodwill	182,145				182,145				182,145	182,145	182,145
Capital expenditures (including the effects of accruals)									$ 317,722	262,503	197,684
Electric Utility
Measurement Disclosures
Number of counties | county									2
Operating Segments | Gas Utility
Measurement Disclosures
Revenues									$ 799,054	677,387	933,080
Cost of sales									318,210	239,163	448,617
Depreciation and amortization									67,357	62,451	58,974
Operating income									219,561	189,412	226,485
Interest expense									38,218	35,786	39,112
Income before income taxes									181,343	153,626	187,373
Total assets	2,833,423				2,570,297				2,833,423	2,570,297	2,360,156
Goodwill	182,145				182,145				182,145	182,145	182,145
Capital expenditures (including the effects of accruals)									306,243	251,261	189,671
Operating Segments | Electric Utility
Measurement Disclosures
Revenues									88,534	91,097	107,577
Cost of sales									49,069	50,623	62,167
Depreciation and amortization									4,975	4,852	4,616
Operating income									8,746	11,489	14,153
Interest expense									1,994	1,844	2,016
Income before income taxes									6,752	9,645	12,137
Total assets	160,592				172,794				160,592	172,794	145,828
Goodwill	$ 0				$ 0				0	0	0
Capital expenditures (including the effects of accruals)									$ 11,479	$ 11,242	8,013
Other
Measurement Disclosures
Revenues											924
Cost of sales											0
Depreciation and amortization											0
Operating income											1,029
Interest expense											0
Income before income taxes											1,029
Total assets											0
Goodwill											0
Capital expenditures (including the effects of accruals)											$ 0
Customer Concentration Risk | Revenue, Consolidated
Measurement Disclosures
Number of customers | customer									0

Other Operating Income (Expen79

Other Operating Income (Expense), Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Component of Operating Income [Abstract]
Non-tariff service income	$ 1,491	$ 2,633	$ 4,760
Environmental matters	6,155	(2,918)	1,152
Construction service income	0	0	2,175
Sale of HVAC Business	0	0	1,065
Net interest on PGC overcollection	(130)	(1,740)	(606)
Other, net	813	25	323
Total other operating income (expense), net	$ 8,329	$ (2,000)	$ 8,869

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2017USD ($)agreementBcf	Sep. 30, 2016USD ($)Bcf	Sep. 30, 2015USD ($)
Related Party Transaction
Related party costs incurred	$ 12,354	$ 11,863	$ 11,956
UGI and Subsidiaries | Administrative Services
Related Party Transaction
Amount of related party transaction	$ 4,346	$ 5,069	3,168
Energy Services
Related Party Transaction
Agreement term (in years)	1 year
Volume of gas storage inventory (in bcf of natural gas) | Bcf	6.8	4.6
Natural gas storage inventory, related parties, current	$ 19,323	$ 11,148
Revenue from related parties	50,948	30,743	79,182
Purchases from related party	84,402	35,067	85,383
Energy Services | SCAAs
Related Party Transaction
Amount of related party transaction	$ 2,747	2,002	2,339
Agreement term (in years)	3 years
Number of storage agreements | agreement	4
Related party costs incurred	$ 21,424	12,739	16,849
Related party security deposits	11,040	8,100
Energy Services | Exclusive of Transactions Pursuant SCAAs
Related Party Transaction
Related party costs incurred	$ 76,010	$ 63,331	$ 47,794

Quarterly Data (unaudited) (Det

Quarterly Data (unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Quarterly Financial Data [Abstract]
Revenues	$ 119,543	$ 146,692	$ 359,940	$ 261,413	$ 108,172	$ 140,283	$ 322,047	$ 197,982	$ 887,588	$ 768,484	$ 1,041,581
Operating income	1,992	27,671	116,408	82,236	8,309	29,815	114,481	48,296	228,307	200,901	241,667
Net income (loss)	$ (4,046)	$ 10,697	$ 65,125	$ 44,265	$ (1,875)	$ 12,603	$ 63,294	$ 23,351	$ 116,041	$ 97,373	$ 121,055

Schedule II - Valuation and Q82

Schedule II - Valuation and Qualifying Accounts (Details) - Allowance for Doubtful Accounts - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Movement in Valuation Allowances and Reserves
Balance at beginning of year	$ 3,946	$ 5,599	$ 6,992
Charged to costs and expenses	8,030	7,760	13,498
Other	(7,924)	(9,413)	(14,891)
Balance at end of year	$ 4,052	$ 3,946	$ 5,599