UNITED STATES

(Exact name of registrant as specified in its charter)

2525 N. 12th Street, Suite 360, Reading,One UGI Drive, Denver, PA 1961217517

(Address of principal executive offices) (Zip Code)

(610) 796-3400

(Registrant’s telephone number, including area code)

(unaudited)

UGI UTILITIES, INC. AND SUBSIDIARIES

(unaudited)

(Thousands of dollars)

UGI UTILITIES, INC. AND SUBSIDIARIES

(unaudited)

(Thousands of dollars)

UGI UTILITIES, INC. AND SUBSIDIARIES

(unaudited)

(Thousands of dollars)

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.”

Basis of Presentation. Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or the “Company”).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 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 disclosures required by accounting principles generally accepted in the United States of America (“GAAP”).GAAP.

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.

current events, historical experiencerelated 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 various other assumptionsto 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 believed to be reasonable underservice contracts incurred beginning October 1, 2018. The adoption of the circumstances. Accordingly, actualnew guidance did not have a material impact on our results may be different from these estimatesof operations for the three and assumptions.six months ended March 31, 2019.

The guidance provided under ASU 2014-09, as amended, supersedes theCompany recognizes revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 requires that an entity recognize revenue to depict the transferwhen control of promised goods or services is transferred to customers in an amount that reflects the consideration to which the entity expectswe expect to be entitled in exchange for those goods or services. The new guidance is effectiveCompany generally has the right to consideration from a customer in an amount that corresponds directly with the value to the customer for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption.

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 six months ended DecemberMarch 31, 2017, contain2018, 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 threesix months ended DecemberMarch 31, 2017,2018, the amount of the reduction in our net deferred income tax liabilitiestaxes 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 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 DecemberMarch 31, 2017,2019, September 30, 2017,2018, and DecemberMarch 31, 2016,2018, were $(1,720), $146$1,047, $2,856 and $6,927,$269, respectively.

For Pennsylvania utilities that were in a general base rate proceeding, including Electric Utility, is entitledno 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 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 January 26, 2018, Electric Utility filed a rate request with the PUCPAPUC to increase its annual base distribution revenues by $9,200.$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 requested thateffective October 27, 2018. As part of the new electric rates become effective March 27,final order, Electric Utility provided customers with a one-time $210 billing credit associated with 2018 althoughTCJA tax benefits. On November 26, 2018, the PUC typically suspendsPennsylvania Office of Consumer Advocate filed an appeal to the effective date for general base rate proceedings to allow for investigationPennsylvania Commonwealth Court challenging the PAPUC’s acceptance of the Company’s use of a fully projected future test year and public hearings. This review process is expected to last up to nine months; however, thehandling of consolidated federal income tax benefits. The Company cannot predict the timing or the ultimate outcome of the rate case review process.this appeal.

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 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 for PNG. Theincrease. On August 31, 2017, the PAPUC approved the Joint Petition and the increase became effective on October 20, 2017.

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 obligation to plug specified natural gas wells.cost 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 March 31, 2019, September 30, 2018 and 2019, respectively. At DecemberMarch 31, 2017, September 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 $50,844, $50,970, and PNG totaled $53,409, $54,250, and $55,300,$51,941, 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 DecemberMarch 31, 2017,2019, September 30, 20172018 and DecemberMarch 31, 2016,2018, 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.

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 threesix months ended DecemberMarch 31, 20172019 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 DecemberMarch 31, 2017,2019, September 30, 20172018 and DecemberMarch 31, 20162018 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 DecemberMarch 31, 2017,2019, September 30, 20172018 and DecemberMarch 31, 2016,2018, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.411.6 million dekatherms, 14.823.2 million dekatherms and 11.712.7 million dekatherms, respectively. At DecemberMarch 31, 2017,2019, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 912 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 DecemberMarch 31, 2017,2019, September 30, 20172018 and DecemberMarch 31, 2016,2018, 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 DecemberMarch 31, 2017,2019, September 30, 20172018 and DecemberMarch 31, 2016,2018, 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 DecemberMarch 31, 2017,2019, September 30, 20172018 and DecemberMarch 31, 2016,2018, we had no unsettled IRPAs. At DecemberMarch 31, 2017,2019, 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.

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At DecemberMarch 31, 2017 and2019, September 30, 2017,2018 and March 31, 2018, restricted cash in brokerage accounts totaled $3,665$837, $1,190 and $3,046,$1,572, respectively. At December 31, 2016, there were no such amounts.

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 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:

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the condensed consolidated statementsCondensed Consolidated Statements of incomeIncome and changes in AOCI for the three and six months ended DecemberMarch 31, 20172019 and 2016:2018:

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.