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EX-32 - EXHIBIT 32 - UGI UTILITIES INCex322017ugiutilitiesinc10-k.htm
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EX-12.1 - EXHIBIT 12.1 - UGI UTILITIES INCex1212017ugiutilities10-k.htm
EX-10.8 - EXHIBIT 10.8 - UGI UTILITIES INCa2017ugicorp10kex1026.htm


 
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. 12th 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 reduced disclosure format permitted by that General Instruction.
 




TABLE OF CONTENTS
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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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 by insurance.

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, which may increase our expenses or decrease our revenues and, thus, have an adverse 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 could reduce 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.


10



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 of warmer-than-normal heating season weather could adversely affect our results of operations, financial condition and cash flows because our rate structure does 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 customer conservation, may result in reduced demand for our energy products and services.

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 and adversely 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

11



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 interest rate 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 our liquidity.

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 unpredictable government 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 industry in 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 affected by 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

12



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

13



(“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).


14



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

15



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.

16



Fiscal 2016 Compared with Fiscal 2015
 
 
 
 
 
 
 
(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.

17



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

18



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.

19



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.

20




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

21



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.


22



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

23



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.

25




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.


26



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):

27



Incorporation by Reference
Exhibit No.
Exhibit
Registrant
Filing
Exhibit
3.1
Utilities
Registration
Statement No.
333-72540
(10/31/01)
3
3.2

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
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
Utilities
Form 8-K
(8/1/96)
4(i)
4.6
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
Utilities
Form 8-K
(8/1/96)
4(iv)
4.9
Utilities
Form 8-K
(5/21/02)
4.2
4.10
Utilities
Form 8-K
(5/21/02)
4.1
4.11
Utilities
Form 8-K
(10/30/13)
4.1
4.12
Utilities
Form 8-K
(4/28/16)
4.1

28



Incorporation by Reference
Exhibit No.
Exhibit
Registrant
Filing
Exhibit
10.1**
UGI
Form 10-K
(9/30/16)


10.25
10.2**

UGI
Form 10-K
(9/30/16)
10.26
10.3**

UGI
Form 10-K
(9/30/16)
10.30
10.4**
UGI
Form 10-Q
(6/30/17)
10.5
10.5**
UGI
Form 10-K
(9/30/16)
10.31
10.6**
UGI
Form 10-Q
(6/30/17)
10.6
10.7**
UGI
Form 10-Q (6/30/17)
10.7
*10.8**
 
 
 
10.9**
UGI
Form 10-Q
(6/30/17)
10.1
10.10**
Utilities
Form 10-Q (3/31/13)
10.2
10.11**

UGI
Form 10-Q
(6/30/17)
10.3
10.12**
UGI
Form 10-Q
(6/30/17)
10.2
10.13**
Utilities
Form 10-Q
(6/30/17)
10.1

29



Incorporation by Reference
Exhibit No.
Exhibit
Registrant
Filing
Exhibit
10.14**
UGI
Form 10-Q (3/31/13)
10.14
10.15
Utilities
Form 10-K (9/30/14)
10.16
10.16
Utilities
Form 10-K (9/30/14)
10.19
10.17
Utilities
Form 10-K
(9/30/16)
10.19
10.18
Utilities
Form 8-K (3/27/15)
10.1
10.19

Utilities
Form 8-K
(10/31/17)
10.1

30



Incorporation by Reference
Exhibit No.
Exhibit
Registrant
Filing
Exhibit
 
 
 
 
 
*12.1
 
 
 
14
UGI
Form 10-K
(9/30/03)
14
*23
 
 
 
*31.1
 
 
 
*31.2
 
 
 
*32
 
 
 
*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
 
 
 
 
12.1
 
 
 
 
23
 
 
 
 
31.1
 
 
 
 
31.2
 
 
 
 
32
 
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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Financial Statement Schedule:
 
 
 
 
 
For the years ended September 30, 2017, 2016 and 2015:
 
 
 
 
 
 
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.

F- 9

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.

F- 15

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<