UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June~~December 3031, 2018



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-1398

UGI UTILITIES, INC.

(Exact name of registrant as specified in its charter)



Pennsylvania		23-1174060
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

~~2525~~One N.UGI ~~12th Street~~Drive, ~~Suite 360~~Denver, ~~Reading,~~ PA ~~19612~~17517

(Address of principal executive offices) (Zip Code)

(610) 796-3400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	o	Accelerated filer	o	Non-accelerated filer	þ
Smaller reporting company	o	Emerging growth company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

At ~~July~~January 31, ~~2018~~2019, there were 26,781,785 shares of UGI Utilities, Inc. Common Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI Corporation.

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
Glossary of Terms and Abbreviations	1
Part I Financial Information
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets as of June 30, 2018, September 30, 2017 and June 30, 2017	1
Condensed Consolidated Balance Sheets as of December 31, 2018, September 30, 2018 and December 31, 2017	3
Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2018 and 2017	2
Condensed Consolidated Statements of Income for the three months ended December 31, 2018 and 2017	4
Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended June 30, 2018 and 2017	3
Condensed Consolidated Statements of Comprehensive Income for the three months ended December 31, 2018 and 2017	5
Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2018 and 2017	4
Condensed Consolidated Statements of Cash Flows for the three months ended December 31, 2018 and 2017	6
Notes to Condensed Consolidated Financial Statements	5
Condensed Consolidated Statements of Stockholder’s Equity	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Notes to Condensed Consolidated Financial Statements	8
Item 3. Quantitative and Qualitative Disclosures About Market Risk	30
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 4. Controls and Procedures	30
Item 3. Quantitative and Qualitative Disclosures About Market Risk	31
Item 4. Controls and Procedures	31
Part II Other Information
Item 1A. Risk Factors	3233
Item 6. Exhibits	3233
Signatures	3435

- i -

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

Terms and abbreviations used in this Form 10-Q are defined below:

UGI Utilities, Inc. and Related Entities

Company - UGI Utilities or collectively UGI Utilities and its subsidiaries

CPG - UGI Central Penn Gas, Inc., a wholly owned subsidiary of UGI Utilities prior to the Utility Merger

Energy Services - UGI Energy Services, LLC, a wholly owned subsidiary of UGI

Electric Utility - UGI Utilities’ regulated electric distribution utility

Gas Utility - UGI Utilities’ regulated natural gas distribution businesses, comprising the natural gas utility businesses owned and operated by UGI Utilities and, prior to the Utility Merger, PNG and CPG

PNG - UGI Penn Natural Gas, Inc., a wholly owned subsidiary of UGI Utilities prior to the Utility Merger

UGI - UGI Corporation

UGI Central - The natural gas rate district of CPG subsequent to the Utility Merger

UGI Gas - UGI Utilities’ natural gas utility, prior to the Utility Merger

UGI North - The natural gas rate district of PNG subsequent to the Utility Merger

UGI South - The natural gas rate district of UGI Gas subsequent to the Utility Merger

UGI Utilities - UGI Utilities, Inc., a wholly owned subsidiary of UGI

Other Terms and Abbreviations

2017 three-month period - Three-month period ended December 31, 2017

2018 Annual Report - UGI Utilities Annual Report on Form 10-K for the fiscal year ended September 30, 2018

2018 three-month period - Three-month period ended December 31, 2018

4.55% Senior Notes - A private placement of $150 million principal amount of senior notes issued by UGI Utilities

AOCI - Accumulated other comprehensive income (loss)

ASC - Accounting Standards Codification

ASC 605 - ASC 605, “Revenue Recognition”

ASC 606 - ASC 606, “Revenue from Contracts with Customers”

ASC 740 - ASC 740, “Income Taxes”

ASU - Accounting Standards Update

Bcf - Billions of cubic feet

BIE - Pennsylvania Public Utility Commission Bureau of Investigation and Enforcement

COA - Consent order and agreement

Core market - Comprises (1) firm residential, commercial and industrial customers for whom UGI Utilities has a statutory obligation to serve who purchase their natural gas or electricity from UGI Utilities; and (2) residential, commercial and industrial customers for whom UGI Utilities has a statutory obligation to serve who purchase their natural gas or electricity from others

Table of Contents

DS - Default service

ERISA - Employee Retirement Income Security Act of 1974

Exchange Act - Securities Exchange Act of 1934, as amended

FASB - Financial Accounting Standards Board

FERC - Federal Energy Regulatory Commission

FTR - Financial transmission rights

GAAP - U.S. generally accepted accounting principles

Gwh - Millions of kilowatt hours

IRPA - Interest rate protection agreement

IT - Information technology

LIBOR - London Inter-bank Offered Rate

MDPSC - Maryland Public Service Commission

MGP - Manufactured gas plant

NOAA - National Oceanic and Atmospheric Administration

NPNS - Normal purchase and normal sale

NTSB - National Transportation Safety Board

NYMEX - New York Mercantile Exchange

PADEP - Pennsylvania Department of Environmental Protection

PAPUC - Pennsylvania Public Utility Commission

Pension Plan - Defined benefit pension plan for employees hired prior to January 1, 2009 of UGI, UGI Utilities, CPG, PNG and certain of UGI’s other domestic wholly owned subsidiaries

PGC - Purchased gas costs

PJM - PJM Interconnection, LLC

Retail core-market - Comprises firm residential, commercial and industrial customers for whom UGI Utilities has a statutory obligation to serve that purchase their natural gas from Gas Utility

SCAA - Storage contract administrative agreements

SEC - U.S. Securities and Exchange Commission

TCJA - Tax Cuts and Jobs Act

UGI Utilities Credit Agreement - Revolving Credit Agreement issued by UGI Utilities

Utility Merger - The merger, effective October 1, 2018, of CPG and PNG with UGI Utilities

VEBA - Voluntary Employees’ Beneficiary Association

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Thousands of dollars)

	June 30, 2018			September 30, 2017			June 30, 2017
	December 31, 2018			September 30, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	2321,~~181~~515		$	510,~~203~~314		$	47,~~828~~289
Restricted cash	~~805~~3,308			31,~~046~~190			23,~~524~~665
Accounts receivable (less allowances for doubtful accounts of $16,261, $4,052 and $10,050, respectively)	107,966			53,720			69,246
Accounts receivable (less allowances for doubtful accounts of $11,694, $9,760 and $6,398, respectively)	117,418			71,507			105,141
Accounts receivable — related parties	~~1,682~~498			2,~~807~~273			~~718~~1,406
Accrued utility revenues	1464,~~425~~694			13,~~296~~977			595,~~924~~854
Inventories	3450,~~663~~798			5352,~~309~~413			3749,~~129~~717
Prepaid income taxes	4143,060			753,~~711~~857			~~428~~1,977
Regulatory assets	23,~~180~~267			87,~~338~~475			~~7,759~~605
Derivative instruments	1,~~874~~070			13,~~354~~004			~~942~~678
Prepaid expenses & other current assets	19,056			16,406			12,995
Prepaid expenses	12,251			9,006			10,402
Total current assets	205,873			165,190			142,493
Other current assets	12,909			8,003			12,664
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $1,069,070, $1,010,781 and $1,008,121, respectively)	2,430,893			2,274,548			2,174,609
Total current assets	330,788			233,019			289,398
Property, plant and equipment, at cost (less accumulated depreciation of $1,091,212, $1,074,521 and $1,026,450, respectively)	2,597,546			2,541,768			2,327,664
Goodwill	182,145			182,145			182,145
Regulatory assets	~~357~~295,~~881~~496			~~360~~293,~~591~~527			~~390~~362,~~988~~237
Other assets	1718,~~233~~798			1116,~~541~~117			1413,~~297~~249
Total assets	$	3,~~194~~424,~~025~~773		$	23,~~994~~266,~~015~~576		$	23,~~904~~174,~~532~~693
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	98,~~474~~786		$	399,~~996~~001		$	39144,~~990~~374
Short-term borrowings	~~118~~296,~~500~~000			~~170~~189,~~000~~500			50181,~~000~~500
Accounts payable	5693,~~297~~157			7187,~~559~~861			5669,~~866~~697
Accounts payable — related parties	1425,~~385~~063			69,~~890~~585			713,~~625~~420
Regulatory liabilities	4926,~~664~~994			1240,~~988~~131			1517,~~294~~091
Derivative instruments	—467			~~1,071~~—			12,~~056~~244
Other current liabilities	~~119~~104,~~196~~466			~~110~~114,~~978~~256			~~126~~106,~~618~~177
Total current liabilities	~~367~~554,~~516~~933			~~413~~450,~~482~~334			~~297~~534,~~449~~503
Long-term debt	~~830~~826,~~982~~844			~~711~~828,~~105~~995			711,~~116~~242
Deferred income taxes	~~336~~414,~~035~~470			~~635~~400,~~465~~939			~~614~~340,~~419~~772
Deferred investment tax credits	2,711			2,950			3,029
Pension and postretirement benefit obligations	81,072			81,590			140,224
Pension and postretirement benefit obligations	133,235			143,674			176,393
Regulatory liabilities	346,474			350,044			340,391
Regulatory liabilities	362,787			36,242			33,376
Other noncurrent liabilities	67,176			61,386			65,540
Other noncurrent liabilities	60,954			63,192			61,732
Total liabilities	2,290,969			2,173,288			2,132,672
Total liabilities	2,094,220			2,006,110			1,897,514
Commitments and contingencies (Note 9)
Commitments and contingencies (Note 8)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)	60,259			60,259			60,259
Additional paid-in capital	473,580			473,580			473,580
Retained earnings	~~590~~626,~~321~~191			~~480~~579,~~857~~778			~~502~~534,~~603~~161
Accumulated other comprehensive loss	(2426,~~355~~226		)	(2620,~~791~~329		)	(2925,~~424~~979		)
Total common stockholder’s equity	1,~~099~~133,~~805~~804			~~987~~1,~~905~~093,288			1,~~007~~042,~~018~~021
Total liabilities and stockholder’s equity	$	3,~~194~~424,~~025~~773		$	23,~~994~~266,~~015~~576		$	23,~~904~~174,~~532~~693

See accompanying notes to condensed consolidated financial statements.

~~- 1 -~~3

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended						~~Nine Months Ended~~
	June 30,						June 30,
	December 31,
	2018			2017			~~2018~~			~~2017~~
Revenues	$	~~159~~322,~~934~~725		$	~~146~~323,~~692~~105		$	~~966,300~~		$	~~768,045~~
Costs and expenses:
Cost of sales — gas and purchased power (excluding depreciation shown below)	72159,~~537~~519			51151,~~979~~774			~~481,613~~			~~325,991~~
Operating and administrative expenses	58,~~225~~940			5251,~~737~~409			~~177,263~~			~~160,474~~
Operating and administrative expenses — related parties	43,~~325~~512			2,~~961~~689			~~10,780~~			~~10,059~~
Depreciation and amortization	21,414			17,912			62,926			53,002
Depreciation	22,474			20,354
Other operating income, net	(481		)	(6,568		)	(1,618		)	(7,796		)
Other operating expense, net	1,206			9
	156,020			119,021			730,964			541,730
	245,651			226,235
Operating income	377,~~914~~074			2796,~~671~~870			~~235,336~~			~~226,315~~
Interest expense	10,003			10,128			32,033			30,478
Pension and other postretirement plans non-service income (expense)	412			(575		)
(Loss) income before income taxes	(6,089		)	17,543			203,303			195,837
Interest expense	(11,738		)	(10,939		)
Income tax (benefit) expense	(3,066		)	6,846			48,839			75,750
Income before income taxes	65,748			85,356
Net (loss) income	$	(3,023	)	$	10,697		$	154,464		$	120,087
Income tax expense	(15,860		)	(17,053		)
Net income	$	49,888		$	68,303

See accompanying notes to condensed consolidated financial statements.

~~- 2 -~~4

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended					~~Nine Months Ended~~
	June 30,					June 30,
	December 31,
	2018			2017		~~2018~~		~~2017~~
Net (loss) income	$	(3,023	)	$	10,697	$	154,464	$	120,087
Net income	$	49,888		$	68,303
Other comprehensive income:
Other comprehensive income (loss):
Reclassifications of net losses on derivative instruments (net of tax of $(279), $(355), $(838) and $(1,047), respectively)	592			501		1,776		1,477
Net losses on derivative instruments (net of tax of $487 and $0, respectively)	(1,198		)	—
Benefit plans reclassifications of actuarial losses and net prior service credits (net of tax of $(104), $(169), $(312) and $(507), respectively)	220			239		660		717
Reclassifications of net losses on derivative instruments (net of tax of $(252) and $(279), respectively)	620			592
Other comprehensive income	812			740		2,436		2,194
Reclassifications of benefit plans actuarial losses and net prior service benefits (net of tax of $(54) and $(104), respectively)	132			220
Comprehensive (loss) income	$	(2,211	)	$	11,437	$	156,900	$	122,281
Other comprehensive (loss) income	(446		)	812
Comprehensive income	$	49,442		$	69,115

See accompanying notes to condensed consolidated financial statements.

~~- 3 -~~5

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Thousands of dollars)

	Nine Months Ended
	Three Months Ended
	June 30,
	December 31,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	~~154~~49,~~464~~888		$	~~120~~68,~~087~~303
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	62,926			53,002
Depreciation	22,474			20,354
Deferred income tax (benefit) expense	(6,024		)	56,285
Deferred income taxes, net	6,721			4,328
Provision for uncollectible accounts	165,~~462~~029			83,~~184~~459
Regulatory impact from tax reform	24,098			—
Other, net	11,451			1,161
Other, net	(1,635		)	4,358
Net change in:
Accounts receivable and accrued utility revenues	(7099,~~726~~882		)	(31136,~~471~~036		)
Inventories	181,~~646~~615			53,~~211~~592
Deferred fuel and power costs, net of changes in unsettled derivatives	39(12,~~657~~501		)	~~(12~~11,~~571~~572		)
Accounts payable	342,~~655~~936			221,~~775~~655
Other current assets	(28,~~650~~150		)	9(6,~~014~~661		)
Other current liabilities	16(4,~~725~~142		)	211,~~727~~172
Net cash provided by operating activities	255,598			236,601
Net cash provided (used) by operating activities	15,439			(7,101		)
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(~~217~~98,~~901~~717		)	(~~201~~88,~~916~~686		)
Net costs of property, plant and equipment disposals	(51,~~682~~691		)	(72,~~734~~382		)
Decrease (increase) in restricted cash	2,241			(1,941		)
Net cash used by investing activities	(100,408		)	(91,068		)
Net cash used by investing activities	(221,342		)	(211,591		)
CASH FLOWS FROM FINANCING ACTIVITIES
Payments of dividends	(45,000		)	(40,000		)
Payment of dividends	(5,000		)	(15,000		)
Issuances of long-term debt, net of issuance costs	124,404			99,499
Increase in short-term borrowings	106,500			11,500
Repayments of long-term debt	(44,182		)	(20,000		)
Issuances of long-term debt, net of issuance costs	—			124,374
Decrease in short-term borrowings	(51,500		)	(62,500		)
Repayments of long-term debt	(2,433		)	(20,000		)
Net cash used by financing activities	(16,278		)	(23,001		)
Other	(779		)	—
Cash and cash equivalents increase	$	17,978		$	2,009
Net cash provided by financing activities	98,288			100,874
Cash, cash equivalents and restricted cash increase	$	13,319		$	2,705
CASH AND CASH EQUIVALENTS
End of period	$	23,181		$	4,828
Cash, cash equivalents and restricted cash at end of period	$	24,823		$	10,954
Beginning of period	5,203			2,819
Cash, cash equivalents and restricted cash at beginning of period	11,504			8,249
Increase	$	17,978		$	2,009
Cash, cash equivalents and restricted cash increase	$	13,319		$	2,705

See accompanying notes to condensed consolidated financial statements.

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Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(unaudited)

(Thousands of dollars)



	Three Months Ended December 31,
	2018			2017
Common stock, $2.25 par value
Balance, beginning of period	$	60,259		$	60,259
Balance, end of period	$	60,259		$	60,259

Retained earnings
Balance, beginning of period	$	579,778		$	480,858
Cumulative effect of change in accounting principle - ASC 606	(3,926		)	—
Reclassification of stranded income tax effects related to TCJA	5,451			—
Net income	49,888			68,303
Cash dividends — Common Stock	(5,000		)	(15,000		)
Balance, end of period	$	626,191		$	534,161

Additional paid-in capital
Balance, beginning of period	$	473,580		$	473,580
Balance, end of period	$	473,580		$	473,580

Accumulated other comprehensive income (loss)
Balance, beginning of period	$	(20,329	)	$	(26,791	)
Reclassification of stranded income tax effects related to TCJA	(5,451		)	—
Net losses on derivative instruments	(1,198		)	—
Reclassifications of net losses on derivative instruments	620			592
Reclassifications of benefit plans actuarial losses and net prior service credits	132			220
Balance, end of period	$	(26,226	)	$	(25,979	)

Total UGI Utilities, Inc. stockholder’s equity	$	1,133,804		$	1,042,021

See accompanying notes to condensed consolidated financial statements.

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

Note 1 — Nature of Operations

UGI Utilities, ~~Inc.~~owns ~~(“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”),~~ and ~~UGI~~operates ~~Utilities’ wholly owned subsidiaries, UGI Penn Natural~~ Gas, ~~Inc. (“PNG”) and UGI Central Penn Gas~~Utility, ~~Inc.~~a ~~(“CPG”), own and operate~~ natural gas distribution ~~utilities~~utility business in eastern and central Pennsylvania and in a portion of one Maryland county~~. UGI~~ ~~Utilities~~directly ~~also owns~~ and, ~~operates~~prior anto ~~electric~~the ~~distribution utility in northeastern Pennsylvania (“Electric~~ Utility~~”).~~ ~~UGI~~Merger ~~Utilities’~~on ~~natural~~October ~~gas~~1, ~~distribution utility is referred to as “UGI Gas.” UGI Gas~~2018, through PNG and CPG. ~~are collectively referred to as “~~Gas Utility~~.” Gas~~ ~~Utility~~ is subject to regulation by the ~~Pennsylvania~~PAPUC ~~Public~~and ~~Utility~~the ~~Commission~~FERC ~~(“PUC”)~~ and, with respect to a small service territory in one Maryland county, the ~~Maryland~~MDPSC. ~~Public~~UGI ~~Service~~Utilities ~~Commission~~also ~~(“MD~~owns ~~PSC”),~~ and operates Electric Utility, isan ~~subject~~electric todistribution ~~regulation~~utility bylocated ~~the~~in ~~PUC~~northeastern Pennsylvania. ~~Gas~~ Electric Utility ~~and~~is ~~Electric~~subject ~~Utility~~to ~~are~~regulation ~~collectively~~by ~~referred~~the toPAPUC asand ~~“Utilities~~the FERC.”

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.

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation. Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries ~~(collectively, “we” or the “Company”)~~. We eliminate intercompany accounts when we consolidate.

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the ~~U.S. Securities and Exchange Commission (“~~SEC”). They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, ~~2017~~2018, ~~condensed~~Condensed ~~consolidated~~Consolidated ~~balance~~Balance ~~sheet~~Sheet ~~data~~ was derived from audited financial statements but dodoes not include all disclosures required by ~~accounting principles generally accepted in the United States of America (“~~GAAP”).

These financial statements should be read in conjunction with the ~~financial statements and related notes included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017 (“the~~ Company’s ~~2017~~2018 Annual Report”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

~~Derivative~~Revenue ~~Instruments~~Recognition. Effective October 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,” which, as amended, is included in ASC 606. This new accounting guidance supersedes previous revenue recognition requirements in ASC 605. ASC 606 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reported in accordance with ASC 605. The Company recorded a $3,926 reduction to opening retained earnings as of October 1, 2018, to reflect the cumulative effect of ASC 606 on certain contracts not complete as of the date of adoption. Although the adoption of ASC 606 did not, and is not expected to, have a material impact on the amount or timing of our revenue recognition and on our consolidated net income, cash flows or financial position, beginning October 1, 2018, certain performance obligations primarily associated with the release of capacity contracts are reflected on a gross, rather than net, basis and revenues from certain other negotiated rate contracts are reflected on a straight-line basis over the length of the contract, rather than as invoiced. The amount of revenues reflected on a gross, rather than net, basis for the three months ended December 31, 2018, was approximately $15,000 with no impact on net income.

~~Derivative~~Certain ~~instruments~~revenues ~~are~~such ~~reported~~as onrevenue ~~the~~from ~~condensed~~leases, ~~consolidated~~financial ~~balance~~instruments ~~sheets~~and atother ~~their~~revenues ~~fair~~are ~~values,~~not ~~unless~~within the ~~normal~~scope ~~purchase~~of ~~and~~ASC ~~normal~~606 ~~sale~~because ~~(“NPNS”)~~they ~~exception~~are isnot ~~elected~~from contracts with customers. ~~The~~Such ~~accounting~~revenues, ~~for~~if ~~changes~~any, are accounted for in ~~fair~~accordance ~~value~~with ~~depends~~other ~~upon~~GAAP. Revenue-related ~~the~~taxes ~~purpose~~collected on behalf of ~~the~~customers ~~derivative~~and ~~instrument~~remitted to taxing authorities, principally sales and ~~whether~~use ittaxes, isare ~~subject~~not included in revenues. Electric Utility’s gross receipts taxes are presented on a gross basis. The Company has elected to ~~regulatory~~use ~~ratemaking~~the ~~mechanisms~~practical orexpedient ifto itexpense ~~qualifies~~the ~~and~~costs isto ~~designated~~obtain contracts when incurred as asuch ~~hedge~~amounts ~~for~~are ~~accounting~~generally ~~purposes~~not material.

~~Gains~~See Note ~~and losses on substantially all of the derivative instruments used by UGI Utilities to hedge commodity prices (~~4 for which NPNS has not been elected) are included in regulatory assets and liabilities. From time to time we enter into derivative instruments that qualify and are designated as cash flow hedges. For cash flow hedges, changes in the ~~fair~~additional ~~values~~disclosures ofregarding the ~~derivative~~Company’s ~~financial~~revenue instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. We do not currently have unsettled derivative instruments that are designated and qualify as cash flow hedges. Certain other commodity derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from ~~derivative~~contracts ~~financial~~with ~~instruments are included in cash flows from operating activities~~customers.

~~For~~Restricted aCash. ~~more~~Restricted ~~detailed~~cash ~~description~~principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. Upon adoption of revised accounting guidance in October 2018 (see Note 3), restricted cash is included within the ~~derivative~~Company’s ~~instruments~~Condensed weConsolidated ~~use~~Statements of Cash Flows, ~~our~~with ~~accounting~~changes in the balance no longer reflected as a separate investing activity. The retrospective application of the new guidance on cash flows from investing activities for ~~derivatives~~the three months ended December 31, ~~our~~2017, ~~objectives~~resulted ~~for~~in ~~using~~the ~~them~~elimination ~~and~~of ~~other~~the ~~information~~item “Increase in restricted cash,” ~~see~~which ~~Note~~had 11previously been reported as a use of cash of $619.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~current~~The ~~events~~following table provides a reconciliation of the total cash, ~~historical~~cash ~~experience~~equivalents and ~~various~~restricted ~~other~~cash ~~assumptions~~reported ~~that~~on ~~are~~the ~~believed~~Company’s toCondensed beConsolidated ~~reasonable~~Balance ~~under~~Sheets to the ~~circumstances. Accordingly,~~corresponding ~~actual~~amounts ~~results~~reported ~~may~~on bethe ~~different~~Condensed ~~from~~Consolidated ~~these~~Statements ~~estimates~~of ~~and~~Cash ~~assumptions.~~Flows:

Reclassifications. Certain prior-period amounts have been reclassified to conform to the current-period presentation.



	Cash, Cash Equivalents and Restricted Cash
	December 31, 2018		December 31, 2017		September 30, 2018		September 30, 2017
Cash and cash equivalents	$	21,515	$	7,289	$	10,314	$	5,203
Restricted cash	3,308		3,665		1,190		3,046
Cash, cash equivalents and restricted cash	$	24,823	$	10,954	$	11,504	$	8,249

Derivative Instruments. Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the NPNS exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument, whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes.

Gains and losses on substantially all of the derivative instruments used by UGI Utilities to hedge commodity prices (for which NPNS has not been elected) are included in regulatory assets and liabilities. From time to time we enter into derivative instruments that qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative financial instruments are recorded in AOCI, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Certain other commodity derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows.

For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 12.

Use of Estimates. The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

Reclassifications. Certain amounts for the three months ended December 31, 2017, have been reclassified as a result of the adoption of revised accounting guidance pertaining to certain net periodic pension and other postretirement benefit costs and restricted cash (see Note 3). In addition, certain other prior-period amounts have been reclassified to conform to the current-period presentation.

Note 3 — Accounting Changes

New Accounting Standards Adopted Effective October 1, 2018

Revenue Recognition. Effective October 1, 2018, the Company adopted new accounting guidance regarding revenue recognition. See Notes 2 and 4 for a detailed description of the impact of the new guidance and related disclosures.

Cloud Computing Implementation Costs. In August 2018, the FASB issued ASU No. 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.” The new guidance requires a customer in a cloud computing arrangement that is a service contract to capitalize certain implementation costs as if the arrangement was an internal-use software project. These deferred implementation costs are expensed over the fixed, noncancelable term of the service arrangement plus any reasonably certain renewal periods. The new guidance also requires the entity to present the expense related to the capitalized implementation costs in the same income statement line as the hosting service fees; to classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments for hosting service fees; and to present the capitalized implementation costs in the balance sheet in the same line item in which prepaid hosting service fees are

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

presented. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We adopted this ASU effective October 1, 2018, and applied the guidance prospectively to all implementation costs associated with cloud computing arrangements that are service contracts incurred beginning October 1, 2018. The adoption of the new guidance did not have a material impact on our results of operations for the three months ended December 31, 2018.

Stranded Tax Effects in Accumulated Other Comprehensive Income. In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded tax effects in AOCI resulting from the remeasurement of deferred income taxes associated with items included in AOCI due to the enactment of the TCJA may be reclassified to retained earnings, at the election of the entity, in the period the ASU is adopted. We adopted this ASU effective October 1, 2018. In connection with the adoption of this guidance, we reclassified a benefit of $5,451 from AOCI to opening retained earnings as of October 1, 2018, to reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of AOCI.

The guidance became effective for the Company beginning October 1, 2018, with retrospective adoption for the presentation of pension and postretirement expense on the income statement and a prospective adoption for capitalization. The Company’s Condensed Consolidated Statement of Income for the three months ended December 31, 2017, has been recast to reflect the retrospective adoption for the presentation of the non-service cost component of net periodic pension and other postretirement benefit costs, net of estimated amounts capitalized, as “Pension and other postretirement plans non-service income (expense)” on the Condensed Consolidated Statements of Income. Previously, the non-service cost components were reflected in “Operating and administrative expenses.”

For the three months ended December 31, 2018, the amount of income comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, presented in "Pension and other postretirement plans non-service income (expense)” on the Condensed Consolidated Statements of Income, totaled $412. For the three months ended December 31, 2017, the amount of (expense) comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, which has been reclassified from "Operating and administrative expenses" to "Pension and other postretirement plans non-service income (expense)” on the Condensed Consolidated Statements of Income, totaled $(575).

Statement of Cash Flows - Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” The guidance in this ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, as well as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents are included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. The amendments in the ASU are required to be adopted on a retrospective basis. We adopted this ASU effective October 1, 2018. Adoption of this new guidance resulted in a change in presentation of restricted cash on the Condensed Consolidated Statement of Cash Flows; otherwise, this guidance did not have a significant impact on our Condensed Consolidated Statement of Cash Flows and disclosures (see Note 2, “Restricted Cash”).

Accounting Standards Not Yet Adopted

Pension and Other ~~Comprehensive~~Postretirement ~~Income~~Benefit Costs Disclosures. In ~~February~~August 2018, the ~~Financial Accounting Standards Board ("~~FASB") issued ~~Accounting Standards Update ("~~ASU") No. 2018-0214, “~~Reclassification~~Changes ofto ~~Certain~~the ~~Tax~~Disclosure ~~Effects~~Requirements ~~from~~for ~~Accumulated~~Defined ~~Other~~Benefit ~~Comprehensive Income~~Plans.” This ASU ~~provides~~modifies ~~that~~ the ~~stranded~~disclosure ~~tax~~requirements ~~effects~~for inemployers ~~AOCI~~that ~~resulting~~sponsor ~~from~~defined ~~the~~benefit ~~Tax~~pension ~~Cuts~~or ~~and~~other ~~Jobs~~postretirement ~~Act~~plans ~~(the~~by ~~“TCJA”)~~removing ~~may~~and beadding ~~reclassified~~certain todisclosures ~~retained~~for ~~earnings,~~these ~~at the election of the entity, in the period of adoption~~plans. The amendments in this ASU are effective for interim and annual periods beginning ~~after~~October ~~December 15~~1, ~~2018~~2020 (Fiscal ~~2020~~2021). ~~Early~~The ~~adoption~~guidance isshall ~~permitted.~~be Weadopted ~~currently~~retrospectively ~~expect~~for toall ~~adopt~~periods ~~this~~presented ~~ASU effective October 1, 2018. The Company is~~ in the ~~process of assessing the impact on its~~ financial statements. ~~from~~Early ~~the~~ adoption ofis ~~the~~permitted. ~~new~~The ~~guidance~~Company ~~but~~is ~~does~~in ~~not~~the ~~expect~~process ~~its adoption will have a material impact on its consolidated financial statements.~~

Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. For entities subject to rate regulation, however, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) with a retrospective adoption for income statement presentation and a prospective adoption for capitalization. We will adopt this ASU effective October 1, 2018. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance but does not expect its adoption will have a material impact on its consolidated financial statements.10

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 the ASU are required to be adopted on a retrospective basis. The ASU is effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. We currently expect to adopt this ASU effective October 1, 2018. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance but does not expect its adoption will have a material impact on its consolidated financial statements.

Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for 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. In July 2018, the FASB issued ASU No. 2018-11, “Leases: Targeted Improvements.” Among other things, this ASU provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption rather than the earliest period presented in the financial statements. We currently expect to adopt ASU No. 2016-02, as updated, effective October 1, 2019. The Company has not yet selected a transition method and is currently in the process of assessing the impact on its financial statements from the adoption of ASU No. 2016-02 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 Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~the~~of ~~ASC.~~assessing ~~ASU~~the ~~2014-09~~impact ~~requires~~on ~~that~~its anfinancial ~~entity~~statement ~~recognize~~disclosures ~~revenue~~from ~~to depict~~ the ~~transfer~~adoption of ~~promised~~the ~~goods~~new orguidance ~~services~~and todetermining ~~customers in an amount that reflects~~ the ~~consideration~~period toin which the ~~entity expects to be entitled in exchange for those goods or services. The~~ new guidance iswill ~~effective~~be ~~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~~adopted.

~~The~~Fair ~~Company~~Value isMeasurements inDisclosures. ~~the~~In ~~process~~August of2018, ~~analyzing~~ the ~~impact~~FASB ofissued ~~the~~ASU ~~new~~No. ~~guidance~~2018-13, ~~using~~“Changes anto ~~integrated~~the ~~approach~~Disclosure ~~which~~Requirements ~~includes~~for ~~evaluating~~Fair ~~differences~~Value inMeasurement.” ~~the~~This ~~amount~~ASU ~~and~~modifies ~~timing~~the ofdisclosure ~~revenue~~requirements ~~recognition~~for ~~from~~fair ~~applying~~value ~~the~~measurements ~~requirements~~by ofremoving, ~~the new guidance~~modifying, ~~reviewing~~or ~~its~~adding ~~accounting~~certain ~~policies~~disclosures. ~~and~~The ~~practices,~~amendments ~~and~~in ~~assessing~~this ~~the~~ASU ~~need~~are effective for ~~changes~~annual toperiods ~~its~~beginning ~~processes~~October 1, ~~accounting~~2020 ~~systems~~(Fiscal ~~and~~2021). The ~~design~~guidance ofregarding ~~internal~~removing ~~controls.~~and ~~The~~modifying ~~Company~~disclosures ~~has~~will ~~completed~~be ~~the~~adopted ~~assessment~~on of a ~~significant~~retrospective ~~number~~basis ofand ~~its~~the ~~contracts~~guidance ~~with~~regarding ~~customers~~new ~~under~~disclosures ~~the~~will ~~new~~be ~~guidance~~adopted toon ~~determine~~a ~~the~~prospective ~~effect~~basis. ofEarly ~~the~~ adoption ofis ~~the new guidance~~permitted. ~~Although~~The ~~the~~ Company ~~has~~is ~~not~~in ~~completed~~the ~~its~~process ~~assessment~~ of assessing the impact ofon ~~the~~its ~~new~~financial ~~guidance,~~statement disclosures from the ~~Company~~adoption ~~does~~of ~~not~~the ~~expect~~new ~~its~~guidance ~~adoption~~and ~~will~~determining ~~have~~the aperiod ~~material~~in ~~impact~~which onthe ~~its~~new ~~consolidated~~guidance ~~financial~~will ~~statements~~be adopted.

~~The~~Derivatives ~~Company~~and ~~anticipates~~Hedging. ~~that~~In itAugust ~~will~~2017, ~~adopt~~the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the ~~new~~economic ~~standard~~effects ~~using~~of risk management activities in the ~~modified~~financial ~~retrospective~~statements. ~~transition~~The ~~method~~amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, ~~2018~~2019 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required prospectively. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

~~Note~~Leases. 4In —February ~~Inventories~~2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption. We will adopt ASU No. 2016-02, as updated, effective October 1, 2019 and expect to adopt the transition option which would allow the Company to maintain historical presentation for periods before October 1, 2019. The Company has completed a preliminary assessment for evaluating the impact of the guidance and anticipates that its adoption will result in a significant amount of right-of-use assets and lease liabilities for leases in effect at the adoption date. The Company has begun implementation activities including accumulating contracts and lease data in formats compatible with a new lease management system that will assist with the initial adoption of the standard.

Note 4 — Revenue from Contracts with Customers

The Company recognizes revenue when control of promised goods or services is transferred to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The Company generally has the right to consideration from a customer in an amount that corresponds directly with the value to the customer for our performance completed to date. As such, we have elected to recognize revenue in the amount to which we have a right to invoice except in the case of certain large delivery service customers for which we recognize revenue on a straight-line basis over the term of the contract, consistent with when the performance obligations are satisfied by the Company.

We do not have significant financing terms in our contracts because we generally receive payment shortly before, at, or shortly after the transfer of control of the good or service. Because the period between the time the performance obligation is satisfied and payment is received is one year or less, the Company has elected to apply the significant financing component practical expedient and no amount of consideration has been allocated as a financing component.

UGI Utilities supplies natural gas and electricity and provides distribution services of natural gas and electricity to residential, commercial, and industrial customers who are generally billed at standard regulated tariff rates approved by the PAPUC through the ratemaking process. Tariff rates include a component that provides for a reasonable opportunity to recover operating costs and expenses and to earn a return on net investment, and a component that provides for the recovery, subject to reasonableness reviews, of PGC and DS costs.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

Customers may choose to purchase their natural gas and electricity from Gas Utility or Electric Utility, or, alternatively, may contract separately with alternate suppliers. Accordingly, our contracts with customers comprise two promised goods or services: (1) delivery service of natural gas and electricity through the Company’s utility distribution systems and (2) the natural gas or electricity commodity itself for those customers who choose to purchase the natural gas or electricity directly from the Company. Revenue is not recorded for the sale of natural gas or electricity to customers who have contracted separately with alternate suppliers. For those customers who choose to purchase their natural gas or electricity from the Company, the performance obligation includes both the supply of the commodity and the delivery service.

The terms of our core market customer contracts are generally considered day-to-day as customers can discontinue service at any time without penalty. Performance obligations are generally satisfied over time as the natural gas or electricity is delivered to customers, at which point the customers simultaneously receive and consume the benefits provided by the delivery service and, when applicable, the commodity. Amounts are billed to customers based upon the reading of a customer’s meter which occurs on a cycle basis throughout each reporting period. An unbilled amount is recorded at the end of each reporting period based upon estimated amounts of natural gas or electricity delivered to customers since the date of the last meter reading. These unbilled estimates consider various factors such as historical customer usage patterns, customer rates and weather.

UGI Utilities has certain fixed-term contracts with large commercial and industrial customers to provide natural gas delivery services at contracted rates and at volumes generally based on the customer’s needs. The performance obligation to provide the contracted delivery service for these large commercial and industrial customers is satisfied over time and revenue is generally recognized on a straight-line basis.

UGI Utilities makes off-system sales whereby natural gas delivered to our system in excess of amounts needed to fulfill our distribution system needs is sold to other customers, primarily other distributors of natural gas, based on an agreed-upon price and volume between the Company and the counterparty. Gas Utility also sells excess capacity whereby interstate pipeline capacity in excess of amounts needed to meet our customer obligations is sold to other distributors of natural gas based upon an agreed-upon rate. Off-system sales and capacity releases are generally entered into one month at a time and comprise the sale of a specific volume of gas or pipeline capacity at a specific delivery point or points over a specific time. As such, performance obligations associated with off-system sales and capacity release customers are satisfied, and associated revenue is recorded, when the agreed upon volume of natural gas is delivered or capacity is provided, and title is transferred, in accordance with the contract terms.

Electric Utility provides transmission services to PJM by allowing PJM to access Electric Utility’s electricity transmission facilities. In exchange for providing access, PJM pays Electric Utility consideration determined by a formula-based rate approved by FERC. The formula-based rate, which is updated annually, allows recovery of costs incurred to provide transmissions services and return on transmission-related net investment. We recognize revenue over time as we provide transmission service.

Other revenues represent revenues from other ancillary services provided to customers and are generally recorded as the service is provided to customers.

Contract Balances

The timing of revenue recognition may differ from the timing of invoicing to customers or cash receipts. Contract assets represent our right to consideration after the performance obligations have been satisfied when such right is conditioned on something other than the passage of time. Contract assets were not material at December 31, 2018. All of our receivables are unconditional rights to consideration and are included in “Accounts receivable” and “Accrued utility revenues” on the Condensed Consolidated Balance Sheets. Amounts billed are generally due within the following month.

Contract liabilities arise when payment from a customer is received before the performance obligations have been satisfied and represent the Company’s obligations to transfer goods or services to a customer for which we have received consideration. The balance of contract liabilities was $6,189 and $5,897 at December 31, 2018 and October 1, 2018, respectively, and are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets. Revenue recognized for the three months ended December 31, 2018 from the amount included in contract liabilities at October 1, 2018 was not material.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

Revenue Disaggregation

The following table presents our disaggregated revenues by reportable segment for the three months ended December 31, 2018:



			Reportable Segments
	Total		Gas Utility			Electric
Revenues from contracts with customers:
Core Market:
Residential	$	175,691	$	158,557		$	17,134
Commercial & industrial	67,574		61,375			6,199
Large delivery service	39,547		39,547			—
Off-system sales and capacity releases	38,131		38,131			—
Other (a)	1,171		(1,079		)	2,250
Total revenue from contracts with customers	322,114		296,531			25,583
Other revenues (b)	611		611			—
Total revenues	$	322,725	$	297,142		$	25,583


(a)	Gas Utility includes unallocated negative surcharge revenue of $(4,128) as a result of a PAPUC Order issued May 17, 2018, related to TCJA (see Note 7).


(b)	Represents certain revenues not from contracts with customers that are not within the scope of ASC 606 and accounted for in accordance with other GAAP.

Remaining Performance Obligations

The Company has elected to use practical expedients as allowed in ASC 606 to exclude disclosures related to the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied for core market customers and off-system sales and capacity releases as of the end of the reporting period because these contracts have an initial expected term of one year or less. Certain contracts with large delivery service customers contain minimum future performance obligations through 2053. At December 31, 2018, the Company expects to record approximately $197,000 of revenues related to the minimum future performance obligations over the remaining terms of the related contracts.

Note 5 — Inventories

Inventories comprise the following:

	June 30, 2018		September 30, 2017		June 30, 2017
	December 31, 2018		September 30, 2018		December 31, 2017
Gas Utility natural gas	$	1834,~~608~~918	$	3937,~~486~~287	$	2134,~~826~~587
Materials, supplies and other	1615,~~055~~880		1315,~~823~~126		15,~~303~~130
Total inventories	$	3450,~~663~~798	$	5352,~~309~~413	$	3749,~~129~~717

At ~~June~~December 3031, 2018, UGI Utilities was a party to five principal ~~storage contract administrative agreements (“~~SCAAs”) ~~which~~with ~~have~~ terms of up to three years. Four of the SCAAs were with ~~UGI~~ Energy Services, ~~LLC~~ (~~“Energy Services”), a second-tier, wholly owned subsidiary of UGI (~~see Note 1314) and one of the SCAAs was with a non-affiliate. Pursuant to the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

The carrying values of gas storage inventories released under the SCAAs at ~~June~~December 3031, 2018, September 30, ~~2017~~2018 and ~~June~~December 3031, 2017, comprising 4.7.8 ~~billion cubic feet (“~~bcf”), 9.10 bcf and 47.8 bcf of natural gas, were $1120,~~944~~529, $2623,~~064~~136 and $1422,~~146~~191, respectively. At June 30, 2018, September 30, 2017 and June 30, 2017, UGI Utilities held a total of $13,840, $15,040 and $15,040, respectively, of security deposits received from its SCAA counterparties. These amounts are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets.

~~For additional information related to the SCAAs with Energy Services, see Note~~ 13.

Note 5 — Income Tax Reform

On December 22, 2017, the TCJA was enacted into law. The significant changes resulting from the law that impact UGI Utilities include a reduction in the U.S. federal income tax rate from 35% to 21%, effective January 1, 2018 (resulting in a blended rate of 24.5% for Fiscal 2018) and the elimination of bonus depreciation for regulated utilities.

In accordance with GAAP as determined by ASC 740, “Income Taxes,” we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three and nine months ended June 30, 2018, contain provisional estimates of the impact of the TCJA. These amounts are considered provisional because they use estimates for which tax returns have not yet been filed and because estimated amounts may be impacted by future regulatory and accounting guidance if and when

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~issued.~~December 31, In2018, ~~accordance~~September 30, ~~with~~2018 ~~SEC~~and ~~Staff~~December 31, ~~Accounting~~2017, ~~Bulletin~~UGI ~~(“SAB”)~~Utilities ~~No.~~held ~~118,~~a wetotal ~~will~~of ~~adjust~~$11,840, ~~these~~$13,840 ~~provisional~~and ~~amounts~~$13,840, asrespectively, ~~further~~of ~~information~~security ~~becomes~~deposits ~~available~~received ~~and~~from asits weSCAA ~~refine our calculations~~counterparties. AsThese ~~permitted~~amounts byare ~~SAB~~included ~~No.~~in ~~118 these adjustments will occur during a reasonable~~ “~~measurement~~Other ~~period~~current liabilities” ~~not~~on ~~to exceed twelve months from~~ the ~~date~~Condensed ofConsolidated ~~enactment~~Balance Sheets.

AsFor aadditional ~~result~~information ofrelated ~~the TCJA, in December 2017, we reduced our net deferred income tax liabilities by $223,660 due~~ to the ~~remeasuring~~SCAAs ofwith ~~our~~Energy ~~existing federal deferred income tax assets and liabilities as of the date of the TCJA enactment. Because a significant amount of the reduction relates to our regulated utility plant assets~~Services, ~~most~~see ofNote ~~the reduction to our deferred income taxes is not being recognized immediately in income tax expense~~14. During the three and nine months ended June 30, 2018, the amount of the reduction in our net deferred income tax liabilities that reduced income tax expense, including adjustments to provisional amounts previously recorded, totaled $1,131 and $9,254, respectively.

InNote ~~order~~6 ~~for~~— ~~utility~~Income ~~assets~~Tax toReform continue to be eligible for accelerated tax depreciation, current law requires that excess deferred federal income taxes resulting from the measurement of deferred taxes on regulated utility plant be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. In December 2017, we recorded a regulatory liability of $216,098 associated with the excess deferred federal income taxes related to our regulated utility plant assets. This regulatory liability was increased, and a federal deferred income tax asset recorded, in the amount of $87,803 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. This regulatory liability is being amortized to income tax expense over the remaining lives of the assets that gave rise to the excess deferred income taxes. For further information on these regulatory assets and liabilities, see Note 6.

~~For~~On ~~the~~December ~~three and nine months ended June 30~~22, ~~2018~~2017, ~~we included~~ the ~~estimated impacts of the~~ TCJA inwas ~~determining~~enacted ~~our~~into ~~estimated annual effective income tax rate~~law. WeThe ~~are~~significant ~~subject~~changes toresulting afrom ~~blended~~the ~~federal~~law ~~tax~~that ~~rate~~impacted ofUGI ~~24.5%~~Utilities ~~for~~include ~~Fiscal~~a ~~2018~~reduction ~~because~~in ~~our fiscal year contains~~ the ~~effective~~U.S. ~~date~~federal ofincome ~~the~~tax rate ~~change~~ from 35% to 21%, oneffective January 1, 2018. As(resulting ~~a result, the U.S. federal income tax rate included~~ in ~~our~~a ~~estimated~~blended ~~annual effective tax~~ rate isof ~~based on the~~ 24.5% ~~blended rate~~ for Fiscal 2018~~. For~~) ~~the three~~ and ~~nine months ended June 30, 2018,~~ the ~~effects~~elimination of ~~the~~bonus ~~tax~~depreciation ~~law changes~~ on ~~current-period~~regulated ~~results~~utility ~~(excluding~~property ~~the~~beginning ~~one-time~~in ~~impacts~~Fiscal ~~described above) decreased income tax expense by approximately $782 and $24,051, respectively~~2019.

AsIn ~~further~~accordance ~~described~~with inGAAP ~~Note~~as 6,determined onby ~~May~~ASC 17740, ~~2018,~~we ~~the~~are ~~PUC~~required ~~issued a Temporary Rates Order for all PUC-regulated utilities with regard~~ to ~~the~~record ~~TCJA. Among other things,~~ the ~~Temporary~~effects ~~Rates~~of ~~Order requires Pennsylvania utilities to establish a regulatory liability for~~ tax ~~benefits~~law ~~that~~changes ~~accrued~~in ~~during~~ the period ~~January~~enacted. 1,As ~~2018~~further ~~through~~discussed ~~June 30~~below, ~~2018,~~our ~~resulting~~results ~~from~~for the ~~change~~three inmonths ~~the~~ended ~~federal~~December ~~income~~31, ~~tax~~2017, ~~rate~~contained ~~from~~provisional ~~35%~~estimates toof ~~21%. In order to reflect~~ the ~~effects~~impact of the ~~tax~~TCJA. These ~~savings~~amounts ~~from~~were ~~the~~considered ~~change~~provisional inbecause ~~the~~they ~~federal~~used ~~income~~estimates ~~tax rate~~ for ~~the~~which ~~period~~tax ~~January~~returns 1,had ~~2018~~not toyet ~~June~~been ~~30,~~filed ~~2018,~~and ~~during~~because ~~the~~estimated ~~three~~amounts ~~months~~could ~~ended~~have ~~June~~been ~~30,~~impacted ~~2018,~~by ~~UGI~~future ~~Utilities~~regulatory ~~reduced~~and ~~its~~accounting ~~combined~~guidance ~~utility~~if ~~revenues~~and bywhen ~~$22,745~~issued. ~~(which~~We isadjusted inprovisional ~~addition~~amounts toas afurther ~~$1,353~~information ~~reduction~~became ~~previously~~available ~~recorded~~and inas ~~March~~we ~~2018),~~refined ~~and~~our ~~recorded~~calculations. As apermitted ~~regulatory~~by ~~liability~~SEC inStaff anBulletin ~~equal amount~~No. ~~The~~118, ~~total~~these ~~reduction~~adjustments inoccurred ~~revenues~~during ~~for~~ the ~~nine~~reasonable ~~months~~“measurement ~~ended~~period” ~~June~~defined ~~30,~~as ~~2018~~twelve ofmonths ~~$24,098~~from ~~reflects~~the ~~(1)~~date ~~$17,135~~ of ~~tax~~enactment. ~~benefits~~During ~~accrued during~~ the ~~period~~three ~~January~~months 1,ended ~~2018,~~December ~~to June 30~~31, 2018, ~~plus~~adjustments ~~(2) $6,963~~ to ~~reflect~~provisional ~~tax~~amounts ~~benefits~~recorded ~~expected~~in toprior beperiods ~~generated~~were bynot ~~the future amortization of the regulatory liability~~material.

~~- 8~~As -a result of the TCJA, during the three months ended December 31, 2017, we reduced our net deferred income tax liabilities by $223,660 due to the remeasurement of existing federal deferred income tax assets and liabilities from 35% to 21%. Because a significant amount of the reduction related to our regulated utility plant assets, most of the reduction to our deferred income taxes was not recognized immediately in income tax expense. During the three months ended December 31, 2017, the amount of the reduction in deferred income taxes that reduced income tax expense totaled $8,122.

In order for utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred federal income taxes resulting from the remeasurement of deferred income taxes on regulated utility plant be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. At December 31, 2017, we had recorded a regulatory liability of $216,098 associated with the excess deferred federal income taxes related to our regulated utility plant assets. The regulatory liability was increased, and a federal deferred income tax asset was recorded, in the amount of $87,803 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes.

For the three months ended December 31, 2018 and 2017, we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rates. We were subject to a blended U.S. federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contained the effective date of the rate change from 35% to 21%. We are subject to a 21% U.S. federal tax rate in Fiscal 2019. As a result, the U.S. federal income tax rate included in our annual effective tax rates used for the three months ended December 31, 2018 and 2017 were based on rates of 21% and 24.5%, respectively. Our estimated annual effective tax rate was not impacted by any regulatory action taken by the PAPUC.

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

Note 67 — Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 4 in the Company’s ~~2017~~2018 Annual Report. Other than removal costs, UGI Utilities ~~currently~~ does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with UGI Utilities are included in our accompanying ~~condensed~~Condensed ~~consolidated~~Consolidated ~~balance~~Balance ~~sheets~~Sheets:

	June 30, 2018		September 30, 2017		June 30, 2017
	December 31, 2018		September 30, 2018		December 31, 2017
Regulatory assets:
Income taxes recoverable	$	~~130~~115,~~024~~204	$	~~121~~110,~~421~~129	$	~~122~~126,~~733~~509
Underfunded pension and postretirement plans	~~132~~85,~~239~~334		~~141~~87,~~310~~106		~~171~~138,~~833~~287
Environmental costs	5958,~~808~~461		6158,~~566~~836		6160,~~616~~760
Deferred fuel and power costs	190		7,685		7,024
Removal costs, net	31,332		32,025		31,426
Removal costs, net	30,987		30,996		29,405
Other	8,432		12,906		5,860
Other	6,813		5,951		6,136
Total regulatory assets	$	298,763	$	301,002	$	362,842
Total regulatory assets	$	360,061	$	368,929	$	398,747
Regulatory liabilities:
Postretirement benefits	$	1617,~~895~~315	$	17,~~493~~781	$	1617,~~715~~315
Deferred fuel and power refunds	4422,~~500~~203		1036,~~621~~723		12,~~587~~658
State tax benefits — distribution system repairs	2023,~~677~~453		1822,~~430~~611		1619,~~662~~101
PUC Temporary Rates Order (a)	24,098		—		—
PAPUC temporary rates order	24,766		24,430		—
Excess federal deferred income taxes (b)	301,151		—		—
Excess federal deferred income taxes	280,940		285,221		303,901
Other	54,~~130~~791		23,~~686~~409		24,~~706~~507
Total regulatory liabilities	$	~~412~~373,~~451~~468	$	49390,~~230~~175	$	48357,~~670~~482

~~(a)~~Deferred ~~Balance~~fuel atand ~~June~~power ~~30,~~refunds. Gas ~~2018,~~Utility’s ~~comprises~~and ~~tax~~Electric ~~savings~~Utility’s ~~for~~tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the ~~period~~application ~~January~~of 1,PGC ~~2018~~rates toin ~~June~~the ~~30,~~case ~~2018~~of ~~resulting~~Gas ~~from~~Utility and DS tariffs in the ~~enactment~~case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the ~~TCJA~~total ~~(see~~amount ~~“PUC~~of ~~Temporary~~purchased ~~Rates~~gas ~~Order”~~and ~~below~~electric generation supply costs collected from customers and ~~Note~~recoverable 5)costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

~~(b)~~Gas ~~Balance~~Utility atuses ~~June~~derivative ~~30,~~instruments ~~2018,~~to ~~comprises~~reduce ~~excess~~volatility ~~federal~~in ~~deferred~~the ~~income~~cost ~~taxes~~of ~~resulting~~gas ~~from~~it ~~the~~purchases ~~enactment~~for ofretail ~~the~~core-market ~~TCJA~~customers. ~~(see~~Realized ~~“Excess~~and ~~federal~~unrealized gains or losses on natural gas derivative instruments are included in deferred ~~income~~fuel ~~taxes”~~costs ~~below~~or refunds. Net unrealized gains (losses) on such contracts at December 31, 2018, September 30, 2018, and ~~Note~~December 31, 52017, were $837, $2,856 and $(1,720), respectively.

~~Deferred~~PAPUC ~~fuel~~Temporary ~~and~~Rates ~~power refunds~~Order. On May 17, 2018, the PAPUC ordered each regulated utility currently not in a general base rate case proceeding, including UGI Gas, ~~Utility’s~~PNG and ~~Electric~~CPG, ~~Utility’s~~to ~~tariffs~~reduce ~~contain~~their ~~clauses~~rates ~~that~~through ~~permit~~the ~~recovery~~establishment of ~~all~~a ~~prudently~~negative ~~incurred~~surcharge ~~purchased~~applied ~~gas~~to ~~and~~bills ~~power~~rendered ~~costs~~on ~~through~~or after July 1, 2018. The temporary negative surcharge will be reconciled at the ~~application~~end of ~~purchased~~each ~~gas~~fiscal ~~cost~~year ~~(“PGC”)~~to ~~rates~~actual tax savings realized. Any difference in the ~~case~~amount of ~~Gas~~bill ~~Utility~~credit received by customers and ~~default~~the ~~service~~amount ~~(“DS”)~~of ~~tariffs~~benefits received by the Company during the period the negative surcharge is in effect is reconciled in the ~~case~~calculation of ~~Electric~~a ~~Utility~~new negative surcharge effective January 1 of the subsequent calendar year. The ~~clauses~~negative ~~provide~~surcharge ~~for~~will ~~periodic~~remain ~~adjustments~~in toplace ~~PGC~~until ~~and~~the DSeffective ~~rates~~date ~~for~~of ~~differences~~new ~~between~~rates established in the ~~total~~utility’s ~~amount~~next ofgeneral ~~purchased~~base ~~gas~~rate ~~and~~proceeding. ~~electric~~For ~~generation~~merged ~~supply~~Gas ~~costs~~Utility, ~~collected~~such ~~from~~negative ~~customers~~surcharge ~~and~~reduced ~~recoverable~~base ~~costs~~rate ~~incurred~~revenues by 5.78%, ~~Net~~3.90% ~~undercollected~~and ~~costs~~8.19%, ~~are~~respectively, ~~classified~~for asthe aUGI ~~regulatory~~South, ~~asset~~UGI North and ~~net~~UGI ~~overcollections~~Central ~~are~~rate ~~classified~~districts asfor athe ~~regulatory~~three ~~liability~~months ended December 31, 2018 and is subject to reconciliation during the period the negative surcharges remain in effect.

~~Gas~~In ~~Utility~~its ~~uses~~May ~~derivative~~17, ~~instruments~~2018 Order, the PAPUC also required Pennsylvania utilities to ~~reduce~~establish ~~volatility~~a inregulatory liability for tax benefits that accrued during the ~~cost~~period ofbeginning ~~gas~~January it1, ~~purchases~~2018 ~~for~~through ~~firm-~~June ~~residential~~30, ~~commercial~~2018, ~~and~~resulting ~~industrial~~from ~~(“retail~~the ~~core-market”)~~reduced ~~customers~~federal tax rate. ~~Realized~~The ~~and~~rate ~~unrealized~~treatment ~~gains~~of orthis ~~losses~~regulatory onliability, ~~natural~~plus ~~gas~~accrued ~~derivative~~interest, ~~instruments~~for ~~are~~each ~~included~~Gas Utility rate district will be addressed in ~~deferred~~a ~~fuel~~future ~~costs~~proceeding orand ~~refunds~~the Company cannot predict the ultimate treatment of this liability. ~~Net~~In ~~unrealized~~UGI ~~gains~~Gas’s ~~(losses)~~base onrate ~~such~~proceeding ~~contracts~~filed atJanuary ~~June 30~~28, ~~2018,~~2019 ~~September 30,~~(see ~~2017,~~“Base ~~and~~Rate ~~June 30,~~Filings” ~~2017~~below), ~~were~~UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $26,249 of tax benefits experienced by UGI Utilities over the period January 1,~~863,~~ ~~$146~~2018 ~~and~~to ~~$(73)~~June 30, ~~respectively.~~2018, inclusive of

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility, from time to time, 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 June 30, 2017, were not material. There were no open FTR positions as of June 30, 2018.15

PUC Temporary Rates Order. By Secretarial Letter dated January 12, 2018, the PUC initiated a review into whether public utility rates should be adjusted to reflect the tax savings from the change in the federal income tax rate from 35% to 21% for the period

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Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~beginning January 1~~interest, ~~2018. Thereafter,~~thereby onsatisfying ~~March~~a ~~15,~~requirement ~~2018,~~to ~~the~~make ~~PUC entered~~ a ~~Temporary~~proposal ~~Rates~~for ~~Order~~distributing ~~that~~those ~~converted~~benefits ~~commission-approved~~within ~~rates~~three years of ~~most~~the ~~large~~May ~~Pennsylvania~~17, ~~public utilities~~2018, ~~including~~Order. ~~Gas~~The ~~Utility,~~negative ~~into~~surcharge ~~“temporary~~will ~~rates”~~become effective for a twelve-month period ofbeginning noon ~~more than 12 months while~~ the ~~PUC~~effective ~~reviewed~~date ~~the~~of ~~data and comments in response to~~ the ~~Secretarial~~new ~~Letter~~base rates.

OnFor ~~May~~Pennsylvania ~~17,~~utilities ~~2018,~~that ~~the~~were ~~PUC ordered each regulated utility currently not~~ in a general base rate ~~case~~ proceeding, including ~~UGI~~Electric ~~Gas~~Utility, ~~PNG~~no ~~and CPG, to reduce their rates through the establishment of a~~ negative surcharge ~~applied to bills rendered on or after July 1, 2018~~applies. The ~~temporary~~tax ~~negative~~benefits ~~surcharge~~that ~~will~~accrued beduring ~~reconciled at~~ the ~~end~~period ofJanuary ~~each~~1, ~~fiscal~~2018 ~~year~~through toOctober ~~actual~~26, ~~tax~~2018, ~~savings realized. The negative surcharge will remain in place until~~ the ~~effective~~ date ofbefore ~~new~~Electric ~~rates established in the utility~~Utility’s ~~next general~~ base rate ~~proceeding. For~~case ~~UGI~~became ~~Gas,~~effective ~~PNG~~(see ~~and CPG~~below), ~~such~~were ~~negative~~refunded ~~surcharge~~to ~~will~~Electric ~~reduce~~Utility ~~base~~ratepayers ~~rate~~through ~~revenues~~a byone-time ~~5.78%,~~bill 3credit.~~90% and 8.19%, respectively.~~

InExcess ~~its~~federal ~~May~~deferred ~~17,~~income ~~2018~~taxes. ~~Order,~~This ~~the PUC also required Pennsylvania utilities to establish a~~ regulatory liability ~~for~~is ~~tax benefits that accrued during~~ the ~~period~~result ~~beginning~~of ~~January~~remeasuring 1,UGI ~~2018~~Utilities’ ~~through~~federal ~~June~~deferred ~~30,~~income ~~2018, resulting from the reduced federal~~ tax ~~rate. For~~liabilities ~~UGI~~on ~~Gas,~~utility ~~PNG~~plant ~~and~~due ~~CPG,~~to ~~during~~ the ~~three~~enactment ~~months~~of ~~ended~~the ~~June~~TCJA ~~30,~~on ~~2018,~~December ~~UGI Utilities reduced its combined utility revenues by $~~22,~~745~~ 2017 (~~which~~see isNote ~~in addition to a $1,353 reduction previously recorded in March 2018~~6)~~, and recorded a regulatory liability in an equal amount~~. ~~The~~In ~~total~~order ~~reduction in revenues~~ for ~~the~~our ~~nine~~utility ~~months~~assets ~~ended~~to ~~June~~continue ~~30,~~to ~~2018~~be ~~reflects~~eligible ~~(1)~~for ~~$17,135~~accelerated of tax ~~benefits~~depreciation, ~~accrued~~current ~~during~~law ~~the~~requires ~~previously~~that ~~mentioned~~excess ~~six-month~~federal ~~period~~deferred ~~plus~~income ~~(2)~~taxes ~~$6,963~~resulting tofrom ~~reflect~~the ~~tax~~remeasurement ~~benefits~~be ~~expected~~amortized tono bemore ~~generated~~rapidly bythan over the ~~future~~remaining ~~amortization~~lives of the ~~regulatory~~assets ~~liability.~~that ~~The~~gave ~~rate~~rise ~~treatment~~to ofthe ~~this~~excess ~~regulatory~~federal ~~liability,~~deferred ~~including~~income ~~accrued interest~~taxes, ~~for~~ranging ~~each~~from of1 ~~UGI~~year ~~Gas,~~to ~~PNG~~approximately ~~and~~65 ~~CPG will be addressed in a future proceeding~~years. ~~Like~~This ~~other~~regulatory ~~similarly~~liability ~~situated~~has ~~utilities,~~been ifincreased ~~UGI~~to ~~Gas,~~reflect ~~PNG~~the ortax ~~CPG~~benefit ~~have~~generated ~~not~~by ~~filed~~the aamortization ~~general base rate proceeding within three years~~ of the ~~Temporary~~excess ~~Rates~~deferred ~~Order,~~federal ~~UGI~~income ~~Gas,~~taxes ~~PNG~~ and ~~CPG~~is ~~will~~being beamortized ~~required~~and tocredited ~~file a petition~~ to ~~propose~~tax ~~how to distribute the balance of these regulatory liabilities~~expense.

For Pennsylvania utilities currently in a general base rate proceeding, including Electric Utility, no negative surcharge will apply, and such tax benefits will be handled through that proceeding, including the benefits that accrue during the period beginning January 1, 2018 until the effective date of new base rates established in the proceeding. At June 30, 2018, such amount for Electric Utility was not material.

Excess federal deferred income taxes. This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 5). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess federal deferred income taxes resulting from the remeasurement be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess federal deferred income taxes, ranging from 1 year to approximately 65 years. This regulatory liability has been increased to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes and will be amortized and credited to tax expense.

Other Regulatory Matters

~~Base~~Utility ~~Rate Filings~~Merger. On ~~January 26~~March 8, 2018 and March 13, ~~Electric~~2018, ~~Utility~~UGI Utilities filed amerger ~~rate~~authorization ~~request~~requests with the ~~PUC~~PAPUC toand ~~increase~~MDPSC, ~~its annual base distribution revenues by $9~~respectively,~~200,~~ ~~which~~to ~~was~~merge ~~later~~PNG ~~reduced~~and byCPG ~~the~~into ~~Company~~UGI ~~to $7~~Utilities,~~700~~ towith ~~reflect~~a ~~the~~targeted ~~impact~~effective date of ~~the~~October ~~TCJA~~1, ~~and other adjustments~~2018. ~~The~~After ~~increased~~receiving ~~revenues~~all ~~would~~necessary ~~fund~~FERC, ~~ongoing~~MDPSC, ~~system improvements~~ and ~~operations~~PAPUC ~~necessary~~approvals, toCPG ~~maintain safe~~ and ~~reliable~~PNG ~~electric~~were ~~service.~~merged ~~Electric~~into ~~Utility~~UGI ~~requested~~Utilities ~~that the new electric rates become~~ effective ~~March~~October 271, 2018. ~~The~~Consistent ~~PUC~~with ~~entered~~the anMDPSC ~~Order~~order ~~dated~~issued ~~March~~July 125, 2018, ~~suspending~~and the ~~effective~~PAPUC ~~date~~order ~~for~~issued ~~the~~September, ~~rate~~26, ~~increase~~2018, tothe ~~allow~~former ~~for~~CPG, ~~investigation~~PNG and ~~public~~UGI ~~hearings~~Utilities, inInc. aGas ~~review~~Division ~~process~~service ~~that~~territories isbecame ~~expected to last up to nine months from~~ the ~~date~~UGI ofCentral, ~~filing. The~~UGI ~~matter~~North isand ~~currently~~UGI ~~pending~~South ~~before~~rate ~~two~~districts ~~PUC~~of ~~administrative~~the ~~law~~UGI ~~judges~~Utilities, ~~who~~Inc. ~~are~~Gas ~~expected~~Division, torespectively, ~~issue~~without aany ~~recommended~~ratemaking ~~decision~~change. ~~that~~UGI ~~will~~Utilities’ beobligations under the ~~subject~~settlement ofapproved ~~a final decision~~ by the ~~PUC. Although~~PAPUC ~~the~~include ~~Company~~various ~~expects~~non-monetary toconditions ~~receive~~requiring aUGI ~~final~~Utilities ~~decision~~to ~~from~~maintain ~~the~~separate ~~PUC~~accounting-type inschedules ~~October~~for ~~2018,~~limited ~~the~~future ~~Company~~ratemaking ~~cannot predict the timing or the ultimate outcome of the rate case review process~~purposes.

OnBase ~~August~~Rate 31Filings. On January 28, ~~2017~~2019, ~~the~~UGI ~~PUC~~Gas ~~approved~~filed a ~~previously~~request ~~filed~~with ~~Joint~~the ~~Petition~~PAPUC to increase its operating revenues for ~~Approval~~residential, ofcommercial ~~Settlement~~and industrial customers by $71,090 annually. The requested rate increase applies to the consolidated UGI Central, UGI North and UGI South rate districts. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Additionally, UGI Gas has proposed a 4.5% negative surcharge applicable to all ~~issues~~customer ~~providing~~distribution ~~for~~service anbills to return $1126,~~250~~249 ~~annual~~of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, inclusive of interest. As proposed, the negative surcharge will become effective for a twelve-month period beginning on the effective date of the new base ~~distribution~~rates. UGI Gas is requesting that the new gas rates become effective March 29, 2019. However, the PAPUC typically suspends the effective date for general base rate ~~increase~~proceedings for ~~PNG~~a period not to exceed nine months after the filing date to allow for investigation and public hearings. The ~~increase~~Company ~~became~~cannot ~~effective~~predict onthe ~~October~~timing ~~20,~~or ~~2017~~the ultimate outcome of the rate case review process.

On ~~October 14~~January 26, ~~2016~~2018, ~~the~~Electric ~~PUC~~Utility ~~approved~~filed a ~~previously~~rate ~~filed~~request ~~Joint~~with ~~Petition~~the ~~for~~PAPUC ~~Approval~~to ofincrease ~~Settlement~~its annual base distribution revenues by $9,200, which was later reduced by the Company to $7,700 to reflect the impact of ~~all~~the ~~issues~~TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $273,~~000~~ 201 annual base distribution rate increase for ~~UGI~~Electric ~~Gas~~Utility effective October 27, 2018. ~~The~~ ~~increase~~As ~~became~~part ~~effective~~of onthe ~~October~~final 19order, ~~2016~~Electric Utility provided customers with a one-time $210 billing credit associated with 2018 TCJA tax benefits. On November 26, 2018, the Pennsylvania Office of Consumer Advocate filed an appeal to the Pennsylvania Commonwealth Court challenging the PAPUC’s acceptance of the Company’s use of a fully projected future test year and handling of consolidated federal income tax benefits. The Company cannot predict the ultimate outcome of this appeal.

~~Distribution~~On ~~System~~January 19, ~~Improvement~~2017, ~~Charge.~~PNG ~~State~~(now ~~legislation~~the ~~permits~~UGI ~~gas~~North ~~and~~rate ~~electric~~district ~~utilities~~of inGas ~~Pennsylvania~~Utility) filed a rate request with the PAPUC to ~~recover~~increase aPNG’s ~~distribution~~annual base operating revenues for residential, commercial and industrial customers by $21,700 annually. The increased revenues would fund ongoing system ~~improvement~~improvements ~~charge~~and ~~(“DSIC”)~~operations onnecessary ~~eligible~~to ~~capital~~maintain ~~investments~~safe asand anreliable ~~alternative~~natural ~~ratemaking~~gas ~~mechanism~~service. ~~providing~~On ~~for~~June 30, 2017, all active parties supported the filing of a ~~more~~Joint ~~timely~~Petition ~~cost~~for ~~recovery~~Approval of ~~qualifying~~Settlement ~~capital~~of ~~expenditures~~all ~~between~~issues with the PAPUC providing for an $11,250 PNG annual base distribution rate ~~cases~~increase. On August 31, 2017, the PAPUC approved the Joint Petition and the increase became effective on October 20, 2017.

~~- 10 -~~16

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Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~PNG~~Manor ~~and~~Township, ~~CPG~~Pennsylvania ~~received~~Natural ~~PUC~~Gas ~~approval~~Incident onComplaint. aIn ~~DSIC~~connection ~~tariff,~~with ~~initially~~a ~~set~~July at2, ~~zero~~2017, explosion in ~~2014.~~Manor ~~PNG~~Township, ~~and~~Lancaster ~~CPG~~County, ~~began~~Pennsylvania, ~~charging~~that aresulted ~~DSIC~~in atthe adeath ~~rate~~of ~~other~~one ~~than~~Company ~~zero~~employee ~~beginning~~and oninjuries ~~April~~to 1,two ~~2015~~Company employees and ~~April~~one 1,sewer ~~2016~~authority employee, ~~respectively.~~and Indestroyed ~~May~~two ~~2017,~~residences ~~the~~and ~~PUC~~damaged ~~issued~~several aother ~~final~~homes, ~~Order~~the toBIE ~~approve~~filed ana ~~increase~~formal ofcomplaint at the ~~maximum~~PAPUC ~~allowable~~in ~~DSIC~~which toBIE ~~7.5%~~alleged ofthat ~~billed~~the ~~distribution~~Company ~~revenues~~committed ~~effective~~multiple ~~July~~violations 1,of ~~2017,~~federal ~~for~~and ~~PNG~~state ~~and~~gas ~~CPG,~~pipeline ~~pending~~regulations ~~reconsideration~~in atconnection ~~each~~with ~~company’s~~its ~~Long-Term~~emergency ~~Infrastructure~~response ~~Improvement~~leading ~~Plan~~up ~~filing.~~to ~~PNG’s~~the ~~DSIC~~explosion, ~~has~~and ~~been~~it ~~reset~~requested tothat ~~zero~~the asPAPUC aorder ~~result~~the ofCompany ~~its~~to ~~most~~pay ~~recent~~approximately $2,100 in ~~base~~civil ~~rate~~penalties, ~~case.~~which ~~The~~is ~~DSIC~~the ~~rate~~maximum ~~for~~allowable ~~PNG~~fine. ~~will~~On ~~resume~~November ~~upon~~16, ~~exceeding~~2018, the ~~threshold~~Company ~~amount~~filed ofits ~~DSIC-eligible~~formal ~~plant~~written inanswer ~~service~~contesting ~~agreed upon during~~ the ~~settlement~~BIE ofcomplaint. ~~its~~The ~~most~~matter ~~recent~~remains ~~base~~pending ~~rate~~before ~~case~~the PAPUC.

InNote ~~November~~8 ~~2016,~~— ~~UGI~~Debt 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 began recovering revenue under the mechanism effective July 1, 2018 for the amount of DSIC-eligible plant placed into service as it exceeded the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case in the third quarter of Fiscal 2018.

~~Utilities~~Subsequent ~~Merger Request~~Event. On ~~March~~February 81, ~~2018 and March 13~~2019, ~~2018,~~UGI ~~the~~Utilities ~~Company~~issued ~~filed~~in ~~merger~~a ~~authorization~~private ~~requests~~placement ~~with the PUC and MD PSC~~$150,000 ~~respectively,~~of to4.55% ~~merge~~Senior ~~PNG~~Notes ~~and~~due ~~CPG~~February ~~into UGI Utilities, with a targeted effective date of October~~ 1, ~~2018~~2049. ~~There~~ ~~are~~The no4.55% ~~expected~~Senior ~~changes~~Notes towere ~~annual~~issued ~~base~~pursuant ~~distribution rates for the combined utilities or~~ to ~~existing regulatory assets and liabilities as~~ a ~~result~~Note ofPurchase ~~the~~Agreement ~~proposed~~dated ~~merger. On~~December ~~July 20~~21, 2018, ~~the~~between ~~Company~~UGI ~~filed~~Utilities aand ~~Joint~~certain ~~Petition~~note ~~for~~purchasers. ~~Settlement~~The ~~among~~4.55% ~~the~~Senior ~~parties~~Notes toare ~~the~~unsecured ~~proceeding~~and ~~for~~rank ~~approval~~equally bywith ~~two~~UGI ~~administrative~~Utilities’ ~~law~~existing ~~judges~~outstanding bysenior ~~recommended~~debt. ~~decision~~The ~~that~~net ~~will~~proceeds befrom the ~~subject~~sale of ~~a final decision by~~ the ~~PUC~~4.55% OnSenior ~~July~~Notes ~~25,~~were ~~2018,~~used ~~the~~to MDreduce ~~PSC~~short-term ~~issued~~borrowings anand ~~order~~for ~~approving~~general ~~the~~corporate ~~Company’s merger request~~purposes. The ~~Company~~4.55% ~~cannot~~Senior ~~predict~~Notes ~~the~~include ~~timing or~~ the ~~ultimate~~usual ~~outcome~~and ofcustomary ~~the~~covenants ~~PUC~~for ~~review~~similar oftype ~~the~~notes ~~merger request. On August 3~~including, ~~2018,~~among ~~the Federal Energy Regulatory Commission (“FERC”) approved requests made by CPG~~others, ~~PNG,~~maintenance ~~and UGI Utilities in May 2018 relating to the transfer~~ of ~~certain FERC authorizations from PNG and CPG to UGI Utilities~~existence, topayment ~~ensure continuity~~ of ~~certain~~taxes ~~interstate~~when ~~gas~~due, ~~transportation~~compliance ~~services~~with ~~currently~~laws ~~conducted by CPG~~ and ~~PNG~~maintenance ~~after the effective date~~ of ~~the~~insurance. ~~proposed~~The ~~merger~~4.55% ~~With~~Senior ~~the~~Notes ~~receipt~~require ofUGI ~~these~~Utilities ~~FERC~~not ~~approvals,~~to ~~the~~exceed ~~approval~~a ratio of anConsolidated ~~application~~Debt to ~~transfer~~Consolidated ~~CPG’s~~Total ~~service~~Capital, ~~territory~~as ~~designation~~defined, toof ~~UGI~~0.65 ~~Utilities remains the only FERC approval yet~~ to ~~be received in connection with the proposed merger~~1. 00.

Note 79 — ~~Debt~~Commitments and Contingencies

In October 2017, UGI Utilities entered into a $125,000 unsecured variable-rate term loan agreement (the “Term Loan”) with a group of banks. Proceeds from the Term Loan were used to repay revolving credit agreement borrowings and for general corporate purposes. The Term Loan is payable in equal quarterly installments of $1,563 commencing March 2018, with the balance of the principal being due and payable in full on October 30, 2022. 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 that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.

Note 8 — Commitments and Contingencies

Contingencies

From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of ~~manufactured gas plants (“~~MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI ~~Gas~~South and Electric Utility. Beginning in 2006 and 2008, UGI Utilities also ~~has~~owned and operated two acquired subsidiaries (CPG and PNG), which now constitute UGI North and UGI Central, with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. CPG and PNG merged into UGI Utilities effective October 1, 2018.

~~Each~~Prior to the Utility Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, ~~has~~were ~~entered~~subject ~~into~~to aCOAs ~~consent order and agreement (“COA”)~~ with the ~~Pennsylvania~~PADEP ~~Department of Environmental Protection (“DEP”)~~ to address the remediation of specified former ~~MGPs~~MGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the Utility Merger, UGI Utilities, as the successor to CPG and PNG, ~~are~~is ~~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 and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap. The cost cap of the three COAs, in the aggregate, is $5,350. The ~~CPG~~three ~~COA~~COAs ~~includes~~are ancurrently ~~obligation~~scheduled to ~~plug~~terminate ~~specified~~at ~~natural~~the end of 2031, 2020, and 2020. At December 31, 2018, September 30, 2018 and December 31, 2017, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $50,484, $50,970, and $53,409, respectively. UGI Utilities has recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 7).

-UGI Utilities does not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Utilities receives ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. 11This -ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~gas~~significant ~~wells. The~~future ~~COA~~costs ~~environmental~~of ~~costs~~an ~~caps~~uncertain ~~are~~amount ~~$2,500,~~associated ~~$1,750,~~with ~~and~~environmental ~~$1,100,~~damage ~~for~~caused by MGPs outside Pennsylvania that UGI Utilities directly operated, ~~CPG~~or ~~and~~that ~~PNG,~~were ~~respectively.~~owned ~~The~~or ~~COAs~~operated ~~for~~by ~~UGI~~a ~~Utilities,~~former ~~CPG~~subsidiary ~~and~~of ~~PNG~~UGI ~~are~~Utilities ~~currently~~if ~~scheduled~~a court were to ~~terminate~~conclude atthat (1) the ~~end~~subsidiary’s ofseparate ~~2031,~~corporate ~~2018,~~form ~~and~~should ~~2019,~~be ~~respectively. At June 30~~disregarded, ~~2018,~~or ~~September~~(2) ~~30,~~UGI ~~2017~~Utilities ~~and~~should ~~June 30,~~be ~~2017,~~considered ~~our~~to ~~estimated~~have ~~accrued~~been ~~liabilities~~an ~~for~~operator ~~environmental~~because ~~investigation~~of ~~and~~its ~~remediation~~conduct ~~costs~~with ~~related~~respect to ~~the~~its ~~COAs~~subsidiary’s ~~for~~MGP. ~~UGI~~At ~~Utilities~~December 31, ~~CPG and PNG totaled $52~~2018,~~231,~~ ~~$54~~September 30,~~250,~~ 2018 and ~~$55~~December 31,~~185,~~ ~~respectively. UGI Utilities~~2017, ~~CPG~~neither ~~and~~the ~~PNG~~undiscounted ~~have~~nor ~~recorded~~the ~~associated~~accrued ~~regulatory~~liability ~~assets~~ for ~~these~~environmental ~~costs~~investigation ~~because~~and ~~recovery~~cleanup ofcosts ~~these~~for ~~costs~~UGI ~~from~~Utilities’ ~~customers~~MGP issites ~~probable~~outside ~~(see~~Pennsylvania ~~Note~~was 6)material.

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 June 30, 2018, September 30, 2017 and June 30, 2017, 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 aone Company employee, ~~significant~~and injuries to two other Company employees and an employee of the local sewer authority, and significant property damage. The ~~National Transportation Safety Board (“~~NTSB”) and the ~~PUC~~BIE are investigating the Manor Township incident. The NTSB investigative team includes representatives from the Company, the ~~PUC~~BIE, the local fire department and the Pipeline and Hazardous Materials Safety Administration, and the Company ~~is cooperating with the investigation~~. The Company continues to cooperate with the investigation and provide information requested by the investigating parties. The Occupational Safety and Health Administration has closed its investigation with no findings. The BIE filed a formal complaint at the PAPUC in which the BIE alleged that the Company committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion and it requested that the PAPUC order the Company to pay approximately $2,100 in civil penalties, which is the maximum allowable fine. On November 16, 2018, the Company filed its formal written answer contesting the BIE complaint. The matter remains pending before the PAPUC.

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~~anticipates that third-party claims associated with the explosion, in excess of the Company’s deductible, ~~are~~will ~~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.

Note 910 — 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 limited postretirement health care benefits to certain retirees and postretirement life insurance benefits to ~~nearly~~certain ~~all~~ active and retired employees ~~(“Other Postretirement Plans”)~~.

~~- 12~~Net -periodic pension expense and other postretirement benefit costs include the following components:



	Pension Benefits						Other Postretirement Benefits
Three Months Ended December 31,	2018			2017			2018			2017
Service cost	$	1,637		$	1,881		$	31		$	67
Interest cost	6,050			5,767			109			112
Expected return on assets	(8,140		)	(7,777		)	(185		)	(177		)
Amortization of:
Prior service cost (benefit)	63			63			(109		)	(110		)
Actuarial loss	1,720			2,984			17			24
Net benefit cost (benefit)	1,330			2,918			(137		)	(84		)
Change in associated regulatory liabilities	—			—			(343		)	(123		)
Net benefit cost (benefit) after change in regulatory liabilities	$	1,330		$	2,918		$	(480	)	$	(207	)

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~Net~~Pension ~~periodic~~Plan ~~pension~~assets ~~expense~~are held in trust and ~~other~~consist ~~postretirement~~principally ~~benefit~~of ~~costs~~publicly ~~include~~traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the ~~following~~minimum ~~components:~~contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. During the three months ended December 31, 2018, the Company made no contributions to the Pension Plan. During the three months ended December 31, 2017, the Company made cash contributions to the Pension Plan of $3,359. The Company expects to make additional cash contributions of approximately $11,500 to the Pension Plan during the remainder of Fiscal 2019.

	Pension Benefits						Other Postretirement Benefits
Three Months Ended June 30,	2018			2017			2018			2017
Service cost	$	1,882		$	2,023		$	66		$	62
Interest cost	5,766			5,540			111			108
Expected return on assets	(7,776		)	(7,497		)	(178		)	(164		)
Amortization of:
Prior service cost (benefit)	61			81			(110		)	(160		)
Actuarial loss	2,984			3,706			23			28
Net benefit cost (benefit)	2,917			3,853			(88		)	(126		)
Change in associated regulatory liabilities	—			—			(122		)	(123		)
Net benefit cost (benefit) after change in regulatory liabilities	$	2,917		$	3,853		$	(210	)	$	(249	)
	Pension Benefits						Other Postretirement Benefits
Nine Months Ended June 30,	2018			2017			2018			2017
Service cost	$	5,644		$	6,068		$	200		$	184
Interest cost	17,300			16,618			335			323
Expected return on assets	(23,330		)	(22,490		)	(532		)	(492		)
Amortization of:
Prior service cost (benefit)	187			244			(330		)	(480		)
Actuarial loss	8,952			11,119			71			85
Net benefit cost (benefit)	8,753			11,559			(256		)	(380		)
Change in associated regulatory liabilities	—			—			(368		)	(368		)
Net benefit cost (benefit) after change in regulatory liabilities	$	8,753		$	11,559		$	(624	)	$	(748	)

UGI Utilities has established a VEBA trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any. The difference between such cash deposits or expense recorded and the amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the three months ended December 31, 2018 and 2017.

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. During the nine months ended June 30, 2018 and 2017, the Company made contributions to the Pension Plan of $10,079 and $8,546, respectively. The Company expects to make additional cash contributions of approximately $5,000 to the Pension Plan during the remainder of Fiscal 2018.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any. The difference between such cash deposits or expense recorded and the amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the nine months ended June 30, 2018 and 2017.

We also participate in an unfunded and non-qualified defined benefit supplemental executive retirement plan. Net benefit costs associated with this plan for all periods presented were not material.

~~- 13~~Note -11 — Fair Value Measurements

Derivative Instruments

The following table presents, on a gross basis, our derivative assets and liabilities, including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of December 31, 2018, September 30, 2018 and December 31, 2017:



	Asset (Liability)
	Level 1			Level 2			Level 3		Total
December 31, 2018:
Assets:
Commodity contracts	$	1,336		$	—		$	—	$	1,336
Liabilities:
Commodity contracts	$	(733	)	$	—		$	—	$	(733	)
Interest rate contracts	$	—		$	(1,655	)	$	—	$	(1,655	)
September 30, 2018:
Assets:
Commodity contracts	$	3,154		$	—		$	—	$	3,154
Interest rate contracts	$	—		$	30		$	—	$	30
Liabilities:
Commodity contracts	$	(146	)	$	—		$	—	$	(146	)
December 31, 2017:
Assets:
Commodity contracts	$	678		$	19		$	—	$	697
Liabilities:
Commodity contracts	$	(2,151	)	$	(112	)	$	—	$	(2,263	)

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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

Note 10 — Fair Value Measurements

Derivative Instruments

The following table presents, on a gross basis, our derivative assets and liabilities, including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of June 30, 2018, September 30, 2017 and June 30, 2017:

	Asset (Liability)
	Level 1			Level 2			Level 3		Total
June 30, 2018:
Assets:
Commodity contracts	$	2,097		$	—		$	—	$	2,097
Liabilities:
Commodity contracts	$	(101	)	$	—		$	—	$	(101	)
September 30, 2017:
Assets:
Commodity contracts	$	1,735		$	72		$	—	$	1,807
Liabilities:
Commodity contracts	$	(1,447	)	$	(73	)	$	—	$	(1,520	)
June 30, 2017:
Assets:
Commodity contracts	$	1,062		$	101		$	—	$	1,163
Liabilities:
Commodity contracts	$	(1,157	)	$	(68	)	$	—	$	(1,225	)

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~~type 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 ~~June~~December 3031, 2018, September 30, ~~2017~~2018 and ~~June~~December 3031, 2017 were as follows:

	June 30, 2018		September 30, 2017		June 30, 2017
	December 31, 2018		September 30, 2018		December 31, 2017
Carrying amount	$	~~844~~840,~~672~~461	$	~~755~~842,~~000~~130	$	~~755~~860,000
Estimated fair value	$	~~858~~829,~~960~~794	$	~~791~~826,~~378~~470	$	~~788~~909,~~472~~283

Note 1112 — 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.

~~- 14~~Commodity -Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PAPUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses NYMEX natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At December 31, 2018, September 30, 2018 and December 31, 2017, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 14.7 million dekatherms, 23.2 million dekatherms and 13.4 million dekatherms, respectively. At December 31, 2018, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 9 months. Gains and losses on Gas Utility natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 7).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At December 31, 2018, September 30, 2018 and December 31, 2017, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. At December 31, 2018, September 30, 2018 and December 31, 2017, the total volumes associated with gasoline futures contracts were not material.

Interest Rate Risk

UGI Utilities has a variable-rate term loan that is indexed to short-term market interest rates. UGI Utilities has entered into a forward starting, amortizing, pay- fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on borrowings at 3.00% beginning September 30, 2019 through July 2022. We have designated this forward-starting interest rate swap as a cash flow hedge. The initial notional amount of term loan debt subject to this interest rate swap agreement is $114,063.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~among~~Our ~~other~~long-term ~~things,~~debt ~~the~~typically ~~derivative~~is ~~instruments~~issued weat ~~can~~fixed ~~use~~rates of interest. As these long-term debt issuances mature, ~~counterparty~~we ~~credit~~typically ~~limits~~refinance ~~and~~such ~~contract~~debt ~~authorization~~with ~~limits.~~new ~~Because~~debt ~~most~~having ofinterest ~~our~~rates ~~commodity~~reflecting ~~derivative~~then-current ~~instruments~~market ~~are~~conditions. ~~generally~~In ~~subject~~order to ~~regulatory~~reduce ~~ratemaking~~market ~~mechanisms,~~rate werisk ~~have~~on ~~limited~~the ~~commodity~~underlying ~~price~~benchmark ~~risk~~rate of interest associated with ~~our~~near- ~~Gas~~to ~~Utility~~medium-term orforecasted ~~Electric~~issuances ~~Utility~~of ~~operations~~fixed-rate debt, from time to time we enter into IRPAs. We account for IRPAs as cash flow hedges.

~~Commodity~~As ~~Price~~of ~~Risk~~December 31, 2018, September 30, 2018 and December 31, 2017, we had no unsettled IRPAs. At December 31, 2018, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3,485.

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 June 30, 2018, September 30, 2017 and June 30, 2017, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 16.8 million dekatherms, 14.8 million dekatherms and 12.7 million dekatherms, respectively. At June 30, 2018, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 16 months. Gains and losses on natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the condensed consolidated balance sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 6).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At June 30, 2018, September 30, 2017 and June 30, 2017, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities on the condensed consolidated balance sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). At June 30, 2018, there were no volumes associated with FTRs. At September 30, 2017 and June 30, 2017, the total volumes associated with FTRs totaled 101.2 million kilowatt hours and 139.4 million kilowatt hours, respectively.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. At June 30, 2018, September 30, 2017 and June 30, 2017, the total volumes associated with gasoline futures contracts were not material.

Interest Rate Risk

Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. As of June 30, 2018, September 30, 2017 and June 30, 2017, we had no unsettled IRPAs. At June 30, 2018, 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 ~~June~~December 3031, 2018, September 30, ~~2017~~2018 and ~~June~~December 3031, 2017, restricted cash in brokerage accounts totaled $~~805~~3,308, $31,~~046~~190 and $23,~~524~~665, respectively.

Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on the ~~condensed~~Condensed ~~consolidated~~Consolidated ~~balance~~Balance ~~sheets~~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. 15Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on the Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions.

In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on the condensed consolidated balance sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.

Fair Value of Derivative Instruments

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of ~~June~~December 3031, 2018, September 30, ~~2017~~2018 and ~~June~~December 3031, 2017:

	June 30, 2018			September 30, 2017			June 30, 2017
	December 31, 2018			September 30, 2018			December 31, 2017
Derivative assets:
Derivatives designated as hedging instruments:
Interest rate contracts	$	—		$	30		$	—
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$1,336	~~1,963~~		$3,002	~~1,665~~		$450	~~1,163~~
Derivatives not subject to PGC and DS mechanisms:
Derivatives not designated as hedging instruments:
Commodity contracts	~~134~~—			~~142~~152			—247
Total derivative assets — gross	21,~~097~~336			13,~~807~~184			~~1,163~~697
Gross amounts offset in the balance sheet	(~~101~~266		)	(~~450~~146		)	(~~159~~19		)
Total derivative assets — net (a)	$	1,~~996~~070		$	13,~~357~~038		$	~~1,004~~678
Derivative liabilities:
Derivatives designated as hedging instruments:
Interest rate contracts	$	(1,655	)	$	—		$	—
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$(499	~~(101~~	)	$(146	~~(1,520~~	)	$(2,263	~~(1,204~~	)
Derivatives not subject to PGC and DS mechanisms:
Derivatives not designated as hedging instruments:
Commodity contracts	—(234		)	—			~~(21~~—		)
Total derivative liabilities — gross	(~~101~~2,388		)	(~~1,520~~146		)	(12,~~225~~263		)
Gross amounts offset in the balance sheet	~~101~~266			~~450~~146			~~159~~19
Total derivative liabilities — net (a)	$	—(2,122	)	$	~~(1,070~~—	)	$	(12,~~066~~244	)


(a)	Derivative assets and liabilities with maturities greater than one year are recorded in “Other assets” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.

~~- 16~~Effects -of Derivative Instruments

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Condensed Consolidated Statements of Income and changes in AOCI for the three months ended December 31, 2018 and 2017:



	Loss Recognized in AOCI					Loss Reclassified from AOCI into Income						Location of Loss Reclassified from AOCI into Income
Three Months Ended December 31,	2018			2017		2018			2017			Location of Loss Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	(1,685	)	$	—	$	(872	)	$	(871	)	Interest expense

	(Loss) Gain Recognized in Income					Location of (Loss) Gain Recognized in Income
Three Months Ended December 31,	2018			2017
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	(396	)	$	149	Operating and administrative expenses

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~Effect~~The amounts of ~~Derivative~~derivative ~~Instruments~~gains and losses on cash flow hedges representing ineffectiveness were not material for all periods presented.

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the condensed consolidated statements of income and changes in AOCI for the three and nine months ended June 30, 2018 and 2017:

	Loss Reclassified from AOCI into Income						Location of Loss Reclassified from AOCI into Income
Three Months Ended June 30,	2018			2017
Cash Flow Hedges:
Interest rate contracts	$	(871	)	$	(856	)	Interest expense
	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Three Months Ended June 30,	2018			2017
Derivatives Not Subject to PGC and DS Mechanisms:
Commodity contracts	$	37		$	(57	)	Operating and administrative expenses
	Loss Reclassified from AOCI into Income						Location of Loss Reclassified from AOCI into Income
Nine Months Ended June 30,	2018			2017
Cash Flow Hedges:
Interest rate contracts	$	(2,614	)	$	(2,524	)	Interest expense
	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Nine Months Ended June 30,	2018			2017
Derivatives Not Subject to PGC and DS Mechanisms:
Commodity contracts	$	198		$	(25	)	Operating and administrative expenses

We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for NPNS exception accounting because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

~~- 17~~Note -13 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2018 and 2017:



Three Months Ended December 31, 2018	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI — September 30, 2018	$	(4,920	)	$	(15,409	)	$	(20,329	)
Net losses on interest rate contract	—			(1,198		)	(1,198		)
Reclassifications of benefit plans actuarial losses and net prior service credits	132			—			132
Reclassifications of net losses on IRPAs	—			620			620
Reclassification of stranded income tax effects related to TCJA	(1,712		)	(3,739		)	(5,451		)
AOCI — December 31, 2018	$	(6,500	)	$	(19,726	)	$	(26,226	)

Three Months Ended December 31, 2017	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI — September 30, 2017	$	(8,995	)	$	(17,796	)	$	(26,791	)
Reclassifications of benefit plans actuarial losses and net prior service credits	220			—			220
Reclassifications of net losses on IRPAs	—			592			592
AOCI — December 31, 2017	$	(8,775	)	$	(17,204	)	$	(25,979	)

Note 14 — Related Party Transactions

UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PAPUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. UGI Utilities also engages in other services with various other affiliates pursuant to arrangements authorized by the PAPUC using similar allocation or market-based pricing methods. These billed expenses are classified as “Operating and administrative expenses — related parties” in the Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PAPUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities totaled $1,182 and $1,046 during the three months ended December 31, 2018 and 2017, respectively.

UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. At December 31, 2018, 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~Note~~certain 12associated —storage ~~Accumulated~~inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $3,101 during both three months ended December 31, 2018 and 2017. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. These payments totaled $743 and $718 during the three months ended December 31, 2018 and 2017, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in “Other ~~Comprehensive~~current ~~Income~~liabilities” on the Condensed Consolidated Balance Sheets, at December 31, 2018, was $9,040 and at September 30, 2018 and December 31, 2017, were $11,040.

~~The~~UGI ~~tables~~Utilities ~~below~~reflects ~~present~~the ~~changes~~historical incost ~~AOCI,~~of ~~net~~the gas storage inventories and any exchange receivable from Energy Services (representing amounts of ~~tax,~~natural ~~during~~gas inventories used but not yet replenished by Energy Services) in “Inventories” on the ~~three~~Condensed ~~and~~Consolidated ~~nine~~Balance ~~months~~Sheets. ~~ended~~At ~~June~~December 31, 2018, September 30, 2018 and December 31, 2017:, the carrying values of these gas storage inventories, comprising approximately 5.9 bcf, 6.7 bcf and 6.1 bcf of natural gas, were $15,921, $17,701 and $17,043, respectively.

Three Months Ended June 30, 2018	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI — March 31, 2018	$	(8,555	)	$	(16,612	)	$	(25,167	)
Reclassifications of benefit plan actuarial losses and net prior service credits	220			—			220
Reclassifications of net losses on IRPAs	—			592			592
AOCI — June 30, 2018	$	(8,335	)	$	(16,020	)	$	(24,355	)
Three Months Ended June 30, 2017	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI — March 31, 2017	$	(11,356	)	$	(18,808	)	$	(30,164	)
Reclassifications of benefit plan actuarial losses and net prior service credits	239			—			239
Reclassifications of net losses on IRPAs	—			501			501
AOCI — June 30, 2017	$	(11,117	)	$	(18,307	)	$	(29,424	)

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility primarily during the heating-season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three months ended December 31, 2018 and 2017 totaled $36,237 and $34,588, respectively.

Nine Months Ended June 30, 2018	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI — September 30, 2017	$	(8,995	)	$	(17,796	)	$	(26,791	)
Reclassifications of benefit plans actuarial losses and net prior service credits	660			—			660
Reclassifications of net losses on IRPAs	—			1,776			1,776
AOCI — June 30, 2018	$	(8,335	)	$	(16,020	)	$	(24,355	)
Nine Months Ended June 30, 2017	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI — September 30, 2016	$	(11,834	)	$	(19,784	)	$	(31,618	)
Reclassifications of benefit plans actuarial losses and net prior service credits	717			—			717
Reclassifications of net losses on IRPAs	—			1,477			1,477
AOCI — June 30, 2017	$	(11,117	)	$	(18,307	)	$	(29,424	)

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2018 and 2017, revenues associated with such sales to Energy Services totaled $22,862 and $21,147, respectively. Also from time to time, UGI Utilities purchases natural gas and pipeline capacity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three months ended December 31, 2018 and 2017, such purchases totaled $44,382 and $37,597, respectively.

Note 1315 — ~~Related~~Segment ~~Party~~Information ~~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. UGI Utilities also engages in other services with various other affiliates pursuant to arrangements authorized by the PUC using similar allocation or market-based pricing methods. These billed expenses are classified as “Operating and administrative expenses — related parties” in the Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities totaled $1,665 and $562 during the three months ended June 30, 2018 and 2017, respectively, and $4,070 and $3,420 during the nine months ended June 30, 2018 and 2017, respectively.

From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories

- 18 -

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $8,114 and $9,777 during the three months ended June 30, 2018 and 2017, respectively, and $11,394 and $12,272 during the nine months ended June 30, 2018 and 2017, respectively. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. These payments totaled $701 and $729 during the three months ended June 30, 2018 and 2017, respectively, and $2,127 and $2,027 during the nine months ended June 30, 2018 and 2017, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets, at June 30, 2018, September 30, 2017 and June 30, 2017, were $11,040.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) in “Inventories” on the Condensed Consolidated Balance Sheets. The carrying values of these gas storage inventories at June 30, 2018, September 30, 2017 and June 30, 2017, comprising approximately 3.6 bcf, 6.8 bcf and 3.6 bcf of natural gas, were $9,294, $19,323 and $10,662, respectively.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility primarily during the heating-season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three months ended June 30, 2018 and 2017 totaled $5,828 and $2,137, respectively, and during the nine months ended June 30, 2018 and 2017 totaled $87,782 and $73,872, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During the three months ended June 30, 2018 and 2017, revenues associated with such sales to Energy Services totaled $11,582 and $10,554, respectively. During the nine months ended June 30, 2018 and 2017, revenues associated with such sales to Energy Services totaled $93,974 and $43,836, respectively. Also from time to time, UGI Utilities purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three months ended June 30, 2018 and 2017, such purchases totaled $19,429 and $14,675, respectively. During the nine months ended June 30, 2018 and 2017, such purchases totaled $140,455 and $75,783, respectively.

Note 14 — Segment Information

We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties.

The accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s ~~2017~~2018 Annual Report. WeOur ~~evaluate~~Chief Operating Decision Maker evaluates the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes. Financial information by business segment follows:

~~- 19 -~~24

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

Financial information by business segment follows:



				Reportable Segments
Three Months Ended December 31, 2018	Total			Gas Utility			Electric Utility
Revenues	$	322,725		$	297,142		$	25,583
Cost of sales	$	159,519		$	145,120		$	14,399
Depreciation	$	22,474		$	21,040		$	1,434
Operating income	$	77,074		$	73,584		$	3,490
Pension and other postretirement plans non-service income	$	412		$	361		$	51
Interest expense	$	(11,738	)	$	(11,218	)	$	(520	)
Income before income taxes	$	65,748		$	62,727		$	3,021
Capital expenditures (including the effects of accruals)	$	77,319		$	75,074		$	2,245

As of December 31, 2018
Total assets	$	3,424,773		$	3,251,331		$	173,442
Goodwill	$	182,145		$	182,145		$	—

				Reportable Segments
Three Months Ended June 30, 2018	Total			Gas Utility			Electric Utility
Three Months Ended December 31, 2017	Total			Gas Utility			Electric Utility
Revenues	$	~~159~~323,~~934~~105		$	~~138~~299,~~597~~965		$	2123,~~337~~140
Cost of sales — gas and purchased power	$	72,537		$	60,837		$	11,700
Cost of sales	$	151,774		$	138,858		$	12,916
Depreciation and amortization	$	21,414		$	20,011		$	1,403
Depreciation	$	20,354		$	19,000		$	1,354
Operating income	$	3,914		$	2,628		$	1,286
Operating income (a)	$	96,870		$	94,185		$	2,685
Interest expense	$	10,003		$	9,829		$	174
Pension and other postretirement plans non-service expense (a)	$	(575	)	$	(504	)	$	(71	)
(Loss) income before income taxes	$	(6,089	)	$	(7,201	)	$	1,112
Interest expense	$	(10,939	)	$	(10,526	)	$	(413	)
Capital expenditures (including the effects of accruals)	$	79,704		$	76,546		$	3,158
Income before income taxes	$	85,356		$	83,155		$	2,201
Capital expenditures (including the effects of accruals)	$	71,699		$	68,842		$	2,857
As of December 31, 2017
Total assets	$	3,174,693		$	3,038,250		$	136,443
Goodwill	$	182,145		$	182,145		$	—

			Reportable Segments
Three Months Ended June 30, 2017	Total		Gas Utility		Electric Utility
Revenues	$	146,692	$	127,849	$	18,843
Cost of sales — gas and purchased power	$	51,979	$	42,180	$	9,799
Depreciation and amortization	$	17,912	$	16,845	$	1,067
Operating income	$	27,671	$	25,628	$	2,043
Interest expense	$	10,128	$	9,601	$	527
Income before income taxes	$	17,543	$	16,027	$	1,516
Capital expenditures (including the effects of accruals)	$	79,088	$	75,836	$	3,252

(a) Amounts reflect the reclassification of non-service income (expense) associated with our pension and other postretirement plans from “Operating and administrative expenses” to “Pension and other postretirement plans non-service income (expense)” on the Condensed Consolidated Statements of Income as a result of the adoption of ASU No. 2017-07 (see Note 3).

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

			Reportable Segments
Nine Months Ended June 30, 2018	Total		Gas Utility		Electric Utility
Revenues	$	966,300	$	894,535	$	71,765
Cost of sales — gas and purchased power	$	481,613	$	440,726	$	40,887
Depreciation and amortization	$	62,926	$	58,787	$	4,139
Operating income	$	235,336	$	230,484	$	4,852
Interest expense	$	32,033	$	31,221	$	812
Income before income taxes	$	203,303	$	199,263	$	4,040
Capital expenditures (including the effects of accruals)	$	206,492	$	196,751	$	9,741
As of June 30, 2018
Total assets	$	3,194,025	$	3,008,441	$	185,584
Goodwill	$	182,145	$	182,145	$	—

			Reportable Segments
Nine Months Ended June 30, 2017	Total		Gas Utility		Electric Utility
Revenues	$	768,045	$	700,813	$	67,232
Cost of sales — gas and purchased power	$	325,991	$	288,610	$	37,381
Depreciation and amortization	$	53,002	$	49,378	$	3,624
Operating income	$	226,315	$	219,700	$	6,615
Interest expense	$	30,478	$	29,017	$	1,461
Income before income taxes	$	195,837	$	190,683	$	5,154
Capital expenditures (including the effects of accruals)	$	199,701	$	191,715	$	7,986
As of June 30, 2017
Total assets	$	2,904,532	$	2,743,035	$	161,497
Goodwill	$	182,145	$	182,145	$	—

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

Information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the ~~Securities~~ Exchange Act ~~of 1934, as amended (the “Exchange Act”)~~. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors that could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability of oil, electricity and natural gas and the capacity to transport them to market areas; (3) changes in laws and regulations, including safety, tax, consumer protection, environmental, and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability for environmental claims; (8) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor relations; (10) customer, counterparty, supplier, or vendor defaults; (11) increased uncollectible accounts expense; (12) liability for uninsured claims and for claims in excess of insurance coverage, including those for personal injury and property damage arising from explosions, terrorism, and other catastrophic events that may result from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas; (13) transmission or distribution system service interruptions; (14) political, regulatory and economic conditions in the United States; (15) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (16) changes in commodity market prices resulting in significantly higher cash collateral requirements; (17) the interruption, disruption, failure, malfunction, or breach of our information technology systems, including due to cyber attack; and (18) continued analysis of recent tax legislation.

These factors, and those factors set forth in Item 1A. Risk Factors in the Company’s ~~2017~~2018 Annual Report, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following ~~analyses~~analysis ~~compare~~compares our results of operations for the ~~three months ended June 30,~~ 2018 ~~(“2018~~ three-month period”) with the ~~three months ended June 30,~~ 2017 ~~(“2017~~ three-month period~~”) and the nine months ended June 30, 2018 (“2018 nine-month period”) with the nine months ended June 30, 2017 (“2017 nine-month period”)~~. Our ~~analyses~~analysis of results of operations should be read in conjunction with the segment information included in Note 1415 to the ~~condensed~~Condensed ~~consolidated~~Consolidated ~~financial~~Financial ~~statements~~Statements.

AsOur ~~further~~2018 ~~discussed~~three-month ~~below~~period and in2017 ~~Note~~three-month 5period toresults were significantly impacted by the ~~condensed~~TCJA ~~consolidated~~in ~~financial~~the ~~statements,~~U.S. ~~our~~The ~~condensed~~significant ~~consolidated~~changes ~~balance~~resulting ~~sheet~~from atthe ~~June~~law ~~30,~~that ~~2018~~impacted ~~and~~UGI ~~our~~Utilities ~~net~~included ~~income~~a ~~for~~reduction in the ~~three~~U.S. ~~and~~federal ~~nine~~income ~~months~~tax ~~ended~~rate ~~June~~from ~~30,~~35% ~~2018,~~to ~~were~~21% ~~significantly~~effective ~~affected~~January by1, ~~the~~2018, ~~December~~resulting ~~22,~~in ~~2017~~a ~~enactment~~blended rate of ~~the~~24.5% ~~Tax~~for ~~Cuts~~Fiscal 2018, and ~~Jobs Act (~~the ~~“TCJA”).~~elimination ~~The~~of ~~TCJA~~bonus ~~includes~~depreciation ~~significant~~on ~~changes~~regulated toutility ~~the~~property ~~U.S.~~beginning ~~Corporate~~in ~~income~~Fiscal ~~tax~~2019. ~~system~~For ~~including~~Fiscal a2019, our U.S. federal ~~corporate~~ income tax rate ~~reduction~~is ~~from 35% to~~ 21% ~~effective January 1, 2018~~.

As a result of the TCJA, during the 2017 three-month period we remeasured our existing deferred income tax assets and liabilities at the new tax rates in the U.S. Due to the effects of utility ratemaking, most of the reductions in UGI Utilities’ deferred income tax assets and liabilities resulting from the enactment of the TCJA were not recognized immediately in income tax expense but were reflected in regulatory assets and liabilities in accordance with utility ratemaking. For further information on the effects of the TCJA, and the regulatory impacts on UGI Utilities resulting from the TCJA and the actions of the PAPUC, see Notes 6 and 7 to Condensed Consolidated Financial Statements.

2018 three-month period compared with the 2017 three-month period

Three Months Ended June 30,	2018			2017			Increase (Decrease)
Three Months Ended December 31,	2018			2017			Increase (Decrease)
(Dollars in millions)
Gas Utility:
Revenues (a)	$	~~138~~297.61		$	~~127~~300.80		$	10(2.89	)	8(1.50	)%
Total margin (a)(b)	$	77152.80		$	85161.61		$	(79.81	)	(95.16	)%
Operating and administrative expenses	$	5556.51		$	4947.79		$	5.8.2		1117.71	%
Operating income	$	273.6		$	2594.62		$	(2320.06	)	(8921.89	)%
(Loss) income before income taxes	$	(7.2	)	$	16.0		$	(23.2	)	(145.0	)%
Income before income taxes	$	62.7		$	83.2		$	(20.5	)	(24.6	)%
System throughput — billions of cubic feet (“bcf”)
System throughput — bcf
Core market	1126.45			825.75			21.70			313.09	%
Total	5375.7			4669.52			76.25			159.54	%
Heating degree days — % colder (warmer) than normal (c)	5.1		%	(21.2		)%	—			—
Heating degree days — % (warmer) than normal (c)	(0.5		)%	(1.9		)%	—			—
Electric Utility:
Revenues	$	2125.36		$	1823.81		$	2.5		1310.38	%
Total margin (b)	$	89.59		$	8.09		$	01.50		611.32	%
Operating and administrative expenses (b)	$	65.1		$	5.0		$	10.1		222.0	%
Operating income	$	1.3.5		$	2.07		$	(0.78	)	~~(35~~29.06	)%
Income before income taxes	$	13.10		$	12.52		$	(0.48	)	~~(26~~36.74	)%
Distribution sales — millions of kilowatt-hours (“gwh”)	221.7			209.5			12.2			5.8	%
Distribution sales — gwh	249.7			246.6			3.1			1.3	%

(a) In accordance with athe ~~PUC~~PAPUC Order issued May 17, 2018, Gas Utility’s revenues and total margin for the three months ended ~~June~~December 3031, 2018, were reduced by $2213.75 million to ~~record~~reflect athe ~~regulatory~~give ~~liability~~back ~~related~~of to tax savings ~~for the period January 1, 2018 to June 30, 2018 as a result~~ of the TCJA (see Notes 56 and 67 to ~~condensed~~Condensed ~~consolidated~~Consolidated ~~financial~~Financial ~~statements~~Statements).

(b) Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.13 million ~~and~~during ~~$1.0~~each ~~million~~of ~~during~~ the three months ended ~~June~~December 3031, 2018 and 2017~~, respectively~~. For financial statement purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from Electric Utility operating expenses presented above).

(c) Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by ~~National~~NOAA ~~Oceanic and Atmospheric Administration~~ for airports located within Gas Utility’s service territory.

Temperatures in Gas Utility’s service territory during the three months ended ~~June~~December 3031, 2018, were ~~5.1%~~slightly ~~colder~~warmer than normal and 331.35% colder than ~~during~~ the three months ended ~~June~~December 3031, 2017. ~~The colder weather occurred during the month of April, which was 33.6% colder than normal.~~ Gas Utility core market volumes increased 21.70 bcf (313.09%) principally reflecting the effects of the colder weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 76.25 bcf ~~principally~~ reflecting higher large firm ~~and interruptible~~ delivery service volumes and ~~higher core market volumes. Electric Utility kilowatt-hour sales were 5.8% higher than~~ the ~~prior-year~~previously ~~period~~mentioned ~~principally reflecting the impact of the colder weather on Electric Utility heating-related sales.~~

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UGI UTILITIES, INC. AND SUBSIDIARIES

~~UGI~~higher ~~Utilities~~core ~~revenues~~market ~~increased~~volumes ~~$13.3~~partially ~~million~~offset ~~reflecting~~by a ~~$10.8~~decrease ~~million increase~~ in ~~Gas~~interruptible ~~Utility~~delivery ~~revenues~~service ~~and~~volumes. ~~higher~~ Electric Utility ~~revenues.~~kilowatt-hour Insales ~~accordance with a PUC Order issued May 17, 2018, Gas Utility’s revenues~~ were ~~reduced by $22~~1.73% ~~million,~~higher ~~and~~than ~~an associated regulatory liability established, to record tax savings that accrued during~~ the prior-year period ~~January~~principally 1,reflecting ~~2018 to June 30, 2018 as a result of~~ the ~~TCJA. Excluding the~~ impact of ~~this~~the ~~reduction~~colder inweather ~~revenues,~~on ~~Gas~~Electric Utility ~~revenues~~heating-related ~~increased $33~~sales.~~5 million principally reflecting an increase in core market revenues ($27.1 million) and higher large firm delivery service revenues ($5.9 million).~~

~~The~~UGI Utilities revenues decreased $270.14 million ~~increase~~reflecting a $2.9 million decrease in Gas Utility ~~core~~revenues ~~market~~partially offset by a $2.5 million increase in Electric Utility revenues. ~~reflects~~In accordance with the ~~effects~~May of17, 2018, PAPUC Order, during the ~~higher~~three ~~core~~months ~~market~~ended ~~throughput~~December ~~($19.5~~31, ~~million)~~2018, ~~higher~~Gas ~~average~~Utility’s ~~retail~~revenues ~~core~~were ~~market~~reduced ~~PGC~~by ~~rates (~~$613.5 million) ~~and~~to reflect the ~~increase~~give inback ~~PNG~~of ~~base~~tax ~~rates~~savings ~~effective~~of ~~October~~the ~~20,~~TCJA. ~~2017~~Excluding ~~($1.1~~the ~~million).~~impact ~~The~~of ~~increase~~this reduction in ~~Electric~~revenues, Gas Utility revenues increased $10.6 million principally ~~reflects~~reflecting ~~the~~an ~~higher~~increase ~~distribution~~in off-system sales ~~and~~revenues ~~slightly~~including ~~higher~~capacity ~~average~~releases ~~DS rates~~ ($217.35 million)., ~~UGI~~due ~~Utilities~~in ~~cost~~large part to the adoption of ~~sales~~ASC ~~was~~606 ~~$72.5~~(which ~~million~~requires inthat ~~the~~capacity ~~three~~release ~~months~~contracts ~~ended~~be ~~June~~reflected ~~30,~~on ~~2018~~a ~~compared~~gross, ~~with~~rather ~~$52.0~~than ~~million~~net, inbasis), ~~the~~and ~~three~~higher ~~months~~other ~~ended~~revenues ~~June 30,~~($1.8 ~~2017~~million), ~~principally~~partially ~~reflecting~~offset ~~higher~~by ~~Gas~~lower ~~Utility~~core ~~cost~~market ofrevenues ~~sales~~ ($189.79 million). ~~and~~The ~~higher~~$9.9 ~~Electric~~million decrease in Gas Utility ~~cost~~core ofmarket ~~sales~~revenues reflects lower average retail core market PGC rates ($119.90 million) ~~from~~partially ~~higher~~offset ~~distribution~~by ~~system~~the ~~sales~~effects ~~and~~of the ~~slightly~~ higher DScore ~~rates~~market throughput ($9.0 million).The ~~higher~~increase ~~Gas~~in Electric Utility ~~cost~~revenues ofduring ~~sales~~the 2018 three-month period principally reflects higher ~~retail~~DS ~~core-market~~rates ~~volumes~~ ($90.89 million), higher ~~average~~transmission ~~retail~~revenue ~~core-market PGC rates~~ ($60.57 million), and, toan aincrease ~~lesser~~in ~~extent,~~Electric ~~higher~~Utility ~~large~~base ~~firm~~rates ~~delivery~~effective ~~service~~October ~~cost~~27, of2018 ~~sales~~($0.5 million).

UGI Utilities’ ~~total~~cost ~~margin~~of ~~decreased~~sales was $7159.35 million ~~reflecting~~in the ~~impact~~three ofmonths ~~the~~ended ~~$22.7~~December ~~million~~31, ~~reduction~~2018 incompared ~~revenues~~with ~~resulting~~$151.8 ~~from~~million in the ~~previously~~three ~~mentioned~~months ~~PUC~~ended ~~Order.~~December 31, ~~Excluding~~2017, ~~this~~principally ~~reduction,~~reflecting ~~UGI~~higher ~~Utilities~~Gas ~~total~~Utility ~~margin~~cost ~~increased~~of sales ($156.43 million) ~~principally~~and ~~reflecting~~ higher ~~total~~Electric ~~margin from Gas~~ Utility ~~core~~cost ~~market~~of ~~customers~~sales ($111.05 million) ~~and~~from the higher ~~large~~DS ~~firm~~rates ~~delivery~~and ~~service~~slightly ~~total~~higher ~~margin~~distribution ~~($3.1~~system ~~million)~~sales. The ~~increase~~higher in Gas Utility ~~core~~cost ~~market~~of ~~margin~~sales principally reflects, ~~among~~higher ~~other~~cost ~~things,~~of ~~the~~sales ~~higher~~associated ~~core~~with ~~market~~off-system ~~throughput~~sales including capacity releases ($1016.19 million) ~~and~~due in large part to the ~~increase~~previously inmentioned ~~PNG~~impact ~~base~~of ~~rates~~ASC ~~effective~~606 ~~October~~on 20the presentation of capacity release contracts, ~~2017~~and the effects of higher core market volumes ($04.93 million). ~~Electric~~partially ~~Utility~~offset ~~total~~by ~~margin~~lower ~~increased~~average ~~slightly~~retail ~~principally~~core-market ~~reflecting~~PGC ~~the~~rates ~~higher~~($16.3 ~~distribution volumes sold~~million).

UGI Utilities ~~operating~~total ~~income~~margin decreased $~~23.~~8.1 million, ~~principally~~ reflecting ~~the~~lower ~~decrease in~~ total margin from Gas Utility ($79.31 million), ~~higher~~attributable ~~Gas~~to ~~Utility~~the ~~and~~impact ~~Electric~~of ~~Utility~~the ~~operating and administrative expenses (~~$613.95 million), ~~greater~~reduction ~~depreciation~~in ~~and~~revenues ~~amortization~~resulting ~~expense~~from ~~($3.5~~the ~~million)~~TCJA, ~~and~~partially ~~lower~~offset ~~other~~by ~~operating~~higher ~~income~~Electric Utility total margin ($6.1.0 million). ~~The~~Excluding ~~increase~~the reduction in ~~UGI~~Gas ~~Utilities~~Utility ~~operating~~total ~~and~~margin ~~administrative~~resulting ~~expenses~~from ~~principally~~the ~~reflects~~TCJA, ~~higher~~Gas ~~general~~Utility ~~and~~total ~~administrative~~margin ~~costs~~increased ~~including~~$4.4 anmillion ~~increase~~principally inreflecting ~~information~~higher ~~technology~~total ~~(“IT”)~~margin ~~maintenance~~from ~~and~~Gas ~~consulting~~Utility ~~expenses~~core ~~($2.4~~market ~~million),~~customers ~~higher distribution system expenses~~ ($12.71 million), and higher ~~uncollectible~~other ~~accounts~~margin ~~expense~~ ($1.59 million). ~~The~~primarily ~~increase~~reflecting inthe ~~depreciation~~margin ~~and~~impacts ~~amortization~~of ~~expense~~the ~~reflects~~presentation ~~increased~~of ~~distribution~~certain ~~system~~revenues ~~and~~in ITaccordance ~~capital~~with ~~expenditure~~the ~~activity.~~adoption of ASC 606. The ~~decrease~~increase in ~~other~~Electric ~~operating~~Utility ~~income~~margin principally reflects the ~~absence~~increase ~~of $5.8 million of income from an environmental insurance settlement recorded~~ in ~~the~~base ~~prior-year~~rates, ~~three-month~~higher ~~period.~~transmission ~~UGI~~revenue ~~Utilities~~and, ~~income~~to ~~before~~a ~~income~~lesser ~~taxes~~extent, ~~decreased $23.6 million reflecting~~ the ~~decrease~~higher indistribution ~~UGI~~volumes ~~Utilities operating income~~sold.

UGI Utilities operating income decreased $19.8 million, principally reflecting the decrease in total margin ($8.1 million), higher Gas Utility and Electric Utility operating and administrative expenses ($8.3 million), greater depreciation expense ($2.1 million), and higher other operating expense ($1.2 million). The increase in UGI Utilities operating and administrative expenses principally reflects the absence of a favorable payroll tax adjustment recorded in the prior-year period ($2.1 million) and higher general and administrative costs including an increase in uncollectible accounts expense ($1.6 million), higher IT maintenance and consulting expense ($1.2 million), higher contractor and outside services expense ($1.1 million) and higher compensation and benefits expense ($0.9 million). The increase in depreciation expense reflects increased distribution system and IT capital expenditure activity. UGI Utilities income before income taxes decreased $19.6 million principally reflecting the decrease in UGI Utilities operating income.

Interest Expense and Income Taxes

Interest expense in the 2018 three-month period was ~~approximately~~slightly ~~equal~~higher tothan the prior-year period. The higher interest expense reflects higher long-term debt outstanding and higher short-term interest rates on revolver borrowings. The lower ~~statutory~~effective income tax rate in the prior-year period reflects the remeasurement effects on certain of our deferred income tax balances resulting from the enactment of the TCJA, which ~~did~~reduced ~~not~~our ~~have~~2017 athree-month ~~material~~period ~~impact~~income ontax expense, and increased our ~~consolidated~~net income, by $8.1 million. Income tax ~~benefit~~expense ~~for~~in the 2018 three-month ~~months~~period ~~ended~~and ~~June~~the 302017 three-month period reflects U.S. federal income tax rates on pre-tax earnings of 21% and 24.5%, ~~2018~~respectively. See Note 6 to Condensed Consolidated Financial Statements.

As more fully described in Notes 5 and 6 to condensed consolidated financial statements, on May 17, 2018, the PUC issued an Order requiring Pennsylvania utilities, including UGI Gas, CPG and PNG, to establish a regulatory liability for tax benefits that accrued during the period beginning January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate under the TCJA. During the three months ended June 30, 2018, UGI Utilities reduced its combined utility revenues by $22.7 million, and recorded a regulatory liability in an equal amount, to reflect (1) $16.2 million of tax benefits accrued during the period January 1 to June 30, 2018, plus (2) $6.5 million of tax benefits expected to be generated by the future amortization of the regulatory liability. Approximately $14.9 million of the previously mentioned $16.2 million of tax benefits accrued relate to the period January 1, 2018 to March 31, 2018.

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UGI UTILITIES, INC. AND SUBSIDIARIES

2018 nine-month period compared with the 2017 nine-month period

Nine Months Ended June 30,	2018			2017			Increase (Decrease)
(Dollars in millions)
Gas Utility:
Revenues (a)	$	894.5		$	700.8		$	193.7		27.6	%
Total margin (a)(b)	$	453.8		$	412.3		$	41.5		10.1	%
Operating and administrative expenses	$	166.0		$	150.8		$	15.2		10.1	%
Operating income	$	230.5		$	219.7		$	10.8		4.9	%
Income before income taxes	$	199.3		$	190.7		$	8.6		4.5	%
System throughput — bcf
Core market	75.8			65.4			10.4			15.9	%
Total	210.2			194.6			15.6			8.0	%
Heating degree days — % (warmer) than normal (c)	(1.3		)%	(11.3		)%	—			—
Electric Utility:
Revenues	$	71.8		$	67.2		$	4.6		6.8	%
Total margin (b)	$	27.2		$	26.3		$	0.9		3.4	%
Operating and administrative expenses (b)	$	18.3		$	16.2		$	2.1		13.0	%
Operating income	$	4.9		$	6.6		$	(1.7	)	(25.8	)%
Income before income taxes	$	4.0		$	5.2		$	(1.2	)	(23.1	)%
Distribution sales — gwh	747.0			710.5			36.5			5.1	%

(a) In accordance with a PUC Order issued May 17, 2018, Gas Utility’s revenues and total margin for the nine months ended June 30, 2018, were reduced by $24.1 million to record a regulatory liability related to tax savings for the period January 1, 2018 to June 30, 2018 as a result of the TCJA (see Notes 5 and 6 to condensed consolidated financial statements).

(b) Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $3.7 million and $3.5 million during each of the nine months ended June 30, 2018 and 2017, respectively. For financial statement purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from Electric Utility operating expenses presented above).

(c) Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by National Oceanic and Atmospheric Administration for airports located within Gas Utility’s service territory.

Temperatures in Gas Utility’s service territory during the nine months ended June 30, 2018, were 1.3% warmer than normal but 11.3% colder than during the nine months ended June 30, 2017. Gas Utility core market volumes increased 10.4 bcf (15.9%) reflecting, among other things, the effects of the colder weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 15.6 bcf principally reflecting the higher core market volumes and slightly higher large firm delivery service volumes. These increases were partially offset by lower interruptible delivery service volumes. Electric Utility kilowatt-hour sales were 5.1% higher than the prior-year period, principally reflecting the impact of the colder weather on Electric Utility heating-related sales.

UGI Utilities revenues increased $198.3 million reflecting a $193.7 million increase in Gas Utility revenues and higher Electric Utility revenues. In accordance with a PUC Order issued May 17, 2018, during the 2018 nine-month period Gas Utility’s revenues were reduced by $24.1 million, and an associated regulatory liability established, to record tax savings that accrued during the period January 1, 2018 to June 30, 2018 as a result of the TCJA. Excluding the impact of this reduction in revenues, Gas Utility revenues increased $217.8 million principally reflecting an increase in core market revenues ($148.4 million), higher off-system sales revenues ($52.7 million), and higher large firm delivery service revenues ($17.6 million).

The $148.4 million increase in Gas Utility core market revenues principally reflects the effects of the higher core market throughput ($72.1 million), higher average retail core market PGC rates ($64.3 million) and the increase in PNG base rates effective October 20, 2017 ($12.0 million). The increase in Electric Utility revenues principally reflects higher Electric Utility distribution system sales ($4.9 million). UGI Utilities cost of sales was $481.6 million in the nine months ended June 30, 2018 compared with $326.0 million in the nine months ended June 30, 2017, principally reflecting higher Gas Utility cost of sales ($152.1 million) and higher Electric Utility cost of sales ($3.5 million) reflecting the higher electricity sales. The higher Gas Utility cost of sales principally

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reflects higher average retail core market PGC rates ($64.3 million), higher cost of sales associated with Gas Utility off-system sales ($52.7 million), and higher retail core-market volumes ($37.0 million).

UGI Utilities total margin increased $42.4 million principally reflecting higher total margin from Gas Utility core market customers ($53.3 million) and higher large firm delivery service total margin ($11.0 million) partially offset by the previously mentioned impact of a $24.1 million reduction in revenues resulting from the previously mentioned PUC Order. The increase in Gas Utility core market margin principally reflects the higher core market throughput ($42.7 million) and the increase in PNG base rates effective October 20, 2017 ($10.6 million). Electric Utility total margin increased $0.9 million principally reflecting the higher distribution system sales.

UGI Utilities operating income increased $9.0 million, principally reflecting the increase in total margin ($42.4 million) partially offset by higher operating and administrative expenses ($17.3 million), greater depreciation and amortization expense ($9.9 million) associated with increased distribution system and IT capital expenditure activity, and lower other operating income ($6.2 million). The increase in UGI Utilities operating and administrative expenses principally reflects higher uncollectible accounts expense ($8.5 million), higher contractor and outside services expenses ($4.3 million), higher compensation and benefits expenses ($3.5 million) and higher IT maintenance and consulting expenses ($3.2 million). The decrease in other operating income principally reflects the absence of $5.8 million of income from an environmental insurance settlement recorded in the prior-year nine-month period. UGI Utilities income before income taxes increased $7.5 million reflecting the increase in UGI Utilities operating income ($9.0 million) partially offset by slightly higher interest expense.

Interest Expense and Income Taxes

Interest expense in the 2018 nine-month period increased $1.6 million primarily reflecting higher short-term debt interest expense and interest on higher average long-term debt outstanding. Our consolidated income taxes for the nine months ended June 30, 2018, were impacted by the enactment of the TCJA. As previously mentioned, we are subject to a blended federal tax rate of 24.5% for Fiscal 2018. As a result of the TCJA, we adjusted our net federal deferred income tax liabilities to remeasure such tax liabilities at the lower corporate rate and certain of these adjustments reduced our income tax expense, and increased net income by $9.3 million for the nine months ended June 30, 2018. In addition to the adjustment to our federal deferred income tax balances, our income taxes for the nine months ended June 30, 2018, were further reduced by approximately $24.1 million principally reflecting the impact of the lower Fiscal 2018 income tax rate and, to a much lesser extent, the amortization of the excess deferred federal income taxes.

As more fully described in Notes 5 and 6 to condensed consolidated financial statements, on May 17, 2018, the PUC issued an Order requiring Pennsylvania utilities, including UGI Gas, CPG and PNG, to establish a regulatory liability for tax benefits that accrued during the period beginning January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate as a result of the TCJA. During the nine months ended June 30, 2018, UGI Utilities reduced its combined utility revenues by $24.1 million, and recorded a regulatory liability in an equal amount, to reflect (1) $17.1 million of tax benefits accrued during the period January 1 to June 30, 2018, plus (2) $7.0 million of additional tax benefits expected to be generated by the future amortization of the regulatory liability.

FINANCIAL CONDITION AND LIQUIDITY

We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities. Our cash and cash equivalents at ~~June~~December 3031, 2018, totaled $2321.25 million compared to $510.23 million at September 30, ~~2017~~2018.

UGI Utilities’ total debt outstanding at ~~June~~December 3031, 2018, was $~~959~~1,131.06 million, which includes $~~118~~296.50 million of short-term borrowings, compared with total debt outstanding of $~~921.~~1,027.5 million at September 30, ~~2017~~2018, which includes $~~170~~189.05 million of short-term borrowings. Total long-term debt outstanding at ~~June~~December 3031, 2018, comprises $675.0 million of Senior Notes, ana ~~unsecured term loan of $121.9 million, and $40.0 million of Medium-Term Notes, and is net of $4.2 million of unamortized debt issuance costs.~~

On October 31, 2017, UGI Utilities entered into a $125.0 million unsecured variable-rate term loan agreement (the “Term Loan”) with a group of banks. Proceeds from the Term Loan were used to repay revolving credit agreement borrowings and for general corporate purposes. The Term Loan is payable in equal quarterly installments of $1.6 million, commencing March 2018, with the balance of the principal being due and payable in full on October 30, 2022. 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. In July 2018, UGI Utilities entered into pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest 28

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~~rates~~$118.8 onmillion ~~Term~~variable-rate ~~Loan~~term ~~borrowings~~loan, ~~at 3~~$40.~~00% through~~0 ~~July~~million ~~2022.~~of ~~This forward~~Medium-~~starting~~Term ~~interest~~Notes ~~rate~~and ~~swap~~$6.6 ~~commences~~million ~~September~~of ~~30,~~other ~~2019.~~long-term Wedebt, ~~have~~and ~~designated~~is ~~this~~net ~~forward-starting~~of ~~interest~~$4.8 ~~rate~~million ~~swap~~of asunamortized adebt ~~cash~~issuance ~~flow hedge~~costs.

The UGI Utilities ~~has~~Credit Agreement is an unsecured revolving credit agreement ~~(the “UGI Utilities Credit Agreement”)~~ with a group of banks providing for borrowings up to $~~300~~450 million (including a $100 million sublimit for letters of credit). which expires in March 2020. Borrowings under the ~~UGI Utilities~~ Credit Agreement are classified as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. At ~~June~~December 3031, 2018, UGI Utilities’ available borrowing capacity under the UGI Utilities Credit Agreement was $~~179~~152.50 million. During the 2018 and 2017 ~~nine~~three-month periods, average daily short-term borrowings under the UGI Utilities Credit Agreement were $~~150~~250.07 million and $74168.51 million, respectively, and peak short-term borrowings totaled $~~215~~311.0 million and $~~137~~205.0 million, respectively. Peak short-term borrowings typically occur during the heating-season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable, is generally greatest.

Subsequent Event. On February 1, 2019, UGI Utilities issued in a private placement $150 million of 4.55% Senior Notes due February 1, 2049. The 4.55% Senior Notes were issued pursuant to a Note Purchase Agreement dated December 21, 2018, between UGI Utilities and certain note purchasers. The 4.55% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.55% Senior Notes were used to reduce short-term borrowings and for general corporate purposes.

We believe that we have sufficient liquidity in the forms of cash and cash equivalents on hand, cash expected to be generated from Gas Utility and Electric Utility operations, short-term borrowings available under the UGI Utilities Credit Agreement and the ability to refinance long-term debt as it matures to meet our anticipated contractual and projected cash commitments.

Cash Flows

Operating activities. Due to the seasonal nature of UGI Utilities’ businesses, cash flows from ~~our~~ operating activities are generally greatest during the second and third fiscal quarters when customers pay for natural gas and electricity consumed during the peak heating-season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally accounts receivable and inventories, is generally greatest. UGI Utilities uses borrowings under the UGI Utilities Credit Agreement to manage seasonal cash flow needs.

Cash provided by operating activities was $~~255~~15.64 million in the 2018 ~~nine~~three-month period compared to cash ~~provided~~used by operating activities of $~~236~~7.61 million in the prior-year period. Cash flow from operating activities before changes in operating working capital was $~~250~~95.36 million in the 2018 ~~nine~~three-month period, ~~compared~~comparable to the $~~241~~97.96 million recorded in the prior-year period. The higher cash flow from operating activities before changes in operating working capital in the 2018 nine-month period largely reflects the increase in operating results in the 2018 nine-month period. Changes in operating working capital ~~provided~~used $580.31 million of operating cash flow during the 2018 ~~nine~~three-month period compared to $5104.37 million of cash used for changes in working capital during the prior-year period. The ~~higher~~lower net cash ~~provided~~used in the 2018 ~~nine~~three-month period reflects, among other things, higher cash receipts from customers during the ~~effects~~current-year period due to the timing of ~~higher~~sales ~~Gas~~and ~~Utility~~associated ~~deferred~~revenues. ~~fuel~~Sales ~~net~~and ~~overcollections~~associated revenues occurred earlier during the ~~current~~2018 three-~~year~~month period ~~offset~~due into ~~large~~colder ~~part~~late byOctober ~~higher~~and ~~cash~~November ~~used~~weather, compared to ~~fund~~higher ~~changes~~sales and associated revenues recorded later in ~~accounts~~the ~~receivable~~2017 three-month period as a result of extremely cold late December 2017 weather. The ~~increase~~higher cash received from customers in ~~cash~~the ~~used~~current toyear ~~fund~~was ~~changes~~partially inoffset ~~accounts~~by ~~receivable~~net ~~primarily~~refunds ~~reflects~~of ~~the~~PGC ~~higher~~costs, ~~Gas~~compared ~~Utility~~to ~~distribution~~net ~~volumes~~recoveries ~~and~~of ~~higher~~PGC ~~natural~~costs ~~gas~~in ~~prices~~the prior-year period.

Investing activities. Cash used by investing activities was $~~221~~100.34 million in the 2018 ~~nine~~three-month period compared to $~~211~~91.61 million in the 2017 ~~nine~~three-month period. Total cash capital expenditures were $~~217~~98.97 million in the 2018 ~~nine~~three-month period compared with $~~201~~88.97 million recorded in the prior-year period. The increase in cash capital expenditures during the 2018 ~~nine~~three-month period principally reflects ~~expenditures~~higher ~~relating~~IT tocapital aexpenditures ~~new~~associated ~~headquarters~~with ~~building~~an ~~and~~Enterprise ~~higher~~Resource ~~new~~Planning ~~business~~system, ~~capital~~and ~~expenditures,~~higher ~~partially~~main ~~offset~~replacement byand ~~lower~~new ITbusiness capital expenditures.

Financing activities. Cash ~~used~~provided by financing activities was $1698.3 million in the 2018 ~~nine~~three-month period compared with $23100.09 million during the 2017 ~~nine~~three-month period. Financing activity cash flows are primarily the result of net borrowings and repayments under revolving credit agreements, net borrowings and repayments of long-term debt and cash dividends paid to UGI. ~~UGI~~Cash ~~Utilities~~from ~~entered~~financing ~~into~~activities in the prior-year period includes the net proceeds from a $125 million unsecured term loan agreement. ~~during~~The ~~the~~ 2018 ~~nine~~three-month period ~~and~~reflects ~~used the~~ net ~~proceeds principally to reduce revolving~~ credit ~~balances~~agreement ~~and~~borrowings ~~for~~of ~~general corporate purposes~~$106.5 ~~During~~million ~~the~~compared ~~2018~~with ~~nine-month~~net ~~period,~~borrowings ~~UGI~~of ~~Utilities repaid~~ $4011.5 million ofduring ~~maturing~~the ~~Medium~~prior-~~Term~~year ~~Notes and $3~~period.1 ~~million~~Credit ofagreement ~~Term~~borrowings ~~Loan~~were ~~debt.~~lower ~~The~~in ~~2018~~the ~~nine~~prior-~~month~~year period ~~reflects~~as ~~net~~the ~~credit~~prior-period ~~agreement~~financing ~~repayments~~cash offlow ~~$51.5~~benefited ~~million~~from ~~compared~~the ~~with~~previously ~~net~~mentioned ~~repayments of~~ $~~62.5~~125 million ~~during~~issuance ~~the~~of ~~prior-year~~term ~~period~~loan debt. Cash dividends paid during the 2018 ~~nine~~three-month period totaled $455.0 million compared to cash dividends paid of $4015.0 million during the prior-year period.

~~IMPACT OF U.S. TAX REFORM~~29

On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was enacted into law. The significant changes resulting from the law that impact UGI Utilities include a reduction in the U.S. federal income tax rate from 35% to 21% effective January 1, 2018 (resulting in a blended rate of 24.5% for Fiscal 2018) and the elimination of bonus depreciation for regulated utilities.

As a result, in December 2017, we reduced our net deferred income tax liabilities by $223.7 million due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of enactment. Because a significant amount of the reduction

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relates to our regulated utility plant assets, most of the reduction to our deferred income taxes is not being recognized immediately in income tax expense. We have recorded a regulatory liability associated with the excess deferred federal income taxes related to our regulated utility plant assets which is being amortized to income tax expense over the remaining lives of the assets that gave rise to the excess deferred income taxes. The amount of the reduction in our net deferred income tax liabilities resulting from the TCJA that reduced income tax expense totaled $1.1 million and $9.3 million for the three and nine months ended June 30, 2018, respectively.

In addition to the adjustments to our net deferred income tax liabilities that reduced our income tax expense as noted above, our income taxes for the three and nine months ended June 30, 2018, were further reduced by approximately $0.8 million and $24.1 million, respectively. These reductions principally reflect the impact of the lower blended income tax rate of 24.5% and, to a much lesser extent, the amortization of the excess deferred federal income taxes.

On May 17, 2018, the PUC issued an Order requiring Pennsylvania utilities, including UGI Gas, CPG and PNG, to establish a regulatory liability for tax benefits that accrued during the period beginning January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate as a result of the TCJA. During the nine months ended June 30, 2018, UGI Utilities reduced its combined utility revenues by $24.1 million, and recorded a regulatory liability in an equal amount, to reflect (1) $17.1 million of tax benefits accrued during the period January 1 to June 30, 2018, plus (2) $7.0 million of tax benefits expected to be generated by the future amortization of the regulatory liability.

For further information on the impacts of U.S. tax reform, see Note 5 and Note 6 to the condensed consolidated financial statements.

REGULATORY MATTERS

~~Base~~Utility ~~Rate Filings~~Merger. On ~~January 26~~March 8, 2018 and March 13, ~~Electric~~2018, ~~Utility~~UGI Utilities filed amerger ~~rate~~authorization ~~request~~requests with the ~~PUC~~PAPUC toand ~~increase~~MDPSC, ~~its annual base distribution revenues by $9.2 million~~respectively, ~~which~~to ~~was~~merge ~~later~~PNG ~~reduced~~and byCPG ~~the~~into ~~Company~~UGI toUtilities, ~~$7.7~~with ~~million~~a totargeted ~~reflect~~effective ~~the~~date ~~impact~~ of ~~the~~October ~~TCJA~~1, ~~and other adjustments~~2018. ~~The~~After ~~increased~~receiving ~~revenues~~all ~~would~~necessary ~~fund~~FERC, ~~ongoing~~MDPSC, ~~system improvements~~ and ~~operations~~PAPUC ~~necessary~~approvals, toCPG ~~maintain safe~~ and ~~reliable~~PNG ~~electric~~were ~~service.~~merged ~~Electric~~into ~~Utility~~UGI ~~requested~~Utilities ~~that the new electric rates become~~ effective ~~March~~October 271, 2018. ~~The~~ ~~PUC~~Consistent ~~entered~~with anthe ~~Order~~MDPSC ~~dated~~order ~~March~~issued 1July 25, 2018, ~~suspending~~and the ~~effective~~PAPUC ~~date~~order ~~for~~issued ~~the~~September, ~~rate~~26, ~~increase~~2018, tothe ~~allow~~former ~~for~~CPG, ~~investigation~~PNG and ~~public~~UGI ~~hearings~~Utilities, inInc. aGas ~~review~~Division ~~process~~service ~~that~~territories isbecame ~~expected to last up to nine months from~~ the ~~date~~UGI ofCentral, ~~filing. The~~UGI ~~matter~~North isand ~~currently~~UGI ~~pending~~South ~~before~~rate ~~two~~districts ~~PUC~~of ~~administrative~~the ~~law~~UGI ~~judges~~Utilities, ~~who~~Inc. ~~are~~Gas ~~expected~~Division, torespectively, ~~issue~~without aany ~~recommended~~ratemaking ~~decision~~change. ~~that~~UGI ~~will~~Utilities’ beobligations under the ~~subject~~settlement ofapproved ~~a final decision~~ by the ~~PUC. Although~~PAPUC ~~the~~include ~~Company~~various ~~expects~~non-monetary toconditions ~~receive~~requiring aUGI ~~final~~Utilities ~~decision~~to ~~from~~maintain ~~the~~separate ~~PUC~~accounting-type inschedules ~~October~~for ~~2018,~~limited ~~the~~future ~~Company~~ratemaking ~~cannot predict the timing or the ultimate outcome of the rate case review process~~purposes.

OnBase ~~August~~Rate 31Filings. On January 28, ~~2017~~2019, ~~the~~UGI ~~PUC~~Gas ~~approved~~filed a ~~previously~~request ~~filed~~with ~~Joint~~the ~~Petition~~PAPUC to increase its operating revenues for ~~Approval~~residential, ofcommercial ~~Settlement~~and industrial customers by $71.1 million annually. The requested rate increase applies to the consolidated UGI Central, UGI North and UGI South rate districts. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Additionally, UGI Gas has proposed a 4.5% negative surcharge applicable to all ~~issues~~customer ~~providing~~distribution ~~for~~service anbills to return $1126.32 million ~~annual~~of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, inclusive of interest. As proposed, the negative surcharge will become effective for a twelve-month period beginning on the effective date of the new base ~~distribution~~rates. UGI Gas is requesting that the new gas rates become effective March 29, 2019. However, the PAPUC typically suspends the effective date for general base rate ~~increase~~proceedings for ~~PNG~~a period not to exceed nine months after the filing date to allow for investigation and public hearings. The ~~increase~~Company ~~became~~cannot ~~effective~~predict onthe ~~October~~timing ~~20,~~or ~~2017~~the ultimate outcome of the rate case review process.

On ~~October 14~~January 26, ~~2016~~2018, ~~the~~Electric ~~PUC~~Utility ~~approved~~filed a ~~previously~~rate ~~filed~~request ~~Joint~~with ~~Petition~~the ~~for~~PAPUC ~~Approval~~to ofincrease ~~Settlement~~its annual base distribution revenues by $9.2 million, which was later reduced by the Company to $7.7 million to reflect the impact of ~~all~~the ~~issues~~TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $273.02 million annual base distribution rate increase for ~~UGI~~Electric ~~Gas~~Utility, effective October 27, 2018. ~~The~~ ~~increase~~As ~~became~~part ~~effective~~of onthe ~~October~~final 19order, ~~2016~~Electric Utility provided customers with a one-time $0.2 million billing credit associated with 2018 TCJA tax benefits. On November 26, 2018, the Pennsylvania Office of Consumer Advocate filed an appeal to the Pennsylvania Commonwealth Court challenging the PAPUC’s acceptance of the Company’s use of a fully projected future test year and handling of consolidated federal income tax benefits. The Company cannot predict the ultimate outcome of this appeal.

~~Distribution~~Manor ~~System~~Township, ~~Improvement~~Pennsylvania ~~Charge~~Natural Gas Incident Complaint. ~~State~~In ~~legislation~~connection ~~permits~~with ~~gas~~a ~~and~~July ~~electric~~2, ~~utilities~~2017, explosion in Manor Township, Lancaster County, Pennsylvania, that resulted in the death of one Company employee and injuries to ~~recover~~two aCompany ~~distribution~~employees ~~system~~and ~~improvement~~one ~~charge~~sewer ~~(“DSIC”)~~authority onemployee, ~~eligible~~and ~~capital~~destroyed ~~investments~~two asresidences anand ~~alternative~~damaged ~~ratemaking~~several ~~mechanism~~other ~~providing~~homes, ~~for~~the BIE filed a ~~more-timely~~formal ~~cost~~complaint ~~recovery~~at the PAPUC in which BIE alleged that the Company committed multiple violations of ~~qualifying~~federal ~~capital~~and ~~expenditures~~state ~~between~~gas ~~base~~pipeline ~~rate~~regulations ~~cases~~in connection with its emergency response leading up to the explosion, and it requested that the PAPUC order the Company to pay approximately $2.1 million in civil penalties, which is the maximum allowable fine. On November 16, 2018, the Company filed its formal written answer contesting the BIE complaint. The matter remains pending before the PAPUC.

PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In May 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing. PNG’s DSIC has been reset to zero as a result of its most recent base rate case. The DSIC rate for PNG will resume upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its most recent base rate case.30

In November 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas began recovering revenue under the mechanism effective July 1, 2018, for the amount of DSIC-eligible plant placed into service as it exceeded the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case during the third quarter of Fiscal 2018.

Utilities Merger Request. On March 8, 2018 and March 13, 2018, the Company filed merger authorization requests with the PUC and MD PSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. There are no expected changes to annual base distribution rates for the combined utilities or to existing regulatory assets and liabilities as a result of the proposed merger. On July 20, 2018, the Company filed a Joint Petition for Settlement among the parties to the

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proceeding for approval by two administrative law judges by recommended decision that will be the subject of a final decision by the PUC. On July 25, 2018, the MD PSC issued an order approving the Company’s merger request. The Company cannot predict the timing or the ultimate outcome of the PUC review of the merger request. On August 3, 2018, FERC approved requests made by CPG, PNG, and UGI Utilities in May 2018 relating to the transfer of certain FERC authorizations from PNG and CPG to UGI Utilities, to ensure continuity of certain interstate gas transportation services currently conducted by CPG and PNG after the effective date of the proposed merger. With the receipt of these FERC approvals, the approval of an application to transfer CPG’s service territory designation to UGI Utilities remains the only FERC approval yet to be received in connection with the proposed merger.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk exposures are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.

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 its retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments, including natural gas futures and option contracts traded on the NYMEX, to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At ~~June~~December 31, 2018, Gas Utility had $3.3 million of restricted cash in brokerage accounts. At December 3031, 2018, the fair values of our natural gas futures and option contracts were not material.

Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of ~~FTRs and~~ forward electricity purchase contracts, associated with our Electric Utility operations. At ~~June~~December 3031, 2018, all of our Electric Utility’s forward electricity purchase contracts were subject to the NPNS exception. ~~At June 30, 2018, Electric Utility did not have any FTR contracts.~~

In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures contracts are recorded at fair value with changes in fair value reflected in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income. The amount of unrealized ~~gains~~losses on these contracts and associated volumes under contract at ~~June~~December 3031, 2018 were not material.

Interest Rate Risk

Our variable-rate debt at ~~June~~December 3031, 2018, includes short-term borrowings and ~~our~~a variable-rate ~~Term~~term ~~Loan~~loan. These debt agreements have interest rates that are generally indexed to short-term market interest rates. At ~~June~~December 3031, 2018, combined borrowings outstanding under these variable-rate debt agreements totaled $~~240~~414.48 million.

~~As previously mentioned, in October 2017,~~ UGI Utilities’ ~~entered into the $125 million~~ variable -rate ~~Term~~term ~~Loan. Under~~loan ~~the~~has ~~Term~~an ~~Loan,~~interest ~~UGI~~rate ~~Utilities~~that ~~may~~is ~~borrow~~indexed atto ~~various~~short-term ~~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~~. In~~ ~~July~~has ~~2018,~~entered ~~UGI~~into ~~Utilities~~a ~~entered~~forward ~~into~~starting, amortizing, pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on ~~Term~~the ~~Loan~~variable-rate ~~borrowings~~term loan at 3.00% beginning September 30, 2019 through July 2022. ~~This~~We have designated this forward-starting interest rate swap ~~commences~~as ~~September~~a ~~30,~~cash ~~2019~~flow hedge. WeAt ~~have~~December 31, ~~designated~~2018, ~~this~~the ~~forward-starting~~fair value of this interest rate swap aswas a ~~cash~~loss ~~flow~~of ~~hedge~~$1.7 million. A 50 basis point adverse change in the one-month LIBOR would result in a decrease in fair value of approximately $1.5 million.

In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate debt, from time to time we enter into IRPAs. There were no unsettled IRPAs outstanding at ~~June~~December 3031, 2018.

ITEM 4. CONTROLS AND PROCEDURES


(a)	Evaluation of Disclosure Controls and Procedures

The Company’s disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed or submitted under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were effective at the reasonable assurance level.

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(b)	Change in Internal Control over Financial Reporting

No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II OTHER INFORMATION

ITEM 1A. RISK FACTORS

In addition to the information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2018 Annual Report ~~on Form 10-K for the fiscal year ended September 30~~, ~~2017,~~ which could materially affect our business, financial condition or future results. The risks described in our 2018 Annual Report ~~on Form 10-K~~ are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

ITEM 6. EXHIBITS

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and last date of the period for which it was filed, and the exhibit number in such filing):

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
12.1	Computation of ratio of earnings to fixed charges
4.1	Form of Note Purchase Agreement dated December 21, 2018 between the Company and the purchasers listed as signatories thereto.	Utilities	Form 8-K (12/21/18)	4.1
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2018, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
10.1	Form of Change in Control Agreement between UGI Utilities, Inc. and Mr. Robert Beard.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2018, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2018, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2018, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2018, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2018, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

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EXHIBIT INDEX

12.1	Computation of ratio of earnings to fixed charges.
10.1	Form of Change in Control Agreement between UGI Utilities, Inc. and Mr. Robert Beard.
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended ~~June~~December 3031, 2018, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended ~~June~~December 3031, 2018, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended ~~June~~December 3031, 2018, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		UGI Utilities, Inc.(Registrant)
Date:	~~August~~February 7, ~~2018~~2019	By:	/s/ Daniel J. Platt
			Daniel J. PlattVice President - Finance andChief Financial Officer
Date:	~~August~~February 7, ~~2018~~2019	By:	/s/ Megan Mattern
			Megan MatternController & Principal Accounting Officer

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