10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

________________

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2017

Commission file number 1-1398

UGI UTILITIES, INC.

(Exact name of registrant as specified in its charter)

Pennsylvania	23-1174060
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

2525 N. 12^th Street, Suite 360

Reading, PA 19612

(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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

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 ¨

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 ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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 Act). Yes ¨No þ

At November 14, 2017, 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.

The Registrant meets the conditions set forth in General Instruction I(1)(a)and (b) of Form 10-K and is therefore filing this Form 10-K with the reduceddisclosure format permitted by that General Instruction.

TABLE OF CONTENTS

	Page
Forward-Looking Information	3
PART I:
Items 1. and 2. Business and Properties	4
Item 1A. Risk Factors	10
Item 1B. Unresolved Staff Comments	13
Item 3. Legal Proceedings	13
Item 4. Mine Safety Disclosures	13
PART II:
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	13
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	25
Item 8. Financial Statements and Supplementary Data	25
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	25
Item 9A. Controls and Procedures	25
Item 9B. Other Information	26
PART III:
Item 14. Principal Accounting Fees and Services	26
PART IV:
Item 15. Exhibits and Financial Statement Schedules	27
Item 16. Form 10-K Summary	31
Signatures	33
Index to Financial Statements and Financial Statement Schedules	F- 1

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FORWARD-LOOKING INFORMATION

Information contained in this Annual Report on Form 10-K may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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 our Risk Factors included in Item 1A herein and the following important factors which 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; and (17) the interruption, disruption, failure or malfunction of our information technology systems, including due to cyber attack.

These factors 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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PART I:

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

GENERAL

UGI Utilities, Inc. (“UGI Utilities” or the “Company”) is a public utility company that owns and operates three natural gas distribution utilities in Pennsylvania and portions of one Maryland county and an electric utility in Pennsylvania. We are a wholly owned subsidiary of UGI Corporation (“UGI”).

The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of UGI Utilities, UGI Penn Natural Gas, Inc. (“PNG”), and UGI Central Penn Gas, Inc. (“CPG”). Gas Utility serves over 635,000 customers in eastern and central Pennsylvania and more than five hundred customers in portions of one Maryland county. UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas”. The Electric Utility segment (“Electric Utility”) consists of the regulated electric distribution business of UGI Utilities, serving approximately 62,000 customers in northeastern Pennsylvania. Gas Utility is regulated by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to its several hundred customers in Maryland, the Maryland Public Service Commission. Electric Utility is regulated by the PUC.

UGI Utilities was incorporated in Pennsylvania in 1925. Our executive offices are located at 2525 N. 12th Street, Suite 360, Reading, Pennsylvania 19612, and our telephone number is (610) 796-3400. In this report, the terms “Company” and “UGI Utilities,” as well as the terms, “our,” “we,” and “its,” are sometimes used to refer to UGI Utilities, Inc. or, collectively UGI Utilities, Inc. and its consolidated subsidiaries. The terms “Fiscal 2018”, “Fiscal 2017”, “Fiscal 2016” and “Fiscal 2015” refer to the fiscal years ended September 30, 2018, September 30, 2017, September 30, 2016 and September 30, 2015, respectively.

GAS UTILITY

Service Area; Revenue Analysis

Gas Utility provides natural gas distribution services to over 635,000 customers in certificated portions of 44 eastern and central Pennsylvania counties through its distribution system. Contemporary materials, such as plastic or coated steel, comprise approximately 90% of Gas Utility's 12,300 miles of gas mains, with bare steel pipe comprising approximately 8% and cast iron pipe comprising approximately 2% of Gas Utility's gas mains. In accordance with Gas Utility’s agreement with the PUC, Gas Utility will replace the cast iron portion of its gas mains by March 2027 and the bare steel portion of its gas mains by September 2041. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock Haven, Pittston, Pottsville, and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility's service area are major production centers for basic industries such as specialty metals, aluminum, glass, and paper product manufacturing. Gas Utility also distributes natural gas to more than 500 customers in portions of one Maryland county.

System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2017 was approximately 243 billion cubic feet (“bcf”). System sales of gas accounted for approximately 23% of system throughput, while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for approximately 77% of system throughput.

Sources of Supply and Pipeline Capacity

Gas Utility is permitted to recover prudently incurred costs of natural gas it sells to its customers. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures” and Note 4 to Consolidated Financial Statements. Gas Utility meets its service requirements by utilizing a diverse mix of natural gas purchase contracts with marketers and producers, along with storage and transportation service contracts. These arrangements enable Gas Utility to purchase gas from Gulf Coast, Mid-Continent, Appalachian and Marcellus sources. For its transportation and storage functions, Gas Utility has long-term agreements with a number of pipeline companies, including Texas Eastern Transmission, LP, Columbia Gas Transmission, LLC, Transcontinental Gas Pipeline Company, LLC, Dominion Transmission, Inc., ANR Pipeline Company, and Tennessee Gas Pipeline Company, L.L.C.

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Gas Supply Contracts

During Fiscal 2017, Gas Utility purchased approximately 77.2 bcf of natural gas for sale to retail core-market customers (principally comprised of firm- residential, commercial and industrial customers that purchase their gas from Gas Utility (“retail core-market”)) and off-system sales customers. Eighty-five percent (85%) of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 15% of gas purchased by Gas Utility was supplied by approximately 35 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 12 months. Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the months of November through March.

Seasonality

Because many of its customers use gas for heating purposes, Gas Utility’s sales are seasonal. For Fiscal 2017, approximately 60% of Gas Utility's sales volume was supplied, and approximately 90% of Gas Utility’s operating income was earned, during the peak heating season from October through March.

Competition

Natural gas is a fuel that competes with electricity and oil and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of the equipment. Natural gas generally benefits from a competitive price advantage over oil, electricity, and propane, although the price gap between natural gas and oil narrowed in recent years due to a reduction in the price of oil. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility responds to this competition with marketing and sales efforts designed to retain, expand, and grow its customer base.

In substantially all of its service territories, Gas Utility is the only regulated gas distribution utility having the right, granted by the PUC or by law, to provide gas distribution services. All of Gas Utility’s customers, including core-market customers, have the right to purchase gas supplies from entities other than natural gas distribution utility companies.

A number of Gas Utility's commercial and industrial customers have the ability to switch to an alternate fuel at any time and, therefore, are served on an interruptible basis under rates that are competitively priced with respect to the alternate fuel. Margin from these customers, therefore, is affected by the difference or “spread” between the customers’ delivered cost of gas and the customers’ delivered cost of the alternate fuel, the frequency and duration of interruptions, and alternative firm service options. See “Gas Utility and Electric Utility Regulation and Rates - Gas Utility Rates.”

Approximately 40% of Gas Utility’s annual throughput volume for commercial and industrial customers includes non-interruptible customers with firm rates with locations that afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. In addition, more than 20% of Gas Utility’s annual throughput volume for commercial and industrial customers is from customers who are served under interruptible rates and are also in a location near an interstate pipeline. Gas Utility has 38 such customers, 34 of which have transportation contracts extending beyond Fiscal 2018. The majority of these customers are served under transportation contracts having 3- to 10-year terms and all are among the largest customers for Gas Utility in terms of annual volumes. No single customer represents, or is anticipated to represent, more than 5% of Gas Utility’s total revenues.

Outlook for Gas Service and Supply

Gas Utility anticipates having adequate pipeline capacity, peaking services, and other sources of supply available to it to meet the full requirements of all firm customers on its system through Fiscal 2018. Supply mix is diversified, market priced, and delivered pursuant to a number of long-term and short-term primary firm transportation and storage arrangements, including transportation contracts held by some of Gas Utility's larger customers.

During Fiscal 2017, Gas Utility supplied transportation service to nine electric generation facilities and installed new service to one co-generation facility. Gas Utility continues to seek new residential, commercial, and industrial customers for both firm and interruptible service. In Fiscal 2017, Gas Utility connected approximately 2,000 new commercial and industrial customers. In the residential market sector, Gas Utility added over 12,000 residential heating customers during Fiscal 2017. Approximately 65% of these customers converted to natural gas heating from other energy sources, mainly oil and electricity. New home construction and existing non-heating gas customers who added gas heating systems to replace other energy sources primarily accounted for the other residential heating connections in Fiscal 2017.

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UGI Utilities continues to monitor and participate, where appropriate, in rulemaking and individual rate and tariff proceedings before the Federal Energy Regulatory Commission (“FERC”) affecting the rates and the terms and conditions under which Gas Utility transports and stores natural gas. Among these proceedings are those arising out of certain FERC orders and/or pipeline filings that relate to (i) the pricing of pipeline services in a competitive energy marketplace; (ii) the flexibility of the terms and conditions of pipeline service tariffs and contracts; and (iii) pipelines' requests to increase their base rates, or change the terms and conditions of their storage and transportation services.

UGI Utilities' objective in negotiations with interstate pipeline and natural gas suppliers, and in proceedings before regulatory agencies, is to ensure availability of supply, transportation, and storage alternatives to serve market requirements at the lowest cost possible, taking into account the need for security with guaranteed deliverability and reliability of supply. Consistent with that objective, UGI Utilities negotiates the terms of firm transportation capacity on all pipelines serving it, arranges for appropriate storage and peak-shaving resources, negotiates with producers for competitively priced gas purchases and aggressively participates in regulatory proceedings related to transportation rights and costs of service.

ELECTRIC UTILITY

Service Area; Sales Analysis

Electric Utility supplies electric service to approximately 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania through a system consisting of over 2,200 miles of transmission and distribution lines and 13 substations. For Fiscal 2017, approximately 55% of sales volume came from residential customers, 33% from commercial customers, and 12% from industrial and other customers.

Sources of Supply

Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed and approved by the PUC. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures” and Note 4 to Consolidated Financial Statements. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers. During Fiscal 2017, eleven retail electric generation suppliers provided energy for customers representing approximately 26% of Electric Utility’s sales volume. See “Gas Utility and Electric Utility Regulation and Rates - Electric Utility Rates.”

Competition

As a result of the Electricity Generation Customer Choice and Competition Act (“ECC Act”), all Pennsylvania retail electric customers have the ability to choose their retail electric generation supplier. Under the ECC Act and Act 129 of 2008, which revised the default service requirements contained in Chapter 28 of the Public Utility Code, Electric Utility remains the “default service” provider for its customers who do not choose an alternate retail electric generation supplier. In Fiscal 2017, Electric Utility served nearly all of the electric customers within its service territory and is the only regulated electric utility having the right, granted by the PUC or by law, to distribute electricity in its service territory. As an energy source, electricity competes with natural gas, oil, propane, and other heating fuels for residential heating purposes.

The terms and conditions under which Electric Utility provides default service, and rules governing the rates that may be charged for such service, have been established in the Default Service (“DS”) rate plans approved by the PUC. Consistent with the terms of the DS rate plans, default service rates are designed to recover all reasonable and prudent costs incurred in providing electricity to default service customers. See “Gas Utility and Electric Utility Regulation and Rates - Electric Utility Rates.”

GAS UTILITY AND ELECTRIC UTILITY REGULATION AND RATES

Pennsylvania Public Utility Commission Jurisdiction

UGI Utilities’ gas and electric utility operations are subject to regulation by the PUC as to rates, terms and conditions of service, accounting matters, issuance of securities, contracts and other arrangements with affiliated entities, gas and electric safety and various other matters. There are primarily two types of rates that UGI Utilities may charge customers for gas and electric service: (i) rates designed to recover purchased gas costs (“PGCs”) and electric default service costs; and (ii) rates designed to recover costs other than PGCs and electric default service costs. Rates designed to recover costs other than PGCs and electric default service costs are primarily established in general base rate proceedings.

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Gas Utility Rates

In January 2016, UGI Gas filed a request with the PUC for its first base rate increase in over 21 years. On October 14, 2016, the PUC approved a settlement that was effective October 19, 2016 and resulted in a $27.0 million increase in annual base rate revenues. The settlement permitted UGI Gas to establish new reconcilable surcharges to permit the timely recovery of the costs of universal service programs designed to assist low income customers, and costs associated with a new energy efficiency and conservation program. UGI Gas was also permitted to implement a new Technology and Economic Development Rider to provide additional flexibility in establishing the rates of smaller volume commercial and industrial customers to encourage cost-effective load growth.

On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s base operating revenues for residential, commercial, and industrial customers by $21.7 million annually. On August 31, 2017, the PUC approved a settlement that permitted PNG to increase its annual base distribution rates by $11.3 million, effective October 20, 2017. The settlement also permitted PNG to recover costs associated with a new energy efficiency and conservation program, and permitted PNG to implement a new Technology and Economic Development Rider to provide additional flexibility in establishing the rates of smaller volume commercial and industrial customers to encourage cost-effective load growth.

On February 20, 2014, the PUC entered an order approving a Growth Extension Tariff (“GET Gas”) program under which UGI Gas, PNG, and CPG may invest up to $5 million per year for five years, or $75 million in the aggregate for all three utilities, to extend natural gas utility pipelines to provide service to unserved and underserved areas within their respective territories. Under the GET Gas program, customers utilizing the extended pipeline to receive natural gas will pay a monthly surcharge over a 10-year period to cover the cost of the extension. Gas Utility began connecting customers under the GET Gas program in October 2014.

In February 2012, Act 11 of 2012 (“Act 11”) became effective. Among other things, Act 11 authorized the PUC to permit electric and gas distribution companies, between base rate cases and subject to certain conditions, to recover reasonable and prudent costs incurred to repair, improve, or replace eligible property through a Distribution System Improvement Charge (“DSIC”) assessed to customers. DSICs are subject to quarterly adjustment, are capped at five percent of total customer charges absent a PUC-granted exception, may only be sought if a base rate case has been filed within the last five years, and are subject to certain earnings tests. In addition, Act 11 requires affected utilities to obtain approval of long-term infrastructure improvement plans (“LTIIP”) from the PUC. Act 11 also authorized electric and gas distribution companies to utilize a fully forecasted future test year when establishing rates in base rate cases before the PUC.

The PUC approved LTIIPs for UGI Gas, PNG, and CPG in 2014, and on June 30, 2016, approved a revised LTIIP for these entities that increases the projected spend on DSIC-eligible property for the 2016-2018 period from approximately $266.3 million to $402.8 million. The PUC also approved DSIC mechanisms for PNG and CPG in September 2014 and July 2015, respectively; both PNG and CPG are collecting revenues under their respective DSICs. On March 31, 2016, PNG and CPG filed petitions with the PUC seeking to increase the cap on their DSIC rate mechanisms from five percent to ten percent of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration of an LTIIP filing in 2018.

On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism effective January 1, 2017.  Revenues collected pursuant to the mechanism will be subject to refund and recoupment based on the PUC’s final resolution of certain matters set aside for hearing before an Administrative Law Judge.  To commence recovery of revenue under the mechanism, UGI Gas must first place into service a threshold level of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.  Achievement of that threshold is likely to occur in Fiscal 2018.

The gas service tariffs for UGI Gas, PNG, and CPG contain PGC rates applicable to firm retail rate schedules for customers who do not obtain natural gas supply service from an alternative supplier. These PGC rates permit recovery of substantially all of the prudently incurred costs of natural gas that UGI Gas, PNG, and CPG sell to their customers. PGC rates are reviewed and approved annually by the PUC. UGI Gas, PNG, and CPG may request quarterly or, under certain conditions, monthly adjustments to reflect the actual cost of gas. Quarterly adjustments become effective on one day’s notice to the PUC and are subject to review during the next annual PGC filing. Each proposed annual PGC rate is required to be filed with the PUC six months prior to its effective date. During this period, the PUC holds hearings to determine whether the proposed rate reflects a least-cost fuel procurement policy consistent with the obligation to provide safe, adequate and reliable service. After completion of these hearings, the PUC issues an order permitting the collection of gas costs at levels that meet such standard. The PGC mechanism also provides for an annual reconciliation and for the payment or collection of interest on over and under collections. UGI Gas, PNG, and CPG may assign to and recover from alternative natural gas suppliers the costs of gas supply contracts and transportation capacity acquired to serve the needs of smaller volume customers who elect to receive their natural gas supply service from an alternative supplier.

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On April 28, 2017, UGI Gas, PNG, and CPG filed the Gas Delivery Enhancement Rider (“GDE”) with the PUC. The GDE provides a tariff mechanism to recover from certain non-choice transportation customers a portion of the costs associated with temporary mobile sources of gas supply and interstate pipeline demand charge enhancements (collectively, “GDE Charges”) that are incurred to achieve least-cost timely solutions to system reinforcement needs or for pipeline integrity management activities. GDE Charges exclude costs that are recovered through existing PGC rate mechanisms as established in each company’s annual 66 Pa.C.S. § 1307(f) PGC proceeding. On August 31, 2017, the PUC entered an order approving the GDE Rider for all three companies.

On June 23, 2016, Act 47 of 2016 was enacted. Act 47 revised the interest rates that applied to PGC over and under collections, removed the requirement that over and under collections be assessed to customers who leave default service to obtain natural gas from an alternative supplier by way of a so-called migration rider, provided additional assurance of cost recovery for PGC costs, and granted natural gas distribution companies the right to recover the reasonable costs incurred to implement customer choice on a full and current basis through a reconcilable rate mechanism. Gas Utility implemented the interest rate revision and migration rider provisions of Act 47 in December 2016.

Electric Transmission and Wholesale Power Sale Rates

FERC has jurisdiction over the rates and terms and conditions of service of electric transmission facilities used for wholesale or retail choice transactions. Electric Utility owns electric transmission facilities that are within the control area of the PJM Interconnection, LLC (“PJM”) and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. PJM is a regional transmission organization that regulates and coordinates generation supply and the wholesale delivery of electricity. Electric Utility receives certain revenues collected by PJM, determined under a formulary rate schedule that is adjusted in June of each year to reflect annual changes in Electric Utility’s electric transmission revenue requirements, when its transmission facilities are used by third parties.

FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy. Electric Utility has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates.

Electric Utility Rates

Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with the PUC. UGI Utilities’ electric utility operations are subject to regulation by the PUC as to rates, terms and conditions of service, accounting matters, issuance of securities, contracts and other arrangements with affiliated entities, electric safety and various other matters. The most recent general base rate increase for Electric Utility became effective in 1996. PUC default service regulations became applicable to Electric Utility’s provision of default service effective January 1, 2010 and Electric Utility, consistent with these regulations, has received PUC approval through May 31, 2021 of (i) default service tariff rules, (ii) a reconcilable default service cost rate recovery mechanism to recover the cost of acquiring default service supplies, (iii) a plan for meeting the post-2009 requirements of the Alternative Energy Portfolio Standards Act (“AEPS Act”), which requires Electric Utility to directly or indirectly acquire certain percentages of its supplies from designated alternative energy sources, and (iv) a reconcilable AEPS Act cost recovery rate mechanism to recover the costs of complying with AEPS Act requirements applicable to default service supplies for service rendered through May 31, 2021. Under these rules, default service rates for most customers are adjusted quarterly. On August 16, 2017, Electric Utility filed a Petition for Approval of its initial LTIIP with the PUC for the 2018-2022 time period. Electric Utility’s projected annual investment in distribution infrastructure replacement will be approximately $7.6 million beginning in Fiscal 2018, increasing to $8.3 million by the fiscal year ending September 30, 2022.

FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers

UGI Utilities is subject to Section 4A of the Natural Gas Act, which prohibits the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of natural gas or natural gas transportation subject to the jurisdiction of FERC, and FERC regulations that are designed to promote the transparency, efficiency, and integrity of gas markets.  UGI Utilities is also subject to Section 222 of the Federal Power Act, which prohibits the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of electric energy or transmission service subject to the jurisdiction of FERC, and FERC regulations that are designed to promote the transparency, efficiency, and integrity of electric markets. Under provisions of the Energy Policy Act of 2005 (“EPACT 2005”), Electric Utility is subject to certain electric reliability standards established by FERC and administered by an Electric Reliability Organization (“ERO”). Electric Utility anticipates that substantially all the costs of complying with the ERO standards will be recoverable through its PJM formulary electric transmission rate schedule.

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EPACT 2005 also granted FERC authority to impose substantial civil penalties for the violation of any regulations, orders, or provisions under the Federal Power Act and Natural Gas Act, and clarified FERC’s authority over certain utility or holding company mergers or acquisitions of electric utilities or electric transmitting utility property valued at $10 million or more.

State Tax Surcharge Clauses

UGI Utilities’ gas and electric service tariffs contain state tax surcharge clauses. The surcharges are recomputed whenever any of the tax rates included in their calculation are changed. These clauses protect UGI Utilities from the effects of increases in most of the Pennsylvania taxes to which it is subject.

Utility Franchises

UGI Utilities holds a certificate of public convenience issued by the PUC and certain “grandfather rights” predating the adoption of the Pennsylvania Public Utility Code and its predecessor statutes, which it believes are adequate to authorize it to carry on its business in substantially all of the territories to which it now renders gas or electric service. Under applicable Pennsylvania law, UGI Utilities has certain rights of eminent domain as well as the right to maintain its facilities in streets and highways in its territories.

Other Government Regulation

In addition to regulation by the PUC and FERC, the gas and electric utility operations of UGI Utilities are subject to various federal, state and local laws governing environmental matters, occupational health and safety, pipeline safety and other matters. UGI Utilities is subject to the requirements of the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation, and Liability Act, and comparable state statutes with respect to the release of hazardous substances on property owned or operated by UGI Utilities. See Note 12 to Consolidated Financial Statements.

Employees

At September 30, 2017, UGI Utilities had over 1,625 employees.

BUSINESS SEGMENT INFORMATION

The table stating the amounts of revenues, operating income and identifiable assets attributable to UGI Utilities’ operating segments for the 2017, 2016 and 2015 fiscal years appears in Note 16 to Consolidated Financial Statements included in this Report and is incorporated herein by reference.

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ITEM 1A. RISK FACTORS

RISKS RELATED TO OUR BUSINESS

Regulators may not approve the rates we request and existing rates may be challenged, which may adversely affect our results of operations.

Our Gas Utility and Electric Utility distribution operations are subject to regulation by the PUC. The PUC, among other things, approves the rates that we may charge to our utility customers, thus impacting the returns that we may earn on the assets that are dedicated to those operations. We expect that UGI Utilities and its subsidiaries will periodically file requests with the PUC to increase base rates that they charge customers. If we are required in a rate proceeding to reduce the rates we charge our utility customers, or if we are unable to obtain approval for timely rate increases from the PUC, particularly when necessary to cover increased costs, our revenue growth will be limited and earnings may decrease.

We are subject to operating and litigation risks that may not be covered byinsurance.

Our business operations are subject to all of the operating hazards and risks normally incidental to the handling, storage and distribution of combustible products, such as natural gas. These risks could result in substantial losses due to personal injury and/or loss of life, and severe damage to and destruction of property and equipment arising from explosions and other catastrophic events, including acts of terrorism. As a result, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. Additionally, environmental contamination could result in future legal proceedings. There can be no assurance that our insurance coverage will be adequate to protect us from all material expenses related to pending and future claims or that such levels of insurance would be available in the future at economical prices.

Transmission and distribution systems may not operate as planned, whichmay increase our expenses or decrease our revenues and, thus, have anadverse effect on our financial results.

Our ability to manage operational risk with respect to our transmission and distribution systems is critical to our financial results. We obtain our supply from local Marcellus Shale sources, as well as other trading points in the United States. If we experience physical capacity constraints on one or more of the interstate or intrastate natural gas pipelines that supply our business, we may not be able to supply our customers, which could have an adverse effect on our financial results. Our business also faces several risks, including the breakdown or failure of or damage to equipment or processes (especially due to severe weather or natural disasters), accidents and other factors. Operation of our transmission and distribution systems below our expectations may result in lost revenues or increased expenses, including higher maintenance costs.

Remediation costs resulting from liability from contamination claims couldreduce our net income.

We have received claims from third parties that allege that we are responsible for costs to clean up properties where we or our former subsidiaries operated a manufactured gas plant or conducted other operations. Costs we incur at sites outside of Pennsylvania cannot be recovered in future UGI Utilities' rate proceedings, and insurance may not cover all or even part of these costs. Our actual costs related to these sites may exceed our current estimates due to factors beyond our control, such as:

• the discovery of presently unknown conditions;

• changes in environmental laws and regulations;

• judicial rejection of our legal defenses to third-party claims; or

• the insolvency of other responsible parties at the sites at which we are involved.

In addition, if we discover additional contaminated sites, we could be required to incur material costs, which would reduce our net income.

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If we are unable to protect our information technology systems against service interruption, misappropriation of data, or breaches of security resulting from cyber security attacks or other events, our operations could be disrupted and our business and reputation may suffer.

In the ordinary course of business, we rely on information technology systems, including the Internet and third-party hosted services, to support a variety of business processes and activities and to store sensitive data, including (i) intellectual property, (ii) our proprietary business information and that of our suppliers and business partners, (iii) personally identifiable information of our customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities.  In addition, we rely on our information technology systems to process financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal, and tax requirements.  Despite our security measures, our information technology systems may be vulnerable to attacks by hackers or breached due to employee error, malfeasance, sabotage, or other disruptions.  A loss of our information technology systems, or temporary interruptions in the operation of our information technology systems, misappropriation of data, and breaches of security could have a material adverse effect on our business, financial condition, results of operations, and reputation.  In addition, a cyber security attack could provide a cyber intruder with the ability to control or alter our pipeline operations. Such an act could result in critical pipeline failures. While we have purchased cyber security insurance, there are no assurances that the coverage would be adequate in relation to any incurred losses.

Unforeseen difficulties with the implementation or operation of our information systems could adversely affect our internal controls and our business.

We contracted with third party consultants to assist us with the design and implementation of an information system that supports our customer management and billing systems.The efficient execution of our business is dependent upon the proper functioning of our internal information systems. Any significant failure or malfunction of our information systems may result in disruptions to our operations. Our results of operations could be adversely affected if we encounter unforeseen problems with respect to the implementation and operation of this system.

INDUSTRY-SPECIFIC RISKS

Decreases in the demand for natural gas and electricity because ofwarmer-than-normal heating season weather could adversely affect our resultsof operations, financial condition and cash flows because our rate structuredoes not contain weather normalization provisions.

Because many of our customers rely on natural gas or electricity to heat their homes and businesses, our results of operations are adversely affected by warmer-than-normal heating season weather. Weather conditions have a significant impact on the demand for natural gas and electricity for heating purposes. Accordingly, demand for natural gas and electricity used for heating purposes is generally at its highest during the peak heating season of October through March and is directly affected by the severity of the winter weather. Our rate structures do not contain weather normalization provisions to compensate for warmer-than-normal weather conditions, and we have historically sold less natural gas and electricity when weather conditions are milder and, consequently, earned less income. As a result, warmer-than-normal heating season weather could reduce our net income, harm our financial condition and adversely affect our cash flows.

Energy efficiency and technology advances, as well as price induced customerconservation, may result in reduced demand for our energy products andservices.

The trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, may reduce the demand for energy products. Prices for natural gas are subject to volatile fluctuations in response to changes in supply and other market conditions. During periods of high energy commodity costs, our prices generally increase which may lead to customer conservation. A reduction in demand could lower our revenues, and, therefore, lower our net income and adversely affect our cash flows. State and/or federal regulation may require mandatory conservation measures which would reduce the demand for our energy products. We cannot predict the materiality of the effect of future conservation measures or the effect that any technological advances in heating, conservation, energy generation or other devices might have on our operations.

Volatility in credit and capital markets may restrict our ability to grow,increase the likelihood of defaults by our customers and counterparties andadversely affect our operating results.

The volatility in credit and capital markets may create additional risks to our business in the future. We are exposed to financial market risk (including refinancing risk) resulting from, among other things, changes in interest rates and conditions in the credit

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and capital markets. Developments in the credit markets have the potential to increase our possible exposure to the liquidity, default and credit risks of our suppliers and vendors, counterparties associated with derivative financial instruments and our customers. Although we believe that current financial market conditions, if they were to continue for the foreseeable future, will not have a significant impact on our ability to fund our existing operations, such market conditions could restrict our ability to grow, limit the scope of major capital projects if access to credit and capital markets is limited, or adversely affect our operating results.

Economic recession, volatility in the stock market and the low interestrate environment may negatively impact our pension liability.

Economic recession, volatility in the stock market and the low interest rate environment have had a significant impact on our pension liability and funded status. Declines in the stock or bond market and valuation of stocks or bonds, combined with continued low interest rates, could further impact our pension liability and funded status and increase the amount of required contributions to our pension plans.

Changes in commodity market prices may have a significant negative effect on ourliquidity.

Depending on the terms of our contracts with suppliers as well as our use of financial instruments including natural gas futures and option contracts to reduce volatility in the cost of natural gas we purchase, changes in the market price of electricity and natural gas could create payment obligations for the Company and expose us to significant liquidity risks.

Our need to comply with, and respond to industry-wide changes resulting from, comprehensive, complex, and sometimes unpredictablegovernment regulations, including regulatory initiatives aimed at increasing competition within our industry, may increase our costs and limit our revenue growth,which may adversely affect our operating results.

There are many governmental regulations that have an impact on our businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company that may affect our businesses in ways that we cannot predict.

Moreover, we may be unable to timely respond to changes within the energy and utility sectors that may result from regulatory initiatives to further increase competition within our industry. Such regulatory initiatives may create opportunities for additional competitors to enter our markets and, as a result, we may be unable to maintain our revenues or continue to pursue our current business strategy.

The risk of terrorism may adversely affect the economy and the price and availability of natural gas.

Terrorist attacks may adversely impact the price and availability of natural gas as well as our results of operations, our ability to raise capital, and our future growth. The impact that the foregoing may have on our industryin general, and on us in particular, is not known at this time. An act of terror could result in disruptions of natural gas supplies and markets, cause price volatility in the cost of natural gas, and our infrastructure facilities could be direct or indirect targets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital.

In response to natural gas incidents in the United States, regulators may adopt new laws or reinterpret existing laws and regulations relating to the replacement of cast iron and bare steel natural gas pipelines which may adversely affect our results of operations and cash flows.

New federal or state laws may be adopted, or state and/or federal regulatory agencies, such as the PUC and United States Department of Transportation, may reinterpret existing laws and regulations relating to the timing of the replacement of cast iron and bare steel natural gas pipelines by all natural gas distribution and transmission companies under their respective jurisdictions. If the Company is required to comply with new or changed laws and regulations or the Company is not permitted to charge increased rates to recover a mandated increase in our costs, our cash flows and earnings may decrease.

Our operations, capital expenditures and financial results may be affectedby regulatory changes and/or market responses to global climate change.

Increased regulation of Greenhouse Gas (“GHG”) emissions, such as propane and methane, could impose significant additional costs on us, our suppliers and our customers. Some states have adopted laws and regulations regulating the emission of GHGs for some industry sectors. For example, the California Environmental Protection Agency established a Cap & Trade program that requires certain covered entities, including propane companies, to purchase allowances to compensate for the GHG emissions

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created by their business operations. In September 2009, the EPA issued a final rule establishing a system for mandatory reporting of GHG emissions. In November 2010, the EPA expanded the reach of its GHG reporting requirements to include the petroleum and natural gas industries, which include certain facilities of our natural gas distribution business. These subject facilities have been required to monitor emissions since January 2011 and to submit detailed annual reports beginning in March 2012. In October 2015, the EPA promulgated the Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (the “Clean Power Plan”), which provides standards and guidelines for reducing existing power plants’ GHG emissions and related pollutants by 2030. However, in October 2017, the EPA announced its proposal to repeal the Clean Power Plan in its entirety on the grounds that it exceeds the EPA’s delegated authority under the Clean Air Act. At this time, we cannot predict the effect that climate change regulation may have on our business, financial condition or operations in the future.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

With the exception of those matters set forth in Note 12 to Consolidated Financial Statements included in Item 8 of this Report, no material legal proceedings are pending involving the Company, or any of its properties, and no such proceedings are known to be contemplated by governmental authorities other than claims arising in the ordinary course of the Company’s business.

ITEM 4. MINE SAFETY DISCLOSURES

None.

PART II:

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

All of the outstanding shares of the Company’s Common Stock are owned by UGI and are not publicly traded.

Dividends

Cash dividends declared on the Company’s Common Stock totaled $57.7 million in Fiscal 2017, $47.0 million in Fiscal 2016, and $65.6 million in Fiscal 2015.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) discusses our results of operations and our financial condition. MD&A should be read in conjunction with our Items 1 & 2, “Business and Properties,” Item 1A, “Risk Factors” and our Consolidated Financial Statements in Item 8 below including “Segment Information” included in Note 16 to Consolidated Financial Statements.

EXECUTIVE OVERVIEW

For the second year in a row, our Gas Utility and Electric Utility experienced the effects of significantly warmer than normal weather. Fiscal 2017 temperatures based upon heating degree days were approximately 11% warmer than normal compared to temperatures that were more than 13% warmer than normal in Fiscal 2016.

Notwithstanding the significantly warmer than normal weather, UGI Utilities net income in Fiscal 2017 increased nearly 20%. UGI Utilities achieved this significant increase in earnings largely as a result of higher base rates at UGI Gas, organic customer growth and incremental revenues from distribution system improvements through distribution system improvement charges

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(“DSIC”). Our Electric Utility’s kilowatt-hour sales in Fiscal 2017 were slightly lower than the prior year principally reflecting lower air-conditioning sales due to cooler summer temperatures. The effects of the lower sales along with slightly lower transmission revenue reduced Electric Utility total margin and operating income. The higher UGI Utilities total margin was partially offset by higher Fiscal 2017 operating and administrative expenses.

Notwithstanding the earnings headwinds brought on by the warm weather, during Fiscal 2017 we made significant strategic and operational progress in support of our long-term goals. Our Gas Utility continues to grow as demand for natural gas remains strong across both the residential and commercial customer segments and as the price difference between natural gas and oil has expanded in the last fiscal year. Gas Utility continued to execute on its infrastructure replacement and system betterment program with record capital expenditures in Fiscal 2017. In January 2017, PNG filed for an increase in annual base rate revenues and received PUC approval for an increase in base rates of $11.3 million. This base rate increase became effective on October 20, 2017. In September 2017, UGI Utilities rolled out its new, state-of-the -art customer information system which will significantly enhance the customer experience and provide for streamlined processes within the company. We will continue to invest in technology change during Fiscal 2018 and beyond with a number of significant IT projects scheduled over the next several years.

During Fiscal 2017, UGI Utilities also issued $100 million of long-term debt to provide additional long-term financing of its infrastructure betterment capital program and information technology initiatives (see Note 7 to Consolidated Financial Statements). We believe we have sufficient liquidity from our revolving credit facility, cash flow from operations and the ability to issue long-term debt at attractive rates to fund business operations during Fiscal 2018 (see “Financial Condition and Liquidity” below and Note 7 to Consolidated Financial Statements for additional information on the credit facility).

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ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare the Company’s results of operations for Fiscal 2017, Fiscal 2016 and Fiscal 2015.

Fiscal 2017 Compared with Fiscal 2016

(Dollars in millions)	2017			2016			Increase (Decrease)
Gas Utility:
Revenues	$	799.1		$	677.4		$	121.7		18.0	%
Total margin (a)	$	480.8		$	438.2		$	42.6		9.7	%
Operating and administrative expenses	$	192.0		$	174.5		$	17.5		10.0	%
Operating income	$	219.6		$	189.4		$	30.2		15.9	%
Income before income taxes	$	181.3		$	153.6		$	27.7		18.0	%
System throughput — bcf
Core market	70.4			66.2			4.2			6.3	%
Total	243.1			212.4			30.7			14.5	%
Degree days — % (warmer) than normal (b)	(11.1		)%	(13.6		)%	—			—
Electric Utility:
Revenues	$	88.5		$	91.1		$	(2.6	)	(2.9	)%
Total margin (a)	$	34.8		$	35.6		$	(0.8	)	(2.2	)%
Operating and administrative expenses	$	20.3		$	18.2		$	2.1		11.5	%
Operating income	$	8.7		$	11.5		$	(2.8	)	(24.3	)%
Income before income taxes	$	6.8		$	9.6		$	(2.8	)	(29.2	)%
Distribution sales — gwh	950.6			961.6			(11.0		)	(1.1	)%

bcf — billions of cubic feet.

gwh — millions of kilowatt-hours.

(a) 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 Electric Utility gross receipts taxes, of $4.7 million and $4.8 million during Fiscal 2017 and Fiscal 2016, respectively. Gross receipt taxes are included in “Taxes other than income taxes” on the Consolidated Statements of Income.

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

Temperatures in Gas Utility’s service territory during Fiscal 2017 were 11.1% warmer than normal but 2.6% colder than during Fiscal 2016. Gas Utility core market volumes increased 4.2 bcf (6.3%) principally reflecting the effects of the slightly colder Fiscal 2017 weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 30.7 bcf reflecting significantly higher large firm delivery service volumes principally associated with service to a new natural gas-fired generation facility and the higher core market volumes. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from others. These increases were partially offset by lower interruptible delivery service volumes. Electric Utility kilowatt-hour sales were 1.1% lower than in the prior year, principally reflecting the impact on air-conditioning sales from cooler summer temperatures.

UGI Utilities Fiscal 2017 revenues increased $119.1 million reflecting a $121.7 million increase in Gas Utility revenues partially offset by slightly lower Electric Utility revenues. The higher Gas Utility revenues principally reflect an increase in core market revenues ($85.1 million), higher large firm delivery service revenues ($14.3 million) and higher off-system sales revenues ($25.0 million). The $85.1 million increase in Gas Utility core market revenues reflects higher average retail core market PGC rates ($37.0 million), the effects of the higher core market throughput ($28.0 million) and the increase in UGI Gas base rates effective October 19, 2016 ($20.1 million). The decrease in Electric Utility revenues principally reflects the lower Electric Utility volumes ($1.8 million), slightly lower average default service (“DS”) rates ($0.5 million) and lower transmission revenue ($0.4 million). Because Gas Utility and Electric Utility are subject to reconcilable PGC and DS recovery mechanisms, increases or decreases in

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the actual cost of gas or electricity associated with customers who purchase their gas or electricity from UGI Utilities impact revenues and cost of sales but have no direct effect on retail core-market margin (see Note 4 to Consolidated Financial Statements for a discussion of these recovery mechanisms). UGI Utilities cost of sales was $367.3 million in Fiscal 2017 compared with $289.8 million in Fiscal 2016, principally reflecting higher average retail core market PGC rates ($37.0 million), the higher Gas Utility retail core-market volumes ($14.0 million) and higher cost of sales associated with Gas Utility off-system sales ($25.0 million). The higher Gas Utility cost of sales is partially offset by a decrease in Electric Utility cost of sales of $1.5 million reflecting the lower volumes sold and the slightly lower DS rates.

UGI Utilities total margin increased $41.7 million principally reflecting higher total margin from Gas Utility core market customers ($32.7 million) and higher large firm delivery service total margin ($11.4 million) partially offset by lower other margin. The increase in Gas Utility core market margin principally reflects the increase in UGI Gas base rates effective October 19, 2016 ($20.1 million) and the higher core market throughput ($12.6 million). Electric Utility total margin decreased $0.8 million principally reflecting the lower volume sales and lower transmission revenue.

UGI Utilities Fiscal 2017 operating income increased $27.4 million, principally reflecting the increase in total margin ($41.7 million) and higher other operating income, net ($10.3 million). These increases in operating income were reduced by higher operating and administrative expenses ($19.7 million) and higher depreciation and amortization expense ($5.0 million) associated with increased capital expenditure activity. The higher other operating income, net, reflects a $5.8 million environmental insurance settlement, the absence of a charge recorded in the prior year related to environmental matters ($2.5 million), and lower interest on PGC overcollections ($1.6 million). The increase in UGI Utilities operating and administrative expenses in the current year reflects higher pension and employee benefits expenses ($7.0 million), higher customer accounts expense ($4.2 million) and higher regulatory asset amortization expense related to environmental remediation expenses ($1.9 million). The increase in Fiscal 2017 operating and administrative expenses also reflects the fact that Fiscal 2016 expenses were reduced by the capitalization of $5.4 million of development stage IT project costs that had been expensed in prior periods but qualified for capitalization during Fiscal 2016. UGI Utilities income before income taxes increased $24.8 million reflecting the increase in UGI Utilities operating income ($27.4 million) partially offset by higher interest expense.

Interest Expense and Income Taxes. Interest expense in Fiscal 2017 increased principally reflecting higher average long-term debt outstanding. Our income taxes as a percentage of pre-tax income for Fiscal 2017 was 38.3% compared to an effective income tax rate of 40.4% in Fiscal 2016. The lower Fiscal 2017 effective income tax rate is due primarily to the impact of excess tax benefits on share-based payments resulting from the adoption of new accounting guidance effective October 1, 2016 (see Note 3 to Consolidated Financial Statements) and the beneficial effects of higher flow through of accelerated state tax depreciation.

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Fiscal2016Compared with Fiscal2015

(Dollars in millions)	2016			2015 (c)			Decrease
Gas Utility:
Revenues	$	677.4		$	933.1		$	(255.7	)	(27.4	)%
Total margin (a)	$	438.2		$	484.5		$	(46.3	)	(9.6	)%
Operating and administrative expenses	$	174.5		$	196.9		$	(22.4	)	(11.4	)%
Operating income	$	189.4		$	226.5		$	(37.1	)	(16.4	)%
Income before income taxes	$	153.6		$	187.4		$	(33.8	)	(18.0	)%
System throughput — bcf
Core market	66.2			81.3			(15.1		)	(18.6	)%
Total	212.4			213.5			(1.1		)	(0.5	)%
Degree days — % (warmer) colder than normal (b)	(13.6		)%	6.4		%	—			—
Electric Utility:
Revenues	$	91.1		$	107.6		$	(16.5	)	(15.3	)%
Total margin (a)	$	35.6		$	39.8		$	(4.2	)	(10.6	)%
Operating and administrative expenses	$	18.2		$	20.4		$	(2.2	)	(10.8	)%
Operating income	$	11.5		$	14.2		$	(2.7	)	(19.0	)%
Income before income taxes	$	9.6		$	12.1		$	(2.5	)	(20.7	)%
Distribution sales — gwh	961.6			1,010.1			(48.5		)	(4.8	)%

(a) 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 Electric Utility gross receipts taxes, of $4.8 million and $5.6 million during Fiscal 2016 and Fiscal 2015, respectively. Gross receipt taxes are included in “Taxes other than income taxes” on the Consolidated Statements of Income.

(b) 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.

(c) Amounts exclude PNG Gas’ heating, ventilation and air-conditioning service business sold in June 2015 (see Note 16 to Consolidated Financial Statements).

Temperatures in Gas Utility’s service territory during Fiscal 2016 based upon heating degree days were 13.6% warmer than normal and 17.8% warmer than Fiscal 2015. In particular, Gas Utility temperatures in the critical heating-season month of December were 37% warmer than normal. Gas Utility core market volumes declined 15.1 bcf (18.6%) reflecting the effects of the significantly warmer weather. Total Gas Utility Fiscal 2016 distribution system throughput was about equal to Fiscal 2015 as the lower core market volumes were substantially offset by higher large firm delivery service volumes. Electric Utility kilowatt-hour sales were 4.8% lower than in the prior year principally reflecting the impact of the warmer weather on heating-related sales.

UGI Utilities Fiscal 2016 revenues decreased $273.1 million principally reflecting a $255.7 million decrease in Gas Utility revenues and a $16.5 million decrease in Electric Utility revenues. The lower Gas Utility revenues principally reflect a decrease in core market revenues ($203.1 million) and lower off-system sales revenues ($51.4 million). The $203.1 million decrease in Fiscal 2016 Gas Utility core market revenues reflects the effects of the lower core market throughput ($135.4 million) and lower average PGC rates ($67.7 million). The lower Electric Utility revenues principally resulted from lower DS rates ($8.0 million), lower sales volumes ($5.4 million) and lower transmission revenue ($2.6 million). UGI Utilities cost of sales was $289.8 million in Fiscal 2016 compared with $510.8 million in Fiscal 2015 principally reflecting the combined effects of the lower average Gas Utility PGC rates ($92.3 million), lower cost of sales associated with Gas Utility off-system sales ($51.4 million) and lower Gas Utility retail core-market volumes sold ($67.5 million). Electric Utility cost of sales was $11.5 million lower reflecting lower DS rates ($8.5 million) and the lower volumes sold.

UGI Utilities Fiscal 2016 total margin decreased $51.3 million principally reflecting lower Gas Utility total margin from core market customers ($43.3 million). The decrease in Gas Utility core market margin reflects the lower core market throughput. Electric Utility total margin decreased $4.2 million principally reflecting the lower volume sales as a result of the warmer Fiscal 2016 weather and the lower transmission revenue.

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UGI Utilities Fiscal 2016 operating income and income before income taxes decreased $40.8 million and $37.3 million, respectively. The decreases in operating income and income before income taxes principally reflects the decrease in total margin ($51.3 million), higher depreciation expense ($4.4 million) and lower other operating income ($10.9 million) which includes, among other things, higher environmental matters expense ($4.1 million), lower margin from off-system sales ($2.2 million), lower revenue from construction services ($2.1 million) and higher interest on PGC overcollections ($1.1 million). These were partially offset by operating and administrative expenses that were $25.6 million lower than the prior year primarily reflecting lower net preliminary development stage expenses associated with an IT project ($8.6 million), including the year-over-year impact of the current year capitalization of $5.4 million of such IT costs expensed in prior years (see Note 4 to Consolidated Financial Statements), and, to a lesser extent, lower uncollectible accounts ($5.7 million), system maintenance expenses ($4.8 million) and employee benefits ($4.7 million).

Interest Expense and Income Taxes. Our interest expense in Fiscal 2016 was $3.5 million lower than in Fiscal 2015 principally reflecting UGI Utilities’ lower average long-term debt outstanding and lower average interest rates. Our effective income tax rate in Fiscal 2016 was slightly higher than in the prior year.

FINANCIAL CONDITION AND LIQUIDITY

Capitalization and Liquidity

UGI Utilities’ total debt outstanding was $921.1 million at September 30, 2017, which includes $170 million of short-term borrowings, compared with total debt outstanding of $783.9 million at September 30, 2016, which includes $112.5 million of short-term borrowings. UGI Utilities’ total long-term debt outstanding at September 30, 2017, comprises $675.0 million of Senior Notes and $80.0 million of Medium-Term Notes, and is net of $3.9 million of unamortized debt issuance costs.

Pursuant to a note purchase agreement, in October 2016, UGI Utilities issued $100 million aggregate principal amount of 4.12% Senior Notes due October 2046 (the “4.12% Senior Notes”). The net proceeds of the issuance of the 4.12% Senior Notes were used (1) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and information technology initiatives and (2) for general corporate purposes.

UGI Utilities has a credit agreement (the “Credit Agreement”) with a group of banks providing for borrowings of up to $300 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 Consolidated Balance Sheets. During Fiscal 2017 and Fiscal 2016, average daily short-term borrowings under the Credit Agreement were $80.7 million and $150.8 million, respectively, and peak short-term borrowings totaled $178.0 million and $232.0 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 October 31, 2017, UGI Utilities entered into a $125 million unsecured term loan (the “Term Loan”) with a group of banks which initially matures on October 30, 2018.  Such maturity will be automatically extended to October 30, 2022 once UGI Utilities delivers to the agent a copy of the securities certificate registered with the PUC authorizing UGI Utilities’ incurring indebtedness with such maturity date.  Proceeds from the Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Term Loan is payable in equal quarterly installments of $1.6 million with the balance of the principal being due and payable in full on the maturity date.

Based upon cash expected to be generated from operations and borrowings under the Credit Agreement, management believes the Company will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2018. For additional discussion of UGI Utilities’ long-term debt and the Credit Agreement, see Note 7 to Consolidated Financial Statements.

Cash Flows

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

Cash provided by operating activities was $243.6 million in Fiscal 2017, $205.4 million in Fiscal 2016 and $306.7 million in Fiscal 2015. The increase in cash flow from operating activities in Fiscal 2017 compared with Fiscal 2016 reflects the impact of the improved operating results and the absence of a $36.0 million cash settlement of interest rate protection agreements (“IRPAs”) paid in the prior year offset by higher cash used to fund operating working capital reflecting in large part the impact of higher

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natural gas prices on changes in accounts receivable and inventories. The increase in cash flow from operating activities in Fiscal 2016 compared to Fiscal 2015 principally reflects lower cash flow from changes in operating working capital including refunds of PGC and DS overcollections. Cash provided by operating activities before changes in operating working capital was $288.7 million in Fiscal 2017, $204.9 million in Fiscal 2016 and $229.3 million in Fiscal 2015. The significantly higher cash flow before changes in operating working capital in Fiscal 2017 reflects improved results and the absence of a $36.0 million cash settlement on IRPAs. The lower cash flow before changes in operating working capital in Fiscal 2016 compared to Fiscal 2015 reflects the lower year-over-year operating results and a $36.0 million cash settlement of IRPAs, partially offset by an increase in deferred income taxes. Changes in operating working capital (used) provided $(45.1) million of cash in Fiscal 2017, $0.5 million of cash in Fiscal 2016 and $77.4 million of cash in Fiscal 2015.

Investing activities. Cash used by investing activities was $320.5 million in Fiscal 2017, $252.5 million in Fiscal 2016, and $216.6 million in Fiscal 2015. The year-over-year increases in capital expenditures during the three-year period principally reflect higher expenditures associated with a pipeline expansion project and higher information technology capital expenditures. Fiscal 2017 cash flow from investing activities includes a $2.5 million increase in restricted cash in futures brokerage accounts compared to a $6.0 million decrease in Fiscal 2016 and a $3.0 million increase in Fiscal 2015. Changes in restricted cash in futures brokerage accounts are generally the result of changes in underlying commodity prices.

Financing activities. Cash provided (used) by financing activities was $79.3 million in Fiscal 2017, $46.9 million in Fiscal 2016 and $(99.4) million in Fiscal 2015. Financing activities cash flows are primarily the result of issuances and repayments of long-term debt, revolving credit agreement borrowings and cash dividends to UGI. During Fiscal 2017, UGI Utilities issued $100 million of Senior Notes and used the net proceeds principally to fund infrastructure replacement and betterment capital expenditures, information technology initiatives and for general corporate purposes. Fiscal 2016 includes the issuance of $300 million of senior notes, the proceeds of which were used to repay maturing long-term debt and short-term borrowings. During Fiscal 2017 and Fiscal 2016, net short-term borrowings totaled $57.5 million and $40.8 million, compared to net short-term debt repayments of $14.6 million in Fiscal 2015. The greater short-term debt repayments in Fiscal 2015 resulted from the significantly higher cash provided by operating activities.

Capital Expenditures

In the following table, we present capital expenditures by business segment for Fiscal 2017, Fiscal 2016 and Fiscal 2015. We also provide amounts we expect to spend in Fiscal 2018. We expect to finance a substantial portion of our Fiscal 2018 capital expenditures from cash generated by operations and borrowings under our Credit Agreement.

(Millions of dollars)	2018		2017		2016		2015
	(estimate)
Gas Utility	$	297.0	$	306.2	$	251.3	$	189.7
Electric Utility	20.0		11.5		11.2		8.0
	$	317.0	$	317.7	$	262.5	$	197.7

The higher levels of Gas Utility capital expenditures in Fiscal 2017 and Fiscal 2016, as well as those estimated for Fiscal 2018, reflect greater main replacement and system improvement capital expenditures, increases in new business capital expenditures and expected investments in new information technology projects.

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Contractual Cash Obligations and Commitments

UGI Utilities has contractual cash obligations that extend beyond Fiscal 2017, including scheduled repayments of long-term debt and interest, operating lease obligations, unconditional purchase obligations for pipeline transportation and natural gas storage services, commitments to purchase natural gas and electricity. The following table presents significant contractual cash obligations under agreements existing as of September 30, 2017:

	Payments Due by Period
			Fiscal		Fiscal		Fiscal
(Millions of dollars)	Total		2018		2019 - 2020		2021 - 2022		Thereafter
Long-term debt (a)	$	755.0	$	40.0	$	—	$	—	$	715.0
Interest on long-term fixed rate debt (b)	779.8		34.2		65.5		65.5		614.6
Operating leases	21.5		7.5		10.3		3.5		0.2
UGI Utilities supply, storage and transportation contracts	629.1		187.9		239.2		127.2		74.8
Total	$	2,185.4	$	269.6	$	315.0	$	196.2	$	1,404.6

(a) Based upon stated maturity dates.

(b) Based upon stated interest rates.

The components of the “Other noncurrent liabilities” included in our Consolidated Balance Sheet at September 30, 2017, principally consist of pension and other postretirement benefit liabilities recorded in accordance with GAAP and estimated obligations for environmental investigation and remediation. These liabilities are not included in the table of Contractual Cash Obligations and Commitments above because they are estimates of future payments and not contractually fixed as to timing or amount. We believe the minimum required contributions to our pension plan in Fiscal 2018 are not expected to be material. Contributions to the pension plan in years beyond Fiscal 2018 will depend in large part on the impacts of future returns on pension plan assets and interest rates on pension plan liabilities. For additional information on these liabilities, see Notes 9 and 12 to Consolidated Financial Statements.

Pension Plan

UGI Utilities has a defined benefit pension plan covering employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (the “Pension Plan”).

The fair values of the Pension Plan’s assets totaled $498.1 million and $463.4 million at September 30, 2017 and 2016, respectively. At September 30, 2017 and 2016, the underfunded positions of the Pension Plan, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plan’s assets, were $141.2 million and $182.0 million, respectively.

We believe we are in compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations. Required minimum contributions to the Pension Plan in Fiscal 2018 are not expected to be material. Pre-tax pension cost associated with the Pension Plan in Fiscal 2017 was $15.4 million. Pre-tax pension cost associated with Pension Plan in Fiscal 2018 is expected to be approximately $12 million.

Generally accepted accounting principles (“GAAP”) guidance associated with pension and other postretirement plans generally requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and other postretirement benefit plans with current year changes recognized in shareholder’s equity unless such amounts are subject to regulatory recovery. Through September 30, 2017, we have recorded cumulative after-tax charges to stockholder’s equity of $9.0 million and regulatory assets of $141.3 million in order to reflect the funded status of our pension and postretirement benefit plans. For a more detailed discussion of the Pension Plans and other postretirement benefit plans, see Note 9 to Consolidated Financial Statements.

REGULATORY MATTERS

Base Rate Filings. On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21.7 million annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PUC providing for an $11.3 million PNG annual base distribution rate increase. On August 31, 2017, the PUC approved the Joint Petition and the increase became effective October 20, 2017.

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On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27.0 million annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016.

Distribution System Improvement Charge.On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at 5% of distribution charges billed to customers.

PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero, beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from 5% to 10% of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018.

On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.

MANUFACTURED GAS PLANTS

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 Gas and Electric Utility. UGI Utilities also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania.

Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into a consent order and agreement (“COA”) with the DEP to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG, and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation, to plug specified natural gas wells. The COA environmental costs caps are $2.5 million, $1.8 million and $1.1 million, for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively. At September 30, 2017 and 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $54.3 million and $55.1 million, respectively. UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable. (See Note 4 to the Consolidated Financial Statements).

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

From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law, UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by a former subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator

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because of its conduct with respect to its subsidiary’s MGP. At September 30, 2017, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material.

RELATED PARTY TRANSACTIONS

UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as “Operating and administrative expenses — related parties” in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities during Fiscal 2017, Fiscal 2016 and Fiscal 2015 totaled $4.3 million, $5.1 million and $3.2 million, respectively.

From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. At September 30, 2017, UGI Utilities was a party to four SCAAs with Energy Services, and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs during Fiscal 2017, Fiscal 2016 and Fiscal 2015 totaling $21.4 million, $12.7 million and $16.8 million, respectively. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, these payments totaled $2.7 million, $2.0 million and $2.3 million, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. At September 30, 2017 and 2016, the amounts of such security deposits, which are included in “Other current liabilities” on the Consolidated Balance Sheets, were $11.0 million and $8.1 million, respectively.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” At September 30, 2017 and 2016, the carrying values of these gas storage inventories, comprising approximately 6.8 bcf and 4.6 bcf of natural gas, were $19.3 million and $11.1 million, respectively.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility primarily during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during Fiscal 2017, Fiscal 2016 and Fiscal 2015 totaled $76.0 million, $63.3 million and $47.8 million, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, revenues associated with such sales to Energy Services totaled $50.9 million, $30.7 million and $79.2 million, respectively. Also from time to time, UGI Utilities purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, such purchases totaled $84.4 million, $35.1 million and $85.4 million, respectively.

OFF-BALANCE-SHEET ARRANGEMENTS

We do not have any off-balance-sheet arrangements that are expected to have an effect on the Company’s financial condition, revenues and expenses, results of operations, liquidity, capital expenditures or capital resources.

MARKET RISK DISCLOSURES

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.

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Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“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 September 30, 2017, Gas Utility had $3.0 million of restricted cash in brokerage accounts. At September 30, 2017, the fair values of our natural gas futures and option contracts were not material.

Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations. At September 30, 2017, all of our Electric Utility’s forward electricity purchase contracts were subject to the normal purchase and normal sale (“NPNS”) exception. At September 30, 2017, the fair values of FTRs were not material.

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 Consolidated Statements of Income. The amount of unrealized gains on these contracts and associated volumes under contract at September 30, 2017 were not material.

Interest Rate Risk

We have both fixed-rate debt and variable rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact their fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.

Our variable-rate debt comprises borrowings under our Credit Agreement. This agreement provides for interest rates on borrowings that are indexed to short-term market interest rates. Based upon the average level of borrowings outstanding under these agreements in Fiscal 2017, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.8 million.

Our long-term debt is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we expect to refinance such debt with new debt having interest rates reflecting then-current market conditions. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of approximately $93 million at September 30, 2017. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of approximately $118 million at September 30, 2017.

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 interest rate protection agreements (“IRPAs”). There were no unsettled IRPAs outstanding at September 30, 2017.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Accounting policies and estimates discussed in this section are those that we consider to be the most critical to an understanding of our financial statements because they involve significant judgments and uncertainties. Changes in these policies and estimates could have a material effect on the financial statements. The application of these accounting policies and estimates necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements. Management has reviewed these critical accounting policies, and the estimates and assumptions associated with them, with the Company’s Audit Committee. In addition, management has reviewed the following disclosures regarding the application of these critical accounting policies and estimates with the Audit Committee. Also, see Note 2 to Consolidated Financial Statements, which discusses the significant accounting policies that we have selected from acceptable alternatives.

Goodwill Impairment Evaluation. Our goodwill is the result of Gas Utility business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one

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level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance simplifying the test for goodwill impairment. The adoption of the new guidance did not impact the consolidated financial statements. See Note 3 to Consolidated Financial Statements for more information.

We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value and the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill. From time to time, we may assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. From time to time, we may bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to the reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit. As of September 30, 2017, our goodwill totaled $182.1 million. We did not record any impairments of goodwill in Fiscal 2017, Fiscal 2016 or Fiscal 2015.

Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation that arises in the normal course of business. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere, and PNG and CPG owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with GAAP, we record a reserve when it is probable that a liability exists and the amount or range of amounts related to such liability can be reasonably estimated. When there is a range of possible loss with equal likelihood, liabilities recorded are based upon the low end of such range. The likelihood of a loss with respect to a particular contingency is often difficult to predict and determining a reasonable estimate of the loss or a range of possible loss may not be practicable based upon the information available and the potential effects of future events and decisions by third parties that will determine the ultimate resolution of the contingency. Reasonable estimates involve management judgments based on a broad range of information and prior experience and include an evaluation of the nature of the claim, the procedural status of the matter, the probability or likelihood of success of prosecuting or defending the claim, the information available with respect to the claim, the opinions and views of outside counsel and other advisors, and past experience in similar matters. These judgments are reviewed quarterly as more information is received, and the amounts reserved are updated as necessary. Our estimated reserves may differ materially from the ultimate liability and such reserves may change materially as more information becomes available.

Depreciation of Property, Plant and Equipment. We compute depreciation on UGI Utilities property, plant and equipment on a straight-line basis based upon the projected service lives of its various classes of depreciable property. The estimated useful lives of the classes of depreciable property are reviewed by a third party and adjusted, if necessary, as part of periodic service life studies required by the PUC. Changes in the estimated useful lives of property, plant and equipment could have a material effect on our results of operations. As of September 30, 2017, UGI Utilities net property, plant and equipment totaled $2,274.5 million and we recorded depreciation expense of $69.8 million during Fiscal 2017.

Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation by the PUC. In accordance with accounting guidance associated with rate-regulated entities, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2017, our regulatory assets and regulatory liabilities totaled $368.9 million and $49.2 million, respectively. For additional information on our regulatory assets and liabilities, see Note 2 and Note 4 to Consolidated Financial Statements.

Pension Plan Assumptions. Pension plan assumptions are significant inputs to the actuarial models that measure pension benefit obligations and pension expense. The cost of providing benefits under the Pension Plan is dependent on historical information such as employee age, length of service, level of compensation and the actual rate of return on plan assets. In addition, certain assumptions relating to the future are used to determine pension expense including mortality assumptions, the discount rate applied

24

to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase, among others. Assets of the Pension Plan are held in trust and consist principally of equity and fixed income mutual funds and investments in UGI Corporation Common Stock. Changes in plan assumptions as well as fluctuations in actual equity or fixed income market returns could have a material impact on future pension costs. We believe the two most critical assumptions are (1) the expected rate of return on plan assets and (2) the discount rate. A decrease in the expected rate of return on Pension Plan assets of 50 basis points to a rate of 6.90% would result in an increase in pre-tax pension cost of approximately $1.6 million in Fiscal 2018. A decrease in the discount rate of 50 basis points to a rate of 3.50% would result in an increase in pre-tax pension cost of approximately $4.0 million in Fiscal 2018. For additional information on our Pension Plan, see Note 9 to Consolidated Financial Statements.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

See Note 3 to Consolidated Financial Statements for a discussion of recently issued accounting guidance.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

“Quantitative and Qualitative Disclosures About Market Risk” are contained in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Market Risk Disclosures” and are incorporated herein by reference.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and the financial statement schedule referred to in the Index contained on page F-1 of this Report are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a) 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 September 30, 2017, were effective at the reasonable assurance level.

(b) Management’s Annual Report on Internal Control over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, of the Company’s internal control over financial reporting as of September 30, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO 2013 Framework”).

Internal control over financial reporting refers to the process, designed under the supervision and participation of management including our Chief Executive Officer and Chief Financial Officer, to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States and includes policies and procedures that, among other things, provide reasonable assurance that assets are safeguarded and that transactions are executed in accordance with management’s authorization and are properly recorded to permit the preparation of reliable financial information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changing conditions, or the degree of compliance with the policies or procedures may deteriorate.

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Based on its assessment, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2017, based on the COSO 2013 Framework. Ernst & Young LLP, our independent registered public accounting firm, has audited the effectiveness of the Company’s internal control over financial reporting as of September 30, 2017, as stated in their report, which appears herein.

(c) Effective on September 4, 2017, we implemented a new customer service and meter management system to replace our legacy system. The implementation resulted in greater automation of internal controls in the UGI Utilities Meter-to-Bill cycle and we consider the system replacement to be material. As a result of the implementation, controls that were previously determined to be effective were replaced with new or modified controls that were also determined to be effective. Other than this system implementation, there were no changes in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the quarter ended September 30, 2017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III:

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The aggregate fees billed by Ernst & Young LLP, the Company’s independent registered public accounting firm in Fiscal 2017 and Fiscal 2016, were as follows:

	2017		2016
Audit Fees (1)	$	915,301	$	1,313,781
Audit-Related Fees (2)	480,458		0
Tax Fees (3)	71,926		0
All Other Fees (4)	66,711		0
Total Fees for Services Provided	$	1,534,396	$	1,313,781

(1) Audit fees for Fiscal 2017 and Fiscal 2016 were for audit services, including (i) the annual audit of the consolidated financial statements of the Company, (ii) regulatory-basis financial statements, and (iii) review of the interim financial statements included in the Quarterly Reports on Form 10-Q of the Company.

(2) Audit-Related Fees for Fiscal 2017 related to pre-implementation reviews of the Company’s new information technology system.

(3) Tax Fees for Fiscal 2017 were for tax compliance or advisory services at the Company.

(4) All Other Fees for Fiscal 2017 were for services provided for the implementation of ASC 606.

Consistent with SEC policies regarding auditor independence, the Audit Committee has responsibility for appointing, setting compensation and overseeing the work of the Company’s independent accountants. In recognition of this responsibility, the Audit Committee has a policy of pre-approving audit and permissible non-audit services provided by the independent accountants. The Audit Committee has also delegated approval authority to its chair, such authority to be exercised in the intervals between meetings, in accordance with the Audit Committee’s pre-approval policy.

Prior to engagement of the Company’s independent accountants for the next year’s audit, management submits a list of services and related fees expected to be rendered during that year within each of the four categories of services noted above to the Audit Committee for approval.

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PART IV:

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents filed as part of this report:

(1) Financial Statements:

Included under Item 8 are the following financial statements and supplementary data:

Report of Independent Registered Public Accounting Firm (on Internal Control over Financial Reporting) - Ernst & Young LLP

Report of Independent Registered Public Accounting Firm (on Consolidated Financial Statements and Schedule) - Ernst & Young LLP

Consolidated Balance Sheets as of September 30, 2017 and 2016

Consolidated Statements of Income for the years ended September 30, 2017, 2016 and 2015

Consolidated Statements of Comprehensive Income for the years ended September 30, 2017, 2016 and 2015

Consolidated Statements of Cash Flows for the years ended September 30, 2017, 2016 and 2015

Consolidated Statements of Stockholder’s Equity for the years ended September 30, 2017, 2016 and 2015

Notes to Consolidated Financial Statements

(2) Financial Statement Schedule:

For the years ended September 30, 2017, 2016 and 2015

II — Valuation and Qualifying Accounts

We have omitted all other financial statement schedules because the required information is (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or notes thereto contained in this Report.

(3) List of 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 registration number or last date of the period for which it was filed, and the exhibit number in such filing):

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Incorporation by Reference

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
3.1	UGI Utilities’ Amended and Restated Articles of Incorporation.	Utilities	Registration Statement No. 333-72540 (10/31/01)	3
3.2	Bylaws of UGI Utilities, Inc., as amended and restated as of July 25, 2017.	Utilities	Form 8-K (7/25/17)	3.1
4	Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of its long-term debt not required to be filed pursuant to the description of Exhibit 4 contained in Item 601 of Regulation S-K).
4.1	UGI Utilities’ Amended and Restated Articles of Incorporation and Amended and Restated Bylaws referred to in Exhibit Nos. 3.1 and 3.2.
4.2	Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994.	Utilities	Registration Statement No. 33-77514 (4/8/94)	4(c)
4.3	Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association.	Utilities	Form 8-K (9/12/06)	4.2
4.4	Form of Fixed Rate Medium-Term Note.	Utilities	Form 8-K (8/26/94)	(4)i
4.5	Form of Fixed Rate Series B Medium-Term Note.	Utilities	Form 8-K (8/1/96)	4(i)
4.6	Form of Floating Rate Series B Medium-Term Note.	Utilities	Form 8-K (8/1/96)	4(ii)
4.7	Officer’s Certificate establishing Medium-Term Notes Series.	Utilities	Form 8-K (8/26/94)	4(iv)
4.8	Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture.	Utilities	Form 8-K (8/1/96)	4(iv)
4.9	Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture.	Utilities	Form 8-K (5/21/02)	4.2
4.10	Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes.	Utilities	Form 8-K (5/21/02)	4.1
4.11	Form of Note Purchase Agreement dated October 30, 2013 between the Company and the purchasers listed as signatories thereto.	Utilities	Form 8-K (10/30/13)	4.1
4.12	Note Purchase Agreement dated April 22, 2016 between the Company and the purchasers listed as signatories thereto.	Utilities	Form 8-K (4/28/16)	4.1

28

Incorporation by Reference

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.1**	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of September 5, 2014.	UGI	Form 10-K (9/30/16)	10.25
10.2**	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of September 5, 2014 - Terms and Conditions as effective January 1, 2016.	UGI	Form 10-K (9/30/16)	10.26
10.3**	UGI Corporation 2013 Omnibus Incentive Compensation Plan, effective as of September 5, 2014.	UGI	Form 10-K (9/30/16)	10.30
10.4**	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 24, 2017.	UGI	Form 10-Q (6/30/17)	10.5
10.5**	UGI Corporation 2013 Omnibus Incentive Compensation Plan, effective as of September 5, 2014 - Terms and Conditions for Non-Employee Directors effective January 1, 2016.	UGI	Form 10-K (9/30/16)	10.31
10.6**	UGI Corporation 2009 Deferral Plan, as Amended and Restated effective June 15, 2017.	UGI	Form 10-Q (6/30/17)	10.6
10.7**	UGI Corporation Senior Executive Employee Severance Plan, as amended and restated as of June 15, 2017.	UGI	Form 10-Q (6/30/17)	10.7
*10.8**	UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective April 1, 2015.
10.9**	UGI Corporation 2009 Supplemental Executive Retirement Plan for New Employees, as Amended and Restated effective June 15, 2017.	UGI	Form 10-Q (6/30/17)	10.1
10.10**	UGI Utilities, Inc. Executive Annual Bonus Plan, effective as of October 1, 2006, as amended as of November 16, 2012.	Utilities	Form 10-Q (3/31/13)	10.2
10.11**	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI and Utilities Employees, dated January 1, 2017.	UGI	Form 10-Q (6/30/17)	10.3
10.12**	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for UGI, Utilities and AmeriGas Employees, dated January 1, 2017.	UGI	Form 10-Q (6/30/17)	10.2
10.13**	UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended as of July 10, 2017.	Utilities	Form 10-Q (6/30/17)	10.1

29

Incorporation by Reference

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.14**	UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006, as amended November 16, 2012.	UGI	Form 10-Q (3/31/13)	10.14
10.15	FSS Service Agreement No. 79028 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.	Utilities	Form 10-K (9/30/14)	10.16
10.16	SST Service Agreement No. 79133 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.	Utilities	Form 10-K (9/30/14)	10.19
10.17	Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, LLC, effective November 1, 2015.	Utilities	Form 10-K (9/30/16)	10.19
10.18	Credit Agreement, dated as of March 27, 2015 among UGI Utilities, Inc., as borrower, PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and Citizens Bank, N.A., as joint lead arrangers and joint bookrunners, and the other financial institutions from time to time parties thereto.	Utilities	Form 8-K (3/27/15)	10.1
10.19	Credit Agreement, dated October 31, 2017, by and among UGI Utilities, Inc., PNC Bank National Association, as administrative agent, The Bank of New York Mellon, as syndication agent, and certain other lenders named therein.	Utilities	Form 8-K (10/31/17)	10.1

30

Incorporation by Reference

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
*12.1	Computation of Ratio of Earnings to Fixed Charges.
14	Code of Ethics for principal executive, financial and accounting officers.	UGI	Form 10-K (9/30/03)	14
*23	Consent of Ernst & Young LLP.
*31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2017 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-K for the fiscal year ended September 30, 2017 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-K for the fiscal year ended September 30, 2017, 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

*	Filed herewith.
**	As required by Item 15(a)(3), this exhibit is identified as a compensatory plan or arrangement.

ITEM 16. FORM 10-K SUMMARY

None.

31

EXHIBIT INDEX

Exhibit No.	Description
10.8	UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective April 1, 2015.
12.1	Computation of Ratio of Earnings to Fixed Charges
23	Consent of Ernst & Young LLP.
31.1	Certification by the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2	Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32	Certification by the Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act
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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.
Date:	November 21, 2017	By:	/s/ Daniel J. Platt
			Daniel J. Platt
			Vice President - Finance and Chief Financial Officer, Assistant Secretary and Treasurer (Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 21, 2017 by the following persons on behalf of the Registrant in the capacities indicated.

Signature	Title
/s/ Robert F. Beard	President and Chief Executive Officer (Principal Executive
Robert F. Beard	Officer) and Director
/s/ Daniel J. Platt	Vice President — Finance and Chief Financial Officer, Assistant
Daniel J. Platt	Secretary and Treasurer (Principal Financial Officer)
/s/ Megan Mattern	Controller (Principal Accounting Officer)
Megan Mattern
/s/ Marvin O. Schlanger	Chairman and Director
Marvin O. Schlanger
/s/ John L. Walsh	Vice Chairman and Director
John L. Walsh
/s/ M. Shawn Bort	Director
M. Shawn Bort
/s/ Theodore A. Dosch	Director
Theodore A. Dosch
/s/ Richard W. Gochnauer	Director
Richard W. Gochnauer
/s/ Frank S. Hermance	Director
Frank S. Hermance
/s/ Anne Pol	Director
Anne Pol
/s/ James B. Stallings, Jr.	Director
James B. Stallings, Jr.
/s/ Roger B. Vincent	Director
Roger B. Vincent

Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:

33

No annual report or proxy material was sent to security holders in Fiscal 2017.

34

UGI UTILITIES, INC. AND SUBSIDIARIES

FINANCIAL INFORMATION

FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K

YEAR ENDED SEPTEMBER 30, 2017

UGI UTILITIES, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE

	Pages
Financial Statements:
Report of Independent Registered Public Accounting Firm (on Internal Control over Financial Reporting)	F- 2
Report of Independent Registered Public Accounting Firm (on Consolidated Financial Statements and Schedule)	F- 3
Consolidated Balance Sheets as of September 30, 2017 and 2016	F- 4
Consolidated Statements of Income for the years ended September 30, 2017, 2016 and 2015	F- 5
Consolidated Statements of Comprehensive Income for the years ended September 30, 2017, 2016 and 2015	F- 6
Consolidated Statements of Cash Flows for the years ended September 30, 2017, 2016 and 2015	F- 7
Consolidated Statements of Stockholder’s Equity for the years ended September 30, 2017, 2016 and 2015	F- 8
Notes to Consolidated Financial Statements	F- 9 to F- 35
Financial Statement Schedule:
For the years ended September 30, 2017, 2016 and 2015:
II — Valuation and Qualifying Accounts	S- 1

We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.

F- 1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder of UGI Utilities, Inc.:

We have audited UGI Utilities, Inc. and subsidiaries' internal control over financial reporting as of September 30, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). UGI Utilities, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, UGI Utilities, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of September 30, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of UGI Utilities, Inc. and subsidiaries as of September 30, 2017 and 2016, and the related consolidated statements of income, comprehensive income, stockholder’s equity and cash flows for each of the three years in the period ended September 30, 2017 and our report dated November 21, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

November 21, 2017

F- 2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder of UGI Utilities, Inc.

We have audited the accompanying consolidated balance sheets of UGI Utilities, Inc. and subsidiaries as of September 30, 2017 and 2016, and the related consolidated statements of income, comprehensive income, stockholder’s equity and cash flows for each of the three years in the period ended September 30, 2017. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of UGI Utilities, Inc. and subsidiaries at September 30, 2017 and 2016, and the consolidated results of their operations and their cash flows for each of the three years in the period ended September 30, 2017, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), UGI Utilities, Inc. and subsidiaries’ internal control over financial reporting as of September 30, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November 21, 2017, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

November 21, 2017

F- 3

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)

	September 30,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	5,203		$	2,819
Restricted cash	3,046			583
Accounts receivable (less allowances for doubtful accounts of $4,052 and $3,946, respectively)	53,720			44,692
Accounts receivable — related parties	2,807			398
Accrued utility revenues	13,296			12,753
Inventories	53,309			42,340
Prepaid income taxes	7,711			1,956
Regulatory assets	8,338			3,208
Derivative instruments	1,354			4,263
Prepaid expenses	8,450			10,499
Other current assets	7,956			11,510
Total current assets	165,190			135,021
Property, plant and equipment	3,285,329			2,998,915
Less accumulated depreciation and amortization	(1,010,781		)	(975,374		)
Net property, plant and equipment	2,274,548			2,023,541
Goodwill	182,145			182,145
Regulatory assets	360,591			391,933
Other assets	11,541			10,451
Total assets	$	2,994,015		$	2,743,091
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	39,996		$	19,986
Short-term borrowings	170,000			112,500
Accounts payable — trade	71,559			65,180
Accounts payable — related parties	6,890			3,995
Employee compensation and benefits accrued	21,851			16,323
Interest accrued	16,200			7,605
Customer deposits and advances	35,278			41,391
Derivative instruments	1,071			310
Regulatory liability — deferred fuel and power refunds	10,621			22,299
Other current liabilities	40,016			44,321
Total current liabilities	413,482			333,910
Long-term debt	711,105			651,455
Deferred income taxes	635,465			550,229
Deferred investment tax credits	2,950			3,268
Pension and other postretirement benefit obligations	143,674			184,516
Other noncurrent liabilities	99,434			94,976
Total liabilities	2,006,110			1,818,354
Commitments and contingencies (Note 12)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)	60,259			60,259
Additional paid-in capital	473,580			473,580
Retained earnings	480,857			422,516
Accumulated other comprehensive loss	(26,791		)	(31,618		)
Total common stockholder’s equity	987,905			924,737
Total liabilities and stockholder’s equity	$	2,994,015		$	2,743,091

See accompanying Notes to Consolidated Financial Statements.

F- 4

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of dollars)

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

See accompanying Notes to Consolidated Financial Statements.

F- 5

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)

	Year Ended September 30,
	2017		2016			2015
Net income	$	116,041	$	97,373		$	121,055
Net losses on derivative instruments (net of tax of $0, $12,016 and $2,911, respectively)	—		(16,942		)	(4,105		)
Reclassifications of net losses on derivative instruments (net of tax of $(1,409), $(1,112) and $(1,109), respectively)	1,988		1,568			1,565
Benefit plans, principally actuarial gains (losses) (net of tax of $(1,336), $2,267 and $2,469, respectively)	1,883		(3,197		)	(3,482		)
Reclassifications of benefit plans actuarial losses and net prior service credits (net of tax of $(678), $(454) and $(367), respectively)	956		639			517
Other comprehensive income (loss)	4,827		(17,932		)	(5,505		)
Comprehensive income	$	120,868	$	79,441		$	115,550

See accompanying Notes to Consolidated Financial Statements.

F- 6

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)

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

See accompanying Notes to Consolidated Financial Statements.

F- 7

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(Thousands of dollars)

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

See accompanying Notes to Consolidated Financial Statements.

F- 8

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

1. NATURE OF OPERATIONS

UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”), own and operate natural gas distribution utilities in eastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.” Prior to June 1, 2015, PNG also had a heating, ventilation and air-conditioning service business which operated principally in the PNG service territory (“PNG HVAC Business”). The assets of the PNG HVAC Business principally comprising customer contracts were sold on June 1, 2015.

The term “UGI Utilities” is used herein as an abbreviated reference to UGI Utilities, Inc., or collectively to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

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

Principles of Consolidation

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

Effects of Regulation

UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator. For additional information regarding the effects of rate regulation on our utility operations, see Note 4.

Fair Value Measurements

The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements performed on a recurring basis principally relate to derivative instruments.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

• Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

• Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means.

• Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.

Derivative Instruments

Derivative instruments are reported on the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or is designated and qualifies for hedge accounting.

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

For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 14.

Revenue Recognition

UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service rendered and commodities delivered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered.

We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.

Accounts Receivable

Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.

F- 10

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

Income Taxes

We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.

We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize.

We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is consistent with income taxes calculated on a separate return basis. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income.

Cash and Cash Equivalents

For cash flow purposes, cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities of three months or less when purchased.

Restricted Cash

Restricted cash represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.

Inventories

Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for substantially all of our inventory.

Property, Plant and Equipment and Related Depreciation

We record property, plant and equipment at original cost. Capitalized costs include labor, materials and other direct and indirect costs, and allowance for funds used during construction (“AFUDC”). The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis based upon projected service lives of the various classes of its depreciable property. The estimated useful lives of the classes of depreciable property are reviewed by a third party and adjusted, if necessary, as part of periodic service life studies required by the PUC. The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2017, 2016 and 2015 were as follows:

	2017		2016		2015
Gas Utility	2.2	%	2.2	%	2.2	%
Electric Utility	2.4	%	2.5	%	2.5	%

When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over five years, consistent with prior ratemaking treatment (See Note 4).

We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. Information technology costs associated with major system installations, conversions and improvements, such as software training, data conversion, business process reengineering costs and preliminary project stage costs are deferred as a regulatory asset if the Company expects to recover these costs in future rates, and the deferral is reported as a component of property, plant and equipment. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.

F- 11

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

No depreciation expense is included in cost of sales in the Consolidated Statements of Income.

Goodwill

Our goodwill is the result of Gas Utility business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance simplifying the test for goodwill impairment. The adoption of the new guidance did not impact the consolidated financial statements (see Note 3).

We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value. From time to time, we may assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. From time to time, we may bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit.

No provisions for goodwill impairments were recorded during Fiscal 2017, Fiscal 2016 or Fiscal 2015.

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No provisions for impairments were recorded during Fiscal 2017, Fiscal 2016 or Fiscal 2015.

Employee Retirement Plans

We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 9).

Equity-Based Compensation

All of our equity-based compensation, principally comprising UGI stock options and grants of UGI stock-based equity instruments (“UGI Units”), is measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, equity-based compensation costs are measured based upon the fair value of the award on the date of grant or the fair value of the award as of the end of each reporting period. In Fiscal 2017, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. (see Note 3).

For additional information on our equity-based compensation plans and related disclosures, see Note 11.

F- 12

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

Environmental Matters

We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.

Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites.  This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see Note 12.

3. ACCOUNTING CHANGES

Adoption of New Accounting Standard

Cash Flow Classification. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance on the classification of certain cash receipts and payments in the statement of cash flows. The guidance is generally required to be applied retrospectively. The adoption of the new guidance did not impact our consolidated financial statements.

Goodwill Impairment. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance regarding the test for goodwill impairment. Under the new accounting guidance, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements.

Employee Share-based Payments. Effective October 1, 2016, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. The adoption of the new accounting guidance did not have a material impact on our financial statements.

Accounting Standards Not Yet Adopted

Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

F- 13

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption.

The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue.

The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.

4. REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS

The following regulatory assets and liabilities are included in our Consolidated Balance Sheets at September 30:

	2017		2016
Regulatory assets:
Income taxes recoverable	$	121,421	$	115,643
Underfunded pension and postretirement plans	141,310		183,129
Environmental costs	61,566		59,397
Deferred fuel and power costs	7,685		151
Removal costs, net	30,996		27,956
Other	5,951		8,865
Total regulatory assets	$	368,929	$	395,141
Regulatory liabilities (a):
Postretirement benefits overcollections	$	17,493	$	17,519
Deferred fuel and power refunds	10,621		22,299
State income tax benefits — distribution system repairs	18,430		15,086
Other	2,686		665
Total regulatory liabilities	$	49,230	$	55,569

(a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance Sheets.

F- 14

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

Other than removal costs, UGI Utilities currently does not recover a rate of return on the regulatory assets included in the table above.

Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of the tax benefit on accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. UGI Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 65 years.

Underfunded pension and other postretirement plans. This regulatory asset represents the portion of net actuarial losses and prior service costs (credits) associated with pension and other postretirement benefits which are probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants.

Environmental costs. Environmental costs principally represent estimated probable future environmental remediation and investigation costs that UGI Gas, CPG and PNG expect to incur, primarily at Manufactured Gas Plant (“MGP”) sites in Pennsylvania, in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (“DEP”). Pursuant to base rate orders, UGI Gas, PNG and CPG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2017, the period over which UGI Gas, PNG and CPG expect to recover these costs will depend upon future remediation activity. For additional information on environmental costs, see Note 12.

Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. As required by PUC ratemaking, removal costs include actual costs incurred associated with asset retirement obligations. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over five years.

Postretirement benefit overcollections. This regulatory liability represents the difference between amounts recovered through rates by UGI Gas and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With respect to UGI Gas, postretirement benefit overcollections are generally being refunded to customers over a ten-year period beginning October 19, 2016, the date UGI Gas’ Joint Petition pursuant to its January 19, 2016 base rate filing became effective (see “Base Rate Filings” below). With respect to Electric Utility, the excess of the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits is being deferred for future rate refund to customers.

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

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains on such contracts at September 30, 2017 and 2016, were $146 and $4,263, respectively.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at September 30, 2017 and 2016, were not material.

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal benefit, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.

Other. Other regulatory assets and liabilities comprise a number of deferred items including, among others, a portion of preliminary stage information technology costs, energy efficiency conservation costs and rate case expenses.

Other Regulatory Matters

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

On January 19, 2016, UGI Utilities filed a rate request with the PUC to increase UGI Gas’s annual base operating revenues for residential, commercial and industrial customers by $58,600. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2016, a Joint Petition for Approval of Settlement of all issues providing for a $27,000 UGI Gas annual base distribution rate increase, to be effective October 19, 2016, was filed with the PUC (“Joint Petition”). On October 14, 2016, the PUC approved the Joint Petition with a minor modification which had no effect on the $27,000 base distribution rate increase. The increase became effective on October 19, 2016.

Distribution System Improvement Charge.On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at 5% of distribution charges billed to customers.

PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero, beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from 5% to 10% of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018.

On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.

Preliminary Stage Information Technology Costs. During Fiscal 2016, we determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during Fiscal 2016, we capitalized $5,830 of such project costs ($5,375 of which had been expensed prior to Fiscal 2016) and recorded associated increases to utility property, plant and equipment ($2,755) and regulatory assets ($3,075). Subsequent to this determination, we continue to capitalize such preliminary stage project costs in accordance with GAAP related to regulated entities.

F- 16

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

5. INVENTORIES

Inventories comprise the following at September 30:

	2017		2016
Gas Utility natural gas	$	39,486	$	29,223
Materials, supplies and other	13,823		13,117
Total inventories	$	53,309	$	42,340

At September 30, 2017, UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) having terms ranging from one to three years. Four of the SCAAs were with UGI Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 18), and one of the SCAAs was with a non-affiliate. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

The carrying values of gas storage inventories released under the SCAAs at September 30, 2017 and 2016, comprising 9.1 billion cubic feet (“bcf”) and 8.1 bcf of natural gas, were $26,064 and $18,773, respectively. At September 30, 2017 and 2016, UGI Utilities held a total of $15,040 and $19,100, respectively, of security deposits received from its SCAA counterparties. These amounts are included in “Other current liabilities” on the Consolidated Balance Sheets.

For additional information related to the SCAAs with Energy Services, see Note 18.

6. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment comprise the following categories at September 30:

	2017		2016
Distribution	$	2,835,339	$	2,634,191
Transmission	96,430		93,454
Construction in process	112,563		103,929
General and other	240,997		167,341
Total property, plant and equipment	$	3,285,329	$	2,998,915

F- 17

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

7. DEBT

Long-term debt comprises the following at September 30:

	2017			2016
Senior Notes:
4.12%, due September 2046	$	200,000		$	200,000
4.98%, due March 2044	175,000			175,000
4.12%, due October 2046	100,000			—
6.21%, due September 2036	100,000			100,000
2.95%, due June 2026	100,000			100,000
Medium-Term Notes:
6.17%, due June 2017	—			20,000
7.25%, due November 2017	20,000			20,000
5.67%, due January 2018	20,000			20,000
6.50%, due August 2033	20,000			20,000
6.13%, due October 2034	20,000			20,000
Total long-term debt	755,000			675,000
Less: unamortized debt issuance costs	(3,899		)	(3,559		)
Less: current maturities	(39,996		)	(19,986		)
Total long-term debt due after one year	$	711,105		$	651,455

Principal payments on long-term debt during the next five fiscal years is as follows: $40,000 is due in Fiscal 2018; $0 is due in Fiscal 2019 through Fiscal 2022.

Pursuant to a note purchase agreement, in October 2016, UGI Utilities issued $100,000 aggregate principal amount of 4.12% Senior Notes due October 2046 (the “4.12% Senior Notes”). The net proceeds of the issuance of the 4.12% Senior Notes were used (1) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and information technology initiatives and (2) for general corporate purposes. The 4.12% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt.

On October 31, 2017, UGI Utilities entered into a $125,000 unsecured term loan (the “Term Loan”) with a group of banks which initially matures on October 30, 2018.  Such maturity will be automatically extended to October 30, 2022 once UGI Utilities delivers to the agent a copy of the securities certificate registered with the PUC authorizing UGI Utilities’ incurring indebtedness with such maturity date.  Proceeds from the Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Term Loan is payable in equal quarterly installments of $1,563 with the balance of the principal being due and payable in full on the maturity date.  Under the term loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin.  The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities.  The Term Loan requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.

UGI Utilities has an unsecured credit agreement (the “Credit Agreement”) with a group of banks providing for borrowings of up to $300,000 (including a $100,000 sublimit for letters of credit) which expires in March 2020. Under the Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. UGI Utilities had borrowings outstanding under the credit agreements, which we classify as “Short-term borrowings” on the Consolidated Balance Sheets, totaling $170,000 and $112,500 at September 30, 2017 and 2016, respectively. The weighted-average interest rates on the credit agreement borrowings at September 30, 2017 and 2016 were 2.11% and 1.42%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the credit agreements, totaled $2,009 and $2,009 at September 30, 2017 and 2016, respectively.

Restrictive Covenants. Certain of UGI Utilities Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of

F- 18

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

insurance. These Senior Notes also contain restrictive and financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

The UGI Utilities Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.

8. INCOME TAXES

The provisions for income taxes consist of the following:

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

A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:

	2017		2016		2015
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Difference in tax rate due to:
State income taxes, net of federal benefit	5.0		5.2		5.1
Excess tax benefits on share-based payments	(0.9	)	—		—
Other, net	(0.8	)	0.2		(0.5	)
Effective tax rate	38.3	%	40.4	%	39.6	%

Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2017, Fiscal 2016 and Fiscal 2015, the beneficial effects of state tax flow through of accelerated depreciation reduced tax expense by $2,537, $1,344 and $1,539, respectively.

F- 19

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

Deferred tax liabilities (assets) comprise the following at September 30:

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

We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. UGI’s federal income tax returns are settled through the tax year 2013.

We file separate company income tax returns in various other states but are subject to state income tax principally in Pennsylvania. Pennsylvania income tax returns are generally subject to examination for a period of three years after the filing of the respective returns.

During Fiscal 2017, Fiscal 2016 and Fiscal 2015, interest (income) expense of $(73), $204 and $0, respectively, was recognized in income taxes in the Consolidated Statements of Income.

As of September 30, 2017, we have unrecognized income tax benefits totaling $1,829 including related accrued interest of $132. If these unrecognized tax benefits were subsequently recognized, $940 would be recorded as a benefit to income taxes on the Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. There is no material change expected in unrecognized tax benefits and related interest in the next twelve months.

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

	2017			2016		2015
Unrecognized tax benefits – beginning of year	$	2,055		$	—	$	—
Additions for tax positions taken in prior years	604			2,055		—
Additions for tax positions of the current year	—			—		—
Settlements with tax authorities/statute lapses	(830		)	—		—
Unrecognized tax benefits – end of year	$	1,829		$	2,055	$	—

9. EMPLOYEE RETIREMENT PLANS

Defined Benefit Pension and Other Postretirement Plans. We sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plan”). Pension Plan benefits are based on years of service, age and employee compensation. We also provide postretirement

F- 20

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

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

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plan, the accumulated benefit obligations (“ABOs”) of the Other Postretirement Plans, plan assets and the funded status of the Pension Plan and Other Postretirement Plans as of September 30, 2017 and 2016. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect future compensation.

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

In Fiscal 2018, we estimate that we will amortize approximately $12,000 of net actuarial losses, primarily associated with Pension Plan, and $250 of prior service credits from stockholder’s equity and regulatory assets.

Actuarial assumptions are described below. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the Company’s postretirement plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the benefit payments. The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).

F- 21

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

	Pension Benefits						Other Postretirement Benefits
Weighted-average assumptions:	2017		2016		2015		2017		2016		2015
Discount rate – benefit obligations	4.00	%	3.80	%	4.60	%	4.00	%	3.80	%	4.70	%
Discount rate – benefit cost	3.80	%	4.60	%	4.60	%	3.80	%	4.70	%	4.60	%
Expected return on plan assets	7.50	%	7.55	%	7.75	%	5.00	%	5.00	%	5.00	%
Rate of increase in salary levels	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%

The ABOs for the Pension Plan were $605,237 and $601,255 as of September 30, 2017 and 2016, respectively. Included in the end of year Pension Plan PBOs above are $62,458 at September 30, 2017, and $63,847 at September 30, 2016, relating to employees of UGI and certain of its other subsidiaries. Included in the end of year Other Postretirement Plans ABOs above are $996 at September 30, 2017, and $951 at September 30, 2016, relating to employees of UGI and certain of its other subsidiaries.

Net periodic pension and other postretirement benefit costs relating to the Company’s employees include the following components:

	Pension Benefits									Other Postretirement Benefits
	2017			2016			2015			2017			2016			2015
Service cost	$	8,091		$	6,927		$	6,962		$	273		$	183		$	202
Interest cost	22,157			23,270			22,511			431			465			479
Expected return on assets	(29,986		)	(28,668		)	(28,898		)	(656		)	(596		)	(612		)
Amortization of:
Prior service cost (benefit)	325			348			348			(641		)	(641		)	(641		)
Actuarial loss	14,825			9,571			8,793			108			98			122
Net benefit cost (income)	15,412			11,448			9,716			(485		)	(491		)	(450		)
Change in associated regulatory liabilities	—			—			—			(490		)	971			3,740
Net benefit cost after change in regulatory liabilities	$	15,412		$	11,448		$	9,716		$	(975	)	$	480		$	3,290

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Corporation Common Stock and smallcap common stocks (prior to their liquidation during Fiscal 2017). It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, we made contributions to the Pension Plan of $11,395, $9,869 and $11,131, respectively. The minimum required contributions in Fiscal 2018 are not expected to be material.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and the amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. The required contributions to the VEBA during Fiscal 2018, if any, are not expected to be material.

Expected payments for pension and other postretirement welfare benefits are as follows:

	Pension Benefits		Other Postretirement Benefits
Fiscal 2018	$	27,176	$	566
Fiscal 2019	28,471		566
Fiscal 2020	29,812		552
Fiscal 2021	31,084		537
Fiscal 2022	32,323		540
Fiscal 2023 - 2027	179,945		2,710

F- 22

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

The assumed health care cost trend rates at September 30 are as follows:

	2017		2016
Health care cost trend rate assumed for next year	7.00	%	7.25	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	5.0	%	5.0	%
Fiscal year that the rate reaches the ultimate trend rate	2026		2026

A one percentage point change in these assumed health care cost trend rates would not have had a material impact on Fiscal 2017 other postretirement benefit cost or the September 30, 2017, other postretirement benefit ABO.

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement income plans. At September 30, 2017 and 2016, the PBOs of these plans were $4,222 and $3,628, respectively. We recorded expense for these plans of $605 in Fiscal 2017, $353 in Fiscal 2016 and $445 in Fiscal 2015.

Pension Plan and VEBA Assets. The assets of the Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks (prior to their liquidation in Fiscal 2017) and UGI Common Stock.

The targets, target ranges and actual allocations for the Pension Plan and VEBA trust assets at September 30 are as follows:

	Actual				Target Asset	Permitted
Pension Plan:	2017		2016		Allocation	Range
Equity investments:
Domestic	55.2	%	54.1	%	52.5%	40.0% – 65.0%
International	12.4	%	10.2	%	12.5%	7.5% – 17.5%
Total	67.6	%	64.3	%	65.0%	60.0% – 70.0%
Fixed income funds & cash equivalents	32.4	%	35.7	%	35.0%	30.0% – 40.0%
Total	100.0	%	100.0	%	100.0%

	Actual				Target Asset	Permitted
VEBA:	2017		2016		Allocation	Range
Domestic equity investments	63.1	%	69.9	%	65.0%	60.0% – 70.0%
Fixed income funds & cash equivalents	36.9	%	30.1	%	35.0%	30.0% – 40.0%
Total	100.0	%	100.0	%	100.0%

Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds, and a separately managed account comprising small-cap common stocks (prior to their liquidation in Fiscal 2017). Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 7.7% and 8.0% of Pension Plan assets at September 30, 2017 and 2016, respectively.

F- 23

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

The fair values of the Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee. The fair values of the Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2, as of September 30, 2017 and 2016 are as follows:

	Pension Plan
	Level 1		Level 2		Level 3		Other(a)		Total
September 30, 2017:
Domestic equity investments:
S&P 500 Index equity mutual funds	$	171,600	$	—	$	—	$	—	$	171,600
Small and midcap equity mutual funds	65,167		—		—		—		65,167
UGI Corporation Common Stock	38,137		—		—		—		38,137
Total domestic equity investments	274,904		—		—		—		274,904
International index equity mutual funds	61,613		—		—		—		61,613
Fixed income investments:
Bond index mutual funds	156,228		—		—		—		156,228
Cash equivalents	—		—		—		5,332		5,332
Total fixed income investments	156,228		—		—		5,332		161,560
Total	$	492,745	$	—	$	—	$	5,332	$	498,077
September 30, 2016:
Equity investments:
S&P 500 Index equity mutual funds	$	158,906	$	—	$	—	$	—	$	158,906
Small and midcap equity mutual funds	43,170		—		—		—		43,170
Smallcap common stocks	11,414		—		—		—		11,414
UGI Corporation Common Stock	37,013		—		—		—		37,013
Total domestic equity investments	250,503		—		—		—		250,503
International index equity mutual funds	47,324		—		—		—		47,324
Fixed income investments:
Bond index mutual funds	147,794		—		—		—		147,794
Cash equivalents	—		—		—		17,811		17,811
Total fixed income investments	147,794		—		—		17,811		165,605
Total	$	445,621	$	—	$	—	$	17,811	$	463,432

	VEBA
	Level 1		Level 2		Level 3		Other(a)		Total
September 30, 2017:
S&P 500 Index equity mutual fund	$	9,318	$	—	$	—	$	—	$	9,318
Bond index mutual fund	5,044		—		—		—		5,044
Cash equivalents	—		—		—		409		409
Total	$	14,362	$	—	$	—	$	409	$	14,771
September 30, 2016:
S&P 500 Index equity mutual fund	$	9,583	$	—	$	—	$	—	$	9,583
Bond index mutual fund	4,019		—		—		—		4,019
Cash equivalents	—		—		—		113		113
Total	$	13,602	$	—	$	—	$	113	$	13,715

(a) Assets measured at net asset value (“NAV”) and therefore excluded from the fair value hierarchy.

F- 24

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

The expected long-term rates of return on Pension Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.

Defined Contribution Plan. We sponsor a 401(k) savings plan for eligible employees (“Utilities Savings Plan”). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. The Utilities Savings Plan provides for employer matching contributions. Those employees hired after December 31, 2008, who are not eligible to participate in the Pension Plan, receive employer matching contributions at a higher rate. The cost of benefits under the Utilities Savings Plan totaled $2,829 in Fiscal 2017, $2,409 in Fiscal 2016 and $2,162 in Fiscal 2015. We also sponsor a nonqualified supplemental defined contribution executive retirement plan. This plan generally provides supplemental benefits to certain executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal Revenue Code. Costs associated with this plan were not material in Fiscal 2017, Fiscal 2016 and Fiscal 2015.

10. SERIES PREFERRED STOCK

We have 2,000,000 shares of Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of Series Preferred Stock outstanding at September 30, 2017 or 2016.

11. EQUITY-BASED COMPENSATION

Under UGI Corporation’s 2013 Omnibus Incentive Compensation Plan (the “2013 OICP”) and prior UGI equity compensation plans, certain key employees of UGI Utilities may be granted stock options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”) and other equity-based awards. The exercise price for UGI stock options may not be less than the fair market value on the grant date. Awards granted under the 2013 OICP and the prior plans may vest immediately or ratably over a period of years (generally three-year periods), and stock options for UGI Common Stock can be exercised no later than ten years from the grant date. In addition, the 2013 OICP and the prior UGI equity compensation plans provide that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.

UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. With respect to UGI Performance Units awards, the actual number of UGI shares actually issued (or their cash equivalent) at the end of the performance period and the actual amount of dividend equivalents paid, may range from 0% to 200% of the target award based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to the Russell Midcap Utility Index, excluding telecommunication companies (“UGI comparator group”). Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.

We use a Black-Scholes option-pricing model to estimate the fair value of UGI stock options. We use a Monte Carlo valuation approach to estimate the fair value of UGI Performance Unit awards. We recorded total net pre-tax equity-based compensation expense associated with both UGI Units and UGI stock options of $1,461 ($855 after-tax) during Fiscal 2017; $1,924 ($1,126 after-tax) during Fiscal 2016; and $1,847 ($1,081 after-tax) during Fiscal 2015.

As of September 30, 2017, there was $1,167 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 1.9 years. As of September 30, 2017, there was a total of $1,029 of unrecognized compensation expense associated with 45,588 UGI Unit awards that is expected to be recognized over a weighted average period of 1.8 years. At September 30, 2017 and 2016, total liabilities of $533 and $1,304, respectively, associated with UGI Unit awards are reflected in other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheets.

F- 25

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

The following table summarizes UGI Unit award activity for Fiscal 2017:

	Total				Vested				Non-Vested
	Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)
September 30, 2016	57,783		$	34.66	10,316		$	34.31	47,467		$	34.74
Granted	16,425		$	51.42	367		$	51.42	16,058		$	51.42
Vested	—		$	—	16,003		$	33.10	(16,003	)	$	33.10
Forfeitures & transfers	(1,934	)	$	34.74	—		$	—	(1,934	)	$	34.74
Unit awards paid	(20,050	)	$	32.59	(20,050	)	$	32.59	—		$	—
September 30, 2017	52,224		$	40.72	6,636		$	37.53	45,588		$	41.19

12. COMMITMENTS AND CONTINGENCIES

Commitments

We lease various buildings and vehicles, computer and office equipment and other facilities under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $7,276 in Fiscal 2017, $7,669 in Fiscal 2016 and $7,956 in Fiscal 2015.

Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year for the fiscal years ending September 30 are as follows: 2018— $7,545; 2019 — $5,961; 2020 — $4,355; 2021 — $2,665; 2022 — $793; after 2022 — $182.

Contingencies

Environmental Matters

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

Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into a consent order and agreement (“COA”) with the DEP to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2,500, $1,750 and $1,100, for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively. At September 30, 2017 and 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $54,250 and $55,063, respectively. UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable. (See Note 4).

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

F- 26

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

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

Other Matters

Manor Township, Pennsylvania Natural Gas Explosion.On July 2, 2017, an explosion occurred in Manor Township, Pennsylvania which resulted in the death of a Company employee, significant injuries to two other Company employees and an employee of the local sewer authority, and significant property damage. The National Transportation Safety Board (“NTSB”), the Occupational Safety and Health Administration (“OSHA”) and the PUC are investigating the Manor Township incident. The NTSB investigative team includes representatives from the Company, the PUC, the local fire department and the Pipeline and Hazardous Materials Safety Administration and the Company is cooperating with the investigation. Other parties may be invited to participate by the NTSB.

While the investigation into this incident is still underway and the cause of the explosion has not been determined, the Company has received claims as a result of the explosion and may become involved in lawsuits relative to the incident. The Company maintains workers’ compensation insurance and liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of the Company’s deductible, are expected to be recovered through the Company’s insurance. Although the Company cannot predict the result of these pending or future claims, we believe that claims and expenses associated with the explosion will not have a material impact on our consolidated financial statements.

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

F- 27

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

13. FAIR VALUE MEASUREMENTS

Derivative Instruments

The following table presents, on a gross basis, our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2, as of September 30, 2017 and 2016:

	Asset (Liability)
	Level 1			Level 2			Level 3		Total
September 30, 2017
Derivative instruments:
Assets:
Commodity contracts	$	1,735		$	72		$	—	$	1,807
Liabilities:
Commodity contracts	$	(1,447	)	$	(73	)	$	—	$	(1,520	)
September 30, 2016
Derivative instruments:
Assets:
Commodity contracts	$	4,506		$	4		$	—	$	4,510
Liabilities:
Commodity contracts	$	(263	)	$	(294	)	$	—	$	(557	)

The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments, which are designated as Level 2, are generally based upon recent market transactions and related market indicators. There were no transfers between Level 1 and Level 2 during the periods presented.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt (Level 2). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2017 and 2016, were as follows:

	2017		2016
Carrying amount	$	755,000	$	675,000
Estimated fair value	$	791,378	$	770,781

14. 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.

F- 28

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 2017 and 2016, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 14.8 million dekatherms and 18.4 million dekatherms, respectively. At September 30, 2017, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 months. Gains and losses on natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 4).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At September 30, 2017 and 2016, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception under GAAP.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 4). At September 30, 2017 and 2016, the total volumes associated with FTRs totaled 101.2 million kilowatt hours and 58.3 million kilowatt hours, respectively. At September 30, 2017, the maximum period over which we are economically hedging electricity congestion is 8 months.

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

Interest Rate Risk

Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. On March 31, 2016, concurrent with the pricing of UGI Utilities’ Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities settled all of its then-existing IRPA contracts associated with such debt at a loss of $35,975. Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs was recorded in AOCI and is being recognized in interest expense as the associated future interest expense impacts earnings. At September 30, 2017 and 2016, we had no unsettled IRPAs.

At September 30, 2017, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,485.

Derivative Instrument Credit Risk

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2017 and 2016, restricted cash in brokerage accounts totaled $3,046 and $583, respectively.

Offsetting Derivative Assets and Liabilities

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

F- 29

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions.

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

Fair Value of Derivative Instruments

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

	2017			2016
Derivative assets:
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$	1,665		$	4,472
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	142			38
Total derivative assets – gross	1,807			4,510
Gross amounts offset in the balance sheet	(450		)	(247		)
Total derivative assets – net (a)	$	1,357		$	4,263
Derivative liabilities:
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$	(1,520	)	$	(499	)
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	—			(58		)
Total derivative liabilities – gross	(1,520		)	(557		)
Gross amounts offset in the balance sheet	450			247
Total derivative liabilities – net (a)	$	(1,070	)	$	(310	)

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

Effect of Derivative Instruments

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Consolidated Statements of Income and changes in AOCI for Fiscal 2017, Fiscal 2016 and Fiscal 2015:

	Loss Recognized in AOCI								Loss Reclassified from AOCI into Income									Location of
	2017		2016			2015			2017			2016			2015			Loss Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—	$	(28,958	)	$	(7,016	)	$	(3,397	)	$	(2,680	)	$	(2,674	)	Interest expense
	Gain (Loss) Recognized in Income																	Location of Gain (Loss)
	2017		2016			2015												Recognized in Income
Derivatives Not Subject to PGC and DS Mechanisms:
Gasoline contracts	$	174	$	(88	)	$	(761	)										Operating and administrative expenses/other operating income, net

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

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

15. ACCUMULATED OTHER COMPREHENSIVE INCOME

Other comprehensive income (loss) principally reflects losses on IRPAs qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

Changes in AOCI, net of tax, during Fiscal 2017, Fiscal 2016 and Fiscal 2015 are as follows:

	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI - September 30, 2014	$	(6,311	)	$	(1,870	)	$	(8,181	)
Reclassifications of benefit plans actuarial losses and net prior service credits	517			—			517
Reclassifications of net losses on IRPAs	—			1,565			1,565
Net losses on IRPAs	—			(4,105		)	(4,105		)
Benefit plans, principally actuarial losses	(3,482		)	—			(3,482		)
AOCI - September 30, 2015	$	(9,276	)	$	(4,410	)	$	(13,686	)
Reclassifications of benefit plans actuarial losses and net prior service credits	639			—			639
Reclassifications of net losses on IRPAs	—			1,568			1,568
Net losses on IRPAs	—			(16,942		)	(16,942		)
Benefit plans, principally actuarial losses	(3,197		)	—			(3,197		)
AOCI - September 30, 2016	$	(11,834	)	$	(19,784	)	$	(31,618	)
Reclassifications of benefit plans actuarial losses and net prior service credits	956			—			956
Reclassifications of net losses on IRPAs	—			1,988			1,988
Benefit plans, principally actuarial gains	1,883			—			1,883
AOCI - September 30, 2017	$	(8,995	)	$	(17,796	)	$	(26,791	)

Reclassifications of net losses on IRPAs are reflected in interest expense on the Consolidated Statements of Income.

16. SEGMENT INFORMATION

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

The accounting policies of our reportable segments are the same as those described in Note 2. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.

No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States, and all of our reportable segments’ long-lived assets are located in the United States.

F- 32

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

Financial information by business segment follows:

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

17. OTHER OPERATING INCOME (EXPENSE), NET

Other operating income (expense), net, comprises the following:

	2017			2016			2015
Non-tariff service income	$	1,491		$	2,633		$	4,760
Environmental matters	6,155			(2,918		)	1,152
Construction service income	—			—			2,175
Sale of HVAC Business	—			—			1,065
Net interest on PGC overcollection	(130		)	(1,740		)	(606		)
Other, net	813			25			323
Total other operating income (expense), net	$	8,329		$	(2,000	)	$	8,869

F- 33

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

18. RELATED PARTY TRANSACTIONS

UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as “Operating and administrative expenses — related parties” in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities during Fiscal 2017, Fiscal 2016 and Fiscal 2015 totaled $4,346, $5,069 and $3,168, respectively.

From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. At September 30, 2017, UGI Utilities was a party to four SCAAs with Energy Services, and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs during Fiscal 2017, Fiscal 2016 and Fiscal 2015 totaling $21,424, $12,739 and $16,849, respectively. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, these payments totaled $2,747, $2,002 and $2,339, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. At September 30, 2017 and 2016, the amounts of such security deposits, which are included in “Other current liabilities” on the Consolidated Balance Sheets, were $11,040 and $8,100, respectively.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” At September 30, 2017 and 2016, the carrying values of these gas storage inventories, comprising approximately 6.8 bcf and 4.6 bcf of natural gas, were $19,323 and $11,148, respectively.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility primarily during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during Fiscal 2017, Fiscal 2016 and Fiscal 2015 totaled $76,010, $63,331 and $47,794, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, revenues associated with such sales to Energy Services totaled $50,948, $30,743 and $79,182, respectively. Also from time to time, UGI Utilities purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, such purchases totaled $84,402, $35,067 and $85,383, respectively.

F- 34

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

19. QUARTERLY DATA (unaudited)

The following quarterly information includes all adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of the Company’s businesses.

	December 31,				March 31,				June 30,				September 30,
	2016		2015		2017		2016		2017		2016		2017			2016
Revenues	$	261,413	$	197,982	$	359,940	$	322,047	$	146,692	$	140,283	$	119,543		$	108,172
Operating income	$	82,236	$	48,296	$	116,408	$	114,481	$	27,671	$	29,815	$	1,992		$	8,309
Net income (loss)	$	44,265	$	23,351	$	65,125	$	63,294	$	10,697	$	12,603	$	(4,046	)	$	(1,875	)

F- 35

UGI UTILITIES, INC. AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

(Thousands of dollars)

	Balance at beginning of year		Charged to costs and expenses		Other				Balance at end of year
September 30, 2017
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	3,946	$	8,030	$	(7,924	)	(1)	$	4,052
September 30, 2016
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	5,599	$	7,760	$	(9,413	)	(1)	$	3,946
September 30, 2015
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	6,992	$	13,498	$	(14,891	)	(1)	$	5,599

⁽¹⁾  Uncollectible accounts written off, net of recoveries

S- 1

EX-10.8

Exhibit 10.8

UGI CORPORATION

SUPPLEMENTAL EXECUTIVE RETIREMENTPLAN AND
SUPPLEMENTAL SAVINGSPLAN

As amended and restated effective April 1, 2015

TABLE OF CONTENTS

Page

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

ARTICLE I STATEMENT OF PURPOSE..............................................................2

ARTICLE II DEFINITIONS.....................................................................................3

ARTICLE III PARTICIPATION.................................................................................6

ARTICLE IV VESTING.............................................................................................7

ARTICLE V BENEFITS...........................................................................................8

ARTICLE VI BENEFIT DISTRIBUTION................................................................11

ARTICLE VII FUNDING OF BENEFITS..................................................................13

ARTICLE VIII THE COMMITTEE.............................................................................14

ARTICLE IX AMENDMENT AND TERMINATION..............................................16

ARTICLE X CLAIMS PROCEDURES...................................................................17

ARTICLE XI MISCELLANEOUS PROVISIONS...................................................19

EXHIBIT A CHANGE OF CONTROL

EXHIBIT B ACTUARIAL ASSUMPTIONS

SUPPLEMENTAL SAVINGS PLAN

ARTICLE I STATEMENT OF PURPOSE...............................................................1

ARTICLE II DEFINITIONS......................................................................................2

ARTICLE III PARTICIPATION..................................................................................5

ARTICLE IV VESTING..............................................................................................6

ARTICLE V BENEFITS............................................................................................7

ARTICLE VI FORM AND TIMING OF BENEFIT DISTRIBUTION.....................10

ARTICLE VII FUNDING OF BENEFITS..................................................................11

ARTICLE VIII THE COMMITTEE.............................................................................12

ARTICLE IX AMENDMENT AND TERMINATION..............................................14

ARTICLE X CLAIMS PROCEDURES...................................................................15

ARTICLE XI MISCELLANEOUS PROVISIONS...................................................17

EXHIBIT A CHANGE OF CONTROL

i

UGI CORPORATION

SUPPLEMENTAL EXECUTIVE RETIREMENTPLAN

BACKGROUND

The Senior Executive Retirement Plan for Certain Employees of UGI Corporation and its Subsidiaries and Affiliates (the “Senior Plan”) was established effective as of January 1, 1985. Until April 10, 1992, it was maintained by UGI Utilities, Inc. (formerly named, prior to April 10, 1992, UGI Corporation and hereinafter sometimes referred to as “UGI Utilities”). On April 10, 1992, UGI Utilities became a subsidiary of New UGI Corporation which was renamed UGI Corporation (“UGI”) on the same date. As of April 10, 1992, UGI assumed sponsorship of the Senior Plan and all obligations of UGI Utilities thereunder, and amended and restated the Senior Plan to reflect the transfer of Senior Plan sponsorship. Effective October 1, 1996, the Senior Plan was amended and restated to eliminate participation by employees of AmeriGas Propane, Inc., to re-name the Senior Plan “The UGI Corporation Supplemental Executive Retirement Plan” and to make other changes. Effective January 1, 2005, the UGI Corporation Supplemental Executive Retirement Plan was amended to comply with section 409A of the Internal Revenue Code and was split into two subplans, the Supplemental Executive Retirement Plan and the Supplemental Savings Plan.

The Supplemental Executive Retirement Plan was amended and restated to allow participants to defer their benefit under the Supplemental Executive Retirement Plan pursuant to the UGI Corporation 2009 Deferral Plan. The amendment and restatement of the Supplemental Executive Retirement Plan was effective as of January 1, 2009. The Supplemental Executive Retirement Plan was amended and restated effective as of November 22, 2013, except where otherwise indicated, and is hereby amended and restated effective as of April 1, 2015.

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ARTICLE I

STATEMENT OF PURPOSE

Sec. 1.01Purpose. The Supplemental Executive Retirement Plan (the “SERP”) is maintained to provide a fair and competitive level of retirement benefits to certain management and other highly compensated employees who have, by operation of laws and regulations relating to qualified pension benefit plans, experienced a reduction in prospective retirement benefits under the Pension Plan (as defined in Article II). The benefits under the SERP are also designed to compensate terminated participants by taking into account periods of time for which payments are made under a Change in Control Agreement (as defined in Article II) or, for employees whose employment terminated on or after January 1, 2005 and before July 25, 2006, under an Executive Severance Plan (as defined in Article II).

Sec. 1.02Grandfathered Benefits. The terms of the amended and restated SERP shall not apply to any participant whose employment terminated before January 1, 2005. Notwithstanding anything in the SERP to the contrary, the vested accrued SERP benefit of a participant whose employment terminated before January 1, 2005 shall be paid according to the terms of the UGI Corporation Supplemental Executive Retirement Plan as in effect before January 1, 2005, consistent with the “grandfather” provisions of section 409A of the Internal Revenue Code of 1986, as amended.

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ARTICLE II

DEFINITIONS

Sec. 2.01“Administrative Committee” shall mean the committee designated by the Compensation Committee to administer the SERP.

Sec. 2.02“Affiliate” shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended.

Sec. 2.03“Beneficiary” means the person designated by a Participant to receive any benefits payable after the Participant’s death in the event of the Participant’s death after termination of employment with UGI and its subsidiaries and Affiliates. UGI shall provide a form for this purpose. In the event a Participant has not filed a Beneficiary designation with UGI or none of the designated Beneficiaries are living at the date of the Participant’s death, the Beneficiary shall be the Participant’s estate.

Sec. 2.04“Board” shall mean the Board of Directors of UGI.

Sec. 2.05“Cause” shall mean misappropriation of funds, habitual insobriety, substance abuse, conviction of a crime involving moral turpitude, or gross negligence in the performance of duties, which gross negligence has had a material adverse effect on the business, operations, assets, properties or financial condition of UGI and its Subsidiaries and Affiliates, taken as a whole.

Sec. 2.06“Change of Control” shall have the meaning set forth on the attached Exhibit A.

Sec. 2.07“Change in Control Agreement” shall mean a Change in Control Agreement between an Employee and UGI or a Subsidiary (other than AmeriGas Propane, Inc. or its subsidiaries).

Sec. 2.08“Code” shall mean the Internal Revenue Code of 1986, as amended.

Sec. 2.09“Compensation Committee” shall mean the Compensation and Management Development Committee of the Board.

Sec. 2.10“Continuation Period” shall mean, with respect to a Participant who is entitled to receive benefits under a Change in Control Agreement, the Continuation Period as defined in the Participant’s Change in Control Agreement.

Sec. 2.11“Credited Service” shall mean a year of Credited Service as determined under the Pension Plan.

Sec. 2.12“Deferral Plan” shall mean the UGI Corporation 2009 Deferral Plan.

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Sec. 2.13“Deferred Earnings” shall mean, for years beginning prior to September 30, 2004, so much of an Employee’s compensation payable under the applicable Executive Annual Bonus Plan as would otherwise be taken into account under the Pension Plan, but which is not taken into account under the Pension Plan due to an election by the Employee to have such compensation deferred to and paid in a subsequent year.

Sec. 2.14“Effective Date” of the amended and restated SERP shall mean April 1, 2015, except where otherwise indicated. The SERP is a continuation of the pensionportion of the UGI Corporation Supplemental Executive Retirement Plan, as in effect before January 1, 2005.

Sec. 2.15“Employee” shall mean an employee of UGI, UGI Utilities, Inc. or another Subsidiary other than AmeriGas Propane, Inc. or its subsidiaries. In no event shall a person who is characterized as an independent contractor by the employer, no matter how characterized by a court or government agency, be considered an “Employee,” and no retroactive characterization of an individual’s status for any other purpose shall make an individual an “Employee.”

Sec. 2.16“Employment Commencement Date” shall mean the first day on which a Participant became an employee of UGI, any Subsidiary or Affiliate of UGI, or any entity whose business or assets have been acquired by UGI, by a Subsidiary or Affiliate of UGI or by any predecessor of such entities.

Sec. 2.17“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

Sec. 2.18“Excess Earnings” shall mean that portion of an Employee’s compensation from UGI or another participating employer hereunder that is not permitted to be taken into account under the Pension Plan by operation of section 401(a)(17) of the Code or any successor thereto, excluding any such compensation earned when the Employee was not a Participant.

Sec. 2.19“Executive Annual Bonus Plan” shall mean the UGI Corporation Executive Annual Bonus Plan or the UGI Utilities, Inc. Executive Annual Bonus Plan, as amended from time to time, and any successor plans (and for fiscal years through 1996, the AmeriGas Propane, Inc. Executive Annual Bonus Plan).

Sec. 2.20“Executive Severance Plan” shall mean an executive severance plan of UGI or a Subsidiary or Affiliate (other than AmeriGas Propane, Inc. or its subsidiaries).

Sec. 2.21“Key Employee” shall mean an employee who, at any time during the 12-month period ending on the identification date, is a “specified employee” under section 409A of the Code, as determined by the Compensation Committee or its delegate. The determination of Key Employees, including the number and identity of persons considered specified employees and the identification date, shall be made by the Compensation Committee or its delegate in

accordance with the provisions of section 409A of the Code and the regulations issued thereunder.

Sec. 2.22“Participant” shall mean each Employee who meets the requirements of Section 3.01 hereof.

Sec. 2.23“Pension Plan” shall mean the Retirement Income Plan for Employees of UGI Utilities, Inc., as currently in effect and as it may hereafter be amended, and any plan designated by the Board as a successor thereto.

Sec. 2.24“Pension Plan Earnings” shall mean so much of an Employee’s compensation from UGI or another participating employer hereunder as is taken into account in determining benefits or contributions under the Pension Plan for the relevant period.

Sec. 2.25“Plan Year” shall mean, effective January 1, 2007, a 12-month period beginning on January 1 and ending on December 31. For periods before January 1, 2007, the Plan Year shall mean a period beginning on October 1 and ending on the following September 30, with a short Plan Year for the period beginning on October 1, 2006 and ending on December 31, 2006.

Sec. 2.26“Postponement Period” shall mean, for a Key Employee, the period of six months after separation from service as defined by section 409A of the Code (or such other period as may be required by section 409A of the Code), during which SERP benefits may not be paid to the Key Employee under section 409A of the Code.

Sec. 2.27“SERP” shall mean the UGI Corporation Supplemental Executive Retirement Plan as set forth herein, and as the same may hereafter be amended.

Sec. 2.28“Subsidiary” shall mean any corporation in which UGI, directly or indirectly, owns at least a 50% interest or an unincorporated entity of which UGI, directly or indirectly, owns at least 50% of the profits or capital interests.

Sec. 2.29“UGI” shall mean UGI Corporation.

Sec. 2.30“Vesting Service” shall mean a year of Vesting Service as determined under the Pension Plan.

ARTICLE III

PARTICIPATION

Sec. 3.01Participants.

(a)Effective as of January 1, 2005, an Employee who meets the requirements of subsection (b), (c) or (d) below shall become a Participant on the first day on which he or she meets the requirements of subsection (b), (c) or (d), as applicable.

(b)Each Employee who (i) is eligible to receive a bonus under an Executive Annual Bonus Plan at any time during the applicable Plan Year, (ii) is an active participant in the Pension Planduring the applicable Plan Year, and (iii) has Excess Earnings for the Plan Year shall be a Participant in this SERP for purposes of accruing a benefit under Section 5.01 for the applicable Plan Year.

(c)Each Employee who has a Change in Control Agreement that provides for the benefits described in Section 5.02 shall be a Participant in this SERP for purposes of being eligible to receive benefits under Section 5.02.

(d)Each Employee whose employment was terminated on or after January 1, 2005 and before July 25, 2006 and who was entitled to receive a severance benefit under an Executive Severance Plan, as described in Section 5.03, shall be a Participant in this SERP for purposes of being eligible to receive benefits under Section 5.03.

(e)Notwithstanding the foregoing, no Employee who is hired or rehired by UGI or an Affiliate on or after January 1, 2009, or who is transferred on or after January 1, 2009 into Employee status from an Affiliate that does not participate in this SERP, shall become a Participant in this SERP on or after January 1, 2009.

Sec. 3.02Transfers. If a Participant ceases to meet the requirements of Section 3.01 but continues to be an employee of UGI or a Subsidiary or Affiliate, the former Participant will cease to accrue benefits under the SERP. The former Participant will continue to earn Vesting Service credit with respect to his or her accrued SERP benefit. If, at a later date, the Participant again meets the requirements of Section 3.01, the Participant may accrue additional benefits under the SERP with respect to his or her subsequent service as an eligible Employee. The Participant shall receive his or her vested accrued SERP benefit at the Participant’s termination of employment with UGI and its Subsidiaries and Affiliates as described in Article VI.

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ARTICLE IV

VESTING

Sec. 4.01Vesting in Section 5.01 Benefits.

(a)A Participant shall vest in the benefits accrued under Section 5.01 of the SERP when the Participant has five years of Vesting Service. If a Participant’s employment with UGI and its Subsidiaries and Affiliates terminates for any reason before the Participant has five years of Vesting Service, all benefits accrued by the Participant under Section 5.01 shall be immediately forfeited, and the Participant shall receive no benefits under Section 5.01.

(b)If a Participant whose employment terminated on or after January 1, 2005 and before July 25, 2006 is entitled to receive a benefit under Section 5.03, the Participant’s salary continuation period under the Executive Severance Plan shall be counted as service for purposes of vesting under this SERP.

Sec. 4.02Vesting in Section 5.02 and Section 5.03 Benefits.

(a)A Participant shall vest in his or her benefits under Section 5.02 of the SERP when the Participant’s employment has terminated under the circumstances described in Section 5.02 and the Participant has met all the requirements of the Participant’s Change in Control Agreement that entitle the Participant to receive the benefits described in Section 5.02.

(b)A Participant whose employment terminated on or after January 1, 2005 and before July 25, 2006 shall vest in his or her benefits under Section 5.03 of the SERP when the Participant’s employment has terminated under the circumstances described in Section 5.03 and the Participant has met all the requirements of the Executive Severance Plan that entitle the Participant to receive the benefits described in Section 5.03.

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ARTICLE V

BENEFITS

Sec. 5.01Pension Benefit. Each Participant who is an active participant in the Pension Plan and who is accruing a benefit under the Pension Plan shall accrue under the SERP a lump sum benefit that is the actuarially equivalent present value of a single life annuity equal to (a) reduced by (b), where:

(a)is the annual accrued benefit, based on a single life annuity, that would have been produced under the Pension Plan if (i) the Participant’s Excess Earnings (without regard to the limitations set forth in section 401(a)(17) of the Code) and Deferred Earnings for each year of his active participation in the Pension Plan had been taken into account and (ii) the limitations set forth in section 415 of the Code (or its successor) were inoperative; and

(b)is the annual accrued benefit, based on a single life annuity, that the Participant is entitled to receive under the Pension Plan.

The annual accrued benefit shall be calculated as described in Section 5.06. A Participant shall be entitled to receive his or her vested accrued SERP benefit upon termination of employment as described in Article VI. Sections 5.01, 5.02 and 5.03 shall be administered so as not to result in duplication of benefits.

Sec. 5.02Change of Control Benefit. In the event of a Change of Control, if and to the extent required by a Participant’s Change in Control Agreement, each Participant who is an active participant in the Pension Plan on the date of the Participant’s termination of employment and who is entitled to receive the benefits described in this Section 5.02 under a Change in Control Agreement shall receive a lump sum benefit that is the actuarially equivalent present value of a single life annuity equal to (a) reduced by (b), where:

(a)is the annual accrued benefit, based on a single life annuity, that the Participant would have received under the Pension Plan if the applicable Continuation Period had been taken into account in determining the Participant’s Vesting Service and Credited Service under the Pension Plan (such benefit to be determined without regard to the limitations set forth in the Code); and

(b)is the Participant’s annual accrued benefit, based on a single life annuity, that the Participant is entitled to receive under the Pension Plan.

The annual benefit shall be calculated as described in Section 5.06 as if the end of the Continuation Period were the Participant’s termination date. The annual benefit under subsection (a) above shall be calculated as if the Participant had continued in employment during the Continuation Period, earning base salary and bonus at the annual rate calculated for purposes of

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the Change in Control Agreement. Sections 5.01, 5.02 and 5.03 shall be administered so as not to result in duplication of benefits.

Sec. 5.03Severance Benefit. The provisions of this Section 5.03 shall apply to a Participant whose employment was terminated by UGI or a Subsidiary or Affiliate on or after January 1, 2005 and before July 25, 2006, if the Participant was entitled to receive a severance benefit under an Executive Severance Plan and the Participant was an active participant in the Pension Plan on the date of the Participant’s termination of employment. If required by the terms of the applicable Executive Severance Plan, each such Participant shall receive a lump sum benefit that is the actuarially equivalent present value of a single life annuity equal to (a) reduced by (b), where:

(a)is the annual accrued benefit, based on a single life annuity, that the Participant would have received under the Pension Plan if the applicable salary continuation period, as determined under the Executive Severance Plan, had been taken into account in determining the Participant’s Credited Service under the Pension Plan (such benefit to be determined without regard to the limitations set forth in the Code); and

(b)is the Participant’s annual accrued benefit, based on a single life annuity, that the Participant is entitled to receive under the Pension Plan.

The annual benefit shall be calculated as described in Section 5.06. The annual accrued benefit under subsection (a) above shall be calculated as if the Participant had continued in employment during the salary continuation period, earning base salary and bonus at the annual rate calculated for purposes of the Executive Severance Plan. Sections 5.01, 5.02 and 5.03 shall be administered so as not to result in duplication of benefits.

Sec. 5.04Death Benefits.

(a)If a Participant has earned a vested accrued SERP benefit under Section 5.01 but the Participant dies while employed by UGI or a Subsidiary or Affiliate, the Participant’s surviving spouse shall be entitled to receive a lump sum death benefit that is the actuarially equivalent present value of a single life annuity equal to (i) reduced by (ii), where:

(i) is the pre-retirement death benefit that would have been paid under the Pension Plan to the Participant’s surviving spouse if (i) the Participant’s Excess Earnings (without regard to the limitations set forth in section 401(a)(17) of the Code) and Deferred Earnings for each year of his active participation in the Pension Plan had been taken into account and (ii) the limitations set forth in section 415 of the Code (or its successor) were inoperative; and

(ii) is the pre-retirement death benefit that the Participant’s surviving spouse is entitled to receive under the Pension Plan.

No death benefit shall be payable under this subsection (a) if the deceased Participant has no surviving spouse.

(b)If a Participant terminates from employment with UGI and its Subsidiaries and Affiliates and meets all the requirements for eligibility for a benefit under Section 5.01, 5.02 or 5.03, but the Participant dies before the benefit described in Section 5.01, 5.02 or 5.03 is paid, the unpaid lump sum benefit described in Section 5.01, 5.02 or 5.03 shall be paid to the Participant’s designated Beneficiary or, if there is no designated Beneficiary, the Participant’s estate.

Sec. 5.05Forfeiture. Each Participant shall immediately forfeit any benefit to which he or she is otherwise entitled under the SERP if the Participant’s employment is terminated for Cause.

Sec. 5.06Calculation of Annual Benefits. The annual accrued benefits described in Sections 5.01, 5.02 and 5.03, and the lump sum present values, shall be calculated as of the Participant’s termination date as follows:

(a)If the Participant has attained age 65, the annual benefit shall be calculated as an annual benefit payable at the Participant’s termination date, and the lump sum present value shall be calculated as of the Participant’s termination date.

(b)If the Participant has attained eligibility for early retirement under the Pension Plan, the annual benefit shall be calculated as an annual benefit payable at the Participant’s termination date (or at age 55, if the Participant has not attained age 55, but is eligible for early retirement), after reduction by the Pension Plan’s actuarial reduction factors for early retirement, and the lump sum present value shall be calculated as of the Participant’s termination date.

(c)If the Participant has not attained age 65 or attained eligibility for early retirement under the Pension Plan, the annual benefit shall be calculated as an annual benefit payable at age 65, and the lump sum present value shall be calculated as of the Participant’s termination date.

(d)For purposes of this SERP, Participant is considered to be eligible for early retirement under the Pension Plan if the Participant has attained age 55 with ten Years of Vesting Service or if the Participant’s employment is involuntarily terminated by the Company after the Participant has attained age 50 with 15 Years of Vesting Service.

Sec. 5.07Actuarial Equivalent. The Compensation Committee shall approve, and may from time to time change, the methodology (including assumptions) pursuant to which an actuarially equivalent benefit is calculated under the SERP. Unless the Committee determines otherwise, the methodology described in Exhibit B shall be used for calculating actuarial equivalence under the SERP. If a Change of Control occurs, the methodology used to calculate actuarial equivalence under the SERP immediately before the Change of Control shall be used to

calculate actuarial equivalence for purposes of all benefits payable under the SERP on and after the Change of Control.

ARTICLE VI

BENEFIT DISTRIBUTION

Sec. 6.01Calculation of Distribution Amount. If a Participant’s employment with UGI and its Subsidiaries and Affiliates terminates without Cause, the Administrative Committee shall calculate the Participant’s vested accrued SERP benefit under Article V (or the death benefit under Section 5.04(a), in the event of death) as of the Participant’s termination date. The Administrative Committee shall calculate the lump sum present value of the vested accrued SERP benefit based on the actuarial assumptions described in Section 5.06.

Sec. 6.02Form of Benefit Distributions.

(a)Effective January 1, 2005, a Participant’s vested accrued SERP benefit shall be paid to the Participant in the form of a lump sum payment upon the Participant’s termination of employment with UGI and its Subsidiaries and Affiliates, as described in Section 6.03 below. The vested accrued benefit of a Participant who terminated employment prior to January 1, 2005 shall be paid in accordance with the provisions of the SERP as in effect before January 1, 2005.

(b)If a Participant dies, the lump sum death benefit described in Section 5.04 (if any) shall be paid within 60 days after the Participant’s death.

Sec. 6.03Timing of Benefit Distributions.

(a)A Participant’s vested accrued SERP benefit shall be paid to the Participant within 60 days following the Participant’s termination of employment with UGI and its Subsidiaries and Affiliates, except as described below. A Participant shall be considered to have incurred a termination of employment under the SERP when the Participant has a “separation from service” under section 409A of the Code. The vested accrued SERP benefit of a Participant who terminated employment prior to January 1, 2005 shall be paid in accordance with the provisions of the SERP as in effect before January 1, 2005.

(b)Notwithstanding the foregoing, if a Participant whose employment terminates after January 1, 2005 is a Key Employee and if required by section 409A of the Code, no SERP benefits shall be paid to the Participant during the Postponement Period. If payment of SERP benefits is required to be delayed for the Postponement Period pursuant to section 409A, the accumulated amounts withheld on account of section 409A, with interest as described below, shall be paid in a lump sum payment within 15 days after the end of the Postponement Period. If the Participant dies during the Postponement Period prior to the payment of benefits, the amounts withheld on account of section 409A, with interest as described below, shall be paid to the Participant’s estate within 60 days after the Participant’s death.

(c)The amount to be withheld on account of section 409A shall be calculated as of the Participant’s termination date in accordance with the provisions hereof.

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Interest shall be calculated on the withheld lump sum amount from the Participant’s termination date to the last day of the calendar month preceding the date on which the withheld amount is paid, based on the daily average of the published six-month Treasury bill rate in effect for the month in which the Participant’s termination date occurs plus 50 basis points.

Sec. 6.04Deferral Elections. A Participant may make a one-time, irrevocable election to elect to have the present value of the Participant’s vested SERP benefit credited to the Participant’s account under the Deferral Plan on the date of the Participant’s separation from service, in lieu of the payments described in Section 6.02. If the Participant makes a deferral election, the present value of the Participant’s vested SERP benefit will be credited to the Participant’s account under the Deferral Plan at separation from service and the amount credited to the Deferral Plan shall be distributed in accordance with the provisions of the Deferral Plan. An election under this Section 6.04 shall be made in writing, on a form and at a time prescribed by the Administrative Committee and shall be irrevocable upon submission to the Corporate Secretary, and no further election shall be available under this SERP.

ARTICLE VII

FUNDING OF BENEFITS

Sec. 7.01Source of Funds. The obligations of UGI and other participating employers in the Pension Plan shall constitute a general, unsecured obligation, payable solely out of their general assets, and no Participant shall have any right to any specific assets of UGI, or any Subsidiary or Affiliate or any trust established by UGI or any Subsidiary or Affiliate to fund such obligations.

Sec. 7.02Participant Contributions. There shall be no contributions made by Participants under the SERP.

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ARTICLE VIII

THE COMMITTEE

Sec. 8.01Appointment and Tenure of Administrative Committee Members. The Administrative Committee shall consist of one or more persons who shall be appointed by and serve at the pleasure of the Compensation Committee. Any Administrative Committee member may resign by delivering his or her written resignation to the Compensation Committee. Vacancies arising by the death, resignation or removal of an Administrative Committee member may be filled by the Compensation Committee.

Sec. 8.02Meetings; Majority Rule. Any and all acts of the Administrative Committee taken at a meeting shall be by a majority of all members of the Administrative Committee. The Administrative Committee may act by vote taken in a meeting (at which a majority of members shall constitute a quorum). The Administrative Committee may also act by unanimous consent in writing without the formality of convening a meeting.

Sec. 8.03Delegation. The Administrative Committee may, by majority decision, delegate to each or any one of its number, authority to sign any documents on its behalf, or to perform ministerial acts, but no person to whom such authority is delegated shall perform any act involving the exercise of any discretion without first obtaining the concurrence of a majority of the members of the Administrative Committee, even though such person alone may sign any document required by third parties. The Administrative Committee shall elect one of its number to serve as Chairperson. The Chairperson shall preside at all meetings of the Administrative Committee or shall delegate such responsibility to another Administrative Committee member. The Administrative Committee shall elect one person to serve as Secretary to the Administrative Committee. All third parties may rely on any communication signed by the Secretary, acting as such, as an official communication from the Administrative Committee.

Sec. 8.04Authority and Responsibility of the Administrative Committee. The Administrative Committee shall have only such authority and responsibilities as are delegated to it by the Compensation Committee or specifically provided herein. The Administrative Committee shall have full power and express discretionary authority to administer and interpret the SERP, to make factual determinations and to adopt or amend such rules and regulations for implementing the SERP and for the conduct of its business as it deems necessary or advisable, in its sole discretion. The Administrative Committee’s authorities and responsibilities shall also include:

(a)maintenance and preservation of records relating to Participants, former Participants, and their beneficiaries;

(b)preparation and distribution to Participants of all information and notices required under Federal law or the provisions of the SERP;

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(c)preparation and filing of all governmental reports and other information required under law to be filed or published;

(d)engagement of assistants and professional advisers;

(e)arrangement for bonding, if required by law; and

(f)promulgation of procedures for determination of claims for benefits.

Sec. 8.05Compensation of Administrative Committee Members. The members of the Administrative Committee shall serve without compensation for their services as such, but all expenses of the Administrative Committee shall be paid or reimbursed by UGI.

Sec. 8.06Administrative Committee Discretion. Any discretion, actions, or interpretations to be made under the SERP by the Administrative Committee shall be made in its sole discretion, need not be uniformly applied to similarly situated individuals, and shall be final, binding, and conclusive on the parties. All benefits under the SERP shall be provided conditional upon the Participant’s acknowledgement, in writing or by acceptance of the benefits, that all decisions and determinations of the Administrative Committee shall be final and binding on the Participant, his or her beneficiaries and any other person having or claiming an interest under the SERP.

Sec. 8.07Indemnification of the Committees. Each member of the Administrative Committee shall be indemnified by UGI against costs, expenses and liabilities (other than amounts paid in settlement to which UGI does not consent) reasonably incurred by him or her in connection with any action to which he or she may be a party by reason of his or her service as a member of the Committee, except in relation to matters as to which he or she shall be adjudged in such action to be personally guilty of gross negligence or willful misconduct in the performance of his or her duties. The foregoing right to indemnification shall be in addition to such other rights as the Administrative Committee member may enjoy as a matter of law or by reason of insurance coverage of any kind, but shall not extend to costs, expenses and/or liabilities otherwise covered by insurance or that would be so covered by any insurance then in force if such insurance contained a waiver of subrogation. Rights granted hereunder shall be in addition to and not in lieu of any rights to indemnification to which the Administrative Committee member may be entitled pursuant to the by-laws of UGI. Service on the Administrative Committee shall be deemed in partial fulfillment of the Administrative Committee member’s function as an employee, officer and/or director of UGI, if he or she serves in that capacity as well as in the role of Administrative Committee member.

ARTICLE IX

AMENDMENT AND TERMINATION

Sec. 9.01Amendment. The provisions of the SERP may be amended at any time and from time to time by the Compensation Committee for any reason without either the consent of or prior notice to any Participant; provided, however, that no such amendment shall serve to reduce the benefit that has accrued on behalf of a Participant as of the effective date of the amendment. Notwithstanding the foregoing, the Administrative Committee may adopt any amendment to the SERP as it shall deem necessary or appropriate to (i) maintain compliance with current laws and regulations; (ii) correct errors and omissions in the SERP document; and (iii) facilitate the administration and operation of the SERP.

Sec. 9.02Plan Termination. While it is UGI’s intention to continue the SERP indefinitely in operation, the right is, nevertheless, reserved to terminate the SERP in whole or in part at any time for any reason without either the consent of or prior notice to any Participant. No such termination shall reduce the benefit that has accrued on behalf of a Participant as of the effective date of the termination, but UGI may immediately distribute all accrued benefits upon termination of the SERP in accordance with section 409A of the Code.

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ARTICLE X

CLAIMS PROCEDURES

Sec. 10.01Claim. Any person or entity claiming a benefit, requesting an interpretation or ruling under the SERP (hereinafter referred to as “claimant”), or requesting information under the SERP shall present the request in writing to the Administrative Committee, which shall respond in writing or electronically. The notice advising of the denial shall be furnished to the claimant within 90 days of receipt of the benefit claim by the Administrative Committee, unless special circumstances require an extension of time to process the claim. If an extension is required, the Administrative Committee shall provide notice of the extension prior to the termination of the 90 day period. In no event may the extension exceed a total of 180 days from the date of the original receipt of the claim.

Sec. 10.02Denial of Claim. If the claim or request is denied, the written or electronic notice of denial shall state:

(a)The reasons for denial;

(b)Reference to the specific SERP provisions on which the denial is based;

(c)A description of any additional material or information required and an explanation of why it is necessary; and

(d)An explanation of the SERP’s claims review procedures and the time limits applicable to such procedures, including the right to bring a civil action under section 502(a) of ERISA.

Sec. 10.03Final Decision. The decision on review shall normally be made within 60 days after the Administrative Committee’s receipt of claimant’s claim or request. If an extension of time is required for a hearing or other special circumstances, the claimant shall be notified and the time limit shall be 120 days. The decision shall be in writing or in electronic form and shall:

(a)State the specific reasons for the denial;

(b)Reference the relevant SERP provisions;

(c)State that the claimant is entitled to receive, upon request and free of charge, and have reasonable access to and copies of all documents, records and other information relevant to the claim for benefits; and

(d)State that the claimant may bring an action under section 502(a) of ERISA.

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All decisions on review shall be final and binding on all parties concerned.

Sec. 10.04Review of Claim. Any claimant whose claim or request is denied or who has not received a response within 60 days may request a review by notice given in writing or electronic form to the Administrative Committee. Such request must be made within 60 days after receipt by the claimant of the written or electronic notice of denial, or in the event the claimant has not received a response, 60 days after receipt by the Administrative Committee of the claimant’s claim or request. The claim or request shall be reviewed by the Administrative Committee which may, but shall not be required to, grant the claimant a hearing. On review, the claimant may have representation, examine pertinent documents, and submit issues and comments in writing.

ARTICLE XI

MISCELLANEOUS PROVISIONS

Sec. 11.01Nonalienation of Benefits. None of the payments, benefits or rights of any participant under the SERP shall be subject to any claim of any creditor, and, in particular, to the fullest extent permitted by law, all such payments, benefits and rights shall be free from attachment, garnishment, trustee’s process, or any other legal or equitable process available to any creditor of such Participant. No Participant shall have the right to alienate, anticipate, commute, pledge, encumber or assign any of the benefits or payments which he or she may expect to receive, contingently or otherwise, under the SERP.

Sec. 11.02No Contract of Employment. Neither the establishment of the SERP, nor any modification thereof, nor the creation of any fund, trust or account, nor the payment of any benefits shall be construed as giving any Participant or Employee, or any person whomsoever, the right to be retained in the service of UGI or any other participating employer hereunder, and all Participants and other Employees shall remain subject to discharge to the same extent as if the SERP had never been adopted.

Sec. 11.03Severability of Provisions. If any provision of the SERP shall be held invalid or unenforceable, such invalidity or unenforceability shall not affect any other provisions hereof, and the SERP shall be construed and enforced as if such provision had not been included.

Sec. 11.04Heirs, Assigns and Personal Representatives. The SERP shall be binding upon the heirs, executors, administrators, successors and assigns of the parties, including each Participant, present and future.

Sec. 11.05Successors. Unless the Compensation Committee directs otherwise before a Change of Control, in the event of a Change of Control, UGI shall require any successor or successors (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of UGI, or a division or Affiliate thereof, (i) to acknowledge expressly that this SERP is binding upon and enforceable against such successor in accordance with the terms hereof, (ii) to become jointly and severally obligated with UGI to perform the obligations under this SERP, and (iii) to agree not to amend or terminate the SERP for a period of three years after the date of succession without the consent of the affected Participant.

Sec. 11.06Headings and Captions. The headings and captions herein are provided for reference and convenience only, and shall not be considered part of the SERP, and shall not be employed in the construction of the SERP.

Sec. 11.07Gender and Number. Except where otherwise clearly indicated by context, the masculine and the neuter shall include the feminine and the neuter, the singular shall include the plural, and vice-versa.

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Sec. 11.08Controlling Law. The SERP shall be construed and enforced according to the laws of the Commonwealth of Pennsylvania, exclusive of conflict of law provisions thereof, to the extent not preempted by Federal law, which shall otherwise control.

Sec. 11.09Payments to Minors, Etc. Any benefit payable to or for the benefit of a minor, an incompetent person or other person incapable of receipting therefore shall be deemed paid when paid to such person’s guardian or to the party providing or reasonably appearing to provide for the care of such person, and such payment shall fully discharge UGI, the Board, the Administrative Committee and all other parties with respect thereto.

Sec. 11.10Reliance on Data and Consents. UGI, the Board, the Compensation Committee, the Administrative Committee, all fiduciaries with respect to the SERP, and all other persons or entities associated with the operation of the SERP, and the provision of benefits thereunder, may reasonably rely on the truth, accuracy and completeness of all data provided by the Participant, including, without limitation, data with respect to age, health and marital status. Furthermore, UGI, the Board, the Compensation Committee, the Administrative Committee and all fiduciaries with respect to the SERP may reasonably rely on all consents, elections and designations filed with the SERP or those associated with the operation of the SERP by any Participant, or the representatives of any such person without duty to inquire into the genuineness of any such consent, election or designation. None of the aforementioned persons or entities associated with the operation of the SERP or the benefits provided under the SERP shall have any duty to inquire into any such data, and all may rely on such data being current to the date of reference, it being the duty of the Participants to advise the appropriate parties of any change in such data.

Sec. 11.11Lost Payees. A benefit shall be deemed forfeited if the Administrative Committee is unable to locate a Participant to whom payment is due; provided, however, that such benefit shall be reinstated if a claim is made by the proper payee for the forfeited benefit.

Sec. 11.12Taxation. The SERP is intended to comply with section 409A of the Code. Notwithstanding anything in the SERP to the contrary, distributions may only be made under the SERP upon an event and in a manner permitted by section 409A of the Code. All payments under the SERP shall be subject to applicable tax withholding. Distributions upon termination of employment shall only be made upon the Participant’s “separation from service” under section 409A of the Code, and in no event may a Participant directly or indirectly designate the calendar year of a payment.

EXHIBIT A

CHANGE OF CONTROL

For purposes of the SERP, the term “Change of Control,” and other defined terms used in this Exhibit A, shall have the following meanings:

1.“Change of Control” shall mean:

(i)Any Person (except UGI, any UGI Subsidiary, any employee benefit plan of UGI or of any UGI Subsidiary, or any Person or entity organized, appointed or established by UGI for or pursuant to the terms of any such employee benefit plan), together with all Affiliates and Associates of such Person, becomes the Beneficial Owner in the aggregate of 20% or more of either (i) the then outstanding shares of common stock of UGI (the “Outstanding UGI Common Stock”) or (ii) the combined voting power of the then outstanding voting securities of UGI entitled to vote generally in the election of directors (the “UGI Voting Securities”); or

(ii)Individuals who, as of the beginning of any 24-month period, constitute the UGI Board of Directors (the “Incumbent UGI Board”) cease for any reason to constitute at least a majority of the Incumbent UGI Board, provided that any individual becoming a director of UGI subsequent to the beginning of such period whose election or nomination for election by the UGI shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent UGI Board shall be considered as though such individual were a member of the Incumbent UGI Board, but excluding, for this purpose, any such individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the Directors of UGI (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act); or

(iii)Consummation by UGI of a reorganization, merger or consolidation (a “Business Combination”), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of the Outstanding UGI Common Stock and UGI Voting Securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of the Outstanding UGI Common Stock and UGI Voting Securities, as the case may be; or

(iv)Consummation of (a) a complete liquidation or dissolution of UGI or (b) a sale or other disposition of all or substantially all of the assets of UGI other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the

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then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of the Outstanding UGI Common Stock and UGI Voting Securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of the Outstanding UGI Common Stock and UGI Voting Securities, as the case may be, immediately prior to such sale or disposition.

2.“Affiliate” and “Associate” shall have the respective meanings ascribed to such terms in Rule 12b-2 of the General Rules and Regulations under the Exchange Act.

3.“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.

4.A Person shall be deemed the “Beneficial Owner” of any securities: (i) that such Person or any of such Person’s Affiliates or Associates, directly or indirectly, has the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the exercise of conversion rights, exchange rights, rights, warrants or options, or otherwise; provided, however, that a Person shall not be deemed the “Beneficial Owner” of securities tendered pursuant to a tender or exchange offer made by such Person or any of such Person’s Affiliates or Associates until such tendered securities are accepted for payment, purchase or exchange; (ii) that such Person or any of such Person’s Affiliates or Associates, directly or indirectly, has the right to vote or dispose of or has “beneficial ownership” of (as determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act), including without limitation pursuant to any agreement, arrangement or understanding, whether or not in writing; provided, however, that a Person shall not be deemed the “Beneficial Owner” of any security under this clause (ii) as a result of an oral or written agreement, arrangement or understanding to vote such security if such agreement, arrangement or understanding (A) arises solely from a revocable proxy given in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable provisions of the General Rules and Regulations under the Exchange Act, and (B) is not then reportable by such Person on Schedule 13D under the Exchange Act (or any comparable or successor report); or (iii) that are beneficially owned, directly or indirectly, by any other Person (or any Affiliate or Associate thereof) with which such Person (or any of such Person’s Affiliates or Associates) has any agreement, arrangement or understanding (whether or not in writing) for the purpose of acquiring, holding, voting (except pursuant to a revocable proxy as described in the proviso to clause (ii) above) or disposing of any securities; provided, however, that nothing in this Section 1(c) shall cause a Person engaged in business as an underwriter of securities to be the “Beneficial Owner” of any securities acquired through such Person’s participation in good faith in a firm commitment underwriting until the expiration of forty (40) days after the date of such acquisition.

5.“Person” shall mean an individual or a corporation, partnership, trust, unincorporated organization, association, or other entity.

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6.“UGI Subsidiary” shall mean any corporation in which UGI directly or indirectly, owns at least a fifty percent (50%) interest or an unincorporated entity of which UGI, as applicable, directly or indirectly, owns at least fifty percent (50%) of the profits or capital interests.

Change of Control with Respect to UGI Utilities, Inc.

In addition to the definition of Change of Control with respect to UGI, as set forth above, for Participants who are employees of UGI Utilities, Inc. (“Utilities”) or a subsidiary of Utilities, the term “Change of Control” shall include the events set forth below:

“Change of Control” shall include any of the following events:

(A)UGI and the UGI Subsidiaries fail to own more than fifty percent (50%) of the then outstanding shares of common stock of Utilities or more than fifty percent (50%) of the combined voting power of the then outstanding voting securities of Utilities entitled to vote generally in the election of directors; or

(B)Completion by Utilities of a reorganization, merger or consolidation (a "Business Combination"), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of Utilities’ outstanding common stock and voting securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of Utilities’ outstanding common stock and voting securities, as the case may be; or

(C)Completion of a complete liquidation or dissolution of the Utilities or sale or other disposition of all or substantially all of the assets of Utilities other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of Utilities’ outstanding common stock and voting securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of Utilities’ outstanding common stock and voting securities, as the case may be, immediately prior to such sale or disposition.

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EXHIBIT B

ACTUARIAL ASSUMPTIONS

Assumptions used for calculating the lump sum payment of vested accrued SERP benefits:

1.For Participants attaining age 50 prior to January 1, 2004, with service after January 1, 2004, the lump sum payment is calculated using two interest rates. One rate is for service prior to January 1, 2004 and the other for service after January 1, 2004. The rates are determined as follows:

▪ Pre-January 1, 2004 Service. The daily average of Moody’s Aaa bond yields for the month in which the Participant’s termination date occurs, plus 50 basis points, tax-adjusted using the highest marginal Federal tax rate (35.0% for 2007).

▪ Post-January 1, 2004 Service. The daily average of 10-year Treasury Bond yields in effect for the month in which the Participant’s termination date occurs, as reported in Federal Reserve Statistical Release H.15 or any comparable successor publication.

The 1994 GAR unisex mortality table is also used in the lump sum calculation.

2.For Participants attaining age 50 on or after January 1, 2004, the rates are determined as follows:

▪ The daily average of 10-year Treasury Bond yields in effect for the month in which the Participant’s termination date occurs, as reported in Federal Reserve Statistical Release H.15 or any comparable successor publication.

The 1994 GAR unisex mortality table is also used in the lump sum calculation.

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UGI CORPORATION

SUPPLEMENTAL SAVINGSPLAN

ARTICLE I

STATEMENT OF PURPOSE

The Supplemental Savings Plan (the “SSP”) is maintained to provide a fair and competitive level of retirement benefits to certain management and other highly compensated employees who have, by operation of laws and regulations relating to qualified savings plans, experienced a reduction in benefits under the Savings Plan (as defined in Article II). The benefits under the SSP are also designed to compensate terminated participants by taking into account periods of time for which payments are made under a Change in Control Agreement (as defined in Article II) or, for employees whose employment terminated on or after January 1, 2005 and before July 25, 2006, under an Executive Severance Plan (as defined in Article II).

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ARTICLE II

DEFINITIONS

Sec. 2.01“Administrative Committee” shall mean the committee designated by the Compensation Committee to administer the SSP.

Sec. 2.02“Affiliate” shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended.

Sec. 2.03“Beneficiary” shall mean the person or entity who shall receive benefits in the event of the Participant’s death, as determined under the Savings Plan.

Sec. 2.04“Board” shall mean the Board of Directors of UGI.

Sec. 2.05“Cause” shall mean misappropriation of funds, habitual insobriety, substance abuse, conviction of a crime involving moral turpitude, or gross negligence in the performance of duties, which gross negligence has had a material adverse effect on the business, operations, assets, properties or financial condition of UGI and its Subsidiaries and Affiliates, taken as a whole.

Sec. 2.06“Change of Control” shall have the meaning set forth on the attached Exhibit A.

Sec. 2.07“Change in Control Agreement” shall mean a Change in Control Agreement between an Employee and UGI or a Subsidiary (other than AmeriGas Propane, Inc. or its subsidiaries).

Sec. 2.08“Code” shall mean the Internal Revenue Code of 1986, as amended.

Sec. 2.09“Compensation Committee” shall mean the Compensation and Management Development Committee of the Board.

Sec. 2.10“Continuation Period” shall mean, with respect to a Participant who is entitled to receive benefits under a Change in Control Agreement, the Continuation Period as defined in the Participant’s Change in Control Agreement.

Sec. 2.11“Effective Date” of the amended SSP shall mean April 1, 2015, except where otherwise indicated. The SSP is a continuation of the savings plan portion of the UGI Corporation Supplemental Executive Retirement Plan, as in effect before January 1, 2005.

Sec. 2.12“Employee” shall mean any person in the employ of UGI, UGI Utilities, Inc. or another Subsidiary other than AmeriGas Propane, Inc. or its subsidiaries. In no event shall a person who is characterized as an independent contractor by the employer, no matter how characterized by a court or government agency, be considered an “Employee,” and

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no retroactive characterization of an individual’s status for any other purpose shall make an individual an “Employee.”

Sec. 2.13“Employment Commencement Date” shall mean the first day on which a Participant became an employee of UGI, any Subsidiary or Affiliate of UGI, or any entity whose business or assets have been acquired by UGI, by a Subsidiary or Affiliate of UGI or by any predecessor of such entities.

Sec. 2.14“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

Sec. 2.15“Excess Earnings” shall mean that portion of an Employee’s compensation from UGI or another participating employer hereunder that is not permitted to be taken into account under the Savings Plan by operation of section 401(a)(17) of the Code or any successor thereto, excluding any such compensation earned when the Employee was not a Participant.

Sec. 2.16“Executive Annual Bonus Plan” shall mean the UGI Corporation Executive Annual Bonus Plan or the UGI Utilities, Inc. Executive Annual Bonus Plan, as amended from time to time, and any successor plans (and for fiscal years through 1996, the AmeriGas Propane, Inc. Executive Annual Bonus Plan).

Sec. 2.17“Executive Severance Plan” shall mean an executive severance plan of UGI or a Subsidiary or Affiliate (other than AmeriGas Propane, Inc. or its subsidiaries).

Sec. 2.18“Key Employee” shall mean an employee who, at any time during the 12-month period ending on the identification date, is a “specified employee” under section 409A of the Code, as determined by the Compensation Committee or its delegate. The determination of Key Employees, including the number and identity of persons considered specified employees and the identification date, shall be made by the Compensation Committee or its delegate in accordance with the provisions of section 409A of the Code and the regulations issued thereunder.

Sec. 2.19“Matching Contribution” shall have the meaning given that term in the Savings Plan.

Sec. 2.20“Participant” shall mean each Employee who meets the requirements of Section 3.01 hereof.

Sec. 2.21“Pension Plan” shall mean the Retirement Income Plan for Employees of UGI Utilities, Inc., as currently in effect and as it may hereafter be amended, and any plan designated by the Board as a successor thereto.

Sec. 2.22“Plan Year” shall mean, effective January 1, 2007, a 12-month period beginning on January 1 and ending on December 31. For periods before January 1, 2007, the Plan Year shall mean a period beginning on October 1 and ending on the following September

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30, with a short Plan Year for the period beginning on October 1, 2006 and ending on December 31, 2006.

Sec. 2.23“Postponement Period” shall mean, for a Key Employee, the period of six months after separation from service (or such other period as may be required by section 409A of the Code), during which SSP benefits may not be paid to the Key Employee under section 409A of the Code.

Sec. 2.24“Prior SERP” shall mean the UGI Corporation Supplemental Executive Retirement Plan as in effect before January 1, 2005.

Sec. 2.25“Savings Plan” shall mean the UGI Utilities, Inc. Savings Plan as it may thereafter be amended, and any plan designated by the Administrative Committee as the successor to the UGI Utilities, Inc. Savings Plan.

Sec. 2.26“Savings Plan Year” shall mean the calendar year.

Sec. 2.27“SSP” shall mean the UGI Corporation Supplemental Savings Plan as set forth herein, and as the same may hereafter be amended.

Sec. 2.28“Subsidiary” shall mean any corporation in which UGI, directly or indirectly, owns at least a 50% interest or an unincorporated entity of which UGI, directly or indirectly, owns at least 50% of the profits or capital interests.

Sec. 2.29“UGI” shall mean UGI Corporation.

Sec. 2.30“Year of Service” shall mean a Year of Service as determined under the Savings Plan for vesting purposes.

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ARTICLE III

PARTICIPATION

Sec. 3.01Participants.

(a)Each Employee who (i) is eligible to receive a bonus under an Executive Annual Bonus Plan at any time during the applicable Plan Year, (ii) is an active participant in the Savings Plan and makes the contributions described in Section 5.01(a) to the Savings Plan for the Plan Year, and (iii) is an active participant in the Pension Plan for the Plan Year, shall be a Participant in the SSP for the applicable Plan Year.

(b)Each Employee who has a Change in Control Agreement that provides for the benefits described in Section 5.04 shall be a Participant in this SSP for purposes of being eligible to receive benefits under Section 5.04.

(c)An Employee whose employment terminated on or after January 1, 2005 and before July 25, 2006, and who was entitled to receive a severance benefit under an Executive Severance Plan, as described in Section 5.05, shall be a Participant in this SSP for purposes of being eligible to receive benefits under Section 5.05.

(d)Notwithstanding the foregoing, no Employee who is hired or rehired by UGI or an Affiliate on or after January 1, 2009, or who is transferred on or after January 1, 2009 into Employee status from an Affiliate that does not participate in this SSP, shall become a Participant in this SSP on or after January 1, 2009.

Sec. 3.02Transfers. If a Participant ceases to meet the requirements of Section 3.01 but continues to be an employee of UGI or a Subsidiary or Affiliate, the former Participant will cease to accrue benefits under the SSP. The former Participant will continue to earn Years of Service credit for vesting purposes with respect to the SSP for purposes of his or her accrued SSP benefit under Section 5.01. The former Participant’s account will continue to be credited with earnings pursuant to Section 5.02 while the former Participant has an account under the SSP.

Sec. 3.03Accounts. UGI shall establish a bookkeeping account for each Participant under the SSP. All contributions under the SSP, and earnings thereon as described in Section 5.02, shall be credited to the Participant’s account.

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ARTICLE IV

VESTING

Sec. 4.01Vesting in Section 5.01 Benefits.

(a)A Participant shall vest in the amounts credited under Sections 5.01 and 5.02 of the SSP when the Participant has five Years of Service. If a Participant’s employment with UGI and its Subsidiaries and Affiliates terminates for any reason other than death before the Participant has five Years of Service, all amounts credited under Sections 5.01 and 5.02 shall be immediately forfeited, and the Participant shall receive no benefits under Sections 5.01 and 5.02. If a Participant dies while employed by UGI or its Subsidiaries or Affiliates, the Participant’s amounts credited under Sections 5.01 and 5.02 shall become fully vested.

(b)If a Participant whose employment terminated on or after January 1, 2005 and before July 25, 2006 is entitled to receive a benefit under Section 5.05, the Participant’s salary continuation period under the Executive Severance Plan shall be counted as service for purposes of vesting under this SSP.

Sec. 4.02Vesting in Section 5.04 and Section 5.05 Benefits.

(a)A Participant shall vest in the amounts credited under Section 5.04 of the SSP when the Participant’s employment has terminated under the circumstances described in Section 5.04 and the Participant has met all the requirements of the Participant’s Change in Control Agreement that entitle the Participant to receive the amounts described in Section 5.04.

(b)A Participant whose employment terminated on or after January 1, 2005 and before July 25, 2006 shall vest in the amounts credited under Section 5.05 of the SSP when the Participant’s employment has terminated under the circumstances described in Section 5.05 and the Participant has met all the requirements of the Executive Severance Plan that entitle the Participant to receive the amounts described in Section 5.05.

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ARTICLE V

BENEFITS

Sec. 5.01SSP Annual Contributions.

(a)Effective January 1, 2007, at the end of each Plan Year, the Administrative Committee shall credit an SSP contribution to the book account of each Participant who is an active participant in the Savings Plan and who contributed to the Savings Plan for the Plan Year an amount at least equal to the lesser of (i) 6% of the Participant’s annual compensation (as determined under the Savings Plan) or (ii) the maximum amount permitted to be contributed under section 402(g) of the Code (without regard to any “catch up” contributions as described below).

(b)The SSP contribution for each Participant described in subsection (a) for the Plan Year shall be calculated as:

(x)The Matching Contribution that would have been made for the Participant under the Savings Plan for the Plan Year, based on an election to contribute 6% of the Participant’s annual compensation (as determined under the Savings Plan), if (i) the Participant’s Excess Earnings (without regard to the limitations set forth in section 401(a)(17) of the Code) had been taken into account, (ii) the limitations set forth in section 402(g) of the Code were inoperative, and (iii) there were no cutbacks of contributions to the Savings Plans to comply with nondiscrimination tests set forth in Sections 401(k) and 401(m) of the Code, less

(y)The Matching Contribution that would have been made to the Savings Plan for the Participant for the Plan Year, based on an election to contribute 6% of the Participant’s annual compensation (as determined under the Savings Plan), and taking into account the limitations set forth in section 401(a)(17) of the Code, the limitations set forth in section 402(g) of the Code and any applicable cutbacks of contributions to the Savings Plans to comply with nondiscrimination tests set forth in Sections 401(k) and 401(m) of the Code.

Notwithstanding the foregoing, no contribution shall be credited under the SSP with respect to “catch-up” contributions made under the Savings Plan pursuant to section 414(v) of the Code. The contribution credited under the SSP for a Participant for a Plan Year shall not exceed the Matching Contribution that would have been provided under the Savings Plan in the absence of any plan-based restrictions that reflect limits on qualified plan contributions under the Code, in accordance with section 409A of the Code.

(c)The Administrative Committee shall calculate a prorated SSP contribution for each Participant for the short Plan Year beginning October 1, 2006 and ending December 31, 2006, in such manner as the Administrative Committee determines.

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(d)The Administrative Committee shall credit each Participant’s SERP contribution for each Plan Year to a bookkeeping account for the Participant on UGI’s records.

Sec. 5.02Earnings. At the end of each Plan Year, each Participant who has an unpaid book account under the SSP as of the end of the Plan Year shall be credited with earnings on the Participant’s SSP account, as described below. The amount of the credit is equal to the product obtained by multiplying the Participant’s cumulative account balance as of the end of the Plan Year by the Participant’s “individual rate per annum,” determined as follows:

(a)For Plan Years ending before October 1, 2005, the “individual rate per annum” is determined by dividing (i) by (ii), where (i) is the total of all actual gains and losses reported on the Participant’s Savings Plan portfolio for the Plan Year, measured on the last day of the Plan Year, and (ii) is the sum of the Participant’s beginning balance in the Savings Plan on the first day of the Plan Year plus all contributions to the Participant’s Savings Plan account during the Plan Year.

(b)For Plan Years beginning on or after October 1, 2005, the “individual rate per annum” is a weighted average return calculated by UGI, based 60% on the total return of the Standard & Poor’s 500 Index and 40% on the total return of the Lehman Brothers Aggregate Bond Index for the Plan Year.

Sec. 5.03Termination of Employment.

(a)If a Participant’s employment terminates during a Plan Year for any reason other than Cause, the Administrative Committee shall credit a pro rata SSP contribution to the Participant’s account for the Plan Year, if the Participant is an active participant in the Savings Plan and has contributed to the Savings Plan for the Plan Year an amount at least equal to the lesser of (i) 6% of the Participant’s annual compensation (as determined under the Savings Plan) or (ii) a pro-rata amount of the maximum amount permitted to be contributed under section 402(g) of the Code (without regard to any “catch up” contributions).

(b)If a Participant’s employment terminates during a Plan Year for any reason other than Cause, the Administrative Committee shall credit earnings on the terminated Participant’s SSP account from the end of the preceding Plan Year to the termination date, based on the “individual rate per annum” described in Section 5.02(b) above for the portion of the Plan Year for which earnings are credited before the termination date.

(c)The amounts described in this Section 5.03 shall be credited to the Participant’s account as of the Participant’s termination date.

Sec. 5.04Change of Control Benefit. In the event of a Change of Control, if and to the extent required by a Participant’s Change in Control Agreement, each Participant who is an active participant in both the Savings Plan and the Pension Plan on the date of the Participant’s termination of employment and who is entitled to receive severance benefits under

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a Change in Control Agreement shall receive a credit to the Participant’s SSP account equal to the Participant’s Matching Contributions that would have been made to the Savings Plan (without regard to the statutory limits) had the Participant been eligible to participate in the Savings Plan and made employee elective deferral contributions to the Savings Plan during the Continuation Period equal to 6% of his or her annual compensation as described in the Change in Control Agreement. This benefit shall be credited to the Participant’s account as of the Participant’s termination date.

Sec. 5.05Severance Benefit. The provisions of this Section 5.05 apply to a Participant whose employment was terminated by UGI or a Subsidiary or Affiliate on or after January 1, 2005 and before July 25, 2006, if the Participant was entitled to receive a severance benefit under an Executive Severance Plan and the Participant was an active participant in the Savings Plan on the date of the Participant’s termination of employment. If required by the terms of the Executive Severance Plan, each such Participant shall receive a credit to the Participant’s SSP account equal to the Participant’s Matching Contributions that would have been made to the Savings Plan (without regard to the statutory limits) had the Participant been eligible to participate in the Savings Plan and made employee elective deferral contributions to the Savings Plan during the Participant’s salary continuation period under the Executive Severance Plan equal to 6% of his or her annual compensation (determined as of the day of his or her termination of employment). This benefit shall be credited to the Participant’s account as of the date of the Participant’s termination date.

Sec. 5.06Death Benefits. If a Participant is entitled to receive a vested benefit under this Article V but the Participant dies before receiving his or her SSP benefit, the Participant’s vested benefit, if any, shall be paid to the Beneficiary.

Sec. 5.07Forfeiture. Each Participant shall immediately forfeit any benefit to which he or she is otherwise entitled under the SSP if the Participant’s employment is terminated for Cause.

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ARTICLE VI

FORM AND TIMING OF BENEFIT DISTRIBUTION

Sec. 6.01Form of Benefit Distributions. A Participant’s vested SSP benefits shall be paid to the Participant in the form of a lump sum payment upon the Participant’s termination of employment with UGI and its Subsidiaries and Affiliates, as described below. A Participant’s vested SSP benefits are the vested amount credited to the Participant’s account under the SSP.

Sec. 6.02Timing of Benefit Distributions.

(a)A Participant’s vested SSP benefits shall be paid to the Participant within 60 days following the Participant’s termination of employment with UGI and its Subsidiaries and Affiliates, except as described below. A Participant shall be considered to have incurred a termination of employment under the SSP when the Participant has a “separation from service” under section 409A of the Code.

(b)Notwithstanding the foregoing, if a Participant whose employment terminates after January 1, 2005 is a Key Employee and if required by section 409A of the Code, no SSP benefits shall be paid to the Participant during the Postponement Period. If payment of SSP benefits is required to be delayed for the Postponement Period pursuant to section 409A, the accumulated amounts withheld on account of section 409A, with interest as described below, shall be paid in a lump sum payment within 15 days after the end of the Postponement Period. If the Participant dies during the Postponement Period prior to the payment of benefits, the amounts withheld on account of section 409A, with interest as described below, shall be paid to the Participant’s estate within 60 days after the Participant’s death.

(c)The amount to be withheld on account of section 409A shall be calculated as of the Participant’s termination date. Interest shall be credited on the withheld amount from the Participant’s termination date to the last day of the calendar month preceding the date on which the withheld amount is paid, based on the daily average of the published six-month Treasury bill rate in effect for the month in which the Participant’s termination date occurs plus 50 basis points.

- 10 -

ARTICLE VII

FUNDING OF BENEFITS

Sec. 7.01Source of Funds. The obligations of UGI and other participating employers hereunder shall constitute a general, unsecured obligation, payable solely out of their general assets, and no Participant shall have any right to any specific assets of UGI, or any Subsidiary or Affiliate or any trust established by UGI or any Subsidiary or Affiliate to fund such obligations.

Sec. 7.02Participant Contributions. There shall be no contributions made by Participants under the SSP.

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ARTICLE VIII

THE COMMITTEE

Sec. 8.01Appointment and Tenure of Administrative Committee Members. The Administrative Committee shall consist of one or more persons who shall be appointed by and serve at the pleasure of the Compensation Committee. Any Administrative Committee member may resign by delivering his or her written resignation to the Compensation Committee. Vacancies arising by the death, resignation or removal of an Administrative Committee member may be filled by the Compensation Committee.

Sec. 8.02Meetings; Majority Rule. Any and all acts of the Administrative Committee taken at a meeting shall be by a majority of all members of the Administrative Committee. The Administrative Committee may act by vote taken in a meeting (at which a majority of members shall constitute a quorum). The Administrative Committee may also act by unanimous consent in writing without the formality of convening a meeting.

Sec. 8.03Delegation. The Administrative Committee may, by majority decision, delegate to each or any one of its number, authority to sign any documents on its behalf, or to perform ministerial acts, but no person to whom such authority is delegated shall perform any act involving the exercise of any discretion without first obtaining the concurrence of a majority of the members of the Administrative Committee, even though such person alone may sign any document required by third parties. The Administrative Committee shall elect one of its number to serve as Chairperson. The Chairperson shall preside at all meetings of the Administrative Committee or shall delegate such responsibility to another Administrative Committee member. The Administrative Committee shall elect one person to serve as Secretary to the Administrative Committee. All third parties may rely on any communication signed by the Secretary, acting as such, as an official communication from the Administrative Committee.

Sec. 8.04Authority and Responsibility of the Administrative Committee. The Administrative Committee shall have only such authority and responsibilities as are delegated to it by the Compensation Committee or specifically provided herein. The Administrative Committee shall have full power and express discretionary authority to administer and interpret the SSP, to make factual determinations and to adopt or amend such rules and regulations for implementing the SSP and for the conduct of its business as it deems necessary or advisable, in its sole discretion. The Administrative Committee’s authorities and responsibilities shall also include:

(a)maintenance and preservation of records relating to Participants, former Participants, and their beneficiaries;

(b)preparation and distribution to Participants of all information and notices required under Federal law or the provisions of the SSP;

- 12 -

(c)preparation and filing of all governmental reports and other information required under law to be filed or published;

(d)engagement of assistants and professional advisers;

(e)arrangement for bonding, if required by law; and

(f)promulgation of procedures for determination of claims for benefits.

Sec. 8.05Compensation of Administrative Committee Members. The members of the Administrative Committee shall serve without compensation for their services as such, but all expenses of the Administrative Committee shall be paid or reimbursed by UGI.

Sec. 8.06Administrative Committee Discretion. Any discretion, actions, or interpretations to be made under the SSP by the Administrative Committee shall be made in its sole discretion, need not be uniformly applied to similarly situated individuals, and shall be final, binding, and conclusive on the parties. All benefits under the SSP shall be provided conditional upon the Participant’s acknowledgement, in writing or by acceptance of the benefits, that all decisions and determinations of the Administrative Committee shall be final and binding on the Participant, his or her Beneficiaries and any other person having or claiming an interest under the SSP.

Sec. 8.07Indemnification of the Committees. Each member of the Administrative Committee shall be indemnified by UGI against costs, expenses and liabilities (other than amounts paid in settlement to which UGI does not consent) reasonably incurred by him or her in connection with any action to which he or she may be a party by reason of his or her service as a member of the Committee, except in relation to matters as to which he or she shall be adjudged in such action to be personally guilty of gross negligence or willful misconduct in the performance of his or her duties. The foregoing right to indemnification shall be in addition to such other rights as the Administrative Committee member may enjoy as a matter of law or by reason of insurance coverage of any kind, but shall not extend to costs, expenses and/or liabilities otherwise covered by insurance or that would be so covered by any insurance then in force if such insurance contained a waiver of subrogation. Rights granted hereunder shall be in addition to and not in lieu of any rights to indemnification to which the Administrative Committee member may be entitled pursuant to the by-laws of UGI. Service on the Administrative Committee shall be deemed in partial fulfillment of the Administrative Committee member’s function as an employee, officer and/or director of UGI, if he or she serves in that capacity as well as in the role of Administrative Committee member.

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ARTICLE IX

AMENDMENT AND TERMINATION

Sec. 9.01Amendment. The provisions of the SSP may be amended at any time and from time to time by the Compensation Committee for any reason without either the consent of or prior notice to any Participant; provided, however, that no such amendment shall serve to reduce the benefit that has accrued on behalf of a Participant as of the effective date of the amendment. Notwithstanding the foregoing, the Administrative Committee may adopt any amendment to the SSP as it shall deem necessary or appropriate to (i) maintain compliance with current laws and regulations; (ii) correct errors and omissions in the SSP document; and (iii) facilitate the administration and operation of the SSP.

Sec. 9.02Plan Termination. While it is UGI’s intention to continue the SSP indefinitely in operation, the right is, nevertheless, reserved to terminate the SSP in whole or in part at any time for any reason without either the consent of or prior notice to any Participant. No such termination shall reduce the benefit that has accrued on behalf of a Participant as of the effective date of the termination, but UGI may immediately distribute all accrued benefits upon termination of the SSP in accordance with section 409A of the Code.

- 14 -

ARTICLE X

CLAIMS PROCEDURES

Sec. 10.01Claim. Any person or entity claiming a benefit, requesting an interpretation or ruling under the SSP (hereinafter referred to as “claimant”), or requesting information under the SSP shall present the request in writing to the Administrative Committee, which shall respond in writing or electronically. The notice advising of the denial shall be furnished to the claimant within 90 days of receipt of the benefit claim by the Administrative Committee, unless special circumstances require an extension of time to process the claim. If an extension is required, the Administrative Committee shall provide notice of the extension prior to the termination of the 90 day period. In no event may the extension exceed a total of 180 days from the date of the original receipt of the claim.

Sec. 10.02Denial of Claim. If the claim or request is denied, the written or electronic notice of denial shall state:

(a)The reasons for denial;

(b)Reference to the specific SSP provisions on which the denial is based;

(c)A description of any additional material or information required and an explanation of why it is necessary; and

(d)An explanation of the SSP’s claims review procedures and the time limits applicable to such procedures, including the right to bring a civil action under section 502(a) of ERISA.

Sec. 10.03Final Decision. The decision on review shall normally be made within 60 days after the Administrative Committee’s receipt of claimant’s claim or request. If an extension of time is required for a hearing or other special circumstances, the claimant shall be notified and the time limit shall be 120 days. The decision shall be in writing or in electronic form and shall:

(a)State the specific reasons for the denial;

(b)Reference the relevant SSP provisions;

(c)State that the claimant is entitled to receive, upon request and free of charge, and have reasonable access to and copies of all documents, records and other information relevant to the claim for benefits; and

(d)State that the claimant may bring an action under section 502(a) of ERISA.

- 15 -

All decisions on review shall be final and binding on all parties concerned.

Sec. 10.04Review of Claim. Any claimant whose claim or request is denied or who has not received a response within 60 days may request a review by notice given in writing or electronic form to the Administrative Committee. Such request must be made within 60 days after receipt by the claimant of the written or electronic notice of denial, or in the event the claimant has not received a response, 60 days after receipt by the Administrative Committee of the claimant’s claim or request. The claim or request shall be reviewed by the Administrative Committee which may, but shall not be required to, grant the claimant a hearing. On review, the claimant may have representation, examine pertinent documents, and submit issues and comments in writing.

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ARTICLE XI

MISCELLANEOUS PROVISIONS

Sec. 11.01Nonalienation of Benefits. None of the payments, benefits or rights of any participant under the SSP shall be subject to any claim of any creditor, and, in particular, to the fullest extent permitted by law, all such payments, benefits and rights shall be free from attachment, garnishment, trustee’s process, or any other legal or equitable process available to any creditor of such Participant. No Participant shall have the right to alienate, anticipate, commute, pledge, encumber or assign any of the benefits or payments which he or she may expect to receive, contingently or otherwise, under the SSP, except any right to designate a Beneficiary in connection with any form of benefit payment providing benefits after the Participant’s death.

Sec. 11.02No Contract of Employment. Neither the establishment of the SSP, nor any modification thereof, nor the creation of any fund, trust or account, nor the payment of any benefits shall be construed as giving any Participant or Employee, or any person whomsoever, the right to be retained in the service of UGI or any other participating employer hereunder, and all Participants and other Employees shall remain subject to discharge to the same extent as if the SSP had never been adopted.

Sec. 11.03Severability of Provisions. If any provision of the SSP shall be held invalid or unenforceable, such invalidity or unenforceability shall not affect any other provisions hereof, and the SSP shall be construed and enforced as if such provision had not been included.

Sec. 11.04Heirs, Assigns and Personal Representatives. The SSP shall be binding upon the heirs, executors, administrators, successors and assigns of the parties, including each Participant, present and future.

Sec. 11.05Successors. Unless the Compensation Committee directs otherwise before a Change of Control, in the event of a Change of Control, UGI shall require any successor or successors (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of UGI, or a division or Affiliate thereof, (i) to acknowledge expressly that this SSP is binding upon and enforceable against such successor in accordance with the terms hereof, (ii) to become jointly and severally obligated with UGI to perform the obligations under this SSP, and (iii) to agree not to amend or terminate the SSP for a period of three years after the date of succession without the consent of the affected Participant.

Sec. 11.06Headings and Captions. The headings and captions herein are provided for reference and convenience only, and shall not be considered part of the SSP, and shall not be employed in the construction of the SSP.

Sec. 11.07Gender and Number. Except where otherwise clearly indicated by context, the masculine and the neuter shall include the feminine and the neuter, the singular shall include the plural, and vice-versa.

- 17 -

Sec. 11.08Controlling Law. The SSP shall be construed and enforced according to the laws of the Commonwealth of Pennsylvania, exclusive of conflict of law provisions thereof, to the extent not preempted by Federal law, which shall otherwise control.

Sec. 11.09Payments to Minors, Etc. Any benefit payable to or for the benefit of a minor, an incompetent person or other person incapable of receipting therefore shall be deemed paid when paid to such person’s guardian or to the party providing or reasonably appearing to provide for the care of such person, and such payment shall fully discharge UGI, the Board, the Administrative Committee and all other parties with respect thereto.

Sec. 11.10Reliance on Data and Consents. UGI, the Board, the Compensation Committee, the Administrative Committee, all fiduciaries with respect to the SSP, and all other persons or entities associated with the operation of the SSP, and the provision of benefits thereunder, may reasonably rely on the truth, accuracy and completeness of all data provided by the Participant, including, without limitation, data with respect to age, health and marital status. Furthermore, UGI, the Board, the Compensation Committee, the Administrative Committee and all fiduciaries with respect to the SSP may reasonably rely on all consents, elections and designations filed with the SSP or those associated with the operation of the SSP by any Participant, or the representatives of any such person without duty to inquire into the genuineness of any such consent, election or designation. None of the aforementioned persons or entities associated with the operation of the SSP or the benefits provided under the SSP shall have any duty to inquire into any such data, and all may rely on such data being current to the date of reference, it being the duty of the Participants to advise the appropriate parties of any change in such data.

Sec. 11.11Lost Payees. A benefit shall be deemed forfeited if the Administrative Committee is unable to locate a Participant to whom payment is due; provided, however, that such benefit shall be reinstated if a claim is made by the proper payee for the forfeited benefit.

Sec. 11.12Taxation. The SSP is intended to comply with the requirements of section 409A of the Code. Notwithstanding anything in the SSP to the contrary, allocations to the SSP shall be made consistent with section 409A, and distributions may only be made under the SSP upon an event and in a manner permitted by section 409A of the Code. All payments under the SSP shall be subject to applicable tax withholding. Distributions upon termination of employment shall only be made upon the Participant’s “separation from service” under section 409A of the Code, and in no event may a Participant directly or indirectly designate the calendar year of a payment.

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EXHIBIT A

CHANGE OF CONTROL

For purposes of the SSP, the term “Change of Control,” and other defined terms used in this Exhibit A, shall have the following meanings:

1.“Change of Control” shall mean:

(i)Any Person (except UGI, any UGI Subsidiary, any employee benefit plan of UGI or of any UGI Subsidiary, or any Person or entity organized, appointed or established by UGI for or pursuant to the terms of any such employee benefit plan), together with all Affiliates and Associates of such Person, becomes the Beneficial Owner in the aggregate of 20% or more of either (i) the then outstanding shares of common stock of UGI (the “Outstanding UGI Common Stock”) or (ii) the combined voting power of the then outstanding voting securities of UGI entitled to vote generally in the election of directors (the “UGI Voting Securities”); or

(ii)Individuals who, as of the beginning of any 24-month period, constitute the UGI Board of Directors (the “Incumbent UGI Board”) cease for any reason to constitute at least a majority of the Incumbent UGI Board, provided that any individual becoming a director of UGI subsequent to the beginning of such period whose election or nomination for election by the UGI shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent UGI Board shall be considered as though such individual were a member of the Incumbent UGI Board, but excluding, for this purpose, any such individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the Directors of UGI (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act); or

(iii)Consummation by UGI of a reorganization, merger or consolidation (a “Business Combination”), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of the Outstanding UGI Common Stock and UGI Voting Securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of the Outstanding UGI Common Stock and UGI Voting Securities, as the case may be; or

(iv)Consummation of (a) a complete liquidation or dissolution of UGI or (b) a sale or other disposition of all or substantially all of the assets of UGI other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the

A-1

then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of the Outstanding UGI Common Stock and UGI Voting Securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of the Outstanding UGI Common Stock and UGI Voting Securities, as the case may be, immediately prior to such sale or disposition.

2.“Affiliate” and “Associate” shall have the respective meanings ascribed to such terms in Rule 12b-2 of the General Rules and Regulations under the Exchange Act.

3.“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.

4.A Person shall be deemed the “Beneficial Owner” of any securities: (i) that such Person or any of such Person’s Affiliates or Associates, directly or indirectly, has the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the exercise of conversion rights, exchange rights, rights, warrants or options, or otherwise; provided, however, that a Person shall not be deemed the “Beneficial Owner” of securities tendered pursuant to a tender or exchange offer made by such Person or any of such Person’s Affiliates or Associates until such tendered securities are accepted for payment, purchase or exchange; (ii) that such Person or any of such Person’s Affiliates or Associates, directly or indirectly, has the right to vote or dispose of or has “beneficial ownership” of (as determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act), including without limitation pursuant to any agreement, arrangement or understanding, whether or not in writing; provided, however, that a Person shall not be deemed the “Beneficial Owner” of any security under this clause (ii) as a result of an oral or written agreement, arrangement or understanding to vote such security if such agreement, arrangement or understanding (A) arises solely from a revocable proxy given in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable provisions of the General Rules and Regulations under the Exchange Act, and (B) is not then reportable by such Person on Schedule 13D under the Exchange Act (or any comparable or successor report); or (iii) that are beneficially owned, directly or indirectly, by any other Person (or any Affiliate or Associate thereof) with which such Person (or any of such Person’s Affiliates or Associates) has any agreement, arrangement or understanding (whether or not in writing) for the purpose of acquiring, holding, voting (except pursuant to a revocable proxy as described in the proviso to clause (ii) above) or disposing of any securities; provided, however, that nothing in this Section 1(c) shall cause a Person engaged in business as an underwriter of securities to be the “Beneficial Owner” of any securities acquired through such Person’s participation in good faith in a firm commitment underwriting until the expiration of forty (40) days after the date of such acquisition.

5.“Person” shall mean an individual or a corporation, partnership, trust, unincorporated organization, association, or other entity.

A-2

6.“UGI Subsidiary” shall mean any corporation in which UGI directly or indirectly, owns at least a fifty percent (50%) interest or an unincorporated entity of which UGI, as applicable, directly or indirectly, owns at least fifty percent (50%) of the profits or capital interests.

Change of Control with Respect to UGI Utilities, Inc.

In addition to the definition of Change of Control with respect to UGI, as set forth above, for Participants who are employees of UGI Utilities, Inc. (“Utilities”) or a subsidiary of Utilities, the term “Change of Control” shall include the events set forth below:

“Change of Control” shall include any of the following events:

(D)UGI and the UGI Subsidiaries fail to own more than fifty percent (50%) of the then outstanding shares of common stock of Utilities or more than fifty percent (50%) of the combined voting power of the then outstanding voting securities of Utilities entitled to vote generally in the election of directors; or

(E)Completion by Utilities of a reorganization, merger or consolidation (a "Business Combination"), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of Utilities’ outstanding common stock and voting securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of Utilities’ outstanding common stock and voting securities, as the case may be; or

(F)Completion of a complete liquidation or dissolution of the Utilities or sale or other disposition of all or substantially all of the assets of Utilities other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of Utilities’ outstanding common stock and voting securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of Utilities’ outstanding common stock and voting securities, as the case may be, immediately prior to such sale or disposition.

A-3

EX-12.1

UGI UTILITIES INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1

(Thousands of dollars)

	Year Ended September 30,
	2017		2016		2015		2014		2013
Earnings:
Earnings before income taxes	$	188,095	$	163,271	$	200,539	$	207,929	$	171,010
Interest expense	39,831		37,285		40,400		37,897		38,578
Amortization of debt discount and
expense	381		345		728		575		731
Estimated interest component of rental
expense	2,373		2,512		2,728		2,398		2,090
	$	230,680	$	203,413	$	244,395	$	248,799	$	212,409
Fixed Charges:
Interest expense	$	39,831	$	37,285	$	40,400	$	37,897	$	38,578
Amortization of debt discount and
expense	381		345		728		575		731
Allowance for funds used during
construction (capitalized interest)	1,608		602		407		227		286
Estimated interest component of rental
expense	2,373		2,512		2,728		2,398		2,090
	$	44,193	$	40,744	$	44,263	$	41,097	$	41,685
Ratio of earnings to fixed charges	5.22		4.99		5.52		6.05		5.10

EX-23

EXHIBIT 23

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-3 No. 333-150719) of UGI Utilities, Inc. of our reports dated November 21, 2017, with respect to the consolidated financial statements and schedule of UGI Utilities, Inc., and the effectiveness of internal control over financial reporting of UGI Utilities, Inc., included in this Annual Report (Form 10-K) for the year ended September 30, 2017.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

November 21, 2017

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Robert F. Beard, certify that:

1. I have reviewed this annual report on Form 10-K of UGI Utilities, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 21, 2017
		/s/ Robert F. Beard
		Robert F. Beard President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Daniel J. Platt, certify that:

1. I have reviewed this annual report on Form 10-K of UGI Utilities, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 21, 2017
		/s/ Daniel J. Platt
		Daniel J. Platt Vice President - Finance and Chief Financial Officer

EX-32

EXHIBIT 32

Certification by the Chief Executive Officer and Chief Financial Officer

Relating to a Periodic Report Containing Financial Statements

I, Robert F. Beard, Chief Executive Officer, and I, Daniel J. Platt, Chief Financial Officer, of UGI Utilities, Inc., a Pennsylvania corporation (the “Company”), hereby certify that to our knowledge:

(1) The Company's annual report on Form 10-K for the period ended September 30, 2017 (the “Form 10-K”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

*   *   *

CHIEF EXECUTIVE OFFICER		CHIEF FINANCIAL OFFICER
/s/ Robert F. Beard		/s/ Daniel J. Platt
Robert F. Beard		Daniel J. Platt
Date:	November 21, 2017	Date:	November 21, 2017

XML

Document and Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2017	Nov. 14, 2017	Mar. 31, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	0000100548
Document Type	10-K
Document Period End Date	Sep. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		26,781,785
Entity Public Float			$ 0

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Current assets:
Cash and cash equivalents	$ 5,203	$ 2,819
Restricted cash	3,046	583
Accounts receivable (less allowances for doubtful accounts of $4,052 and $3,946, respectively)	53,720	44,692
Accounts receivable — related parties	2,807	398
Accrued utility revenues	13,296	12,753
Inventories	53,309	42,340
Prepaid income taxes	7,711	1,956
Regulatory assets	8,338	3,208
Derivative instruments	1,354	4,263
Prepaid expenses	8,450	10,499
Other current assets	7,956	11,510
Total current assets	165,190	135,021
Property, plant and equipment	3,285,329	2,998,915
Less accumulated depreciation and amortization	(1,010,781)	(975,374)
Net property, plant and equipment	2,274,548	2,023,541
Goodwill	182,145	182,145
Regulatory assets	360,591	391,933
Other assets	11,541	10,451
Total assets	2,994,015	2,743,091
Current liabilities:
Current maturities of long-term debt	39,996	19,986
Short-term borrowings	170,000	112,500
Accounts payable — trade	71,559	65,180
Accounts payable — related parties	6,890	3,995
Employee compensation and benefits accrued	21,851	16,323
Interest accrued	16,200	7,605
Customer deposits and advances	35,278	41,391
Derivative instruments	1,071	310
Regulatory liability — deferred fuel and power refunds	10,621	22,299
Other current liabilities	40,016	44,321
Total current liabilities	413,482	333,910
Long-term debt	711,105	651,455
Deferred income taxes	635,465	550,229
Deferred investment tax credits	2,950	3,268
Pension and other postretirement benefit obligations	143,674	184,516
Other noncurrent liabilities	99,434	94,976
Total liabilities	2,006,110	1,818,354
Commitments and contingencies (Note 12)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)	60,259	60,259
Additional paid-in capital	473,580	473,580
Retained earnings	480,857	422,516
Accumulated other comprehensive loss	(26,791)	(31,618)
Total common stockholder’s equity	987,905	924,737
Total liabilities and stockholder’s equity	$ 2,994,015	$ 2,743,091

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

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

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

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

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

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

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Nature of Operations

12 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

NATURE OF OPERATIONS

UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”), own and operate natural gas distribution utilities in eastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.” Prior to June 1, 2015, PNG also had a heating, ventilation and air-conditioning service business which operated principally in the PNG service territory (“PNG HVAC Business”). The assets of the PNG HVAC Business principally comprising customer contracts were sold on June 1, 2015.

The term “UGI Utilities” is used herein as an abbreviated reference to UGI Utilities, Inc., or collectively to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.

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Summary of Significant Accounting Policies

12 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

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

Principles of Consolidation

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

Effects of Regulation

UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator. For additional information regarding the effects of rate regulation on our utility operations, see Note 4.

Fair Value Measurements

The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements performed on a recurring basis principally relate to derivative instruments.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

• Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

• Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means.

• Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.

Derivative Instruments

Derivative instruments are reported on the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or is designated and qualifies for hedge accounting.

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

For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 14.

Revenue Recognition

UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service rendered and commodities delivered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered.

We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.

Accounts Receivable

Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.

Income Taxes

We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.

We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize.

We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is consistent with income taxes calculated on a separate return basis. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income.

Cash and Cash Equivalents

For cash flow purposes, cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities of three months or less when purchased.

Restricted Cash

Restricted cash represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.

Inventories

Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for substantially all of our inventory.

Property, Plant and Equipment and Related Depreciation

We record property, plant and equipment at original cost. Capitalized costs include labor, materials and other direct and indirect costs, and allowance for funds used during construction (“AFUDC”). The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis based upon projected service lives of the various classes of its depreciable property. The estimated useful lives of the classes of depreciable property are reviewed by a third party and adjusted, if necessary, as part of periodic service life studies required by the PUC. The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2017, 2016 and 2015 were as follows:

	2017		2016		2015
Gas Utility	2.2	%	2.2	%	2.2	%
Electric Utility	2.4	%	2.5	%	2.5	%

When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over five years, consistent with prior ratemaking treatment (See Note 4).

We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. Information technology costs associated with major system installations, conversions and improvements, such as software training, data conversion, business process reengineering costs and preliminary project stage costs are deferred as a regulatory asset if the Company expects to recover these costs in future rates, and the deferral is reported as a component of property, plant and equipment. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.

No depreciation expense is included in cost of sales in the Consolidated Statements of Income.

Goodwill

Our goodwill is the result of Gas Utility business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance simplifying the test for goodwill impairment. The adoption of the new guidance did not impact the consolidated financial statements (see Note 3).

We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value. From time to time, we may assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. From time to time, we may bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit.

No provisions for goodwill impairments were recorded during Fiscal 2017, Fiscal 2016 or Fiscal 2015.

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No provisions for impairments were recorded during Fiscal 2017, Fiscal 2016 or Fiscal 2015.

Employee Retirement Plans

We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 9).

Equity-Based Compensation

All of our equity-based compensation, principally comprising UGI stock options and grants of UGI stock-based equity instruments (“UGI Units”), is measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, equity-based compensation costs are measured based upon the fair value of the award on the date of grant or the fair value of the award as of the end of each reporting period. In Fiscal 2017, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. (see Note 3).

For additional information on our equity-based compensation plans and related disclosures, see Note 11.

Environmental Matters

We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.

Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites.  This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see Note 12.

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Accounting Changes

12 Months Ended

Sep. 30, 2017

Accounting Changes and Error Corrections [Abstract]

Accounting Changes

ACCOUNTING CHANGES

Adoption of New Accounting Standard

Cash Flow Classification. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance on the classification of certain cash receipts and payments in the statement of cash flows. The guidance is generally required to be applied retrospectively. The adoption of the new guidance did not impact our consolidated financial statements.

Goodwill Impairment. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance regarding the test for goodwill impairment. Under the new accounting guidance, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements.

Employee Share-based Payments. Effective October 1, 2016, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. The adoption of the new accounting guidance did not have a material impact on our financial statements.

Accounting Standards Not Yet Adopted

Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption.

The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue.

The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.

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Regulatory Assets and Liabilities and Regulatory Matters

12 Months Ended

Sep. 30, 2017

Regulated Operations [Abstract]

Regulatory Assets and Liabilities and Regulatory Matters

REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS

The following regulatory assets and liabilities are included in our Consolidated Balance Sheets at September 30:

	2017		2016
Regulatory assets:
Income taxes recoverable	$	121,421	$	115,643
Underfunded pension and postretirement plans	141,310		183,129
Environmental costs	61,566		59,397
Deferred fuel and power costs	7,685		151
Removal costs, net	30,996		27,956
Other	5,951		8,865
Total regulatory assets	$	368,929	$	395,141
Regulatory liabilities (a):
Postretirement benefits overcollections	$	17,493	$	17,519
Deferred fuel and power refunds	10,621		22,299
State income tax benefits — distribution system repairs	18,430		15,086
Other	2,686		665
Total regulatory liabilities	$	49,230	$	55,569

(a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance Sheets.

Other than removal costs, UGI Utilities currently does not recover a rate of return on the regulatory assets included in the table above.

Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of the tax benefit on accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. UGI Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 65 years.

Underfunded pension and other postretirement plans. This regulatory asset represents the portion of net actuarial losses and prior service costs (credits) associated with pension and other postretirement benefits which are probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants.

Environmental costs. Environmental costs principally represent estimated probable future environmental remediation and investigation costs that UGI Gas, CPG and PNG expect to incur, primarily at Manufactured Gas Plant (“MGP”) sites in Pennsylvania, in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (“DEP”). Pursuant to base rate orders, UGI Gas, PNG and CPG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2017, the period over which UGI Gas, PNG and CPG expect to recover these costs will depend upon future remediation activity. For additional information on environmental costs, see Note 12.

Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. As required by PUC ratemaking, removal costs include actual costs incurred associated with asset retirement obligations. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over five years.

Postretirement benefit overcollections. This regulatory liability represents the difference between amounts recovered through rates by UGI Gas and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With respect to UGI Gas, postretirement benefit overcollections are generally being refunded to customers over a ten-year period beginning October 19, 2016, the date UGI Gas’ Joint Petition pursuant to its January 19, 2016 base rate filing became effective (see “Base Rate Filings” below). With respect to Electric Utility, the excess of the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits is being deferred for future rate refund to customers.

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

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains on such contracts at September 30, 2017 and 2016, were $146 and $4,263, respectively.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at September 30, 2017 and 2016, were not material.

State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal benefit, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.

Other. Other regulatory assets and liabilities comprise a number of deferred items including, among others, a portion of preliminary stage information technology costs, energy efficiency conservation costs and rate case expenses.

Other Regulatory Matters

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

On January 19, 2016, UGI Utilities filed a rate request with the PUC to increase UGI Gas’s annual base operating revenues for residential, commercial and industrial customers by $58,600. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2016, a Joint Petition for Approval of Settlement of all issues providing for a $27,000 UGI Gas annual base distribution rate increase, to be effective October 19, 2016, was filed with the PUC (“Joint Petition”). On October 14, 2016, the PUC approved the Joint Petition with a minor modification which had no effect on the $27,000 base distribution rate increase. The increase became effective on October 19, 2016.

Distribution System Improvement Charge.On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at 5% of distribution charges billed to customers.

PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero, beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from 5% to 10% of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018.

On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.

Preliminary Stage Information Technology Costs. During Fiscal 2016, we determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during Fiscal 2016, we capitalized $5,830 of such project costs ($5,375 of which had been expensed prior to Fiscal 2016) and recorded associated increases to utility property, plant and equipment ($2,755) and regulatory assets ($3,075). Subsequent to this determination, we continue to capitalize such preliminary stage project costs in accordance with GAAP related to regulated entities.

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Inventories

12 Months Ended

Sep. 30, 2017

Inventory Disclosure [Abstract]

Inventories

INVENTORIES

Inventories comprise the following at September 30:

	2017		2016
Gas Utility natural gas	$	39,486	$	29,223
Materials, supplies and other	13,823		13,117
Total inventories	$	53,309	$	42,340

At September 30, 2017, UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) having terms ranging from one to three years. Four of the SCAAs were with UGI Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 18), and one of the SCAAs was with a non-affiliate. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

The carrying values of gas storage inventories released under the SCAAs at September 30, 2017 and 2016, comprising 9.1 billion cubic feet (“bcf”) and 8.1 bcf of natural gas, were $26,064 and $18,773, respectively. At September 30, 2017 and 2016, UGI Utilities held a total of $15,040 and $19,100, respectively, of security deposits received from its SCAA counterparties. These amounts are included in “Other current liabilities” on the Consolidated Balance Sheets.

For additional information related to the SCAAs with Energy Services, see Note 18.

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Property, Plant and Equipment

12 Months Ended

Sep. 30, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment comprise the following categories at September 30:

	2017		2016
Distribution	$	2,835,339	$	2,634,191
Transmission	96,430		93,454
Construction in process	112,563		103,929
General and other	240,997		167,341
Total property, plant and equipment	$	3,285,329	$	2,998,915

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Debt

12 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Debt

DEBT

Long-term debt comprises the following at September 30:

	2017			2016
Senior Notes:
4.12%, due September 2046	$	200,000		$	200,000
4.98%, due March 2044	175,000			175,000
4.12%, due October 2046	100,000			—
6.21%, due September 2036	100,000			100,000
2.95%, due June 2026	100,000			100,000
Medium-Term Notes:
6.17%, due June 2017	—			20,000
7.25%, due November 2017	20,000			20,000
5.67%, due January 2018	20,000			20,000
6.50%, due August 2033	20,000			20,000
6.13%, due October 2034	20,000			20,000
Total long-term debt	755,000			675,000
Less: unamortized debt issuance costs	(3,899		)	(3,559		)
Less: current maturities	(39,996		)	(19,986		)
Total long-term debt due after one year	$	711,105		$	651,455

Principal payments on long-term debt during the next five fiscal years is as follows: $40,000 is due in Fiscal 2018; $0 is due in Fiscal 2019 through Fiscal 2022.

Pursuant to a note purchase agreement, in October 2016, UGI Utilities issued $100,000 aggregate principal amount of 4.12% Senior Notes due October 2046 (the “4.12% Senior Notes”). The net proceeds of the issuance of the 4.12% Senior Notes were used (1) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and information technology initiatives and (2) for general corporate purposes. The 4.12% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt.

On October 31, 2017, UGI Utilities entered into a $125,000 unsecured term loan (the “Term Loan”) with a group of banks which initially matures on October 30, 2018.  Such maturity will be automatically extended to October 30, 2022 once UGI Utilities delivers to the agent a copy of the securities certificate registered with the PUC authorizing UGI Utilities’ incurring indebtedness with such maturity date.  Proceeds from the Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Term Loan is payable in equal quarterly installments of $1,563 with the balance of the principal being due and payable in full on the maturity date.  Under the term loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin.  The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities.  The Term Loan requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.

UGI Utilities has an unsecured credit agreement (the “Credit Agreement”) with a group of banks providing for borrowings of up to $300,000 (including a $100,000 sublimit for letters of credit) which expires in March 2020. Under the Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. UGI Utilities had borrowings outstanding under the credit agreements, which we classify as “Short-term borrowings” on the Consolidated Balance Sheets, totaling $170,000 and $112,500 at September 30, 2017 and 2016, respectively. The weighted-average interest rates on the credit agreement borrowings at September 30, 2017 and 2016 were 2.11% and 1.42%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the credit agreements, totaled $2,009 and $2,009 at September 30, 2017 and 2016, respectively.

Restrictive Covenants. Certain of UGI Utilities Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. These Senior Notes also contain restrictive and financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

The UGI Utilities Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.

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Income Taxes

12 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

The provisions for income taxes consist of the following:

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

A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:

	2017		2016		2015
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Difference in tax rate due to:
State income taxes, net of federal benefit	5.0		5.2		5.1
Excess tax benefits on share-based payments	(0.9	)	—		—
Other, net	(0.8	)	0.2		(0.5	)
Effective tax rate	38.3	%	40.4	%	39.6	%

Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2017, Fiscal 2016 and Fiscal 2015, the beneficial effects of state tax flow through of accelerated depreciation reduced tax expense by $2,537, $1,344 and $1,539, respectively.

Deferred tax liabilities (assets) comprise the following at September 30:

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

We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. UGI’s federal income tax returns are settled through the tax year 2013.

We file separate company income tax returns in various other states but are subject to state income tax principally in Pennsylvania. Pennsylvania income tax returns are generally subject to examination for a period of three years after the filing of the respective returns.

During Fiscal 2017, Fiscal 2016 and Fiscal 2015, interest (income) expense of $(73), $204 and $0, respectively, was recognized in income taxes in the Consolidated Statements of Income.

As of September 30, 2017, we have unrecognized income tax benefits totaling $1,829 including related accrued interest of $132. If these unrecognized tax benefits were subsequently recognized, $940 would be recorded as a benefit to income taxes on the Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. There is no material change expected in unrecognized tax benefits and related interest in the next twelve months.

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

	2017			2016		2015
Unrecognized tax benefits – beginning of year	$	2,055		$	—	$	—
Additions for tax positions taken in prior years	604			2,055		—
Additions for tax positions of the current year	—			—		—
Settlements with tax authorities/statute lapses	(830		)	—		—
Unrecognized tax benefits – end of year	$	1,829		$	2,055	$	—

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Employee Retirement Plans

12 Months Ended

Sep. 30, 2017

Defined Benefit Plan [Abstract]

Employee Retirement Plans

EMPLOYEE RETIREMENT PLANS

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

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plan, the accumulated benefit obligations (“ABOs”) of the Other Postretirement Plans, plan assets and the funded status of the Pension Plan and Other Postretirement Plans as of September 30, 2017 and 2016. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect future compensation.

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

In Fiscal 2018, we estimate that we will amortize approximately $12,000 of net actuarial losses, primarily associated with Pension Plan, and $250 of prior service credits from stockholder’s equity and regulatory assets.

Actuarial assumptions are described below. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the Company’s postretirement plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the benefit payments. The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).

	Pension Benefits						Other Postretirement Benefits
Weighted-average assumptions:	2017		2016		2015		2017		2016		2015
Discount rate – benefit obligations	4.00	%	3.80	%	4.60	%	4.00	%	3.80	%	4.70	%
Discount rate – benefit cost	3.80	%	4.60	%	4.60	%	3.80	%	4.70	%	4.60	%
Expected return on plan assets	7.50	%	7.55	%	7.75	%	5.00	%	5.00	%	5.00	%
Rate of increase in salary levels	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%

The ABOs for the Pension Plan were $605,237 and $601,255 as of September 30, 2017 and 2016, respectively. Included in the end of year Pension Plan PBOs above are $62,458 at September 30, 2017, and $63,847 at September 30, 2016, relating to employees of UGI and certain of its other subsidiaries. Included in the end of year Other Postretirement Plans ABOs above are $996 at September 30, 2017, and $951 at September 30, 2016, relating to employees of UGI and certain of its other subsidiaries.

Net periodic pension and other postretirement benefit costs relating to the Company’s employees include the following components:

	Pension Benefits									Other Postretirement Benefits
	2017			2016			2015			2017			2016			2015
Service cost	$	8,091		$	6,927		$	6,962		$	273		$	183		$	202
Interest cost	22,157			23,270			22,511			431			465			479
Expected return on assets	(29,986		)	(28,668		)	(28,898		)	(656		)	(596		)	(612		)
Amortization of:
Prior service cost (benefit)	325			348			348			(641		)	(641		)	(641		)
Actuarial loss	14,825			9,571			8,793			108			98			122
Net benefit cost (income)	15,412			11,448			9,716			(485		)	(491		)	(450		)
Change in associated regulatory liabilities	—			—			—			(490		)	971			3,740
Net benefit cost after change in regulatory liabilities	$	15,412		$	11,448		$	9,716		$	(975	)	$	480		$	3,290

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Corporation Common Stock and smallcap common stocks (prior to their liquidation during Fiscal 2017). It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, we made contributions to the Pension Plan of $11,395, $9,869 and $11,131, respectively. The minimum required contributions in Fiscal 2018 are not expected to be material.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and the amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. The required contributions to the VEBA during Fiscal 2018, if any, are not expected to be material.

Expected payments for pension and other postretirement welfare benefits are as follows:

	Pension Benefits		Other Postretirement Benefits
Fiscal 2018	$	27,176	$	566
Fiscal 2019	28,471		566
Fiscal 2020	29,812		552
Fiscal 2021	31,084		537
Fiscal 2022	32,323		540
Fiscal 2023 - 2027	179,945		2,710

The assumed health care cost trend rates at September 30 are as follows:

	2017		2016
Health care cost trend rate assumed for next year	7.00	%	7.25	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	5.0	%	5.0	%
Fiscal year that the rate reaches the ultimate trend rate	2026		2026

A one percentage point change in these assumed health care cost trend rates would not have had a material impact on Fiscal 2017 other postretirement benefit cost or the September 30, 2017, other postretirement benefit ABO.

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement income plans. At September 30, 2017 and 2016, the PBOs of these plans were $4,222 and $3,628, respectively. We recorded expense for these plans of $605 in Fiscal 2017, $353 in Fiscal 2016 and $445 in Fiscal 2015.

Pension Plan and VEBA Assets. The assets of the Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks (prior to their liquidation in Fiscal 2017) and UGI Common Stock.

The targets, target ranges and actual allocations for the Pension Plan and VEBA trust assets at September 30 are as follows:

	Actual				Target Asset	Permitted
Pension Plan:	2017		2016		Allocation	Range
Equity investments:
Domestic	55.2	%	54.1	%	52.5%	40.0% – 65.0%
International	12.4	%	10.2	%	12.5%	7.5% – 17.5%
Total	67.6	%	64.3	%	65.0%	60.0% – 70.0%
Fixed income funds & cash equivalents	32.4	%	35.7	%	35.0%	30.0% – 40.0%
Total	100.0	%	100.0	%	100.0%

	Actual				Target Asset	Permitted
VEBA:	2017		2016		Allocation	Range
Domestic equity investments	63.1	%	69.9	%	65.0%	60.0% – 70.0%
Fixed income funds & cash equivalents	36.9	%	30.1	%	35.0%	30.0% – 40.0%
Total	100.0	%	100.0	%	100.0%

Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds, and a separately managed account comprising small-cap common stocks (prior to their liquidation in Fiscal 2017). Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 7.7% and 8.0% of Pension Plan assets at September 30, 2017 and 2016, respectively.

The fair values of the Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee. The fair values of the Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2, as of September 30, 2017 and 2016 are as follows:

	Pension Plan
	Level 1		Level 2		Level 3		Other(a)		Total
September 30, 2017:
Domestic equity investments:
S&P 500 Index equity mutual funds	$	171,600	$	—	$	—	$	—	$	171,600
Small and midcap equity mutual funds	65,167		—		—		—		65,167
UGI Corporation Common Stock	38,137		—		—		—		38,137
Total domestic equity investments	274,904		—		—		—		274,904
International index equity mutual funds	61,613		—		—		—		61,613
Fixed income investments:
Bond index mutual funds	156,228		—		—		—		156,228
Cash equivalents	—		—		—		5,332		5,332
Total fixed income investments	156,228		—		—		5,332		161,560
Total	$	492,745	$	—	$	—	$	5,332	$	498,077
September 30, 2016:
Equity investments:
S&P 500 Index equity mutual funds	$	158,906	$	—	$	—	$	—	$	158,906
Small and midcap equity mutual funds	43,170		—		—		—		43,170
Smallcap common stocks	11,414		—		—		—		11,414
UGI Corporation Common Stock	37,013		—		—		—		37,013
Total domestic equity investments	250,503		—		—		—		250,503
International index equity mutual funds	47,324		—		—		—		47,324
Fixed income investments:
Bond index mutual funds	147,794		—		—		—		147,794
Cash equivalents	—		—		—		17,811		17,811
Total fixed income investments	147,794		—		—		17,811		165,605
Total	$	445,621	$	—	$	—	$	17,811	$	463,432

	VEBA
	Level 1		Level 2		Level 3		Other(a)		Total
September 30, 2017:
S&P 500 Index equity mutual fund	$	9,318	$	—	$	—	$	—	$	9,318
Bond index mutual fund	5,044		—		—		—		5,044
Cash equivalents	—		—		—		409		409
Total	$	14,362	$	—	$	—	$	409	$	14,771
September 30, 2016:
S&P 500 Index equity mutual fund	$	9,583	$	—	$	—	$	—	$	9,583
Bond index mutual fund	4,019		—		—		—		4,019
Cash equivalents	—		—		—		113		113
Total	$	13,602	$	—	$	—	$	113	$	13,715

(a) Assets measured at net asset value (“NAV”) and therefore excluded from the fair value hierarchy.

The expected long-term rates of return on Pension Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.

Defined Contribution Plan. We sponsor a 401(k) savings plan for eligible employees (“Utilities Savings Plan”). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. The Utilities Savings Plan provides for employer matching contributions. Those employees hired after December 31, 2008, who are not eligible to participate in the Pension Plan, receive employer matching contributions at a higher rate. The cost of benefits under the Utilities Savings Plan totaled $2,829 in Fiscal 2017, $2,409 in Fiscal 2016 and $2,162 in Fiscal 2015. We also sponsor a nonqualified supplemental defined contribution executive retirement plan. This plan generally provides supplemental benefits to certain executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal Revenue Code. Costs associated with this plan were not material in Fiscal 2017, Fiscal 2016 and Fiscal 2015.

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Series Preferred Stock

12 Months Ended

Sep. 30, 2017

Equity [Abstract]

Series Preferred Stock

SERIES PREFERRED STOCK

We have 2,000,000 shares of Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of Series Preferred Stock outstanding at September 30, 2017 or 2016.

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Equity-Based Compensation

12 Months Ended

Sep. 30, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity-Based Compensation

EQUITY-BASED COMPENSATION

Under UGI Corporation’s 2013 Omnibus Incentive Compensation Plan (the “2013 OICP”) and prior UGI equity compensation plans, certain key employees of UGI Utilities may be granted stock options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”) and other equity-based awards. The exercise price for UGI stock options may not be less than the fair market value on the grant date. Awards granted under the 2013 OICP and the prior plans may vest immediately or ratably over a period of years (generally three-year periods), and stock options for UGI Common Stock can be exercised no later than ten years from the grant date. In addition, the 2013 OICP and the prior UGI equity compensation plans provide that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.

UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. With respect to UGI Performance Units awards, the actual number of UGI shares actually issued (or their cash equivalent) at the end of the performance period and the actual amount of dividend equivalents paid, may range from 0% to 200% of the target award based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to the Russell Midcap Utility Index, excluding telecommunication companies (“UGI comparator group”). Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.

We use a Black-Scholes option-pricing model to estimate the fair value of UGI stock options. We use a Monte Carlo valuation approach to estimate the fair value of UGI Performance Unit awards. We recorded total net pre-tax equity-based compensation expense associated with both UGI Units and UGI stock options of $1,461 ($855 after-tax) during Fiscal 2017; $1,924 ($1,126 after-tax) during Fiscal 2016; and $1,847 ($1,081 after-tax) during Fiscal 2015.

As of September 30, 2017, there was $1,167 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 1.9 years. As of September 30, 2017, there was a total of $1,029 of unrecognized compensation expense associated with 45,588 UGI Unit awards that is expected to be recognized over a weighted average period of 1.8 years. At September 30, 2017 and 2016, total liabilities of $533 and $1,304, respectively, associated with UGI Unit awards are reflected in other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheets.

The following table summarizes UGI Unit award activity for Fiscal 2017:

	Total				Vested				Non-Vested
	Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)
September 30, 2016	57,783		$	34.66	10,316		$	34.31	47,467		$	34.74
Granted	16,425		$	51.42	367		$	51.42	16,058		$	51.42
Vested	—		$	—	16,003		$	33.10	(16,003	)	$	33.10
Forfeitures & transfers	(1,934	)	$	34.74	—		$	—	(1,934	)	$	34.74
Unit awards paid	(20,050	)	$	32.59	(20,050	)	$	32.59	—		$	—
September 30, 2017	52,224		$	40.72	6,636		$	37.53	45,588		$	41.19

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Commitments and Contingencies

12 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Commitments

We lease various buildings and vehicles, computer and office equipment and other facilities under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $7,276 in Fiscal 2017, $7,669 in Fiscal 2016 and $7,956 in Fiscal 2015.

Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year for the fiscal years ending September 30 are as follows: 2018— $7,545; 2019 — $5,961; 2020 — $4,355; 2021 — $2,665; 2022 — $793; after 2022 — $182.

Contingencies

Environmental Matters

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

Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into a consent order and agreement (“COA”) with the DEP to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2,500, $1,750 and $1,100, for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively. At September 30, 2017 and 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $54,250 and $55,063, respectively. UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable. (See Note 4).

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

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

Other Matters

Manor Township, Pennsylvania Natural Gas Explosion.On July 2, 2017, an explosion occurred in Manor Township, Pennsylvania which resulted in the death of a Company employee, significant injuries to two other Company employees and an employee of the local sewer authority, and significant property damage. The National Transportation Safety Board (“NTSB”), the Occupational Safety and Health Administration (“OSHA”) and the PUC are investigating the Manor Township incident. The NTSB investigative team includes representatives from the Company, the PUC, the local fire department and the Pipeline and Hazardous Materials Safety Administration and the Company is cooperating with the investigation. Other parties may be invited to participate by the NTSB.

While the investigation into this incident is still underway and the cause of the explosion has not been determined, the Company has received claims as a result of the explosion and may become involved in lawsuits relative to the incident. The Company maintains workers’ compensation insurance and liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of the Company’s deductible, are expected to be recovered through the Company’s insurance. Although the Company cannot predict the result of these pending or future claims, we believe that claims and expenses associated with the explosion will not have a material impact on our consolidated financial statements.

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

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Fair Value Measurements

12 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

Derivative Instruments

The following table presents, on a gross basis, our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2, as of September 30, 2017 and 2016:

	Asset (Liability)
	Level 1			Level 2			Level 3		Total
September 30, 2017
Derivative instruments:
Assets:
Commodity contracts	$	1,735		$	72		$	—	$	1,807
Liabilities:
Commodity contracts	$	(1,447	)	$	(73	)	$	—	$	(1,520	)
September 30, 2016
Derivative instruments:
Assets:
Commodity contracts	$	4,506		$	4		$	—	$	4,510
Liabilities:
Commodity contracts	$	(263	)	$	(294	)	$	—	$	(557	)

The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments, which are designated as Level 2, are generally based upon recent market transactions and related market indicators. There were no transfers between Level 1 and Level 2 during the periods presented.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt (Level 2). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2017 and 2016, were as follows:

	2017		2016
Carrying amount	$	755,000	$	675,000
Estimated fair value	$	791,378	$	770,781

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Derivative Instruments and Hedging Activities

12 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 2017 and 2016, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 14.8 million dekatherms and 18.4 million dekatherms, respectively. At September 30, 2017, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 months. Gains and losses on natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 4).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At September 30, 2017 and 2016, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception under GAAP.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 4). At September 30, 2017 and 2016, the total volumes associated with FTRs totaled 101.2 million kilowatt hours and 58.3 million kilowatt hours, respectively. At September 30, 2017, the maximum period over which we are economically hedging electricity congestion is 8 months.

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

Interest Rate Risk

Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. On March 31, 2016, concurrent with the pricing of UGI Utilities’ Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities settled all of its then-existing IRPA contracts associated with such debt at a loss of $35,975. Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs was recorded in AOCI and is being recognized in interest expense as the associated future interest expense impacts earnings. At September 30, 2017 and 2016, we had no unsettled IRPAs.

At September 30, 2017, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,485.

Derivative Instrument Credit Risk

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2017 and 2016, restricted cash in brokerage accounts totaled $3,046 and $583, respectively.

Offsetting Derivative Assets and Liabilities

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

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

Fair Value of Derivative Instruments

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

	2017			2016
Derivative assets:
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$	1,665		$	4,472
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	142			38
Total derivative assets – gross	1,807			4,510
Gross amounts offset in the balance sheet	(450		)	(247		)
Total derivative assets – net (a)	$	1,357		$	4,263
Derivative liabilities:
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$	(1,520	)	$	(499	)
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	—			(58		)
Total derivative liabilities – gross	(1,520		)	(557		)
Gross amounts offset in the balance sheet	450			247
Total derivative liabilities – net (a)	$	(1,070	)	$	(310	)

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

Effect of Derivative Instruments

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Consolidated Statements of Income and changes in AOCI for Fiscal 2017, Fiscal 2016 and Fiscal 2015:

	Loss Recognized in AOCI								Loss Reclassified from AOCI into Income									Location of
	2017		2016			2015			2017			2016			2015			Loss Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—	$	(28,958	)	$	(7,016	)	$	(3,397	)	$	(2,680	)	$	(2,674	)	Interest expense
	Gain (Loss) Recognized in Income																	Location of Gain (Loss)
	2017		2016			2015												Recognized in Income
Derivatives Not Subject to PGC and DS Mechanisms:
Gasoline contracts	$	174	$	(88	)	$	(761	)										Operating and administrative expenses/other operating income, net

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

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

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Accumulated Other Comprehensive Income

12 Months Ended

Sep. 30, 2017

Equity [Abstract]

Accumulated Other Comprehensive Income

ACCUMULATED OTHER COMPREHENSIVE INCOME

Other comprehensive income (loss) principally reflects losses on IRPAs qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.

Changes in AOCI, net of tax, during Fiscal 2017, Fiscal 2016 and Fiscal 2015 are as follows:

	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI - September 30, 2014	$	(6,311	)	$	(1,870	)	$	(8,181	)
Reclassifications of benefit plans actuarial losses and net prior service credits	517			—			517
Reclassifications of net losses on IRPAs	—			1,565			1,565
Net losses on IRPAs	—			(4,105		)	(4,105		)
Benefit plans, principally actuarial losses	(3,482		)	—			(3,482		)
AOCI - September 30, 2015	$	(9,276	)	$	(4,410	)	$	(13,686	)
Reclassifications of benefit plans actuarial losses and net prior service credits	639			—			639
Reclassifications of net losses on IRPAs	—			1,568			1,568
Net losses on IRPAs	—			(16,942		)	(16,942		)
Benefit plans, principally actuarial losses	(3,197		)	—			(3,197		)
AOCI - September 30, 2016	$	(11,834	)	$	(19,784	)	$	(31,618	)
Reclassifications of benefit plans actuarial losses and net prior service credits	956			—			956
Reclassifications of net losses on IRPAs	—			1,988			1,988
Benefit plans, principally actuarial gains	1,883			—			1,883
AOCI - September 30, 2017	$	(8,995	)	$	(17,796	)	$	(26,791	)

Reclassifications of net losses on IRPAs are reflected in interest expense on the Consolidated Statements of Income.

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Segment Information

12 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Segment Information

SEGMENT INFORMATION

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

The accounting policies of our reportable segments are the same as those described in Note 2. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.

No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States, and all of our reportable segments’ long-lived assets are located in the United States.

Financial information by business segment follows:

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

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Other Operating Income (Expense), Net

12 Months Ended

Sep. 30, 2017

Component of Operating Income [Abstract]

Other Operating Income (Expense), Net

OTHER OPERATING INCOME (EXPENSE), NET

Other operating income (expense), net, comprises the following:

	2017			2016			2015
Non-tariff service income	$	1,491		$	2,633		$	4,760
Environmental matters	6,155			(2,918		)	1,152
Construction service income	—			—			2,175
Sale of HVAC Business	—			—			1,065
Net interest on PGC overcollection	(130		)	(1,740		)	(606		)
Other, net	813			25			323
Total other operating income (expense), net	$	8,329		$	(2,000	)	$	8,869

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Related Party Transactions

12 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as “Operating and administrative expenses — related parties” in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities during Fiscal 2017, Fiscal 2016 and Fiscal 2015 totaled $4,346, $5,069 and $3,168, respectively.

From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. At September 30, 2017, UGI Utilities was a party to four SCAAs with Energy Services, and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs during Fiscal 2017, Fiscal 2016 and Fiscal 2015 totaling $21,424, $12,739 and $16,849, respectively. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, these payments totaled $2,747, $2,002 and $2,339, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. At September 30, 2017 and 2016, the amounts of such security deposits, which are included in “Other current liabilities” on the Consolidated Balance Sheets, were $11,040 and $8,100, respectively.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” At September 30, 2017 and 2016, the carrying values of these gas storage inventories, comprising approximately 6.8 bcf and 4.6 bcf of natural gas, were $19,323 and $11,148, respectively.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility primarily during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during Fiscal 2017, Fiscal 2016 and Fiscal 2015 totaled $76,010, $63,331 and $47,794, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, revenues associated with such sales to Energy Services totaled $50,948, $30,743 and $79,182, respectively. Also from time to time, UGI Utilities purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, such purchases totaled $84,402, $35,067 and $85,383, respectively.

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Quarterly Data (unaudited)

12 Months Ended

Sep. 30, 2017

Quarterly Financial Data [Abstract]

Quarterly Data (unaudited)

QUARTERLY DATA (unaudited)

The following quarterly information includes all adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of the Company’s businesses.

	December 31,				March 31,				June 30,				September 30,
	2016		2015		2017		2016		2017		2016		2017			2016
Revenues	$	261,413	$	197,982	$	359,940	$	322,047	$	146,692	$	140,283	$	119,543		$	108,172
Operating income	$	82,236	$	48,296	$	116,408	$	114,481	$	27,671	$	29,815	$	1,992		$	8,309
Net income (loss)	$	44,265	$	23,351	$	65,125	$	63,294	$	10,697	$	12,603	$	(4,046	)	$	(1,875	)

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Sep. 30, 2017

Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

(Thousands of dollars)

	Balance at beginning of year		Charged to costs and expenses		Other				Balance at end of year
September 30, 2017
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	3,946	$	8,030	$	(7,924	)	(1)	$	4,052
September 30, 2016
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	5,599	$	7,760	$	(9,413	)	(1)	$	3,946
September 30, 2015
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	6,992	$	13,498	$	(14,891	)	(1)	$	5,599

⁽¹⁾  Uncollectible accounts written off, net of recoveries

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

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

Principles of Consolidation

Principles of Consolidation

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

Effects of Regulation

Effects of Regulation

UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator.

Fair Value Measurements

Fair Value Measurements

The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements performed on a recurring basis principally relate to derivative instruments.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

• Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

• Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means.

• Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.

Derivative Instruments

Derivative Instruments

Derivative instruments are reported on the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or is designated and qualifies for hedge accounting.

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

Revenue Recognition

Revenue Recognition

UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service rendered and commodities delivered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered.

We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.

Accounts Receivable

Accounts Receivable

Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.

Income Taxes

Income Taxes

We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.

We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize.

We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is consistent with income taxes calculated on a separate return basis. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income.

Cash and Cash Equivalents

Cash and Cash Equivalents

For cash flow purposes, cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities of three months or less when purchased.

Restricted Cash

Restricted Cash

Restricted cash represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.

Inventories

Inventories

Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for substantially all of our inventory.

Property, Plant and Equipment and Related Depreciation

Property, Plant and Equipment and Related Depreciation

We record property, plant and equipment at original cost. Capitalized costs include labor, materials and other direct and indirect costs, and allowance for funds used during construction (“AFUDC”). The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis based upon projected service lives of the various classes of its depreciable property. The estimated useful lives of the classes of depreciable property are reviewed by a third party and adjusted, if necessary, as part of periodic service life studies required by the PUC. The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2017, 2016 and 2015 were as follows:

	2017		2016		2015
Gas Utility	2.2	%	2.2	%	2.2	%
Electric Utility	2.4	%	2.5	%	2.5	%

When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over five years, consistent with prior ratemaking treatment (See Note 4).

We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. Information technology costs associated with major system installations, conversions and improvements, such as software training, data conversion, business process reengineering costs and preliminary project stage costs are deferred as a regulatory asset if the Company expects to recover these costs in future rates, and the deferral is reported as a component of property, plant and equipment. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.

Goodwill

Goodwill

Our goodwill is the result of Gas Utility business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance simplifying the test for goodwill impairment. The adoption of the new guidance did not impact the consolidated financial statements (see Note 3).

We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value. From time to time, we may assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. From time to time, we may bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets.

Employee Retirement Plans

Employee Retirement Plans

We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value

Equity-Based Compensation

Equity-Based Compensation

All of our equity-based compensation, principally comprising UGI stock options and grants of UGI stock-based equity instruments (“UGI Units”), is measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, equity-based compensation costs are measured based upon the fair value of the award on the date of grant or the fair value of the award as of the end of each reporting period. In Fiscal 2017, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows.

Environmental Matters

Environmental Matters

We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.

Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites.  This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.

Adoption of New Accounting Standard and Accounting Standards Not Yet Adopted

Adoption of New Accounting Standard

Cash Flow Classification. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance on the classification of certain cash receipts and payments in the statement of cash flows. The guidance is generally required to be applied retrospectively. The adoption of the new guidance did not impact our consolidated financial statements.

Goodwill Impairment. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance regarding the test for goodwill impairment. Under the new accounting guidance, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements.

Employee Share-based Payments. Effective October 1, 2016, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. The adoption of the new accounting guidance did not have a material impact on our financial statements.

Accounting Standards Not Yet Adopted

Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption.

The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue.

The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.

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Regulatory Assets and Liabilities and Regulatory Matters (Tables)

12 Months Ended

Sep. 30, 2017

Regulated Operations [Abstract]

Schedule of Regulatory Assets

The following regulatory assets and liabilities are included in our Consolidated Balance Sheets at September 30:

	2017		2016
Regulatory assets:
Income taxes recoverable	$	121,421	$	115,643
Underfunded pension and postretirement plans	141,310		183,129
Environmental costs	61,566		59,397
Deferred fuel and power costs	7,685		151
Removal costs, net	30,996		27,956
Other	5,951		8,865
Total regulatory assets	$	368,929	$	395,141
Regulatory liabilities (a):
Postretirement benefits overcollections	$	17,493	$	17,519
Deferred fuel and power refunds	10,621		22,299
State income tax benefits — distribution system repairs	18,430		15,086
Other	2,686		665
Total regulatory liabilities	$	49,230	$	55,569

(a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance Sheets.

Schedule of Regulatory Liabilities

The following regulatory assets and liabilities are included in our Consolidated Balance Sheets at September 30:

	2017		2016
Regulatory assets:
Income taxes recoverable	$	121,421	$	115,643
Underfunded pension and postretirement plans	141,310		183,129
Environmental costs	61,566		59,397
Deferred fuel and power costs	7,685		151
Removal costs, net	30,996		27,956
Other	5,951		8,865
Total regulatory assets	$	368,929	$	395,141
Regulatory liabilities (a):
Postretirement benefits overcollections	$	17,493	$	17,519
Deferred fuel and power refunds	10,621		22,299
State income tax benefits — distribution system repairs	18,430		15,086
Other	2,686		665
Total regulatory liabilities	$	49,230	$	55,569

(a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance Sheets.

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Inventories (Tables)

12 Months Ended

Sep. 30, 2017

Inventory Disclosure [Abstract]

Schedule of Inventories

Inventories comprise the following at September 30:

	2017		2016
Gas Utility natural gas	$	39,486	$	29,223
Materials, supplies and other	13,823		13,117
Total inventories	$	53,309	$	42,340

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Property, Plant and Equipment (Tables)

12 Months Ended

Sep. 30, 2017

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

Property, plant and equipment comprise the following categories at September 30:

	2017		2016
Distribution	$	2,835,339	$	2,634,191
Transmission	96,430		93,454
Construction in process	112,563		103,929
General and other	240,997		167,341
Total property, plant and equipment	$	3,285,329	$	2,998,915

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Debt (Tables)

12 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Composition of Long-term Debt

Long-term debt comprises the following at September 30:

	2017			2016
Senior Notes:
4.12%, due September 2046	$	200,000		$	200,000
4.98%, due March 2044	175,000			175,000
4.12%, due October 2046	100,000			—
6.21%, due September 2036	100,000			100,000
2.95%, due June 2026	100,000			100,000
Medium-Term Notes:
6.17%, due June 2017	—			20,000
7.25%, due November 2017	20,000			20,000
5.67%, due January 2018	20,000			20,000
6.50%, due August 2033	20,000			20,000
6.13%, due October 2034	20,000			20,000
Total long-term debt	755,000			675,000
Less: unamortized debt issuance costs	(3,899		)	(3,559		)
Less: current maturities	(39,996		)	(19,986		)
Total long-term debt due after one year	$	711,105		$	651,455

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Income Taxes (Tables)

12 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Provisions for Income Taxes

The provisions for income taxes consist of the following:

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

Reconciliation from US Federal Statutory Tax Rate to Effective Tax Rate

A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:

	2017		2016		2015
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Difference in tax rate due to:
State income taxes, net of federal benefit	5.0		5.2		5.1
Excess tax benefits on share-based payments	(0.9	)	—		—
Other, net	(0.8	)	0.2		(0.5	)
Effective tax rate	38.3	%	40.4	%	39.6	%

Deferred Tax Liabilities (Assets)

Deferred tax liabilities (assets) comprise the following at September 30:

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

Reconciliation of Unrecognized Tax Benefits

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

	2017			2016		2015
Unrecognized tax benefits – beginning of year	$	2,055		$	—	$	—
Additions for tax positions taken in prior years	604			2,055		—
Additions for tax positions of the current year	—			—		—
Settlements with tax authorities/statute lapses	(830		)	—		—
Unrecognized tax benefits – end of year	$	1,829		$	2,055	$	—

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Employee Retirement Plans (Tables)

12 Months Ended

Sep. 30, 2017

Defined Benefit Plan [Abstract]

Change in Pension Benefits and Other Postretirement Benefit Obligations, Plan Assets, and Funded Status

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plan, the accumulated benefit obligations (“ABOs”) of the Other Postretirement Plans, plan assets and the funded status of the Pension Plan and Other Postretirement Plans as of September 30, 2017 and 2016. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect future compensation.

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

Actuarial Assumptions for Domestic Plans

The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).

	Pension Benefits						Other Postretirement Benefits
Weighted-average assumptions:	2017		2016		2015		2017		2016		2015
Discount rate – benefit obligations	4.00	%	3.80	%	4.60	%	4.00	%	3.80	%	4.70	%
Discount rate – benefit cost	3.80	%	4.60	%	4.60	%	3.80	%	4.70	%	4.60	%
Expected return on plan assets	7.50	%	7.55	%	7.75	%	5.00	%	5.00	%	5.00	%
Rate of increase in salary levels	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%

Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs

Net periodic pension and other postretirement benefit costs relating to the Company’s employees include the following components:

	Pension Benefits									Other Postretirement Benefits
	2017			2016			2015			2017			2016			2015
Service cost	$	8,091		$	6,927		$	6,962		$	273		$	183		$	202
Interest cost	22,157			23,270			22,511			431			465			479
Expected return on assets	(29,986		)	(28,668		)	(28,898		)	(656		)	(596		)	(612		)
Amortization of:
Prior service cost (benefit)	325			348			348			(641		)	(641		)	(641		)
Actuarial loss	14,825			9,571			8,793			108			98			122
Net benefit cost (income)	15,412			11,448			9,716			(485		)	(491		)	(450		)
Change in associated regulatory liabilities	—			—			—			(490		)	971			3,740
Net benefit cost after change in regulatory liabilities	$	15,412		$	11,448		$	9,716		$	(975	)	$	480		$	3,290

Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits

Expected payments for pension and other postretirement welfare benefits are as follows:

	Pension Benefits		Other Postretirement Benefits
Fiscal 2018	$	27,176	$	566
Fiscal 2019	28,471		566
Fiscal 2020	29,812		552
Fiscal 2021	31,084		537
Fiscal 2022	32,323		540
Fiscal 2023 - 2027	179,945		2,710

Schedule of Effect of One-percentage-point Change in Assumed Health Care Cost Trend Rates

The assumed health care cost trend rates at September 30 are as follows:

	2017		2016
Health care cost trend rate assumed for next year	7.00	%	7.25	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	5.0	%	5.0	%
Fiscal year that the rate reaches the ultimate trend rate	2026		2026

Allocation of Pension Plan and VEBA Trust Assets

The targets, target ranges and actual allocations for the Pension Plan and VEBA trust assets at September 30 are as follows:

	Actual				Target Asset	Permitted
Pension Plan:	2017		2016		Allocation	Range
Equity investments:
Domestic	55.2	%	54.1	%	52.5%	40.0% – 65.0%
International	12.4	%	10.2	%	12.5%	7.5% – 17.5%
Total	67.6	%	64.3	%	65.0%	60.0% – 70.0%
Fixed income funds & cash equivalents	32.4	%	35.7	%	35.0%	30.0% – 40.0%
Total	100.0	%	100.0	%	100.0%

	Actual				Target Asset	Permitted
VEBA:	2017		2016		Allocation	Range
Domestic equity investments	63.1	%	69.9	%	65.0%	60.0% – 70.0%
Fixed income funds & cash equivalents	36.9	%	30.1	%	35.0%	30.0% – 40.0%
Total	100.0	%	100.0	%	100.0%

Fair Value of Pension Plan and VEBA Trust Assets

The fair values of the Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2, as of September 30, 2017 and 2016 are as follows:

	Pension Plan
	Level 1		Level 2		Level 3		Other(a)		Total
September 30, 2017:
Domestic equity investments:
S&P 500 Index equity mutual funds	$	171,600	$	—	$	—	$	—	$	171,600
Small and midcap equity mutual funds	65,167		—		—		—		65,167
UGI Corporation Common Stock	38,137		—		—		—		38,137
Total domestic equity investments	274,904		—		—		—		274,904
International index equity mutual funds	61,613		—		—		—		61,613
Fixed income investments:
Bond index mutual funds	156,228		—		—		—		156,228
Cash equivalents	—		—		—		5,332		5,332
Total fixed income investments	156,228		—		—		5,332		161,560
Total	$	492,745	$	—	$	—	$	5,332	$	498,077
September 30, 2016:
Equity investments:
S&P 500 Index equity mutual funds	$	158,906	$	—	$	—	$	—	$	158,906
Small and midcap equity mutual funds	43,170		—		—		—		43,170
Smallcap common stocks	11,414		—		—		—		11,414
UGI Corporation Common Stock	37,013		—		—		—		37,013
Total domestic equity investments	250,503		—		—		—		250,503
International index equity mutual funds	47,324		—		—		—		47,324
Fixed income investments:
Bond index mutual funds	147,794		—		—		—		147,794
Cash equivalents	—		—		—		17,811		17,811
Total fixed income investments	147,794		—		—		17,811		165,605
Total	$	445,621	$	—	$	—	$	17,811	$	463,432

	VEBA
	Level 1		Level 2		Level 3		Other(a)		Total
September 30, 2017:
S&P 500 Index equity mutual fund	$	9,318	$	—	$	—	$	—	$	9,318
Bond index mutual fund	5,044		—		—		—		5,044
Cash equivalents	—		—		—		409		409
Total	$	14,362	$	—	$	—	$	409	$	14,771
September 30, 2016:
S&P 500 Index equity mutual fund	$	9,583	$	—	$	—	$	—	$	9,583
Bond index mutual fund	4,019		—		—		—		4,019
Cash equivalents	—		—		—		113		113
Total	$	13,602	$	—	$	—	$	113	$	13,715

(a) Assets measured at net asset value (“NAV”) and therefore excluded from the fair value hierarchy.

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Equity-Based Compensation (Tables)

12 Months Ended

Sep. 30, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

UGI Unit Award Activity

The following table summarizes UGI Unit award activity for Fiscal 2017:

	Total				Vested				Non-Vested
	Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)
September 30, 2016	57,783		$	34.66	10,316		$	34.31	47,467		$	34.74
Granted	16,425		$	51.42	367		$	51.42	16,058		$	51.42
Vested	—		$	—	16,003		$	33.10	(16,003	)	$	33.10
Forfeitures & transfers	(1,934	)	$	34.74	—		$	—	(1,934	)	$	34.74
Unit awards paid	(20,050	)	$	32.59	(20,050	)	$	32.59	—		$	—
September 30, 2017	52,224		$	40.72	6,636		$	37.53	45,588		$	41.19

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Fair Value Measurements (Tables)

12 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table presents, on a gross basis, our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2, as of September 30, 2017 and 2016:

	Asset (Liability)
	Level 1			Level 2			Level 3		Total
September 30, 2017
Derivative instruments:
Assets:
Commodity contracts	$	1,735		$	72		$	—	$	1,807
Liabilities:
Commodity contracts	$	(1,447	)	$	(73	)	$	—	$	(1,520	)
September 30, 2016
Derivative instruments:
Assets:
Commodity contracts	$	4,506		$	4		$	—	$	4,510
Liabilities:
Commodity contracts	$	(263	)	$	(294	)	$	—	$	(557	)

Schedule of Carrying Amount and Estimated Fair Value of Long-term Debt

The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2017 and 2016, were as follows:

	2017		2016
Carrying amount	$	755,000	$	675,000
Estimated fair value	$	791,378	$	770,781

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Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Assets and Liabilities Including Offsetting Amounts

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

	2017			2016
Derivative assets:
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$	1,665		$	4,472
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	142			38
Total derivative assets – gross	1,807			4,510
Gross amounts offset in the balance sheet	(450		)	(247		)
Total derivative assets – net (a)	$	1,357		$	4,263
Derivative liabilities:
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$	(1,520	)	$	(499	)
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	—			(58		)
Total derivative liabilities – gross	(1,520		)	(557		)
Gross amounts offset in the balance sheet	450			247
Total derivative liabilities – net (a)	$	(1,070	)	$	(310	)

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

Effects of Derivative Instruments on Consolidated Statements of Income and Changes in AOCI

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Consolidated Statements of Income and changes in AOCI for Fiscal 2017, Fiscal 2016 and Fiscal 2015:

	Loss Recognized in AOCI								Loss Reclassified from AOCI into Income									Location of
	2017		2016			2015			2017			2016			2015			Loss Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—	$	(28,958	)	$	(7,016	)	$	(3,397	)	$	(2,680	)	$	(2,674	)	Interest expense
	Gain (Loss) Recognized in Income																	Location of Gain (Loss)
	2017		2016			2015												Recognized in Income
Derivatives Not Subject to PGC and DS Mechanisms:
Gasoline contracts	$	174	$	(88	)	$	(761	)										Operating and administrative expenses/other operating income, net

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Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Sep. 30, 2017

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income

Changes in AOCI, net of tax, during Fiscal 2017, Fiscal 2016 and Fiscal 2015 are as follows:

	Postretirement Benefit Plans			Derivative Instruments			Total
AOCI - September 30, 2014	$	(6,311	)	$	(1,870	)	$	(8,181	)
Reclassifications of benefit plans actuarial losses and net prior service credits	517			—			517
Reclassifications of net losses on IRPAs	—			1,565			1,565
Net losses on IRPAs	—			(4,105		)	(4,105		)
Benefit plans, principally actuarial losses	(3,482		)	—			(3,482		)
AOCI - September 30, 2015	$	(9,276	)	$	(4,410	)	$	(13,686	)
Reclassifications of benefit plans actuarial losses and net prior service credits	639			—			639
Reclassifications of net losses on IRPAs	—			1,568			1,568
Net losses on IRPAs	—			(16,942		)	(16,942		)
Benefit plans, principally actuarial losses	(3,197		)	—			(3,197		)
AOCI - September 30, 2016	$	(11,834	)	$	(19,784	)	$	(31,618	)
Reclassifications of benefit plans actuarial losses and net prior service credits	956			—			956
Reclassifications of net losses on IRPAs	—			1,988			1,988
Benefit plans, principally actuarial gains	1,883			—			1,883
AOCI - September 30, 2017	$	(8,995	)	$	(17,796	)	$	(26,791	)

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Segment Information (Tables)

12 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Segment Information

Financial information by business segment follows:

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

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Other Operating Income (Expense), Net (Tables)

12 Months Ended

Sep. 30, 2017

Component of Operating Income [Abstract]

Schedule of Other Operating Income (Expense), Net

Other operating income (expense), net, comprises the following:

	2017			2016			2015
Non-tariff service income	$	1,491		$	2,633		$	4,760
Environmental matters	6,155			(2,918		)	1,152
Construction service income	—			—			2,175
Sale of HVAC Business	—			—			1,065
Net interest on PGC overcollection	(130		)	(1,740		)	(606		)
Other, net	813			25			323
Total other operating income (expense), net	$	8,329		$	(2,000	)	$	8,869

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Quarterly Data (unaudited) (Tables)

12 Months Ended

Sep. 30, 2017

Quarterly Financial Data [Abstract]

Schedule of Quarterly Financial Information

The following quarterly information includes all adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of the Company’s businesses.

	December 31,				March 31,				June 30,				September 30,
	2016		2015		2017		2016		2017		2016		2017			2016
Revenues	$	261,413	$	197,982	$	359,940	$	322,047	$	146,692	$	140,283	$	119,543		$	108,172
Operating income	$	82,236	$	48,296	$	116,408	$	114,481	$	27,671	$	29,815	$	1,992		$	8,309
Net income (loss)	$	44,265	$	23,351	$	65,125	$	63,294	$	10,697	$	12,603	$	(4,046	)	$	(1,875	)

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

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

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

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

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

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Regulatory Assets and Liabilities and Regulatory Matters - Additional Information (Details) - USD ($) $ in Thousands											1 Months Ended	12 Months Ended
	Oct. 20, 2017	Jul. 01, 2017	Jan. 19, 2017	Jan. 01, 2017	Oct. 19, 2016	Oct. 14, 2016	Jun. 30, 2016	Apr. 01, 2016	Jan. 19, 2016	Apr. 01, 2015	Mar. 31, 2016	Sep. 30, 2017	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2016
Regulatory Assets
Unrealized gains (losses) on derivative financial instruments contracts												$ 146			$ 4,263
Capitalized project costs															5,830
Project costs expensed in prior periods													$ 5,375
Information Technology
Regulatory Assets
Associated increase to utility property, plant and equipment															2,755
Pennsylvania Public Utility Commission
Regulatory Assets
Requested operating revenue increase			$ 21,700
Maximum period post petition to file general rate filing												5 years
Distribution system improvement charge, percent of amount billed to customers														0.00%
Pennsylvania Public Utility Commission | PNG
Regulatory Assets
Distribution system improvement charge, percent of amount billed to customers		7.50%								0.00%
Pennsylvania Public Utility Commission | PNG | Subsequent Event
Regulatory Assets
Approved operating revenue increase	$ 11,250
Pennsylvania Public Utility Commission | UGI Gas
Regulatory Assets
Requested operating revenue increase									$ 58,600
Amount of operating revenue increase							$ 27,000
Approved operating revenue increase						$ 27,000
Pennsylvania Public Utility Commission | CPG
Regulatory Assets
Distribution system improvement charge, percent of amount billed to customers		7.50%						0.00%
Removal Costs
Regulatory Assets
Period to recover costs related to regulatory assets												5 years
Deferred Project Costs
Regulatory Assets
Associated increase to utility regulatory assets															$ 3,075
Minimum
Regulatory Assets
Average remaining depreciable lives of the associated property												1 year
Maximum
Regulatory Assets
Average remaining depreciable lives of the associated property												65 years
Maximum | Pennsylvania Public Utility Commission
Regulatory Assets
Distribution system improvement charge, percent of amount billed to customers				5.00%							5.00%
Maximum | Pennsylvania Public Utility Commission | PNG
Regulatory Assets
Distribution system improvement charge, percent of amount billed to customers											10.00%
Maximum | Pennsylvania Public Utility Commission | CPG
Regulatory Assets
Distribution system improvement charge, percent of amount billed to customers											10.00%
Maximum | Postretirement benefits overcollections
Regulatory Assets
Regulatory liability, period over which overcollections will be refunded to customers					10 years

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

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

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

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

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Debt - Additional Information (Details)		12 Months Ended
	Oct. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Oct. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)
Debt Instrument
Due in Fiscal 2018		$ 40,000,000
Due in Fiscal 2019		0
Due in Fiscal 2020		0
Due in Fiscal 2021		0
Due in Fiscal 2022		0
Short-term borrowings		170,000,000		$ 112,500,000
UGI Utilities 2015 Credit Agreement
Debt Instrument
Short-term borrowings		$ 170,000,000		$ 112,500,000
Weighted average interest rate at period end		2.11%		1.42%
UGI Utilities 2015 Credit Agreement | Line of Credit
Debt Instrument
Credit agreement		$ 300,000,000
Issued and outstanding letters of credit		2,009,000		$ 2,009,000
UGI Utilities 2015 Credit Agreement | Letter of Credit
Debt Instrument
Credit agreement		$ 100,000,000
UGI Utilities 2015 Credit Agreement | Minimum | Line of Credit
Debt Instrument
Margin on term loan base rate borrowings (as a percent)		0.00%
UGI Utilities 2015 Credit Agreement | Maximum | Line of Credit
Debt Instrument
Margin on term loan base rate borrowings (as a percent)		1.75%
Senior Notes
Debt Instrument
Debt to capital ratio		0.65
Senior Notes | 4.12% Senior Notes, due September 2046
Debt Instrument
Interest rate		4.12%
Senior Notes | 4.12%, due October 2046
Debt Instrument
Aggregate principal amount			$ 100,000,000
Interest rate		4.12%	4.12%
Unsecured Debt [Member] | Subsequent Event
Debt Instrument
Aggregate principal amount	$ 125,000,000
Principal repayment in equal quarterly installments	$ 1,563,000
Unsecured Debt [Member] | Subsequent Event | Minimum
Debt Instrument
Margin on term loan base rate borrowings (as a percent)	0.00%
Unsecured Debt [Member] | Subsequent Event | Maximum
Debt Instrument
Margin on term loan base rate borrowings (as a percent)	1.875%

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

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

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

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

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

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

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

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

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

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Employee Retirement Plans - Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits (Details) $ in Thousands	Sep. 30, 2017 USD ($)
Pension Benefits
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Fiscal 2018	$ 27,176
Fiscal 2019	28,471
Fiscal 2020	29,812
Fiscal 2021	31,084
Fiscal 2022	32,323
Fiscal 2023 - 2027	179,945
Other Postretirement Benefits
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Fiscal 2018	566
Fiscal 2019	566
Fiscal 2020	552
Fiscal 2021	537
Fiscal 2022	540
Fiscal 2023 - 2027	$ 2,710

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Employee Retirement Plans - Schedule of Effect of One-percentage-point Change in Assumed Health Care Cost Trend Rates (Details)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Plan [Abstract]
Health care cost trend rate assumed for next year	7.00%	7.25%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	5.00%	5.00%
Fiscal year that the rate reaches the ultimate trend rate	2026	2026

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

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

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

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

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Equity-Based Compensation - UGI Unit Award Activity (Details)	12 Months Ended
	Sep. 30, 2017 $ / shares shares
Number of UGI Units
Beginning balance (in units) | shares	57,783
Granted (in units) | shares	16,425
Vested (in units) | shares	0
Forfeitures & transfers (in units) | shares	(1,934)
Unit awards paid (in units) | shares	(20,050)
Ending balance (in units) | shares	52,224
Weighted Average Grant Date Fair Value (per Unit)
Beginning balance (in usd per share) | $ / shares	$ 34.66
Granted (in usd per share) | $ / shares	51.42
Vested (in usd per share) | $ / shares	0.00
Forfeitures & transfers (in usd per share) | $ / shares	34.74
Unit awards paid (in usd per share) | $ / shares	32.59
Ending balance (in usd per share) | $ / shares	$ 40.72
Vested
Number of UGI Units
Beginning balance (in units) | shares	10,316
Granted (in units) | shares	367
Vested (in units) | shares	16,003
Forfeitures & transfers (in units) | shares	0
Unit awards paid (in units) | shares	(20,050)
Ending balance (in units) | shares	6,636
Weighted Average Grant Date Fair Value (per Unit)
Beginning balance (in usd per share) | $ / shares	$ 34.31
Granted (in usd per share) | $ / shares	51.42
Vested (in usd per share) | $ / shares	33.10
Forfeitures & transfers (in usd per share) | $ / shares	0.00
Unit awards paid (in usd per share) | $ / shares	32.59
Ending balance (in usd per share) | $ / shares	$ 37.53
Non-Vested
Number of UGI Units
Beginning balance (in units) | shares	47,467
Granted (in units) | shares	16,058
Vested (in units) | shares	16,003
Forfeitures & transfers (in units) | shares	(1,934)
Unit awards paid (in units) | shares	0
Ending balance (in units) | shares	45,588
Weighted Average Grant Date Fair Value (per Unit)
Beginning balance (in usd per share) | $ / shares	$ 34.74
Granted (in usd per share) | $ / shares	51.42
Vested (in usd per share) | $ / shares	33.10
Forfeitures & transfers (in usd per share) | $ / shares	34.74
Unit awards paid (in usd per share) | $ / shares	0.00
Ending balance (in usd per share) | $ / shares	$ 41.19

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Commitments and Contingencies - Commitments (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Rental expense	$ 7,276	$ 7,669	$ 7,956
2018	7,545
2019	5,961
2020	4,355
2021	2,665
2022	793
After 2022	$ 182

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

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

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

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

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

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

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

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

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

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

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

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