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

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).SEC. They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2017, condensed consolidated balance sheet data2018, Condensed Consolidated Balance Sheet was derived from audited financial statements but dodoes not include all footnote disclosures required by accounting principles generally accepted infrom the United States of America (“GAAP”).annual financial statements.

These financial statements should be read in conjunction with the financial statements and related notes included in ourCompany’s 2018 Annual Report on Form 10-K for the fiscal year ended September 30, 2017 (“the Company’s 2017 Annual Report”).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.

At December 31, 2017,June 30, 2019, UGI Utilities was a party to fivefour principal storage contract administrative agreements (“SCAAs”) which haveSCAAs with terms of up to three years. FourAll four of the SCAAs were with UGI Energy Services LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 13) and one of the SCAAs was with a non-affiliate.14). Pursuant to the SCAAs, UGI Utilities has, among other things, released certain natural gas storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated natural gas storage

inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

In accordance with GAAP as determined by ASC 740, “Income Taxes,” we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three and nine months ended December 31, 2017, containJune 30, 2018, contained provisional estimates of the impact of the TCJA. These amounts arewere considered provisional because they useused estimates for which tax returns havehad not yet been filed and because estimated amounts may becould have been impacted by future regulatory and accounting guidance if and when issued. We will adjust theseadjusted provisional amounts as further information becomesbecame available and as we refinerefined our calculations. As permitted by recent guidance issued by the SEC Staff Bulletin No. 118, these adjustments will occuroccurred during athe reasonable “measurement period” not to exceeddefined 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 remeasuringremeasurement of our existing federal deferred income tax assets and liabilities as of the date of enactment.from 35% to 21%. Because a significant amount of the reduction relatesrelated to our regulated utility plant assets, most of the reduction to our excess deferred income taxes iswas not being recognized immediately in income tax expense. During the threenine months ended December 31, 2017,June 30, 2018, the amount of the reduction in our net deferred income tax liabilitiestaxes that reduced income tax expense totaled $8,122.$9,254.

In order for utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred federal income taxes resulting from the remeasurement of deferred income taxes on regulated utility plant be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. AtIn December 31, 2017, we have recorded a regulatory liability of $216,098 associated with the excess deferred federal income taxes related to our regulated utility plant assets. ThisThe regulatory liability has beenwas 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.

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”)core-market customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel and power costs or refunds. Net unrealized (losses) gains on such contracts at December 31, 2017,June 30, 2019, September 30, 2017,2018, and December 31, 2016,June 30, 2018, were $(1,720)$(2,141), $146$2,856 and $6,927,$1,863, respectively.

For Pennsylvania utilities that were in a general base rate proceeding, including Electric Utility, is entitledno negative surcharge applied. The tax benefits that accrued during the period January 1, 2018 through October 26, 2018, the date before Electric Utility’s base rate case became effective (see below), were refunded to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at December 31, 2017, September 30, 2017, and December 31, 2016, were not material.Electric Utility ratepayers through a one-time bill credit.

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

for an $11,250 PNG annual base distribution rate increase for PNG. Theincrease. On August 31, 2017, the PAPUC approved the Joint Petition and the increase became effective on October 20, 2017.

On October 31, 2017,February 1, 2019, UGI Utilities entered intoissued in a $125,000 unsecured variable-rate term loan agreement (the “Term Loan”) withprivate placement $150,000 of 4.55% Senior Notes due February 1, 2049. The 4.55% Senior Notes were issued pursuant to a group of banks which initially matures on October 30, 2018.  Such maturity will be automatically extended to October 30, 2022, afterNote Purchase Agreement dated December 21, 2018, between UGI Utilities receives a securities certificateand 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 PUC authorizing issuancesale of the security and upon delivery of such certificate to the agent.  Proceeds from the Term Loan4.55% Senior Notes were used to repay revolving credit balancesreduce short-term borrowings and for general corporate purposes. The outstanding principal4.55% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The 4.55% Senior Notes require UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

On June 27, 2019, UGI Utilities entered into the UGI Utilities 2019 Credit Agreement with a group of banks providing for borrowings up to $350,000 (including a $100,000 sublimit for letters of credit). The Company may request an increase in the amount of loan commitments under the Term Loan is payable in equal quarterly installmentsUGI Utilities 2019 Credit Agreement to a maximum aggregate amount of $1,563$150,000. Concurrently with entering into the balance ofUGI Utilities 2019 Credit Agreement, the principal being due and payable in full on the maturity date.Company terminated its existing $450,000 revolving credit agreement dated March 27, 2015. Under the Term Loan,UGI Utilities 2019 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875%1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The Term LoanUGI Utilities 2019 Credit Agreement requires UGI Utilities not to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. Becausedefined, of 0.65 to 1.0. The UGI Utilities has not yet2019 Credit Agreement is currently scheduled to expire in June 2020, but will be extended to June 2024 if on or before June 25, 2020, UGI Utilities satisfies certain requirements relating to approval by the PAPUC. UGI Utilities is currently seeking such PAPUC approval.

EachPrior to the Utility Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into a consent order and agreement (“COA”)were subject to COAs with the Pennsylvania Department of Environmental Protection (“DEP”)PADEP to address the remediation of specified former MGPsMGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the Utility Merger, UGI Utilities, as the successor to CPG and PNG, are eachis 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.cap (i.e. minimum expenditure threshold). The CPG COA includes an obligationcost cap of the three COAs, in the aggregate, is

$5,350. The COA environmental costs capsthree COAs are $2,500, $1,750, and $1,100, for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG arecurrently scheduled to terminate at the end of 2031, 2020 and 2020. At June 30, 2019, September 30, 2018 and 2019, respectively. At December 31, 2017, SeptemberJune 30, 2017 and December 31, 2016,2018, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPGtotaled $47,560, $50,970, and PNG totaled $53,409, $54,250, and $55,300,$52,231, respectively. UGI Utilities CPG and PNG havehas recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 6)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 CPG and PNG receivereceives ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.

From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that, under applicable law, UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by a former subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At December 31, 2017,June 30, 2019, September 30, 20172018 and December 31, 2016,June 30, 2018, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material.

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.

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”).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 nearly allcertain active and retired employees (“Other Postretirement Plans”).employees.

The service cost component of our pension and other postretirement plans, net of amounts capitalized, are reflected in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income. The non-service cost component, net of amounts capitalized, are reflected in “Pension and other postretirement plans non-service income (expense)” on the Condensed Consolidated Statements of Income. Net periodic pension expense and other postretirement benefit costs include the following components:

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”)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 amountcash 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 threenine months ended December 31, 2017June 30, 2019 and 2016.2018.

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

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, 2017, September 30, 2017 and December 31, 2016:hierarchy:

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.

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types oftype 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 31, 2017,June 30, 2019, September 30, 20172018 and December 31, 2016June 30, 2018 were as follows:

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,

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUCPAPUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”)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, 2017,June 30, 2019, September 30, 20172018 and December 31, 2016,June 30, 2018, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.416.5 million dekatherms, 14.823.2 million dekatherms and 11.716.8 million dekatherms, respectively. At December 31, 2017,June 30, 2019, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 915 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 sheetsCondensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 6)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, 2017,June 30, 2019, September 30, 20172018 and December 31, 2016,June 30, 2018, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. At December 31, 2017,June 30, 2019, September 30, 20172018 and December 31, 2016,June 30, 2018, the total volumes associated with gasoline futures contracts were not material.

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

As of December 31, 2017,June 30, 2019, September 30, 20172018 and December 31, 2016,June 30, 2018, we had no unsettled IRPAs. At December 31, 2017,June 30, 2019, the amount of net losses associated with IRPAsinterest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3,485.approximately $3,500.

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2017 andJune 30, 2019, September 30, 2017,2018 and June 30, 2018, restricted cash in brokerage accounts totaled $3,665$4,255, $1,190 and $3,046,$805, respectively. At December 31, 2016, there were no such amounts.

Derivative assets and liabilities are presented net by counterparty on the condensed consolidated balance sheetsCondensed 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

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 sheetsCondensed 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.

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of December 31, 2017, September 30, 2017 and December 31, 2016:offsetting: