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 ~~December~~March 31, ~~2018~~2019



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.)

One UGI Drive, Denver, PA 17517

(Address of principal executive offices) (Zip Code)

(610) 796-3400

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

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 ~~January~~April 3130, 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 December 31, 2018, September 30, 2018 and December 31, 2017	3
Condensed Consolidated Balance Sheets as of March 31, 2019, September 30, 2018 and March 31, 2018	3
Condensed Consolidated Statements of Income for the three months ended December 31, 2018 and 2017	4
Condensed Consolidated Statements of Income for the three and six months ended March 31, 2019 and 2018	4
Condensed Consolidated Statements of Comprehensive Income for the three months ended December 31, 2018 and 2017	5
Condensed Consolidated Statements of Comprehensive Income for the three and six months ended March 31, 2019 and 2018	5
Condensed Consolidated Statements of Cash Flows for the three months ended December 31, 2018 and 2017	6
Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 2019 and 2018	6
Condensed Consolidated Statements of Stockholder’s Equity	7
Condensed Consolidated Statements of Stockholder’s Equity for the three and six months ended March 31, 2019 and 2018	7
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2628
Item 3. Quantitative and Qualitative Disclosures About Market Risk	3135
Item 4. Controls and Procedures	3135
Part II Other Information
Item 1A. Risk Factors	3337
Item 6. Exhibits	3337
Signatures	3539

- 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 and affiliate of UGI Utilities

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, parent company of UGI Utilities

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~~six-month period - ~~Three~~Six-month period ended ~~December~~March 31, 2018

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

2019 six-month period - Six-month period ended March 31, 2019

2019 three-month period - Three-month period ended March 31, 2019

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)

	December 31, 2018			September 30, 2018			December 31, 2017
	March 31, 2019			September 30, 2018			March 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	2141,~~515~~421		$	10,314		$	74,~~289~~710
Restricted cash	~~3,308~~837			1,190			31,~~665~~572
Accounts receivable (less allowances for doubtful accounts of $11,694, $9,760 and $6,398, respectively)	117,418			71,507			105,141
Accounts receivable (less allowances for doubtful accounts of $16,205, $9,760 and $15,582, respectively)	156,634			71,507			169,555
Accounts receivable — related parties	~~498~~1,999			2,273			1,~~406~~564
Accrued utility revenues	6452,~~694~~068			13,977			9562,~~854~~343
Inventories	5019,~~798~~942			52,413			4919,717
Prepaid income taxes	~~43,060~~536			53,857			~~1,977~~41
Regulatory assets	31,~~267~~343			7,475			~~605~~2,942
Derivative instruments	1,~~070~~047			3,004			~~678~~1,014
Prepaid expenses	125,~~251~~883			9,006			108,~~402~~746
Other current assets	1210,~~909~~692			8,003			1211,~~664~~451
Total current assets	~~330~~292,~~788~~402			233,019			~~289~~283,~~398~~655
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
Property, plant and equipment, at cost (less accumulated depreciation of $1,101,798, $1,074,521 and $1,038,824, respectively)	2,646,983			2,541,768			2,363,373
Goodwill	182,145			182,145			182,145
Regulatory assets	~~295~~298,~~496~~026			293,527			~~362~~358,~~237~~696
Other assets	18,~~798~~881			16,117			1316,~~249~~176
Total assets	$	3,~~424~~438,~~773~~437		$	3,266,576		$	3,~~174~~204,~~693~~045
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	8,~~786~~546		$	9,001		$	~~144~~6,~~374~~250
Short-term borrowings	~~296~~105,000			189,500			~~181~~135,~~500~~000
Accounts payable	9374,~~157~~833			87,861			6959,~~697~~870
Accounts payable — related parties	258,~~063~~881			9,585			1311,~~420~~188
Regulatory liabilities	2636,~~994~~558			40,131			1741,~~091~~154
Derivative instruments	467			—			2,244
Other current liabilities	107,722			114,256			126,643
Other current liabilities	104,466			114,256			106,177
Total current liabilities	341,540			450,334			380,105
Total current liabilities	554,933			450,334			534,503
Long-term debt	974,779			828,995			827,878
Long-term debt	826,844			828,995			711,242
Deferred income taxes	423,377			400,939			339,008
Deferred income taxes	414,470			400,939			340,772
Pension and postretirement benefit obligations	75,626			81,590			136,687
Pension and postretirement benefit obligations	81,072			81,590			140,224
Regulatory liabilities	342,966			350,044			339,567
Regulatory liabilities	346,474			350,044			340,391
Other noncurrent liabilities	68,354			61,386			63,784
Other noncurrent liabilities	67,176			61,386			65,540
Total liabilities	2,226,642			2,173,288			2,087,029
Total liabilities	2,290,969			2,173,288			2,132,672
Commitments and contingencies (Note 9)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)	60,259			60,259			60,259
Additional paid-in capital	473,580			473,580			473,580
Retained earnings	~~626~~704,~~191~~051			579,778			~~534~~608,~~161~~344
Accumulated other comprehensive loss	(26,~~226~~095		)	(20,329		)	(25,~~979~~167		)
Total common stockholder’s equity	1,~~133~~211,~~804~~795			1,093,288			1,~~042~~117,~~021~~016
Total liabilities and stockholder’s equity	$	3,~~424~~438,~~773~~437		$	3,266,576		$	3,~~174~~204,~~693~~045

See accompanying notes to condensed consolidated financial statements.

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended						Six Months Ended
	December 31,
	March 31,						March 31,
	2018			2017
	2019			2018			2019			2018
Revenues	$	~~322~~429,~~725~~592		$	~~323~~483,~~105~~261		$	752,317		$	806,366
Costs and expenses:
Cost of sales — gas and purchased power (excluding depreciation shown below)	~~159~~217,~~519~~976			~~151~~257,~~774~~302			377,495			409,076
Operating and administrative expenses	5863,~~940~~932			5166,~~409~~410			122,872			117,819
Operating and administrative expenses — related parties	35,~~512~~198			23,~~689~~766			8,710			6,455
Depreciation	22,~~474~~341			2021,~~354~~158			44,815			41,512
Other operating expense, net	1,206			9
Other operating expense (income), net	279			(1,146		)	1,485			(1,137		)
	245,651			226,235
	309,726			347,490			555,377			573,725
Operating income	77119,~~074~~866			96135,~~870~~771			196,940			232,641
Pension and other postretirement plans non-service income (expense)	~~412~~395			(~~575~~644		)	807			(1,219		)
Interest expense	(1112,~~738~~231		)	(1011,~~939~~091		)	(23,969		)	(22,030		)
Income before income taxes	65108,~~748~~030			85124,~~356~~036			173,778			209,392
Income tax expense	(1525,~~860~~170		)	(1734,~~053~~852		)	(41,030		)	(51,905		)
Net income	$	4982,~~888~~860		$	6889,~~303~~184		$	132,748		$	157,487

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended					Six Months Ended
	December 31,
	March 31,					March 31,
	2018			2017
	2019			2018		2019			2018
Net income	$	4982,~~888~~860		$	6889,~~303~~184	$	132,748		$	157,487
Other comprehensive income (loss):
Net losses on derivative instruments (net of tax of $487 and $0, respectively)	(1,198		)	—
Net losses on derivative instruments (net of tax of $252, $0, $739 and $0, respectively)	(621		)	—		(1,819		)	—
Reclassifications of net losses on derivative instruments (net of tax of $(252) and $(279), respectively)	620			592
Reclassifications of net losses on derivative instruments (net of tax of $(251), $(280), $(503) and $(559), respectively)	619			592		1,239			1,184
Reclassifications of benefit plans actuarial losses and net prior service benefits (net of tax of $(54) and $(104), respectively)	132			220
Reclassifications of benefit plan actuarial losses and net prior service benefits (net of tax of $(54), $(104), $(108) and $(208), respectively)	133			220		265			440
Other comprehensive (loss) income	(446		)	812
Other comprehensive income (loss)	131			812		(315		)	1,624
Comprehensive income	$	4982,~~442~~991		$	6989,~~115~~996	$	132,433		$	159,111

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Thousands of dollars)

	Three Months Ended
	Six Months Ended
	December 31,
	March 31,
	2018			2017
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	49132,~~888~~748		$	68157,~~303~~487
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	2244,~~474~~815			2041,~~354~~512
Deferred income taxes, net	6,721			4,328
Deferred income tax expense (benefit), net	6,966			(1,619		)
Provision for uncollectible accounts	511,~~029~~078			313,~~459~~142
Other, net	113,~~451~~881			~~1,161~~(345		)
Net change in:
Accounts receivable and accrued utility revenues	(99134,~~882~~022		)	(~~136~~176,~~036~~795		)
Inventories	132,~~615~~471			333,592
Deferred fuel and power costs, net of changes in unsettled derivatives	(1216,~~501~~951		)	1131,~~572~~481
Accounts payable	4216,~~936~~252			2117,~~655~~302
Other current assets	(859,~~150~~962		)	(63,~~661~~791		)
Other current liabilities	(43,~~142~~764		)	123,~~172~~090
Net cash provided (used) by operating activities	15,439			(7,101		)
Net cash provided by operating activities	160,964			135,056
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(98177,~~717~~338		)	(88151,~~686~~468		)
Net costs of property, plant and equipment disposals	(12,~~691~~769		)	(23,~~382~~397		)
Net cash used by investing activities	(~~100~~180,~~408~~107		)	(91154,~~068~~865		)
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of dividends	(510,000		)	(1530,000		)
Increase in short-term borrowings	106,500			11,500
Decrease in short-term borrowings	(84,500		)	(35,000		)
Issuances of long-term debt, net of issuance costs	—149,211			124,~~374~~404
Repayments of long-term debt	(24,~~433~~814		)	(2041,~~000~~562		)
Other	(779		)	—
Net cash provided by financing activities	49,897			17,842
Net cash provided by financing activities	98,288			100,874
Cash, cash equivalents and restricted cash increase (decrease)	$	30,754		$	(1,967	)
Cash, cash equivalents and restricted cash increase	$	13,319		$	2,705
CASH AND CASH EQUIVALENTS
Cash, cash equivalents and restricted cash at end of period	$	2442,~~823~~258		$	106,~~954~~282
Cash, cash equivalents and restricted cash at beginning of period	11,504			8,249
Cash, cash equivalents and restricted cash increase	$	13,319		$	2,705
Cash, cash equivalents and restricted cash increase (decrease)	$	30,754		$	(1,967	)

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(unaudited)

(Thousands of dollars)

	Three Months EndedDecember 31,
	Three Months Ended						Six Months Ended
	2018			2017
	March 31,						March 31,
Common stock, $2.25 par value
	2019			2018			2019			2018
Balance, beginning of period	$	60,259		$	60,259
Common stock, $2.25 par value
Balance, end of period	$	60,259		$	60,259
Balance, beginning of period	$	60,259		$	60,259		$	60,259		$	60,259
Retained earnings
Balance, end of period	$	60,259		$	60,259		$	60,259		$	60,259
Balance, beginning of period	$	579,778		$	480,858
Retained earnings
Cumulative effect of change in accounting principle - ASC 606	(3,926		)	—
Balance, beginning of period	$	626,191		$	534,160		$	579,778		$	480,857
Reclassification of stranded income tax effects related to TCJA	5,451			—
Cumulative effect of change in accounting principle - ASC 606	—			—			(3,926		)	—
Net income	49,888			68,303
Reclassification of stranded income tax effects related to TCJA	—			—			5,451			—
Cash dividends — Common Stock	(5,000		)	(15,000		)
Net income	82,860			89,184			132,748			157,487
Balance, end of period	$	626,191		$	534,161
Cash dividends — Common Stock	(5,000		)	(15,000		)	(10,000		)	(30,000		)
Additional paid-in capital
Balance, end of period	$	704,051		$	608,344		$	704,051		$	608,344
Balance, beginning of period	$	473,580		$	473,580
Additional paid-in capital
Balance, end of period	$	473,580		$	473,580
Balance, beginning of period	$	473,580		$	473,580		$	473,580		$	473,580
Accumulated other comprehensive income (loss)
Balance, end of period	$	473,580		$	473,580		$	473,580		$	473,580
Balance, beginning of period	$	(20,329	)	$	(26,791	)
Accumulated other comprehensive income (loss)
Reclassification of stranded income tax effects related to TCJA	(5,451		)	—
Balance, beginning of period	$	(26,226	)	$	(25,979	)	$	(20,329	)	$	(26,791	)
Net losses on derivative instruments	(1,198		)	—
Reclassification of stranded income tax effects related to TCJA	—			—			(5,451		)	—
Reclassifications of net losses on derivative instruments	620			592
Net losses on derivative instruments	(621		)	—			(1,819		)	—
Reclassifications of benefit plans actuarial losses and net prior service credits	132			220
Reclassifications of net losses on derivative instruments	619			592			1,239			1,184
Balance, end of period	$	(26,226	)	$	(25,979	)
Reclassifications of benefit plans actuarial losses and net prior service credits	133			220			265			440
Total UGI Utilities, Inc. stockholder’s equity	$	1,133,804		$	1,042,021
Balance, end of period	$	(26,095	)	$	(25,167	)	$	(26,095	)	$	(25,167	)
Total UGI Utilities common stockholder's equity	$	1,211,795		$	1,117,016		$	1,211,795		$	1,117,016

See accompanying notes to condensed consolidated financial statements.

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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 owns and operates Gas Utility, a natural gas distribution utility business in eastern and central Pennsylvania and in a portion of one Maryland county directly and, prior to the Utility Merger on October 1, 2018, through PNG and CPG. Gas Utility is subject to regulation by the PAPUC and the FERC and, with respect to a small service territory in one Maryland county, the MDPSC. UGI Utilities also owns and operates Electric Utility, an electric distribution utility located in northeastern Pennsylvania. Electric Utility is subject to regulation by the PAPUC and the FERC.

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation. Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries. We eliminate intercompany accounts when we consolidate.

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the SEC. They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2018, Condensed Consolidated Balance Sheet was derived from audited financial statements but does not include all disclosures required by GAAP.

These financial statements should be read in conjunction with the Company’s 2018 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Revenue Recognition. Effective October 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,” which, as amended, is included in ASC 606. This new accounting guidance supersedes previous revenue recognition requirements in ASC 605. ASC 606 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reported in accordance with ASC 605. The Company recorded a $3,926 reduction to opening retained earnings as of October 1, 2018, to reflect the cumulative effect of ASC 606 on certain contracts not complete as of the date of adoption. Although the adoption of ASC 606 did not, and is not expected to, have a material impact on the amount or timing of our revenue recognition and on our consolidated net income, cash flows or financial position, beginning October 1, 2018, certain performance obligations primarily associated with the release of capacity contracts are reflected on a gross, rather than net, basis and revenues from certain other negotiated rate contracts are reflected on a straight-line basis over the length of the contract, rather than as invoiced. The amount of revenues reflected on a gross, rather than net, basis for the three and six months ended ~~December~~ March 31, ~~2018~~2019, was approximately $1517,000 and $32,000, respectively, with no impact on net income.

Certain revenues such as revenue from leases, financial instruments and other revenues are not within the scope of ASC 606 because they are not from contracts with customers. Such revenues, if any, are accounted for in accordance with other GAAP. Revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, are not included in revenues. Electric Utility’s gross receipts taxes are presented on a gross basis. The Company has elected to use the practical expedient to expense the costs to obtain contracts when incurred as such amounts are generally not material.

See Note 4 for ~~the~~ additional disclosures regarding the Company’s revenue from contracts with customers.

Restricted Cash. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. Upon adoption of revised accounting guidance in October 2018 (see Note 3), changes in restricted cash is ~~included~~no ~~within~~longer ~~the~~reflected ~~Company’s~~as ~~Condensed~~a ~~Consolidated~~separate ~~Statements~~investing ofactivity ~~Cash~~but ~~Flows,~~included ~~with changes~~ in ~~the~~cash, ~~balance~~cash noequivalents ~~longer~~and ~~reflected~~restricted ascash awhen ~~separate~~reconciling ~~investing~~the ~~activity. The~~beginning ~~retrospective~~and ~~application~~end of ~~the~~period ~~new~~total ~~guidance~~amounts onin ~~cash~~the ~~flows~~Company’s ~~from~~Condensed ~~investing~~Consolidated ~~activities~~Statements ~~for~~of ~~the~~Cash ~~three~~Flows. ~~months~~The ~~ended~~guidance ~~December~~required ~~31,~~retrospective ~~2017~~application, which resulted in ~~the~~adjustments ~~elimination~~to of the ~~item~~previously ~~“Increase~~reported incash ~~restricted~~flows ~~cash,”~~from ~~which~~investing ~~had~~activities ~~previously~~for ~~been~~the ~~reported~~six asmonths aended ~~use~~March 31, of2018, increasing net cash ofused by investing activities by $~~619~~1,474.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Company’s Condensed Consolidated Balance Sheets to the corresponding amounts reported on the Condensed Consolidated Statements of Cash Flows:.

	Cash, Cash Equivalents and Restricted Cash
	December 31, 2018		December 31, 2017		September 30, 2018		September 30, 2017
	March 31, 2019		March 31, 2018		September 30, 2018		September 30, 2017
Cash and cash equivalents	$	2141,~~515~~421	$	74,~~289~~710	$	10,314	$	5,203
Restricted cash	~~3,308~~837		31,~~665~~572		1,190		3,046
Cash, cash equivalents and restricted cash	$	2442,~~823~~258	$	106,~~954~~282	$	11,504	$	8,249

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

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

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

Income Taxes. Our results for the three and six-months ended March 31, 2018 were significantly affected by the enactment of the TCJA. For additional information regarding the effects of the TCJA and associated regulatory effects, see Notes 6 and 7.

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

Reclassifications. Certain amounts for the three and six months ended ~~December~~ March 31, ~~2017~~2018, have been reclassified as a result of the adoption of revised accounting guidance pertaining to certain net periodic pension and other postretirement benefit costs and restricted cash (see Note 3). In addition, certain other prior-period amounts have been reclassified to conform to the current-period presentation.

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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Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

related to the capitalized implementation costs in the same income statement line as the hosting service fees; to classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments for hosting service fees; and to present the capitalized implementation costs in the balance sheet in the same line item in which prepaid hosting service fees are presented. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We adopted this ASU effective October 1, 2018, and applied the guidance prospectively to all implementation costs associated with cloud computing arrangements that are service contracts incurred beginning October 1, 2018. The adoption of the new guidance did not have a material impact on our results of operations for the three and six months ended ~~December~~ March 31, ~~2018~~2019.

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

Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization, when applicable. For entities subject to rate regulation, including UGI Utilities, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability.

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

~~For~~The ~~the three months ended December 31, 2018, the~~ amount of income (expense) comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, presented in "Pension and other postretirement plans non-service income (expense)” on the Condensed Consolidated Statements of Income, totaled $~~412.~~395 ~~For~~and ~~the three months ended December 31~~$807, ~~2017~~respectively, ~~the~~for ~~amount of (expense) comprising~~ the ~~non-service~~three ~~cost components of our pension~~ and ~~postretirement~~six ~~benefit~~months ~~plans,~~ended ~~net of amounts capitalized~~March 31, ~~which~~2019 ~~has been reclassified from "Operating~~ and ~~administrative~~$(644) ~~expenses" to "Pension~~ and ~~other postretirement plans non-service income~~ $(~~expense~~1,219)”, onrespectively, for the ~~Condensed~~three ~~Consolidated~~and ~~Statements~~six ofmonths ~~Income~~ended March 31, ~~totaled $(575)~~2018.

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

Accounting Standards Not Yet Adopted

Pension and Other Postretirement Benefit Costs Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. The amendments in this ASU are effective for interim and annual periods beginning October 1, 2020 (Fiscal 2021). The guidance shall be adopted ~~retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company is in the process~~

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. The amendments in this ASU are effective for annual periods beginning October 1, 2020 (Fiscal 2021). The guidance regarding removing and modifying disclosures will be adopted on a retrospective basis and the guidance regarding new disclosures will be adopted on a prospective basis. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

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

Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption. We will adopt ASU No. 2016-02, as updated, effective October 1, 2019 and expect to adopt the transition option which would allow the Company to maintain historical presentation for periods before October 1, 2019. The Company has completed a preliminary assessment for evaluating the impact of the guidance and anticipates that its adoption will result in a significant amount of right-of-use assets and lease liabilities for leases in effect at the adoption date. The Company has begun implementation activities including accumulating contracts and lease data in formats compatible with a new lease management system that will assist with the initial adoption ofand future reporting required by 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~~ March 31, ~~2018~~2019. All of our receivables are unconditional rights to consideration and are included in “Accounts receivable” and “Accrued utility revenues” on the Condensed Consolidated Balance Sheets. Amounts billed are generally due within the following month.

Contract liabilities arise when payment from a customer is received before the performance obligations have been satisfied and represent the Company’s obligations to transfer goods or services to a customer for which we have received consideration. The ~~balance~~balances of contract liabilities ~~was~~were $6,~~189~~481 and $5,897 at ~~December~~ March 31, ~~2018~~2019 and October 1, 2018, respectively, and are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets. Revenue recognized for the ~~three~~six months ended ~~December~~ March 31, ~~2018~~2019 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 and six months ended ~~December~~ March 31, ~~2018~~2019:

				Reportable Segments
	Three Months EndedMarch 31, 2019								Six Months EndedMarch 31, 2019
	Total			Gas Utility			Electric Utility		Total			Gas Utility			Electric Utility
Revenues from contracts with customers:
Core Market:
Residential	$	~~175~~240,~~691~~316		$	~~158~~220,~~557~~728		$	1719,~~134~~588	$	416,007		$	379,285		$	36,722
Commercial & industrial	67100,~~574~~686			6194,~~375~~412			6,~~199~~274		168,260			155,787			12,473
Large delivery service	3944,~~547~~038			3944,~~547~~038			—		83,585			83,585			—
Off-system sales and capacity releases	3846,~~131~~403			3846,~~131~~403			—		84,534			84,534			—
Other (a)	1(2,~~171~~446		)	(14,~~079~~761		)	2,~~250~~315		(1,275		)	(5,840		)	4,565
Total revenue from contracts with customers	322,114			296,531			25,583
Total revenues from contracts with customers	428,997			400,820			28,177		751,111			697,351			53,760
Other revenues (b)	~~611~~595			~~611~~595			—		1,206			1,206			—
Total revenues	$	~~322~~429,~~725~~592		$	~~297~~401,~~142~~415		$	2528,~~583~~177	$	752,317		$	698,557		$	53,760

(a) Gas Utility includes unallocated negative surcharge revenue of $(410,~~128~~496) and $(14,624) for the three and six months ended March 31, 2019, respectively, as a result of a PAPUC Order issued May 17, 2018, related to the TCJA (see Note 7).


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

Remaining Performance Obligations

The Company has elected to use practical expedients as allowed in ASC 606 to exclude disclosures related to the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied for core market customers and off-system sales and capacity releases as of the end of the reporting period because these contracts have an initial expected term of one year or less. Certain contracts with large delivery service customers contain minimum future performance obligations through 2053. At ~~December~~ March 31, ~~2018~~2019, the Company expects to record approximately $~~197~~195,000 of revenues related to the minimum future performance obligations over the remaining terms of the related contracts.

Note 5 — Inventories

Inventories comprise the following:

	December 31, 2018		September 30, 2018		December 31, 2017
	March 31, 2019		September 30, 2018		March 31, 2018
Gas Utility natural gas	$	343,~~918~~396	$	37,287	$	343,~~587~~459
Materials, supplies and other	1516,~~880~~546		15,126		1516,~~130~~258
Total inventories	$	5019,~~798~~942	$	52,413	$	4919,717

At ~~December~~March 31, ~~2018~~2019, UGI Utilities was a party to five principal SCAAs with terms of up to three years. Four of the SCAAs were with Energy Services (see Note 14) and one of the SCAAs was with a non-affiliate. Pursuant to the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

The carrying values of gas storage inventories released under the SCAAs at December 31, 2018, September 30, 2018 and December 31, 2017, comprising 7.8 bcf, 9.0 bcf and 7.8 bcf of natural gas, were $20,529, $23,136 and $22,191, respectively. At

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

~~December~~The carrying values of gas storage inventories released under the SCAAs at March 31, 2019, September 30, 2018 and March 31, 2018, comprising 0.8 bcf, 9.0 bcf and 0.9 bcf of natural gas, were $2,075, $23,136 and $2,532, respectively. At March 31, 2019, September 30, 2018 and ~~December~~March 31, ~~2017~~2018, UGI Utilities held a total of $11,840, $13,840 and $13,840, respectively, of security deposits received from its SCAA counterparties. These amounts are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets.

For additional information related to the SCAAs with Energy Services, see Note 14.

Note 6 — Income Tax Reform

On December 22, 2017, the TCJA was enacted into law. The significant changes resulting from the law that impacted UGI Utilities include a reduction in the U.S. federal income tax rate from 35% to 21%, effective January 1, 2018 (resulting in a blended rate of 24.5% for Fiscal 2018) and the elimination of bonus depreciation on regulated utility property beginning in Fiscal 2019.

In accordance with GAAP as determined by ASC 740, we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three and six months ended ~~December~~March 31, ~~2017~~2018, contained provisional estimates of the impact of the TCJA. These amounts were considered provisional because they used estimates for which tax returns had not yet been filed and because estimated amounts could have been impacted by future regulatory and accounting guidance if and when issued. We adjusted provisional amounts as further information became available and as we refined our calculations. As permitted by SEC Staff Bulletin No. 118, these adjustments occurred during the reasonable “measurement period” defined as twelve months from the date of enactment. During the three months ended December 31, 2018, adjustments to provisional amounts recorded in prior periods were not material.

As a result of the TCJA, during the three months ended December 31, 2017, we reduced our net deferred income tax liabilities by $223,660 due to the remeasurement of existing federal deferred income tax assets and liabilities from 35% to 21%. Because a significant amount of the reduction related to our regulated utility plant assets, most of the reduction to our deferred income taxes was not recognized immediately in income tax expense. During the ~~three~~six months ended ~~December~~March 31, ~~2017~~2018, the amount of the reduction in deferred income taxes that reduced income tax expense totaled $8,122.

In order for utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred federal income taxes resulting from the remeasurement of deferred income taxes on regulated utility plant be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. AtIn 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 and six months ended ~~December~~March 31, ~~2018~~2019 and ~~2017~~2018, we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rates. We were subject to a blended U.S. federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contained the effective date of the rate change from 35% to 21%. We are subject to a 21% U.S. federal tax rate in Fiscal 2019. As a result, our annual effective tax rates used for the ~~U.S.~~three and six months ended March 31, 2019 were based upon a federal income tax rate ~~included~~of in21%, and our annual effective tax rates used for the three and six months ended ~~December~~March 31, 2018, ~~and 2017~~ were based onupon ~~rates~~a offederal ~~21%~~income ~~and~~tax rate of 24.5%~~, respectively~~. Our estimated annual effective tax rate was not impacted by any regulatory action taken by the PAPUC.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

Note 7 — Regulatory Assets and Liabilities and Regulatory Matters

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

	December 31, 2018		September 30, 2018		December 31, 2017
	March 31, 2019		September 30, 2018		March 31, 2018
Regulatory assets:
Income taxes recoverable	$	~~115~~120,~~204~~279	$	110,129	$	~~126~~128,~~509~~267
Underfunded pension and postretirement plans	8583,~~334~~563		87,106		~~138~~135,~~287~~263
Environmental costs	58,~~461~~758		58,836		6059,~~760~~788
Removal costs, net	3130,~~332~~055		32,025		3130,~~426~~478
Other	86,~~432~~714		12,906		57,~~860~~842
Total regulatory assets	$	~~298~~299,~~763~~369	$	301,002	$	~~362~~361,~~842~~638
Regulatory liabilities:
Postretirement benefits	$	1716,~~315~~914	$	17,781	$	17,~~315~~105
Deferred fuel and power refunds	2217,~~203~~731		36,723		1235,~~658~~278
State tax benefits — distribution system repairs	2324,~~453~~294		22,611		19,~~101~~888
PAPUC temporary rates order	2425,~~766~~098		24,430		—
Excess federal deferred income taxes	~~280~~276,~~940~~659		285,221		~~303~~301,~~901~~151
Other	418,~~791~~828		3,409		47,~~507~~299
Total regulatory liabilities	$	~~373~~379,~~468~~524	$	390,175	$	~~357~~380,~~482~~721

Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of PGC rates in the case of Gas Utility and DS tariffs in the case of Electric Utility. ~~The~~These clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for retail core-market customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel and power costs or refunds. Net unrealized gains ~~(losses)~~ on such contracts at ~~December~~March 31, ~~2018~~2019, September 30, 2018, and ~~December~~March 31, ~~2017~~2018, were $~~837~~1,047, $2,856 and $(1269,~~720),~~ respectively.

PAPUC ~~Temporary~~temporary ~~Rates~~rates ~~Order~~order. On May 17, 2018, the PAPUC ordered each regulated utility currently not in a general base rate case proceeding, including UGI Gas, PNG and CPG, to reduce their rates through the establishment of a negative surcharge applied to bills rendered on or after July 1, 2018. ~~The~~In accordance with the terms of the temporary rates order, the initial temporary negative surcharge ~~will~~was be reconciled at the end of ~~each~~Fiscal ~~fiscal~~2018 ~~year~~ to ~~actual~~reflect ~~tax~~the ~~savings realized. Any~~ difference in the amount of bill credit received by customers and the amount of benefits received by the Company ~~during~~through the ~~period~~fiscal ~~the~~year ~~negative~~end ~~surcharge~~period isand inupdated ~~effect~~negative issurcharges ~~reconciled~~were placed in ~~the~~effect ~~calculation~~on ~~of a new negative surcharge effective~~ January 1, of2019 ~~the~~at ~~subsequent~~rates ~~calendar year. The negative surcharge will remain in place until the effective date~~ of ~~new rates established in the utility’s next general base rate proceeding~~4. ~~For merged Gas Utility, such negative surcharge reduced base rate revenues by 5.78~~71%, 32.9087% and 86.1934%, respectively, for the UGI South, UGI North and UGI Central rate districts ~~for~~(as ~~the~~described ~~three~~below). ~~months~~These ~~ended~~negative ~~December 31,~~surcharges ~~2018~~will ~~and~~remain isin ~~subject~~place tountil ~~reconciliation during~~ the ~~period~~effective ~~the~~date ~~negative~~of ~~surcharges~~new ~~remain~~rates established in ~~effect~~UGI Gas’s current general base rate proceeding filed January 28, 2019.

In its May 17, 2018 Order, the PAPUC also required Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period ~~beginning~~ January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate. The rate treatment of this regulatory liability, ~~plus~~is ~~accrued interest, for each Gas Utility rate district will be~~ addressed in ~~a future proceeding and the Company cannot predict the ultimate treatment of this liability. In~~ UGI Gas’s base rate proceeding filed January 28, 2019 (see “Base Rate Filings” below). In its initial filing, UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $2624,~~249~~029 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, ~~inclusive~~plus applicable interest, thereby satisfying a requirement to make a proposal for distributing those benefits within three years of the May 17, 2018, Order. As

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~~interest~~proposed, ~~thereby satisfying a requirement to make a proposal for distributing those benefits within three years of~~ the ~~May 17, 2018, Order. The~~ negative surcharge ~~will~~would become effective for a twelve-month period beginning on the effective date of the new base rates.

For Pennsylvania utilities that were in a general base rate proceeding, including Electric Utility, no negative surcharge applies. The tax benefits that accrued during the period January 1, 2018 through October 26, 2018, the date before Electric Utility’s base rate case became effective (see below), were refunded to Electric Utility ratepayers through a one-time bill credit.

Excess federal deferred income taxes. This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 6). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess federal deferred income taxes resulting from the remeasurement be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess federal deferred income taxes, ranging from 1 year to approximately 65 years. This regulatory liability has been increased to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes and is being amortized and credited to tax expense.

Other Regulatory Matters

Utility Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and MDPSC, respectively, to merge PNG and CPG into UGI Utilities~~, with a targeted effective date of October 1, 2018~~. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged with and into UGI Utilities, effective October 1, 2018. Consistent with the MDPSC order issued July 25, 2018, and the PAPUC order issued September, 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type schedules for limited future ratemaking purposes.

Base Rate Filings. On January 28, 2019, UGI Gas filed a request with the PAPUC to increase its operating revenues for residential, commercial and industrial customers by $71,090 annually. The requested rate increase applies to the consolidated UGI Central, UGI North and UGI South rate districts. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Additionally, UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $2624,~~249~~029 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, ~~inclusive~~plus ofapplicable interest. As proposed, the negative surcharge ~~will~~would become effective for a twelve-month period beginning on the effective date of the new base rates. UGI Gas isrequested ~~requesting~~ that the new gas rates become effective March 29, 2019. ~~However,~~The ~~the~~ PAPUC ~~typically~~entered ~~suspends~~an Order dated February 28, 2019, suspending the effective date for ~~general~~the ~~base~~ rate ~~proceedings~~increase to allow for investigation and public hearings. Unless a ~~period~~settlement ~~not~~is toreached ~~exceed~~sooner, ~~nine~~this ~~months~~review ~~after~~process ~~the~~is ~~filing~~expected ~~date~~to last up to nine ~~allow~~months ~~for~~from ~~investigation~~the ~~and~~date ~~public~~of ~~hearings~~filing. The Company cannot predict the timing or the ultimate outcome of the rate case review process.

On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution revenues by $9,200, which was later reduced by the Company to $7,700 to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $3,201 annual base distribution rate increase for Electric Utility effective October 27, 2018. As part of the final order, Electric Utility provided customers with a one-time $210 billing credit associated with 2018 TCJA tax benefits. On November 26, 2018, the Pennsylvania Office of Consumer Advocate filed an appeal to the Pennsylvania Commonwealth Court challenging the PAPUC’s acceptance of the Company’s use of a fully projected future test year and handling of consolidated federal income tax benefits. The Company cannot predict the ultimate outcome of this appeal.

On January 19, 2017, PNG (now the UGI North rate district of Gas Utility) filed a rate request with the PAPUC to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21,700 annually. The increased revenues would be used to fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PAPUC providing for an $11,250 PNG annual base distribution rate increase. On August 31, 2017, the PAPUC approved the Joint Petition and the increase became effective on October 20, 2017.

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Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017, explosion in Manor Township, Lancaster County, Pennsylvania, that resulted in the death of one Company employee and injuries to two Company employees and one sewer authority employee, and destroyed two residences and damaged several other homes, the BIE filed a formal complaint at the PAPUC in which BIE alleged that the Company committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion, and it requested that the PAPUC order the Company to pay approximately $2,100 in civil penalties, which is the maximum allowable fine. On November 16, 2018, the Company filed its formal written answer contesting the BIE complaint. The matter remains pending before the PAPUC. See additional discussion in Note 9.

Note 8 — Debt

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

Note 9 — Commitments and Contingencies

Contingencies

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

Prior to the Utility Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, were subject to COAs with the PADEP to address the remediation of specified former MGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the Utility Merger, UGI Utilities, as the successor to CPG and PNG, is required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap (i.e. minimum expenditure threshold). The cost cap of the three COAs, in the aggregate, is $5,350. The three COAs are currently scheduled to terminate at the end of 2031, 2020, and 2020. At ~~December~~March 31, ~~2018~~2019, September 30, 2018 and ~~December~~March 31, ~~2017~~2018, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $50,~~484~~844, $50,970, and $5351,~~409~~941, respectively. UGI Utilities has recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 7).

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

From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that, under applicable law, UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that

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~~significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that~~ UGI Utilities directly operated, or that were owned or operated by a former subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At ~~December~~March 31, ~~2018~~2019, September 30, 2018 and ~~December~~March 31, ~~2017~~2018, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material.

Other Matters

Manor Township, Pennsylvania Natural Gas Explosion. On July 2, 2017, an explosion occurred in Manor Township, Pennsylvania which resulted in the death of one Company employee and injuries to two other Company employees and an employee of the local sewer authority, and significant property damage. The ~~NTSB~~Company has received several claims for property damage and ~~the~~personal ~~BIE~~injuries ~~are~~related ~~investigating~~to the ~~Manor~~explosion ~~Township~~but ~~incident.~~no ~~The~~civil ~~NTSB~~lawsuit ~~investigative~~has ~~team~~been ~~includes~~filed ~~representatives~~to ~~from~~date. On the ~~Company~~regulatory side, ~~the~~on ~~BIE~~February 25, 2019, the ~~local~~NTSB ~~fire~~issued ~~department~~a ~~and~~Pipeline Accident Brief of its investigation into the ~~Pipeline~~incident, ~~and~~in ~~Hazardous~~which ~~Materials~~it ~~Safety~~concluded ~~Administration~~that ~~and~~the explosion resulted from gas that migrated from an incorrectly installed mechanical tapping tee connecting the Company.’s ~~The~~distribution ~~Company~~main ~~continues~~and service line to ~~cooperate~~the ~~with~~home that exploded. In its report, the ~~investigation~~NTSB also restated its four recommendations that it issued in a June 25, 2018 preliminary report concerning the mechanical tapping tee manufacturer’s installation instructions and ~~provide~~the ~~information~~oversight ~~requested~~of mechanical tapping tees by the ~~investigating~~Pipeline ~~parties.~~and ~~The~~Hazardous ~~Occupational~~Materials Safety ~~and~~Administration. With ~~Health~~the ~~Administration~~issuance ~~has~~of ~~closed~~the ~~its~~NTSB ~~investigation~~report, ~~with~~the noone ~~findings.~~remaining ~~The~~regulatory ~~BIE~~matter ~~filed~~arising afrom the incident is the BIE formal complaint atbefore 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 anticipates that third-party claims associated with the explosion, in excess of the Company’s deductible, will be recovered through the Company’s insurance. Although the Company cannot predict the result of these pending or future claims, we believe that claims and expenses associated with the explosion will not have a material impact on our consolidated financial statements.

In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial statements.

Note 10 — Defined Benefit Pension and Other Postretirement Plans

We sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries. Pension Plan benefits are based on years of service, age and employee compensation. We also provide limited postretirement health care benefits to certain retirees and postretirement life insurance benefits to certain active and retired employees.

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

	Pension Benefits						Other Postretirement Benefits
Three Months Ended 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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~~Pension~~Net ~~Plan~~periodic ~~assets~~pension ~~are~~expense ~~held in trust~~ and ~~consist~~other ~~principally~~postretirement ofbenefit ~~publicly~~costs ~~traded,~~include ~~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~~following 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. components:

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 Benefits						Other Postretirement Benefits
Three Months Ended March 31,	2019			2018			2019			2018
Service cost	$	1,638		$	1,881		$	32		$	67
Interest cost	6,051			5,767			109			112
Expected return on assets	(8,140		)	(7,777		)	(184		)	(177		)
Amortization of:
Prior service cost (benefit)	62			63			(109		)	(110		)
Actuarial loss	1,721			2,984			17			24
Net benefit cost (benefit)	1,332			2,918			(135		)	(84		)
Change in associated regulatory liabilities	—			—			(342		)	(123		)
Net benefit cost (benefit) after change in regulatory liabilities	$	1,332		$	2,918		$	(477	)	$	(207	)

	Pension Benefits						Other Postretirement Benefits
Six Months Ended March 31,	2019			2018			2019			2018
Service cost	$	3,275		$	3,762		$	63		$	134
Interest cost	12,101			11,534			218			224
Expected return on assets	(16,280		)	(15,554		)	(369		)	(354		)
Amortization of:
Prior service cost (benefit)	125			126			(218		)	(220		)
Actuarial loss	3,441			5,968			34			48
Net benefit cost (benefit)	2,662			5,836			(272		)	(168		)
Change in associated regulatory liabilities	—			—			(685		)	(246		)
Net benefit cost (benefit) after change in regulatory liabilities	$	2,662		$	5,836		$	(957	)	$	(414	)

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. During the six months ended March 31, 2019 and 2018, the Company made cash contributions to the Pension Plan of $5,000 and $6,720, respectively. The Company expects to make additional cash contributions of approximately $6,500 to the Pension Plan during the remainder of Fiscal 2019.

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.

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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Note 11 — Fair Value Measurements

Derivative Instruments



	Asset (Liability)
	Level 1			Level 2			Level 3		Total
March 31, 2019:
Assets:
Commodity contracts	$	1,258		$	—		$	—	$	1,258
Liabilities:
Commodity contracts	$	(251	)	$	—		$	—	$	(251	)
Interest rate contracts	$	—		$	(2,528	)	$	—	$	(2,528	)
September 30, 2018:
Assets:
Commodity contracts	$	3,154		$	—		$	—	$	3,154
Interest rate contracts	$	—		$	30		$	—	$	30
Liabilities:
Commodity contracts	$	(146	)	$	—		$	—	$	(146	)
March 31, 2018:
Assets:
Commodity contracts	$	1,042		$	9		$	—	$	1,051
Liabilities:
Commodity contracts	$	(582	)	$	(7	)	$	—	$	(589	)

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at ~~December~~March 31, ~~2018~~2019, September 30, 2018 and ~~December~~March 31, ~~2017~~2018 were as follows:

	December 31, 2018		September 30, 2018		December 31, 2017
	March 31, 2019		September 30, 2018		March 31, 2018
Carrying amount	$	~~840~~988,~~461~~080	$	842,130	$	~~860~~838,~~000~~437
Estimated fair value	$	~~829~~1,~~794~~005,920	$	826,470	$	~~909~~871,~~283~~853

Note 12 — Derivative Instruments and Hedging Activities

We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations. For more information on the accounting for our derivative instruments, see Note 2.

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PAPUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses NYMEX natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At 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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market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations. For more information on the accounting for our derivative instruments, see Note 2.

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PAPUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses NYMEX natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At March 31, 2019, September 30, 2018 and March 31, 2018, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.6 million dekatherms, 23.2 million dekatherms and 12.7 million dekatherms, respectively. At March 31, 2019, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 months. Gains and losses on Gas Utility natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 7).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At March 31, 2019, September 30, 2018 and March 31, 2018, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. At March 31, 2019, September 30, 2018 and March 31, 2018, the total volumes associated with gasoline futures contracts were not material.

Interest Rate Risk

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

Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issuances mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into IRPAs. We account for IRPAs as cash flow hedges.

As of ~~December~~March 31, ~~2018~~2019, September 30, 2018 and ~~December~~March 31, ~~2017~~2018, we had no unsettled IRPAs. At ~~December~~March 31, ~~2018~~2019, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3,485.

Derivative Instrument Credit Risk

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At ~~December~~March 31, ~~2018~~2019, September 30, 2018 and ~~December~~March 31, ~~2017~~2018, restricted cash in brokerage accounts totaled $3837,~~308,~~ $1,190 and $31,~~665~~572, respectively.

Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on the Condensed Consolidated Balance Sheets if the right of offset exists. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange or clearinghouse to enter, execute or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions.

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

Offsetting Derivative Assets and Liabilities

Fair Value of Derivative Instruments

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting~~, as of December 31, 2018, September 30, 2018 and December 31, 2017~~:

	December 31, 2018			September 30, 2018			December 31, 2017
	March 31, 2019			September 30, 2018			March 31, 2018
Derivative assets:
Derivatives designated as hedging instruments:
Interest rate contracts	$	—		$	30		$	—
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	1,~~336~~258			3,002			~~450~~860
Derivatives not designated as hedging instruments:
Commodity contracts	—			152			~~247~~191
Total derivative assets — gross	1,~~336~~258			3,184			~~697~~1,051
Gross amounts offset in the balance sheet	(~~266~~211		)	(146		)	(1937		)
Total derivative assets — net (a)	$	1,~~070~~047		$	3,038		$	~~678~~1,014
Derivative liabilities:
Derivatives designated as hedging instruments:
Interest rate contracts	$	(12,~~655~~528	)	$	—		$	—
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	(~~499~~211		)	(146		)	(~~2,263~~589		)
Derivatives not designated as hedging instruments:
Commodity contracts	(~~234~~40		)	—			—
Total derivative liabilities — gross	(2,~~388~~779		)	(146		)	(~~2,263~~589		)
Gross amounts offset in the balance sheet	~~266~~211			146			1937
Total derivative liabilities — net (a)	$	(2,~~122~~568	)	$	—		$	(~~2,244~~552	)

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

Effects of Derivative Instruments

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Condensed Consolidated Statements of Income and changes in AOCI for the three 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
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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Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

Effects of Derivative Instruments



	Loss Recognized in AOCI					Loss Reclassified from AOCI into Income						Location of Loss Reclassified from AOCI into Income
Three Months Ended March 31,	2019			2018		2019			2018			Location of Loss Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	(873	)	$	—	$	(870	)	$	(872	)	Interest expense

	Gain Recognized in Income					Location of Gain Recognized in Income
Three Months Ended March 31,	2019			2018
Derivatives Not Subject to PGC and DS Mechanisms:
Commodity contracts	$	129		$	12	Operating and administrative expenses

	Loss Recognized in AOCI					Loss Reclassified from AOCI into Income						Location of Loss Reclassified from AOCI into Income
Six Months Ended March 31,	2019			2018		2019			2018			Location of Loss Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	(2,558	)	$	—	$	(1,742	)	$	(1,743	)	Interest expense

	(Loss) Gain Recognized in Income					Location of (Loss) Gain Recognized in Income
Six Months Ended March 31,	2019			2018
Derivatives Not Subject to PGC and DS Mechanisms:
Commodity contracts	$	(267	)	$	161	Operating and administrative expenses

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

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

Note 13 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI, net of tax, during the three and six months ended ~~December~~March 31, ~~2018~~2019 and ~~2017~~2018:

Three Months Ended December 31, 2018	Postretirement Benefit Plans			Derivative Instruments			Total
Three Months Ended March 31, 2019	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI — September 30, 2018	$	(4,920	)	$	(15,409	)	$	(20,329	)
Net losses on interest rate contract	—			(1,198		)	(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
Net losses on interest rate contract	—			(621		)	(621		)
AOCI — September 30, 2017	$	(8,995	)	$	(17,796	)	$	(26,791	)
Reclassifications of benefit plan actuarial losses and net prior service benefits	133			—			133
Reclassifications of benefit plans actuarial losses and net prior service credits	220			—			220
Reclassifications of net losses on IRPAs	—			619			619
Reclassifications of net losses on IRPAs	—			592			592
AOCI — March 31, 2019	$	(6,367	)	$	(19,728	)	$	(26,095	)
Three Months Ended March 31, 2018	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI — December 31, 2017	$	(8,775	)	$	(17,204	)	$	(25,979	)
Reclassifications of benefit plan actuarial losses and net prior service benefits	220			—			220
Reclassifications of net losses on IRPAs	—			592			592
AOCI — March 31, 2018	$	(8,555	)	$	(16,612	)	$	(25,167	)



Six Months Ended March 31, 2019	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI — September 30, 2018	$	(4,920	)	$	(15,409	)	$	(20,329	)
Net losses on interest rate contract	—			(1,819		)	(1,819		)
Reclassifications of benefit plan actuarial losses and net prior service benefits	265			—			265
Reclassifications of net losses on IRPAs	—			1,239			1,239
Reclassification of stranded income tax effects related to TCJA	(1,712		)	(3,739		)	(5,451		)
AOCI — March 31, 2019	$	(6,367	)	$	(19,728	)	$	(26,095	)

Six Months Ended March 31, 2018	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI — September 30, 2017	$	(8,995	)	$	(17,796	)	$	(26,791	)
Reclassifications of benefit plan actuarial losses and net prior service benefits	440			—			440
Reclassifications of net losses on IRPAs	—			1,184			1,184
AOCI — March 31, 2018	$	(8,555	)	$	(16,612	)	$	(25,167	)

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~~510 and $1,~~046~~359 during the three months ended ~~December~~March 31, 2019 and 2018, respectively, and ~~2017~~$2,692 and $2,405 during the six months ended March 31, 2019 and 2018, respectively.

UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. At 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 24

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. At March 31, 2019, UGI Utilities was a party to four SCAAs with Energy Services, and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $~~3,101~~168 and $179 during ~~both~~the three months ended ~~December~~March 31, 2019 and 2018, respectively, and ~~2017~~$3,269 and $3,280 during the six months ended March 31, 2019 and 2018, respectively. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. These payments totaled $~~743~~776 and $~~718~~708 during the three months ended ~~December~~March 31, 2019 and 2018, respectively, and ~~2017~~$1,519 and $1,426 during the six months ended March 31, 2019 and 2018, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets, at ~~December~~March 31, ~~2018,~~2019 was $9,040 and at September 30, 2018 and ~~December~~March 31, ~~2017~~2018, ~~were~~was $11,040.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) in “Inventories” on the Condensed Consolidated Balance Sheets. At ~~December~~March 31, ~~2018~~2019, September 30, 2018 and ~~December~~March 31, ~~2017~~2018, the carrying values of these gas storage inventories, comprising approximately 50.98 bcf, 6.7 bcf and 60.19 bcf of natural gas, were $152,~~921~~075, $17,701 and $172,~~043~~532, respectively.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility primarily during the heating-season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three months ended ~~December~~March 31, 2019 and 2018 totaled $54,120 and ~~2017~~$47,366, respectively, and during the six months ended March 31, 2019 and 2018 totaled $3690,~~237~~357 and $3481,~~588~~954, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During the three months ended ~~December~~March 31, 2019 and 2018, revenues associated with such sales to Energy Services totaled $24,564 and ~~2017~~$61,245, respectively. During the six months ended March 31, 2019 and 2018, revenues associated with such sales to Energy Services totaled $2247,~~862~~426 and $2182,~~147~~392, respectively. Also from time to time, UGI Utilities purchases natural gas and pipeline capacity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three months ended ~~December~~March 31, 2019 and 2018, such purchases totaled $46,295 and ~~2017~~$83,429, respectively. During the six months ended March 31, 2019 and 2018, such purchases totaled $4490,~~382~~677 and $37121,~~597~~026, respectively.

Note 15 — Segment Information

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

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

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Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars, except where indicated otherwise)

				Reportable Segments
Three Months Ended December 31, 2018	Total			Gas Utility			Electric Utility
Three Months Ended March 31, 2019	Total			Gas Utility			Electric Utility
Revenues	$	~~322~~429,~~725~~592		$	~~297~~401,~~142~~415		$	2528,~~583~~177
Cost of sales	$	~~159~~217,~~519~~976		$	~~145~~202,~~120~~164		$	1415,~~399~~812
Depreciation	$	22,~~474~~341		$	2120,~~040~~902		$	1,~~434~~439
Operating income	$	77119,~~074~~866		$	73116,~~584~~580		$	3,~~490~~286
Pension and other postretirement plans non-service income	$	~~412~~395		$	~~361~~346		$	5149
Interest expense	$	(1112,~~738~~231	)	$	(11,~~218~~622	)	$	(~~520~~609	)
Income before income taxes	$	65108,~~748~~030		$	62105,~~727~~304		$	32,~~021~~726
Capital expenditures (including the effects of accruals)	$	7770,~~319~~799		$	7566,~~074~~766		$	24,~~245~~033
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 December 31, 2017	Total			Gas Utility			Electric Utility
Three Months Ended March 31, 2018	Total			Gas Utility			Electric Utility
Revenues	$	~~323~~483,~~105~~261		$	~~299~~455,~~965~~973		$	2327,~~140~~288
Cost of sales	$	~~151~~257,~~774~~302		$	~~138~~241,~~858~~031		$	1216,~~916~~271
Depreciation	$	2021,~~354~~158		$	19,~~000~~776		$	1,~~354~~382
Operating income (a)	$	96135,~~870~~771		$	94134,~~185~~738		$	21,~~685~~033
Pension and other postretirement plans non-service expense (a)	$	(~~575~~644	)	$	(~~504~~563	)	$	(7181	)
Interest expense	$	(1011,~~939~~091	)	$	(10,~~526~~866	)	$	(~~413~~225	)
Income before income taxes	$	85124,~~356~~036		$	83123,~~155~~309		$	~~2,201~~727
Capital expenditures (including the effects of accruals)	$	7155,~~699~~089		$	6851,~~842~~363		$	23,~~857~~726
As of December 31, 2017
Total assets	$	3,174,693		$	3,038,250		$	136,443
Goodwill	$	182,145		$	182,145		$	—



				Reportable Segments
Six Months Ended March 31, 2019	Total			Gas Utility			Electric Utility
Revenues	$	752,317		$	698,557		$	53,760
Cost of sales	$	377,495		$	347,284		$	30,211
Depreciation	$	44,815		$	41,942		$	2,873
Operating income	$	196,940		$	190,164		$	6,776
Pension and other postretirement plans non-service income	$	807		$	707		$	100
Interest expense	$	(23,969	)	$	(22,840	)	$	(1,129	)
Income before income taxes	$	173,778		$	168,031		$	5,747
Capital expenditures (including the effects of accruals)	$	148,118		$	141,840		$	6,278

As of March 31, 2019
Total assets	$	3,438,437		$	3,252,092		$	186,345
Goodwill	$	182,145		$	182,145		$	—

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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
Six Months Ended March 31, 2018	Total			Gas Utility			Electric Utility
Revenues	$	806,366		$	755,938		$	50,428
Cost of sales	$	409,076		$	379,889		$	29,187
Depreciation	$	41,512		$	38,776		$	2,736
Operating income (a)	$	232,641		$	228,923		$	3,718
Pension and other postretirement plans non-service expense (a)	$	(1,219	)	$	(1,067	)	$	(152	)
Interest expense	$	(22,030	)	$	(21,392	)	$	(638	)
Income before income taxes	$	209,392		$	206,464		$	2,928
Capital expenditures (including the effects of accruals)	$	126,788		$	120,205		$	6,583

As of March 31, 2018
Total assets	$	3,204,045		$	3,033,352		$	170,693
Goodwill	$	182,145		$	182,145		$	—

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

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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 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~~continuous ~~analysis~~enactment of ~~recent~~ tax legislation.

These factors, and those factors set forth in Item 1A. Risk Factors in the Company’s 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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ANALYSIS OF RESULTS OF OPERATIONS

The following ~~analysis~~analyses ~~compares~~compare our results of operations for the ~~2018~~2019 three-month period with the ~~2017~~2018 three-month period and the 2019 six-month period with the 2018 six-month period. Our ~~analysis~~analyses of results of operations should be read in conjunction with the segment information included in Note 15 to the Condensed Consolidated Financial Statements.

~~Our~~As ~~2018~~further ~~three-month~~discussed ~~period~~below and ~~2017~~in Notes 6 and 7 to the Condensed Consolidated Financial Statements, our 2019 and 2018 three and six-month period results were significantly impacted by the enactment of the TCJA. inWith respect to our 2019 three and six-month results, actions taken by the UPAPUC to address the effects of the TCJA on rates we charge our customers also significantly impacted our results.S. The significant income tax changes resulting from the ~~law~~TCJA that most impacted UGI Utilities ~~included~~include a reduction in the U.S. federal income tax rate from 35% to 21% effective January 1, 2018, (resulting in a blended rate of 24.5% for Fiscal 2018,) and the elimination of bonus depreciation on regulated utility property beginning in Fiscal 2019. ~~For~~Our Fiscal 2019, ~~our~~ U.S. federal income tax rate is 21%.

AsWe arecorded ~~result~~net ofincome ~~the~~for ~~TCJA, during~~ the ~~2017~~2019 three-month period weof ~~remeasured~~$82.9 ~~our~~million ~~existing~~compared ~~deferred~~to net income ~~tax~~for ~~assets and liabilities at~~ the ~~new~~2018 ~~tax~~three-month ~~rates~~period inof ~~the~~$89.2 Umillion.S. ~~Due~~We torecorded ~~the~~net ~~effects~~income offor ~~utility ratemaking, most of~~ the ~~reductions~~2019 insix-month ~~UGI~~period ~~Utilities’ deferred income tax assets and liabilities resulting from the enactment~~ of ~~the~~$132.7 ~~TCJA~~million ~~were~~compared ~~not~~to ~~recognized~~net ~~immediately in~~ income ~~tax~~for ~~expense but were reflected in regulatory assets and liabilities in accordance with utility ratemaking. For further information on~~ the ~~effects~~2018 ofsix-month ~~the~~period ~~TCJA, and the regulatory impacts on UGI Utilities resulting from the TCJA and the actions~~ of ~~the~~$157.5 ~~PAPUC, see Notes 6 and 7 to Condensed Consolidated Financial Statements~~million.

~~2018~~The decreases in the 2019 three and six-month period results compared with the ~~2017~~prior-year periods are the result of reflecting the credit to customers for tax savings resulting from the TCJA in accordance with the PAPUC’s May 17, 2018 Order. Substantially all of the credit to customers of tax savings resulting from the TCJA that accrued beginning January 1, 2018 through March 31, 2018 of approximately $14.9 million was recorded during the three months ended June 30, 2018. Accordingly, net income for the prior-~~month~~year ~~period~~periods was not reduced by the previously mentioned $14.9 million credit to customers for tax savings resulting from the TCJA.

Three Months Ended December 31,	2018			2017			Increase (Decrease)
(Dollars in millions)
Gas Utility:
Revenues (a)	$	297.1		$	300.0		$	(2.9	)	(1.0	)%
Total margin (a)(b)	$	152.0		$	161.1		$	(9.1	)	(5.6	)%
Operating and administrative expenses	$	56.1		$	47.9		$	8.2		17.1	%
Operating income	$	73.6		$	94.2		$	(20.6	)	(21.9	)%
Income before income taxes	$	62.7		$	83.2		$	(20.5	)	(24.6	)%
System throughput — bcf
Core market	26.5			25.5			1.0			3.9	%
Total	75.7			69.2			6.5			9.4	%
Heating degree days — % (warmer) than normal (c)	(0.5		)%	(1.9		)%	—			—
Electric Utility:
Revenues	$	25.6		$	23.1		$	2.5		10.8	%
Total margin (b)	$	9.9		$	8.9		$	1.0		11.2	%
Operating and administrative expenses (b)	$	5.1		$	5.0		$	0.1		2.0	%
Operating income	$	3.5		$	2.7		$	0.8		29.6	%
Income before income taxes	$	3.0		$	2.2		$	0.8		36.4	%
Distribution sales — gwh	249.7			246.6			3.1			1.3	%

2019 three-month period compared with the 2018 three-month period

(a) In accordance with the PAPUC Order issued May 17, 2018, Gas Utility’s revenues and total margin for the three months ended December 31, 2018, were reduced by $13.5 million to reflect the give back of tax savings of the TCJA (see Notes 6 and 7 to Condensed Consolidated Financial Statements).



Three Months Ended March 31,	2019			2018			Increase (Decrease)
(Dollars in millions)
Gas Utility:
Revenues (a)	$	401.4		$	456.0		$	(54.6	)	(12.0	)%
Total margin (a)(b)	$	199.2		$	215.0		$	(15.8	)	(7.3	)%
Operating and administrative expenses	$	61.6		$	61.7		$	(0.1	)	(0.2	)%
Operating income	$	116.6		$	134.7		$	(18.1	)	(13.4	)%
Income before income taxes	$	105.3		$	123.3		$	(18.0	)	(14.6	)%
System throughput — bcf
Core market	40.2			38.9			1.3			3.3	%
Total	96.6			87.3			9.3			10.7	%
Heating degree days — % (warmer) than normal (c)	(0.8		)%	(2.2		)%	—			—
Electric Utility:
Revenues	$	28.2		$	27.3		$	0.9		3.3	%
Total margin (b)	$	11.0		$	9.6		$	1.4		14.6	%
Operating and administrative expenses (b)	$	6.1		$	7.2		$	(1.1	)	(15.3	)%
Operating income	$	3.3		$	1.0		$	2.3		230.0	%
Income before income taxes	$	2.7		$	0.7		$	2.0		285.7	%
Distribution sales — gwh	279.2			278.7			0.5			0.2	%

(ba) ~~Gas~~In ~~Utility’s~~accordance ~~total~~with ~~margin~~the ~~represents~~PAPUC ~~total~~Order ~~revenues~~issued ~~less~~May ~~total~~17, ~~cost~~2018, ofGas ~~sales. Electric~~ Utility’s revenues and total margin ~~represents~~for ~~total~~the ~~revenues~~three ~~less~~months ~~total~~ended ~~cost~~March of31, ~~sales~~2019, ~~and~~were ~~revenue-related~~reduced ~~taxes,~~by i$22.e.7 ~~Electric~~million ~~Utility~~to ~~gross~~reflect ~~receipts~~the ~~taxes,~~credit ofto ~~$1.3~~customers ~~million~~of ~~during~~tax ~~each~~savings of the ~~three~~TCJA. ~~months~~Substantially ~~ended~~all ~~December~~of ~~31,~~the ~~2018~~credits ~~and~~to ~~2017.~~customers ~~For~~associated ~~financial~~with ~~statement~~tax ~~purposes,~~savings ~~revenue-related~~for ~~taxes~~the ~~are~~2018 ~~included~~three-month inperiod ~~“Operating~~were ~~and~~recorded ~~administrative~~during ~~expenses” on~~ the ~~Condensed~~three ~~Consolidated~~months ~~Statements~~ended ofJune ~~Income~~30, ~~(but~~2018. ~~are~~See ~~excluded~~Notes ~~from~~6 ~~Electric~~and ~~Utility~~7 ~~operating~~to ~~expenses~~Condensed ~~presented~~Consolidated ~~above)~~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 $1.4 million during each of the three months ended March 31, 2019 and 2018. For financial statement purposes, revenue-related taxes are included in

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“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 NOAA for airports located within Gas Utility’s service territory.

Temperatures in Gas Utility’s service territory during the three months ended ~~December~~March 31, ~~2018~~2019, were slightly warmer than normal and 1.54% colder than the three months ended ~~December~~March 31, ~~2017~~2018. Gas Utility core market volumes increased 1.03 bcf (3.93%) principally reflecting the effects of the ~~colder weather and~~ growth in the number of core market customers and the slightly colder temperatures. Total Gas Utility distribution system throughput increased 69.53 bcf reflecting higher large firm delivery service volumes (10.1 bcf) and the previously mentioned higher core market volumes partially offset by a decrease in interruptible delivery service volumes. Electric Utility kilowatt-hour sales were slightly higher than the prior-year period principally reflecting the impact of the colder weather on Electric Utility heating-related sales.

UGI Utilities revenues decreased $53.7 million in the three months ended March 31, 2019, reflecting a $54.6 million decrease in Gas Utility revenues partially offset by a $0.9 million increase in Electric Utility revenues. In accordance with the May 17, 2018, PAPUC Order, during the three months ended March 31, 2019, Gas Utility’s revenues were reduced by $22.7 million to reflect the credit to customers of tax savings of the TCJA. Excluding the impact of this reduction in revenues, Gas Utility revenues decreased $31.9 million. The decrease principally reflects $18.8 million of lower off-system sales revenue which is net of capacity releases due in part to the adoption of ASC 606 (which requires that capacity release contracts be reflected on a gross, rather than net, basis), lower core market revenues ($13.2 million) and lower firm delivery service revenue ($2.7 million). The $13.2 million decrease in Gas Utility core market revenues reflects lower average retail core market PGC rates ($24.3 million) partially offset by the effects of the higher core market throughput ($11.1 million).The $0.9 million increase in Electric Utility revenues during the 2019 three-month period principally reflects an increase in Electric Utility base rates effective October 27, 2018 ($0.8 million) and higher transmission revenue ($0.7 million).

UGI Utilities’ cost of sales was $218.0 million in the three months ended March 31, 2019 compared with $257.3 million in the three months ended March 31, 2018, reflecting lower Gas Utility cost of sales ($38.9 million) and lower Electric Utility cost of sales ($0.5 million) from DS customers transferring to alternate suppliers. The lower Gas Utility cost of sales principally reflects a decrease in cost of sales associated with off-system sales ($20.0 million), which is net of capacity release cost of sales (due principally to the presentation of capacity release contracts resulting from the adoption of ASC 606), and the effects of lower average retail core-market PGC rates ($20.7 million), partially offset by the higher core market volumes ($2.0 million).

UGI Utilities total margin decreased $14.4 million reflecting lower total margin from Gas Utility ($15.8 million) principally attributable to the impact of the $22.7 million reduction in revenues resulting from the PAPUC Order, partially offset by higher Electric Utility total margin ($1.4 million). Excluding the reduction in Gas Utility total margin resulting from the PAPUC Order, Gas Utility total margin increased $6.9 million principally reflecting higher total margin from Gas Utility core market customers and, to a lesser extent, higher off-system sales margin reflecting the margin impacts of the presentation of certain revenues in accordance with ASC 606. The increase in Electric Utility margin principally reflects the increase in base rates and higher transmission revenue.

UGI Utilities operating income decreased $15.8 million principally reflecting the decrease in total margin ($14.4 million), greater depreciation expense ($1.2 million), and higher other operating expense ($1.4 million) partially offset by slightly lower operating and administrative expenses ($1.1 million). The slight decrease in UGI Utilities operating and administrative expenses principally reflects lower uncollectible accounts expense due principally to the timing of adjustments to reserves and lower benefit-related expenses partially offset by higher contractor and outside services expense and higher allocated corporate expenses. The increase in depreciation expense reflects increased distribution system capital expenditure activity. UGI Utilities income before income taxes decreased $15.9 million principally reflecting the decrease in UGI Utilities operating income.

Interest Expense and Income Taxes

Interest expense in the 2019 three-month period was $1.1 million higher than the prior-year period. The higher interest expense principally reflects higher long-term debt outstanding and, to a lesser extent, higher average interest rates under UGI Utilities Credit Agreement.

Our effective income tax rate for the 2019 three-month period was lower than in the prior-year period. The lower effective income tax rate in the current-year period reflects a federal income tax rate of 21% compared with a blended federal income tax rate of 24.5% in the prior-year period. See Note 6 to Condensed Consolidated Financial Statements.

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~~higher~~2019 ~~core market volumes partially offset by a decrease in interruptible delivery service volumes. Electric Utility kilowatt~~six-~~hour~~month ~~sales were 1.3% higher than the prior-year~~ period ~~principally~~compared ~~reflecting~~with the ~~impact~~2018 ~~of the colder weather on Electric Utility heating~~six-~~related~~month ~~sales.~~period

UGI Utilities revenues decreased $0.4 million reflecting a $2.9 million decrease in Gas Utility revenues partially offset by a $2.5 million increase in Electric Utility revenues. In accordance with the May 17, 2018, PAPUC Order, during the three months ended December 31, 2018, Gas Utility’s revenues were reduced by $13.5 million to reflect the give back of tax savings of the TCJA. Excluding the impact of this reduction in revenues, Gas Utility revenues increased $10.6 million principally reflecting an increase in off-system sales revenues including capacity releases ($17.5 million), due in large part to the adoption of ASC 606 (which requires that capacity release contracts be reflected on a gross, rather than net, basis), and higher other revenues ($1.8 million), partially offset by lower core market revenues ($9.9 million). The $9.9 million decrease in Gas Utility core market revenues reflects lower average retail core market PGC rates ($19.0 million) partially offset by the effects of the higher core market throughput ($9.0 million).The increase in Electric Utility revenues during the 2018 three-month period principally reflects higher DS rates ($0.9 million), higher transmission revenue ($0.7 million), and an increase in Electric Utility base rates effective October 27, 2018 ($0.5 million).



Six Months Ended March 31,	2019			2018			Increase (Decrease)
(Dollars in millions)
Gas Utility:
Revenues (a)	$	698.6		$	755.9		$	(57.3	)	(7.6	)%
Total margin (a)(b)	$	351.3		$	376.1		$	(24.8	)	(6.6	)%
Operating and administrative expenses	$	117.7		$	109.5		$	8.2		7.5	%
Operating income	$	190.2		$	228.9		$	(38.7	)	(16.9	)%
Income before income taxes	$	168.0		$	206.5		$	(38.5	)	(18.6	)%
System throughput — bcf
Core market	66.7			64.4			2.3			3.6	%
Total	172.3			156.6			15.7			10.0	%
Heating degree days — % (warmer) than normal (c)	(0.7		)%	(2.1		)%	—			—
Electric Utility:
Revenues	$	53.8		$	50.4		$	3.4		6.7	%
Total margin (b)	$	20.9		$	18.6		$	2.3		12.4	%
Operating and administrative expenses (b)	$	11.2		$	12.2		$	(1.0	)	(8.2	)%
Operating income	$	6.8		$	3.7		$	3.1		83.8	%
Income before income taxes	$	5.7		$	2.9		$	2.8		96.6	%
Distribution sales — gwh	528.9			525.3			3.6			0.7	%

~~UGI~~(a) ~~Utilities’~~In ~~cost~~accordance ofwith ~~sales was $159.5 million in~~ the ~~three~~PAPUC ~~months~~Order ~~ended~~issued ~~December~~May 3117, 2018, ~~compared~~Gas ~~with~~Utility’s ~~$151.8~~revenues ~~million~~and intotal margin for the ~~three~~six months ended ~~December~~ March 31, ~~2017~~2019, ~~principally~~were ~~reflecting~~reduced ~~higher~~by ~~Gas Utility cost of sales (~~$636.32 million) ~~and~~to ~~higher~~reflect ~~Electric~~the ~~Utility~~credit ~~cost~~to customers of ~~sales~~tax ~~($1.5~~savings ~~million)~~of ~~from~~ the ~~higher DS rates and slightly higher distribution system sales~~TCJA. ~~The~~Substantially ~~higher~~all ~~Gas Utility cost~~ of ~~sales~~the ~~principally~~credits ~~reflects~~to ~~higher~~customers ~~cost of sales~~ associated with ~~off-system~~tax ~~sales~~savings ~~including~~for ~~capacity releases ($16.9 million) due in large part to~~ the ~~previously~~2018 ~~mentioned~~six-month ~~impact~~period ofwere ~~ASC~~recorded ~~606~~during on the ~~presentation~~three ofmonths ~~capacity~~ended ~~release~~June ~~contracts~~30, ~~and the effects of higher core market volumes ($4~~2018.3 ~~million)~~See ~~partially~~Notes ~~offset~~6 byand ~~lower~~7 ~~average~~to ~~retail~~Condensed ~~core-market~~Consolidated ~~PGC~~Financial ~~rates ($16~~Statements.~~3 million).~~

~~UGI~~(b) ~~Utilities~~Gas Utility’s total margin ~~decreased~~represents ~~$8.1~~total ~~million~~revenues ~~reflecting~~less ~~lower~~ total ~~margin~~cost ~~from Gas Utility ($9.1 million) attributable to the impact~~ of ~~the $13~~sales.5 ~~million reduction in revenues resulting from the TCJA, partially offset by higher~~ Electric Utility’s total margin ~~($1.0~~represents ~~million).~~total ~~Excluding~~revenues ~~the~~less ~~reduction in Gas Utility~~ total ~~margin~~cost ~~resulting~~of ~~from~~sales ~~the~~and ~~TCJA~~revenue-related taxes, ~~Gas Utility total margin increased $4~~i.4e. ~~million~~Electric ~~principally reflecting higher total margin from Gas~~ Utility ~~core~~gross ~~market~~receipts ~~customers~~taxes, (of $2.17 million) and ~~higher other margin (~~$12.96 million) ~~primarily~~during ~~reflecting~~ the ~~margin~~six ~~impacts~~months ofended ~~the~~March ~~presentation~~31, of2019 ~~certain~~and ~~revenues~~2018, inrespectively. ~~accordance~~For ~~with~~financial ~~the~~statement ~~adoption~~purposes, ofrevenue-related ~~ASC~~taxes ~~606. The~~are ~~increase~~included in ~~Electric~~“Operating ~~Utility~~and ~~margin~~administrative ~~principally~~expenses” ~~reflects~~on the ~~increase~~Condensed inConsolidated ~~base~~Statements ~~rates,~~of ~~higher~~Income ~~transmission~~(but ~~revenue~~are ~~and,~~excluded tofrom aElectric ~~lesser~~Utility ~~extent,~~operating ~~the~~expenses ~~higher~~presented ~~distribution volumes sold~~above).

~~UGI Utilities operating income decreased $19.8 million, principally reflecting the decrease in total margin~~ (~~$8.1 million~~c), ~~higher~~Deviation ~~Gas~~from ~~Utility~~average ~~and~~heating ~~Electric~~degree ~~Utility~~days ~~operating~~for 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~~15-year period ~~($2.1~~2000-2014 ~~million)~~based ~~and~~upon ~~higher~~weather ~~general~~statistics ~~and~~provided ~~administrative~~by ~~costs~~NOAA ~~including~~for anairports ~~increase~~located inwithin ~~uncollectible~~Gas ~~accounts~~Utility’s ~~expense~~service ~~($1~~territory.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.

Temperatures in Gas Utility’s service territory during the 2019 six-month period were slightly warmer than normal and 1.5% colder than the 2018 six-month period. Gas Utility core market volumes increased 2.3 bcf (3.6%) principally reflecting the effects of the colder weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 15.7 bcf reflecting higher large firm delivery service volumes (17.4 bcf) and the previously mentioned increase in core market volumes partially offset by a decrease in interruptible delivery service volumes (3.9 bcf). Electric Utility kilowatt-hour sales were 0.7% higher than the prior-year period principally reflecting the impact of the colder weather on Electric Utility heating-related sales.

UGI Utilities revenues decreased $54.0 million reflecting a $57.4 million decrease in Gas Utility revenues partially offset by a $3.3 million increase in Electric Utility revenues. In accordance with the May 17, 2018, PAPUC Order, during the six months ended March 31, 2019, Gas Utility’s revenues were reduced by $36.2 million to reflect the credit to customers of tax savings of the TCJA. Excluding the impact of this reduction in revenues, Gas Utility revenues decreased $21.2 million. The decrease principally reflects lower core market revenues ($23.1 million) and a decrease in off-system sales revenues ($1.3 million) which is net of capacity release revenues due principally to the adoption of ASC 606 (which requires capacity release contracts be reflected on a gross, rather than net, basis) partially offset by higher other revenues ($3.3 million). The $23.1 million decrease in Gas Utility core market revenues reflects lower average retail core market PGC rates ($43.2 million) partially offset by the effects of the higher core market throughput ($20.1 million). The increase in Electric Utility revenues during the 2019 six-month period principally reflects higher transmission revenue ($1.4 million), an increase in Electric Utility base rates effective October 27, 2018 ($1.3 million) and higher DS rates ($0.4 million).

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UGI Utilities’ cost of sales was $377.5 million in the 2019 six-month period compared with $409.1 million in the 2018 six-month period reflecting lower Gas Utility cost of sales ($32.6 million) partially offset by higher Electric Utility cost of sales ($1.0 million) from the higher DS rates. The lower Gas Utility cost of sales principally reflects lower average retail core-market PGC rates ($40.3 million) partially offset by the higher core market volumes ($9.8 million).

UGI Utilities total margin decreased $22.6 million reflecting lower total margin from Gas Utility ($24.8 million) principally attributable to the impact of the $36.2 million reduction in revenues resulting from the PAPUC Order, partially offset by higher Electric Utility total margin ($2.3 million). Excluding the reduction in Gas Utility total margin resulting from the PAPUC Order, Gas Utility total margin increased $11.4 million principally reflecting higher total margin from Gas Utility core market customers and, to a much lesser extent, higher off-system sales margin reflecting the margin impacts of the presentation of certain revenues in accordance with the adoption of ASC 606. The increase in Electric Utility margin principally reflects higher transmission revenue and the increase in base rates.

UGI Utilities operating income decreased $35.7 million principally reflecting the decrease in total margin ($22.6 million), higher operating and administrative expenses ($7.3 million), greater depreciation expense ($3.3 million), and higher other operating expense ($2.6 million). The increase in UGI Utilities operating and administrative expenses principally reflects higher general and administrative costs including higher contractor and outside services expense ($3.2 million), higher allocated corporate expenses ($2.3 million), the absence of a favorable payroll tax adjustment recorded in the prior-year period ($2.1 million) and higher IT maintenance and consulting expense ($1.9 million). These increases were partially offset by a decrease in uncollectible accounts expense ($2.0 million). The increase in depreciation expense reflects increased distribution system and IT capital expenditure activity. UGI Utilities income before income taxes decreased $35.6 million principally reflecting the decrease in UGI Utilities operating income.

Interest Expense and Income Taxes

Interest expense in the ~~2018~~2019 ~~three~~six-month period was ~~slightly~~$1.9 million higher than in the prior-year period. The higher interest expense reflects higher long-term debt outstanding, and higher ~~short-term~~average interest rates onand ~~revolver~~ borrowings. ~~The~~under ~~lower effective income tax rate in~~ the ~~prior-year~~UGI ~~period~~Utilities ~~reflects~~Credit the remeasurement effects on certain of our deferred income tax balances resulting from the enactment of the TCJA, which reduced our 2017 three-month period income tax expense, and increased our net income, by $8Agreement.1 million. Income tax expense in the 2018 three-month period and the 2017 three-month period reflects U.S. federal income tax rates on pre-tax earnings of 21% and 24.5%, respectively. See Note 6 to Condensed Consolidated Financial Statements.

Our effective income tax rate for the 2019 six-month period was lower than in the prior-year period. The lower effective income tax rate in the current-year period reflects the impact of a federal income tax rate of 21%, compared with a blended federal income tax rate of 24.5% in the prior-year period. Income tax expense in the 2018 six-month period was reduced by the remeasurement effects on certain of our deferred income tax balances resulting from the enactment of the TCJA in the first quarter of Fiscal 2018, which reduced 2018 six-month period income tax expense by $8.1 million.

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~~the ~~facilities~~UGI Utilities Credit Agreement. Our cash and cash equivalents at ~~December~~March 31, ~~2018~~2019, totaled $2141.54 million compared to $10.3 million at September 30, 2018.

UGI Utilities’ total debt outstanding at ~~December~~March 31, ~~2018~~2019, was $1,~~131~~088.63 million, which includes $~~296~~105.0 million of short-term borrowings, compared with total debt outstanding of $1,027.5 million at September 30, 2018, which includes $189.5 million of short-term borrowings. Total long-term debt outstanding at ~~December~~March 31, ~~2018~~2019, comprises $~~675~~825.0 million of Senior Notes, a $117.2 million variable-rate term loan, $40.0 million of Medium-Term Notes and $5.9 million of other long-term debt, and is net of $4.8 million of unamortized debt issuance costs.

28The UGI Utilities Credit Agreement comprises an unsecured revolving credit agreement with a group of banks providing for borrowings up to $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 March 31, 2019, UGI Utilities’ available borrowing capacity under the UGI Utilities Credit Agreement was $343.0 million. During the 2019 and 2018 six-month periods, average daily short-term borrowings under the UGI Utilities Credit Agreement were $223.8 million and $171.4 million, respectively, and peak short-term borrowings totaled $311.0 million and $215.0 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.

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

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~~$118.8~~certain ~~million~~note ~~variable-rate~~purchasers. ~~term~~The ~~loan, $40~~4.055% ~~million~~Senior ofNotes ~~Medium-Term~~are ~~Notes~~unsecured and ~~$6.6~~rank ~~million~~equally ofwith ~~other~~UGI ~~long-term~~Utilities’ ~~debt,~~existing ~~and~~outstanding issenior debt. The net proceeds from the sale of $the 4.855% ~~million~~Senior ofNotes ~~unamortized~~were ~~debt~~used ~~issuance~~to ~~costs~~reduce short-term borrowings and for general corporate purposes.

The UGI Utilities Credit Agreement is an unsecured revolving credit agreement with a group of banks providing for borrowings up to $450 million (including a $100 million sublimit for letters of credit) which expires in March 2020. Borrowings under the Credit Agreement are classified as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. At December 31, 2018, UGI Utilities’ available borrowing capacity under the UGI Utilities Credit Agreement was $152.0 million. During the 2018 and 2017 three-month periods, average daily short-term borrowings under the UGI Utilities Credit Agreement were $250.7 million and $168.1 million, respectively, and peak short-term borrowings totaled $311.0 million and $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 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 $15161.40 million in the ~~2018~~2019 ~~three~~six-month period compared to ~~cash used by operating activities of~~ $7135.1 million in the prior-year period. Cash flow from operating activities before changes in operating working capital was $95199.65 million in the ~~2018~~2019 ~~three~~six-month period, ~~comparable~~compared to the $97210.62 million ~~recorded~~ in the prior-year period. The slightly lower cash flow from operating activities before changes in operating working capital includes, among other things, the impact of the credit to customers of tax savings from the TCJA in accordance with the May 17, 2018 PAPUC Order. Changes in operating working capital used $8038.15 million of operating cash flow during the ~~2018~~2019 ~~three~~six-month period compared to $~~104~~75.71 million of cash used for changes in working capital during the prior-year period. The lower net cash used by changes in operating working capital in the ~~2018~~2019 ~~three~~six-month period reflects, among other things, ~~higher~~a ~~cash~~smaller ~~receipts~~increase ~~from~~in ~~customers~~changes ~~during~~in ~~the~~accounts ~~current-year~~receivable ~~period~~as ~~due to~~ the ~~timing~~prior ofyear ~~sales~~included ~~and associated revenues. Sales and associated revenues occurred earlier during~~ the ~~2018~~effects ~~three-month~~of ~~period due to~~ colder late ~~October~~winter ~~and November~~ weather, ~~compared~~on toaccounts ~~higher~~receivable ~~sales~~balances. ~~and~~Cash ~~associated~~flow ~~revenues~~from ~~recorded~~changes ~~later~~ in ~~the~~operating ~~2017~~working ~~three-month~~capital ~~period~~also asreflects anet ~~result~~refunds of ~~extremely~~deferred ~~cold~~fuel ~~late~~and ~~December~~power ~~2017~~costs ~~weather.~~during ~~The higher cash received from customers in~~ the current -year ~~was~~period ~~partially offset by net refunds of PGC costs,~~ compared to net recoveries of ~~PGC~~such costs induring the prior-year period.

Investing activities. Cash used by investing activities was $~~100~~180.41 million in the ~~2018~~2019 ~~three~~six-month period compared to $91154.19 million in the ~~2017~~2018 ~~three~~six-month period. Total cash capital expenditures were $98177.73 million in the ~~2018~~2019 ~~three~~six-month period compared with $88151.75 million recorded in the prior-year period. The increase in cash capital expenditures during the ~~2018~~2019 ~~three~~six-month period principally reflects higher ITcash capital expenditures associated with an Enterprise Resource Planning system, and higher main replacement and new business cash capital expenditures.

Financing activities. Cash provided by financing activities was $9849.39 million in the ~~2018~~2019 ~~three~~six-month period compared with $~~100~~17.98 million during the ~~2017~~2018 ~~three~~six-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. Cash from financing activities in the 2019 six-month period reflects net proceeds from the issuance of $150 million of UGI Utilities 4.55% Senior Notes due February 1, 2049. Cash from financing activities in the prior-year period includes the net proceeds from a $125 million unsecured term loan agreement. The ~~2018~~2019 ~~three~~six-month period reflects net credit agreement borrowings of $~~106~~84.5 million compared with net borrowings of $1135.50 million during the prior-year period. ~~Credit agreement borrowings were lower in the prior-year period as the prior-period financing cash flow benefited from the previously mentioned $125 million issuance of term loan debt.~~ Cash dividends paid during the ~~2018~~2019 ~~three~~six-month period totaled $510.0 million compared to cash dividends paid of $1530.0 million during the prior-year period.

29REGULATORY MATTERS

Utility Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and MDPSC, respectively, to merge PNG and CPG into UGI Utilities. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged with and into UGI Utilities effective October 1, 2018. Consistent with the MDPSC order issued July 25, 2018, and the PAPUC order issued September, 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type schedules for limited future ratemaking purposes.

Base Rate Filings. On January 28, 2019, UGI Gas filed a request with the PAPUC to increase its operating revenues for residential, commercial and industrial customers by $71.1 million annually. The requested rate increase applies to the consolidated UGI Central, UGI North and UGI South rate districts. The increased revenues would be used to fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Additionally, UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $24.0 million of tax benefits experienced by UGI Utilities over the period

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~~REGULATORY~~January ~~MATTERS~~1, 2018 to June 30, 2018, plus applicable interest. As proposed, the negative surcharge would become effective for a twelve-month period beginning on the effective date of the new base rates. UGI Gas requested that the new gas rates become effective March 29, 2019. The PAPUC entered an Order dated February 28, 2019, suspending the effective date for the rate increase to allow for investigation and public hearings. Unless a settlement is reached sooner, this review process is expected to last up to nine months from the date of filing. The Company cannot predict the timing or the ultimate outcome of the rate case review process.

~~Utility Merger.~~ On ~~March 8~~January 26, 2018 ~~and March 13~~, ~~2018,~~Electric ~~UGI~~Utility ~~Utilities~~ filed ~~merger~~a ~~authorization~~rate ~~requests~~request with the PAPUC ~~and~~to ~~MDPSC,~~increase ~~respectively,~~its toannual ~~merge~~base ~~PNG~~distribution ~~and~~revenues ~~CPG~~by ~~into~~$9.2 ~~UGI Utilities~~million, ~~with~~which awas ~~targeted~~later ~~effective~~reduced ~~date~~by ofthe ~~October~~Company 1,to ~~2018~~$7.7 ~~After~~million ~~receiving~~to ~~all~~reflect ~~necessary~~the ~~FERC,~~impact ~~MDPSC,~~of the TCJA and ~~PAPUC~~other ~~approvals,~~adjustments. ~~CPG~~The ~~and~~increased ~~PNG~~revenues ~~were~~would ~~merged~~be ~~into~~used ~~UGI~~to ~~Utilities~~fund ~~effective~~ongoing ~~October~~system 1,improvements ~~2018.~~and ~~Consistent~~operations ~~with~~necessary ~~the~~to ~~MDPSC~~maintain ~~order~~safe ~~issued~~and ~~July~~reliable electric service. On October 25, 2018, ~~and~~ the PAPUC approved a final order ~~issued~~providing ~~September,~~for ~~26,~~a $3.2 ~~2018,~~million annual ~~the~~base ~~former~~distribution ~~CPG,~~rate ~~PNG~~increase ~~and~~for ~~UGI~~Electric ~~Utilities~~Utility, ~~Inc.~~effective ~~Gas~~October ~~Division~~27, ~~service~~2018. ~~territories~~As ~~became~~part of the ~~UGI~~final ~~Central~~order, ~~UGI~~Electric ~~North~~Utility ~~and~~provided ~~UGI~~customers ~~South~~with ~~rate~~a ~~districts~~one-time $0.2 ofmillion billing ~~the~~credit ~~UGI~~associated ~~Utilities,~~with ~~Inc~~2018 TCJA tax benefits. ~~Gas~~On ~~Division~~November 26, ~~respectively~~2018, ~~without~~the ~~any~~Pennsylvania ~~ratemaking~~Office ~~change.~~of ~~UGI~~Consumer ~~Utilities’~~Advocate ~~obligations~~filed ~~under~~an appeal to the ~~settlement~~Pennsylvania ~~approved~~Commonwealth byCourt challenging the PAPUC’s ~~include~~acceptance ~~various~~of ~~non-monetary~~the ~~conditions~~Company’s ~~requiring~~use ~~UGI~~of ~~Utilities~~a tofully ~~maintain~~projected ~~separate~~future ~~accounting-type~~test ~~schedules~~year ~~for~~and ~~limited~~handling ~~future~~of ~~ratemaking~~consolidated ~~purposes~~federal income tax benefits. The Company cannot predict the ultimate outcome of this appeal.

~~Base~~Manor ~~Rate Filings. On January 28~~Township, ~~2019,~~Pennsylvania ~~UGI~~Natural Gas ~~filed~~Incident aComplaint. ~~request~~In connection with ~~the~~a ~~PAPUC~~July to2, ~~increase~~2017, ~~its~~explosion ~~operating~~in ~~revenues~~Manor ~~for residential~~Township, ~~commercial~~Lancaster ~~and~~County, ~~industrial~~Pennsylvania, ~~customers~~that ~~by $71.1~~resulted ~~million annually.~~in ~~The requested rate increase applies to~~ the ~~consolidated~~death ~~UGI~~of ~~Central,~~one ~~UGI~~Company ~~North~~employee and ~~UGI~~injuries ~~South~~to ~~rate~~two ~~districts.~~Company ~~The~~employees ~~increased~~and ~~revenues~~one ~~would~~sewer ~~fund~~authority ~~ongoing~~employee, ~~system improvements~~ and ~~operations~~destroyed ~~necessary~~two toresidences ~~maintain safe~~ and ~~reliable~~damaged ~~natural~~several ~~gas~~other ~~service~~homes, ~~and~~the ~~fund~~BIE ~~new~~filed ~~programs~~a ~~designed~~formal tocomplaint ~~promote~~at ~~and~~the ~~reward~~PAPUC ~~customers’~~in ~~efforts~~which toBIE ~~increase~~alleged ~~efficient~~that ~~use~~the ofCompany ~~natural~~committed ~~gas.~~multiple ~~Additionally,~~violations ~~UGI~~of ~~Gas~~federal ~~has~~and ~~proposed~~state agas ~~4.5%~~pipeline ~~negative~~regulations ~~surcharge~~in ~~applicable~~connection towith ~~all~~its ~~customer~~emergency ~~distribution~~response ~~service~~leading ~~bills~~up to ~~return $26.2 million of tax benefits experienced by UGI Utilities over~~ the ~~period January 1~~explosion, ~~2018~~and toit ~~June~~requested ~~30,~~that ~~2018, inclusive of interest. As proposed,~~ the ~~negative~~PAPUC ~~surcharge~~order ~~will become effective for a twelve-month period beginning on~~ the ~~effective~~Company ~~date~~to ofpay ~~the~~approximately $2.1 ~~new~~million in ~~base~~civil ~~rates.~~penalties, ~~UGI~~which ~~Gas~~ is ~~requesting that~~ the ~~new~~maximum ~~gas~~allowable ~~rates~~fine. ~~become~~On ~~effective~~November ~~March 29~~16, ~~2019. However~~2018, the ~~PAPUC~~Company ~~typically~~filed ~~suspends~~its ~~the~~formal ~~effective~~written ~~date~~answer ~~for~~contesting ~~general~~the ~~base~~BIE ~~rate~~complaint. ~~proceedings~~The ~~for~~matter aremains ~~period~~pending ~~not~~before ~~to exceed nine months after~~ the ~~filing date to allow for investigation and public hearings~~PAPUC. ~~The~~See ~~Company~~additional ~~cannot~~discussion ~~predict~~in ~~the~~Note ~~timing~~9 orto the ~~ultimate~~Condensed ~~outcome~~Consolidated ofFinancial ~~the rate case review process~~Statements.

On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase 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 the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $3.2 million annual base distribution rate increase for Electric Utility, effective October 27, 2018. As part of the final order, Electric Utility provided customers with a one-time $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.34

Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017, explosion in Manor Township, Lancaster County, Pennsylvania, that resulted in the death of one Company employee and injuries to two Company employees and one sewer authority employee, and destroyed two residences and damaged several other homes, the BIE filed a formal complaint at the PAPUC in which BIE alleged that the Company committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion, and it requested that the PAPUC order the Company to pay approximately $2.1 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.

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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 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 ~~December~~ March 31, ~~2018~~2019, Gas Utility had $30.38 million of restricted cash in brokerage accounts. At ~~December~~March 31, ~~2018~~2019, the fair values of our natural gas futures and option contracts were ~~not~~gains ~~material~~of $1.0 million.

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 forward electricity purchase contracts, associated with our Electric Utility operations. At ~~December~~March 31, ~~2018~~2019, all of our Electric Utility’s forward electricity purchase contracts were subject to the NPNS exception.

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~~At ~~amount~~March 31, of2019, ~~unrealized~~the ~~losses~~fair onvalues ~~these~~of ~~contracts~~our ~~and~~gasoline ~~associated~~futures ~~volumes~~contracts ~~under contract at December 31, 2018~~ were not material.

Interest Rate Risk

Our variable-rate debt at ~~December~~March 31, ~~2018~~2019, includes short-term borrowings and a variable-rate term loan. These debt agreements have interest rates that are generally indexed to short-term market interest rates. At ~~December~~March 31, ~~2018~~2019, combined borrowings outstanding under these variable-rate debt agreements totaled $~~414~~222.82 million.

UGI Utilities’ variable-rate term loan has an interest rate 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 the variable-rate term loan at 3.00% beginning September 30, 2019 through July 2022. We have designated this forward-starting interest rate swap as a cash flow hedge. At ~~December~~March 31, ~~2018~~2019, the fair value of this interest rate swap was a loss of $12.75 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 ~~December~~March 31, ~~2018~~2019.

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, which could materially affect our business, financial condition or future results. The risks described in our 2018 Annual Report 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
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
10.1	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI and Utilities Employees.
10.1	Form of Change in Control Agreement between UGI Utilities, Inc. and Mr. Robert Beard.
10.2	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI and Utilities Employees.
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.
10.3	UGI Utilities, Inc. Executive Annual Bonus Plan as amended November 15, 2018.
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.
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2019, 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.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2019, 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 March 31, 2019, 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

10.1	Form of ~~Change~~UGI inCorporation ~~Control~~2013 ~~Agreement~~Omnibus ~~between~~Incentive ~~UGI~~Compensation ~~Utilities,~~Plan ~~Inc.~~Nonqualified ~~and~~Stock ~~Mr.~~Option ~~Robert~~Grant ~~Beard~~Letter for UGI and Utilities Employees.
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.
10.2	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI and Utilities Employees.
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.
10.3	UGI Utilities, Inc. Executive Annual Bonus Plan as amended November 15, 2018.
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.
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2019, 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 March 31, 2019, 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 March 31, 2019, 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:	~~February~~May 78, 2019	By:	/s/ Daniel J. Platt
			Daniel J. PlattVice President - Finance andChief Financial Officer
Date:	~~February~~May 78, 2019	By:	/s/ Megan Mattern
			Megan MatternController & Principal Accounting Officer

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