SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934



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



Large accelerated filer ¨o	Accelerated filer ¨o	Non-accelerated filer þ
Smaller reporting company ¨o	Emerging growth company o

FORWARD-LOOKING INFORMATION

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Service Area; Revenue Analysis

Sources of Supply and Pipeline Capacity

Gas Supply Contracts

During Fiscal ~~2014,~~2017, Gas Utility purchased approximately ~~84.2~~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. ~~Approximately 90%~~Eighty-five percent (85%) of the volumes purchased were supplied under agreements with 10 suppliers. The remaining ~~10%~~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 1612 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. ~~During~~For Fiscal ~~2014,~~2017, approximately ~~65%~~60% of Gas Utility's sales volume was supplied, and ~~over~~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.~~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. ~~Larger commercial and industrial~~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. ~~As a result of Pennsylvania's Natural Gas Choice and Competition Act, effective July 1, 1999, all of Gas Utility’s customers, including core-market customers, have been afforded this opportunity.~~

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 ~~23%~~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, ~~approximately 31%~~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 ~~approximately 26 of~~38 such customers, ~~with~~34 of which have transportation contracts extending beyond ~~fiscal year 2015.~~Fiscal 2018. The majority of these customers are served under transportation contracts having 33- to ~~20 year~~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 year 2015.~~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 ~~2014,~~2017, Gas Utility supplied transportation service to ~~five major co-generation installations and four~~nine electric generation ~~facilities.~~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 ~~2014,~~2017, Gas Utility connected approximately 2,000 new commercial and industrial customers. In the residential market sector, Gas Utility ~~connected nearly 16,000~~added over 12,000 residential heating customers during Fiscal ~~2014. Over 12,000~~2017. Approximately 65% of these customers converted to natural gas heating from other energy sources, mainly oil and electricity. New home construction ~~customers~~ 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 ~~2014.~~2017.

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 ~~assure~~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 ~~1,900~~2,200 miles of transmission and distribution lines and 13 substations. For Fiscal ~~2014,~~2017, approximately ~~56%~~55% of sales volume came from residential customers, ~~32%~~33% from commercial customers, and 12% from industrial and other customers.

Sources of Supply

~~In accordance with Electric Utility’s default service settlement with the PUC effective January 1, 2010,~~ 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~~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 ~~2014, five~~2017, eleven retail electric generation suppliers provided energy for customers representing approximately ~~24%~~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 ~~2014,~~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 athe Default Service (“DS”) rate ~~plan~~plans approved by the PUC. Consistent with the terms of the DS rate ~~plan, effective January 1, 2010,~~plans, default service rates are designed to recover all reasonable and prudent costs incurred in providing electricity to default service customers. This recovery, through default service rates, no longer subjects Electric Utility to the risk that actual costs for purchased power will exceed default service revenues. Conversely, effective January 1, 2010, Electric Utility does not have the opportunity to recover revenues in excess of actual power costs. 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 PGCs and electric default service costs are reviewed in PGC and electric default service rate proceedings.~~ Rates designed to recover costs other than PGCs and electric default service costs are primarily established in general base rate proceedings.

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.~~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 ~~that~~such standard. The PGC mechanism also provides for an annual ~~reconciliation.~~

~~UGI Gas has two PGC rates: (i) applicable to small, firm, retail core-market customers consisting~~reconciliation and for the payment or collection of ~~the residential~~interest on over and small commercial and industrial classes; and (ii) applicable to firm, high-load factor, customers served on three separate rates. PNG and CPG each have one PGC rate applicable to all customers. Base rates for each ofunder collections. UGI Gas, PNG, and CPG ~~were last established in 1995, 2009,~~may assign to and ~~2011, respectively.~~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.

On ~~February 20, 2014,~~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 ~~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~~GDE Rider for all three ~~utilities,~~companies.

On June 23, 2016, Act 47 of 2016 was enacted. Act 47 revised the interest rates that applied to ~~extend~~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 ~~utility pipelines to provide service to unserved~~from an alternative supplier by way of a so-called migration rider, provided additional assurance of cost recovery for PGC costs, and ~~underserved areas within their respective territories. Under the GET Gas program, customers utilizing the extended pipeline to receive~~granted natural gas ~~will pay~~distribution companies the right to recover the reasonable costs incurred to implement customer choice on a ~~monthly surcharge over~~full and current basis through a ~~10-year period to cover the cost of the extension.~~reconcilable rate mechanism. Gas Utility ~~began connecting customers under~~implemented the ~~GET Gas program~~interest rate revision and migration rider provisions of Act 47 in ~~October 2014.~~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

~~In accordance with Electric Utility’s default service settlement with the PUC effective June 1, 2014 through May 31, 2017,~~ 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. ~~Electric Utility’s~~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, ~~2017~~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, ~~2017.~~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

~~Both Gas Utility and Electric Utility are~~UGI Utilities is subject to Section 4A of the Natural Gas Act, ~~and Section 222 of the Federal Power Act~~ which ~~prohibit~~prohibits the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of natural gas ~~electric energy,~~ or natural gas transportation ~~or electric transmission services~~ subject to the jurisdiction of FERC, and FERC regulations ~~which~~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.

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, ~~2014,~~2017, UGI Utilities had ~~approximately 1,470~~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 ~~2014, 2013~~2017, 2016 and ~~2012~~2015 fiscal years appears in Note 1516 to Consolidated Financial Statements included in this Report and is incorporated herein by reference.

ITEM 1A. RISK FACTORS

RISKS RELATED TO OUR BUSINESS

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

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

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

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

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

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

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

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

the discovery of presently unknown conditions;

changes in environmental laws and regulations;

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

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

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

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

and capital markets. Developments in the credit markets ~~during~~have the ~~past few years~~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 ~~transmission and distribution systems may not operate as planned, whichmay increase our expenses or decrease our revenues and, thus, have anadverse effect on our financial results.~~

Our ability to manage operational risk with respect to our transmission and distribution systems is critical to our financial results. 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.

~~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.

~~Regulators may not allow timely recovery~~The risk of ~~costs for us in the future,which~~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 Gas Utility~~operations, our ability to raise capital, and ~~Electric Utility distribution operations are subject to regulation by~~our future growth. The impact that the ~~PUC. The PUC, among other things, approves the rates that we~~foregoing may ~~charge to~~have on our ~~utility customers, thus impacting the returns that we may earn~~industryin general, and 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 requiredus 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~~particular, is not ~~be covered byinsurance.~~

~~Our business operations are subject to all~~known at this time. An act of ~~the operating hazards and risks normally incidental to the handling, storage and distribution of combustible products, such as natural gas. These risks~~terror could result in ~~substantial losses due to personal injury and/~~disruptions of natural gas supplies and markets, cause price volatility in the cost of natural gas, and our infrastructure facilities could be direct or ~~loss~~indirect targets. A lower level of ~~life, and severe damage to and destruction of property and equipment arising from explosions and other catastrophic events, including acts of terrorism. As~~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 ~~we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course~~ of ~~business. There can be no assurance that~~terrorism could also affect our ~~insurance will be adequate~~ability to ~~protect us from all material expenses related to pending and future claims or that such levels of insurance will be available in the future at economical prices.~~raise capital.

In response to ~~recent~~ natural gas ~~explosions~~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.

~~There continues to be concern, both nationally and internationally, about climate change and the contribution~~Increased regulation of ~~greenhouse gas~~Greenhouse Gas (“GHG”) emissions, ~~most notably carbon dioxide, to global warming. In addition to carbon dioxide, greenhouse gases include, among others,~~such as propane and methane, ~~a component of natural gas. While some~~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, there is currently no federal or regional legislation mandating~~sectors. For example, the ~~reduction of GHG emissions in the United States. Although Congress has not enacted federal climate change legislation, the~~California Environmental Protection Agency ~~(“EPA”) has begun adopting and implementing regulations~~established a Cap & Trade program that requires certain covered entities, including propane companies, to ~~restrict emissions of GHGs from motor vehicles and certain large stationary sources, and~~purchase allowances to ~~require reporting of~~compensate for the GHG emissions

created by ~~certain regulated facilities on an annual basis. Increased regulation of GHG emissions could impose significant additional costs on us, our suppliers, and our customers.~~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. Petroleum and natural gas facilities subject to the rule,~~industries, which include certain facilities of our natural gas distribution ~~business, were~~business. These subject facilities have been required to ~~begin~~monitor emissions ~~monitoring in~~since January 2011 and to submit detailed annual reports beginning in March 2012. ~~The rule does not require affected facilities to implement GHG emission controls or reductions. However, in June 2014,~~In October 2015, the EPA ~~proposed~~promulgated the ~~Clean~~Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (the “Clean Power ~~Plan,~~Plan”), which ~~will provide~~provides standards and guidelines for reducing existing power plants’ GHG emissions and related pollutants by 2030. ~~The~~However, in October 2017, the EPA announced its proposal to repeal the Clean Power Plan ~~standards and guidelines are expected to be finalized by June 2015. The impact of such legislation and regulations~~

~~will depend~~in its entirety on ~~a number of factors, including (i) what industry sectors would be impacted, (ii)~~ the ~~timing of required compliance, (iii)~~grounds that it exceeds the ~~overall GHG emissions cap level, (iv)~~EPA’s delegated authority under the ~~allocation of emission allowances to specific sources and (v) the costs and opportunities associated with compliance.~~Clean Air Act. At this time, we cannot predict the effect that climate change regulation may have on our business, financial condition or ~~results of~~ operations in the future.

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

~~the discovery of presently unknown conditions;~~

~~changes in environmental laws and regulations;~~

~~judicial rejection of our legal defenses to the 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.~~

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 ~~$77.4~~$57.7 million in Fiscal ~~2014, $59.0~~2017, $47.0 million in Fiscal ~~2013~~2016, and ~~$70.6~~$65.6 million in Fiscal ~~2012.~~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 1516 to Consolidated Financial Statements.

EXECUTIVE OVERVIEW

~~Our results~~For the second year in a row, our Gas Utility and Electric Utility experienced the effects of significantly warmer than normal weather. Fiscal ~~2014 reflect~~2017 temperatures based upon heating degree days ~~in our Gas Utility service territory~~were approximately 11% warmer than normal compared to temperatures that were ~~10% colder~~more than 13% warmer than normal ~~and almost 11% colder than~~ in Fiscal ~~2013. During Fiscal 2014, Gas Utility experienced record customer growth as continuing low natural gas prices relative to~~2016.

Notwithstanding the ~~price of heating oil resulted in continuing high numbers of conversions from oil to natural gas.~~

~~Our~~significantly warmer than normal weather, UGI Utilities net income in Fiscal ~~2014 was $124.1~~ ~~million, an~~2017 increased nearly 20%. UGI Utilities achieved this significant increase in earnings largely as a result of ~~$22.0 million (21.6%~~)higher base rates at UGI Gas, organic customer growth and incremental revenues from ~~Fiscal 2013 net income of $102.1~~ million. The improved results in Fiscal 2014 at our Gas Utility principally reflect the effects on core market volumes of the significantly colder heating-season weather and customer growth. The significantly colder heating-season weather resulted in higher core market volumes and core market total margin. The benefit of the greater total Gas Utility margin was reduced, in part, by higher Gas Utility operating and administrative expenses including greater distribution system ~~maintenance and uncollectible accounts expenses.~~improvements through distribution system improvement charges

(“DSIC”). Our Electric Utility’s kilowatt-hour sales in Fiscal ~~2014~~2017 were ~~about equal with~~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 ~~colder winter weather’s impact~~price difference between natural gas and oil has expanded in the last fiscal year. Gas Utility continued to execute on ~~heating-related sales were offset by~~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 ~~effects of a milder summer on air-conditioning sales. Electric Utility incurred higher distribution system maintenance expenses~~customer experience and provide for streamlined processes within the company. We will continue to invest in technology change during Fiscal ~~2014 primarily related~~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 ~~summer storm damage.~~

provide additional long-term financing of its infrastructure betterment capital program and information technology initiatives (see Note 7 to Consolidated Financial Statements). We believe ~~that~~ we have sufficient liquidity ~~in the forms of cash generated~~ from ~~operations and~~ our revolving credit facility, cash flow from operations and the ability to issue long-term debt at attractive rates to fund business operations induring Fiscal ~~2015.~~2018 (see “Financial Condition and Liquidity” below and Note 7 to Consolidated Financial Statements for additional information on the credit facility).

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare the Company’s results of operations for Fiscal ~~2014~~2017, Fiscal ~~2013~~2016 and ~~the year ended September 30,~~ ~~2012~~ (“Fiscal ~~2012~~2015”).

Fiscal ~~2014~~2017 Compared with Fiscal ~~2013~~2016


							Increase
(Millions of dollars)	2014			2013			(Decrease)
(Dollars in millions)												2017			2016			Increase (Decrease)
Gas Utility:
Revenues	$	977.3		$	839.1		$	138.2		16.5	%	$	799.1		$	677.4		$	121.7		18.0	%
Total margin (a)	$	480.6		$	431.8		$	48.8		11.3	%	$	480.8		$	438.2		$	42.6		9.7	%
Operating and administrative expenses												$	192.0		$	174.5		$	17.5		10.0	%
Operating income	$	236.2		$	198.4		$	37.8		19.1	%	$	219.6		$	189.4		$	30.2		15.9	%
Income before income taxes	$	199.6		$	161.1		$	38.5		23.9	%	$	181.3		$	153.6		$	27.7		18.0	%
System throughput — bcf
Core market	80.4			70.6			9.8			13.9	%	70.4			66.2			4.2			6.3	%
Total	208.8			192.1			16.7			8.7	%	243.1			212.4			30.7			14.5	%
Degree days — % colder (warmer) than normal (b)	10.0		%	(0.5		)%	—			—
Degree days — % (warmer) than normal (b)												(11.1		)%	(13.6		)%	—			—
Electric Utility:
Revenues	$	108.1		$	100.0		$	8.1		8.1	%	$	88.5		$	91.1		$	(2.6	)	(2.9	)%
Total margin (a)	$	36.0		$	35.8		$	0.2		0.6	%	$	34.8		$	35.6		$	(0.8	)	(2.2	)%
Operating and administrative expenses												$	20.3		$	18.2		$	2.1		11.5	%
Operating income	$	9.7		$	11.4		$	(1.7	)	(14.9	)%	$	8.7		$	11.5		$	(2.8	)	(24.3	)%
Income before income taxes	$	7.8		$	9.4		$	(1.6	)	(17.0	)%	$	6.8		$	9.6		$	(2.8	)	(29.2	)%
Distribution sales — gwh	987.3			992.6			(5.3		)	(0.5	)%	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 ~~revenue-related taxes, i.e.~~ Electric Utility gross receipts taxes, of $~~5.8~~4.7 million and $~~5.4~~4.8 million during Fiscal ~~2014~~2017 and Fiscal ~~2013~~2016, respectively. ~~For financial statement purposes, revenue-related~~Gross receipt taxes are included in ~~taxes~~“Taxes other than income ~~taxes in~~taxes” on the Consolidated Statements of Income.


(b)	Deviation from average heating degree days for the 15-year period ~~1995-2009~~2000-2014 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

~~Gas Utility~~.

Temperatures in Gas Utility’s service territory induring Fiscal ~~2014 based upon heating degree days~~2017 were ~~10.0%~~11.1% warmer than normal but 2.6% colder than ~~normal and 10.6% colder than~~during Fiscal ~~2013. Total distribution system throughput increased 16.7 bcf principally reflecting a 9.8 bcf (13.9%) increase in demand from~~2016. Gas ~~Utility’s~~Utility core market ~~customers and, to a lesser extent, greater net large firm and interruptible delivery service volumes. Gas Utility system throughput to core market customers was higher than last year~~volumes increased 4.2 bcf (6.3%) principally reflecting the effects of the ~~significantly~~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 ~~lesser extent, customer growth due principally to conversions from other fuels prompted by sustained lower~~new natural ~~gas prices relative to heating oil prices.~~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 ~~alternate suppliers.~~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 ~~increased $138.2 million during Fiscal 2014~~partially offset by slightly lower Electric Utility revenues. The higher Gas Utility revenues principally reflecting higher revenues from core market customers ($83.6 million), higher revenues from off-system sales ($36.4 million) and, to a much lesser extent, higher revenues from large firm delivery service customers on higher throughput ($12.5 million). Thereflect an increase in core market revenues ~~principally~~($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. Increases~~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 ~~retail core-market~~

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 principally result from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market

~~customers~~but have no direct effect on retail core-market ~~margin. Gas Utility’s~~margin (see Note 4 to Consolidated Financial Statements for a discussion of these recovery mechanisms). UGI Utilities cost of sales ~~were $496.8~~was $367.3 million in Fiscal ~~2014~~2017 compared with ~~$407.2~~$289.8 million in Fiscal ~~2013~~2016, principally reflecting higher average retail core market PGC rates ($37.0 million), the ~~effects of the greater~~higher Gas Utility retail core-market volumes ~~sold~~ ($~~50.1~~14.0 million) and ~~the effects~~higher cost of ~~the higher~~sales associated with Gas Utility off-system sales ($~~36.4~~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 ~~$48.8~~$41.7 million ~~in Fiscal 2014~~ principally reflecting higher total margin from Gas Utility core market ~~total margin~~customers ($~~33.8~~32.7 million) and ~~greater~~higher large firm delivery service total margin ($~~10.8~~11.4 million)~~. The higher core market and large firm delivery service total margin reflects the effects of the previously mentioned colder weather and customer growth.~~

~~Gas Utility operating income and income before income taxes during Fiscal 2014 increased $37.8 million and $38.5 million, respectively, over Fiscal 2013.~~ partially offset by lower other margin. The increase in Gas Utility ~~operating income~~core market margin principally reflects the ~~$48.8~~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 ~~partially offset~~($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. Operating~~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 ($1.6 million). The increase in UGI Utilities operating and administrative expenses in ~~Fiscal 2014 were modestly~~the current year reflects higher ~~than the prior year principally reflecting greater Fiscal 2014 distribution system maintenance~~pension and employee benefits expenses ($~~5.3~~7.0 million), higher ~~uncollectible~~customer accounts expense ($~~3.0~~4.2 million) and ~~greater incentive compensation~~higher regulatory asset amortization expense ~~partially offset by lower pension expense.~~related to environmental remediation expenses ($1.9 million). The increase in ~~Gas Utility~~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 ~~reflects~~increased $24.8 million reflecting the ~~greater~~increase in UGI Utilities operating income ($~~37.8~~27.4 million) ~~and slightly lower~~partially offset by higher interest ~~expense.~~

~~Electric Utility~~. Temperatures based upon heating degree days during Fiscal 2014 were approximately 6.6% colder than normal and approximately 8.5% colder than the prior year. The increase in Electric Utility revenues primarily reflects higher average Default Service (“DS”) rates. Electric Utility cost of sales increased to $66.2 million in Fiscal 2014 from $58.8 million in Fiscal 2013 principally reflecting the effects of the greater DS rates.

Electric Utility total margin was about equal to the prior year. Operating income and income before income taxes in Fiscal 2014 decreased $1.7 million and $1.6 million, respectively, principally reflecting higher distribution system maintenance costs resulting from Fiscal 2014 summer storm damage and slightly higher uncollectible accounts expense.

Interest Expense and Income Taxes. ~~Our interest~~Interest expense in Fiscal ~~2014 was slightly lower than the prior year~~2017 increased principally reflecting ~~lower~~higher average ~~interest rates.~~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 ~~2014 was comparable with~~2016. The lower Fiscal 2017 effective income tax rate is due primarily to the ~~prior year.~~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.

Fiscal ~~2013~~2016 Compared with Fiscal ~~2012~~2015


							Increase
(Millions of dollars)	2013			2012			(Decrease)
(Dollars in millions)												2016			2015 (c)			Decrease
Gas Utility:
Revenues	$	839.1		$	785.4		$	53.7		6.8	%	$	677.4		$	933.1		$	(255.7	)	(27.4	)%
Total margin (a)	$	431.8		$	382.8		$	49.0		12.8	%	$	438.2		$	484.5		$	(46.3	)	(9.6	)%
Operating and administrative expenses												$	174.5		$	196.9		$	(22.4	)	(11.4	)%
Operating income	$	198.4		$	172.2		$	26.2		15.2	%	$	189.4		$	226.5		$	(37.1	)	(16.4	)%
Income before income taxes	$	161.1		$	132.0		$	29.1		22.0	%	$	153.6		$	187.4		$	(33.8	)	(18.0	)%
System throughput — bcf
Core market	70.6			59.2			11.4			19.3	%	66.2			81.3			(15.1		)	(18.6	)%
Total	192.1			177.6			14.5			8.2	%	212.4			213.5			(1.1		)	(0.5	)%
Degree days —% (warmer) colder than normal (b)	(0.5		)%	(16.3		)%	—			—
Degree days — % (warmer) colder than normal (b)												(13.6		)%	6.4		%	—			—
Electric Utility:
Revenues	$	100.0		$	97.1		$	2.9		3.0	%	$	91.1		$	107.6		$	(16.5	)	(15.3	)%
Total margin (a)	$	35.8		$	35.3		$	0.5		1.4	%	$	35.6		$	39.8		$	(4.2	)	(10.6	)%
Operating and administrative expenses												$	18.2		$	20.4		$	(2.2	)	(10.8	)%
Operating income	$	11.4		$	12.6		$	(1.2	)	(9.5	)%	$	11.5		$	14.2		$	(2.7	)	(19.0	)%
Income before income taxes	$	9.4		$	10.3		$	(0.9	)	(8.7	)%	$	9.6		$	12.1		$	(2.5	)	(20.7	)%
Distribution sales — gwh	992.6			974.6			18.0			1.8	%	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 ~~revenue-related taxes, i.e.~~ Electric Utility gross receipts taxes, of ~~$5.4~~$4.8 million inand $5.6 million during Fiscal ~~2013~~2016 and ~~$5.3~~ ~~million in~~ Fiscal ~~2012. For financial statement purposes, revenue-related~~2015, respectively. Gross receipt taxes are included in ~~taxes~~“Taxes other than income ~~taxes in~~taxes” on the Consolidated Statements of Income.


(b)	Deviation from average heating degree days for the 15-year period ~~1995-2009~~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).

~~Gas Utility~~. Temperatures in ~~the~~ Gas ~~Utility~~Utility’s service territory induring Fiscal ~~2013~~2016 based upon heating degree days were ~~0.5%~~13.6% warmer than normal ~~but 18.2% colder~~and 17.8% warmer than Fiscal ~~2012. Total distribution system throughput increased principally reflecting significantly higher throughput to~~2015. In particular, Gas Utility temperatures in the critical heating-season month of December were 37% warmer than normal. Gas Utility core market ~~customers and, to a lesser extent, greater net~~ volumes ~~associated with lower margin firm and interruptible delivery service customers. Gas Utility system throughput to core-market customers was above last year principally~~declined 15.1 bcf (18.6%) reflecting the effects of the significantly ~~colder~~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 ~~and, to~~on heating-related sales.

UGI Utilities Fiscal 2016 revenues decreased $273.1 million principally reflecting a ~~much lesser extent, customer growth, principally conversions from oil prompted by sustained lower natural gas prices relative to heating oil prices.~~

$255.7 million decrease in Gas Utility revenues ~~increased $53.7~~and a $16.5 million ~~during~~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 ~~2013~~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 ~~higher revenues~~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 $51.3 million principally reflecting lower Gas Utility total margin from core market customers ($~~52.8 million) and higher large firm delivery service revenues ($9.2 million) partially offset by lower off-system sales revenues ($8.6~~43.3 million). The ~~increase~~decrease in core market revenues principally reflects the effects of higher retail core-market volumes on PGC revenues ($60.4 million) and greater core market delivery service revenues partially offset by the effects of lower average PGC rates on retail core-market revenues ($50.6 million). Gas Utility's cost of sales were $407.2 million in Fiscal 2013 compared with $402.5 million in Fiscal 2012 principally reflecting the effects on cost of sales of the greater retail core-market volumes ($60.4 million) substantially offset by the effects of lower average PGC rates ($50.6 million) and the lower off-system sales.

Gas Utility ~~total margin increased $49.0 million in Fiscal 2013 principally reflecting higher core market margin ($38.1 million) and higher large firm delivery service total margin ($9.6 million). The higher~~ core market margin reflects the ~~effects of the greater~~lower core market ~~volumes.~~

~~The increase in Gas~~throughput. Electric Utility ~~operating income during Fiscal 2013 principally reflects the increase in~~ total margin ($49.0 million) partially offset by higher operating and administrative expenses ($20.2 million) including, among other things, higher pension and benefits expenses ($10.7 million), higher uncollectible accounts expenses ($2.8 million) on higher core market volumes, and greater injuries and damages and distribution system expenses ($4.5 million). The greater income before income taxes in Fiscal 2013 reflectsdecreased $4.2 million principally reflecting the ~~higher operating income ($26.2 million) and slightly~~ lower ~~interest expense on lower long-term debt outstanding.~~

~~Electric Utility.~~ Temperatures based upon heating degree days during Fiscal 2013 were approximately 1.8% warmer than normal but approximately 17% colder than the prior-year period. The increase in Fiscal 2013 revenues reflects in large part the effects of highervolume sales ~~principally~~as a result of the ~~colder heating-season~~warmer Fiscal 2016 weather and ~~spring temperatures. Electric Utility cost of sales increased to $58.8 million in Fiscal 2013 compared to $56.5 million in Fiscal 2012 principally reflecting~~ the ~~effects of the greater sales.~~

~~Electric Utility total margin increased $0.5 million in Fiscal 2013 reflecting in large part the higher distribution sales and greater~~lower transmission revenue.

~~Notwithstanding the increase in total margin, Electric Utility~~

UGI Utilities Fiscal ~~2013~~2016 operating income and income before income taxes decreased ~~reflecting greater~~$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 ~~costs including distribution system repair and maintenance costs principally~~expenses that were $25.6 million lower than the prior year primarily reflecting lower net preliminary development stage expenses associated with ~~Hurricane Sandy early~~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 ~~Fiscal 2013.~~

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~~Taxes.. Our interest expense in Fiscal ~~2013~~2016 was ~~$3.1~~$3.5 million lower than in Fiscal ~~2012~~2015 principally reflecting UGI Utilities’ lower average long-term debt ~~outstanding.~~outstanding and lower average interest rates. Our effective income tax rate in Fiscal ~~2013~~2016 was slightly higher than in ~~Fiscal 2012 as~~ the prior ~~year tax rate reflected the regulatory effects of greater state tax depreciation.~~year.

FINANCIAL CONDITION AND LIQUIDITY

Capitalization and Liquidity

UGI Utilities’ total debt outstanding was $~~728.3~~$921.1 million at September 30, ~~2014~~,2017, which includes $~~86.3~~$170 million of short-term borrowings, compared with total debt outstanding of $~~659.5~~$783.9 million at September 30, ~~2013~~,2016, which includes ~~$17.5~~$112.5 million of short-term borrowings. UGI Utilities’ total long-term debt outstanding at September 30, ~~2014~~,2017, comprises ~~$450.0~~$675.0 million of Senior Notes and ~~$192.0~~$80.0 million of Medium-Term ~~Notes.~~Notes, and is net of $3.9 million of unamortized debt issuance costs.

~~In March 2014,~~Pursuant to a note purchase agreement, in October 2016, UGI Utilities issued ~~in a private placement, $175~~$100 million aggregate principal amount of ~~4.98%~~4.12% Senior Notes due ~~March 2044 (“4.98%~~October 2046 (the “4.12% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds ~~from the sale~~ of the ~~4.98%~~issuance of the 4.12% Senior Notes were used (1) to ~~repay $175 million of borrowings under~~provide additional financing for UGI Utilities’ ~~364-day Term Loan Credit Agreement. Because the Company had the intent~~infrastructure replacement and ability to refinance the Term Loan Credit Agreement on a long-term basis as of September 30, 2013, amounts outstanding under the Term Loan Credit Agreement were classified as long-term debt on the 2013 Consolidated Balance Sheet.betterment capital program and information technology initiatives and (2) for general corporate purposes.

UGI Utilities has a credit agreement ~~(“Credit~~(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 ~~October 2015.~~March 2020. Borrowings under the Credit Agreement are classified as short-term borrowings on the Consolidated Balance Sheets. During Fiscal ~~2014~~2017 and Fiscal ~~2013~~,2016, average daily short-term borrowings under the Credit Agreement were ~~$29.9~~$80.7 million and ~~$25.6~~$150.8 million,, respectively, and peak short-term borrowings totaled ~~$86.3~~$178.0 million and ~~$79.0~~$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, ~~and inventories,~~ is generally greatest. ~~The Credit Agreement requires~~

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 ~~not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.~~October 30, 2022 once UGI Utilities ~~was~~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 ~~compliance~~equal quarterly installments of $1.6 million with ~~this covenant at~~ ~~September 30, 2014~~.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 ~~2015~~.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 ~~$188.7~~$243.6 million in Fiscal ~~2014~~, ~~$169.9~~2017, $205.4 million in Fiscal ~~2013~~2016 and ~~$209.7~~$306.7 million in Fiscal ~~2012~~.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

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 ~~$224.6~~$288.7 million in Fiscal ~~2014~~, ~~$196.7~~2017, $204.9 million in Fiscal ~~2013~~2016 and ~~$185.3~~$229.3 million in Fiscal ~~2012~~.2015. The significantly higher cash flow before changes in operating working capital in Fiscal ~~2014~~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 ~~2013, and Fiscal 2013 compared with Fiscal 2012,~~2015 reflects ~~in large part,~~ the ~~higher~~lower year-over-year operating ~~results.~~results and a $36.0 million cash settlement of IRPAs, partially offset by an increase in deferred income taxes. Changes in operating working capital (used) provided ~~$(35.9)~~$(45.1) million of cash in Fiscal ~~2014~~, ~~$(26.8)~~2017, $0.5 million of cash in Fiscal ~~2013~~2016 and ~~$24.5~~$77.4 million of cash in Fiscal ~~2012~~.2015.

Investing activities. Cash used by investing activities was ~~$172.8~~$320.5 million in Fiscal ~~2014~~, ~~$159.2~~2017, $252.5 million in Fiscal ~~2013~~,2016, and ~~$114.7~~$216.6 million in Fiscal ~~2012~~.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 2014 compared with Fiscal 2013, and Fiscal 2013 compared with Fiscal 2012, principally reflects higher year-over-year Gas Utility capital expenditures for infrastructure improvements and customer growth. Fiscal 20142017 cash flow from investing activities includes a ~~$0.4~~$2.5 million increase in restricted cash in futures brokerage accounts compared to a ~~$3.2~~$6.0 million decrease in Fiscal 2016 and a $3.0 million increase in Fiscal ~~2013 and a $4.3 million decrease in Fiscal 2012.~~2015. Changes in restricted cash in futures brokerage accounts are generally the result of changes in underlying commodity prices.

Financing activities. Cash ~~used~~provided (used) by financing activities was $~~8.2~~79.3 million in Fiscal ~~2014~~2017, $~~7.3~~46.9 million in Fiscal ~~2013~~2016 and $~~101.0~~(99.4) million in Fiscal ~~2012~~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 ~~2014,~~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 ~~$68.8~~$57.5 million and $40.8 million, compared to net ~~borrowings~~short-term debt repayments of ~~$8.3 million and $9.2~~$14.6 million in Fiscal ~~2013 and~~2015. The greater short-term debt repayments in Fiscal ~~2012, respectively.~~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 ~~2014,~~2017, Fiscal ~~2013~~2016 and Fiscal ~~2012.~~2015. We also provide amounts we expect to spend in Fiscal ~~2015.~~2018. We expect to finance a substantial portion of our Fiscal ~~2015~~2018 capital expenditures from cash generated by operations and ~~the remainder from~~ borrowings under our Credit Agreement.


(Millions of dollars)	2015		2014		2013		2012		2018		2017		2016		2015
	(estimate)								(estimate)
Gas Utility	$	191.9	$	156.4	$	144.4	$	109.0	$	297.0	$	306.2	$	251.3	$	189.7
Electric Utility	8.6		7.8		6.7		5.1		20.0		11.5		11.2		8.0
	$	200.5	$	164.2	$	151.1	$	114.1	$	317.0	$	317.7	$	262.5	$	197.7

Contractual Cash Obligations and Commitments

UGI Utilities has contractual cash obligations that extend beyond Fiscal ~~2014~~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 and derivative financial instruments.~~electricity. The following table presents significant contractual cash obligations under agreements existing as of September 30, ~~2014~~2017:


	Payments Due by Period										Payments Due by Period
			Fiscal		Fiscal		Fiscal						Fiscal		Fiscal		Fiscal
(Millions of dollars)	Total		2015		2016 - 2017		2018 - 2019		Thereafter		Total		2018		2019 - 2020		2021 - 2022		Thereafter
Long-term debt (a)	$	642.0	$	20.0	$	267.0	$	40.0	$	315.0	$	755.0	$	40.0	$	—	$	—	$	715.0
Interest on long-term fixed rate debt (b)	488.7		36.8		54.7		36.3		360.9		779.8		34.2		65.5		65.5		614.6
Derivative financial instruments (c)	1.6		1.6		—		—		—
Operating leases	23.2		6.7		10.7		5.1		0.7		21.5		7.5		10.3		3.5		0.2
Gas Utility and Electric Utility supply, storage and transportation contracts	591.8		204.0		184.2		107.3		96.3
UGI Utilities supply, storage and transportation contracts											629.1		187.9		239.2		127.2		74.8
Total	$	1,747.3	$	269.1	$	516.6	$	188.7	$	772.9	$	2,185.4	$	269.6	$	315.0	$	196.2	$	1,404.6


(a)	Based upon stated maturity dates.


(b)	Based upon stated interest rates.


~~(c)~~	~~Represents sum of amounts due from us if derivative financial instruments were settled at the September 30, 2014, amounts reflected in the Consolidated Balance Sheet.~~

The components of the ~~other~~“Other noncurrent ~~liabilities~~liabilities” included in our Consolidated Balance Sheet at September 30, ~~2014~~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 ~~we will be~~the minimum required ~~to make~~ contributions to our pension plan in Fiscal ~~2015~~2018 ~~of approximately $1.1~~ ~~million.~~are not expected to be material. Contributions to the pension plan in years beyond Fiscal ~~2015~~2018 will depend in large part on the ~~effects~~impacts of future returns on pension plan assets and interest rates on pension plan ~~assets.~~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 $~~442.5~~498.1 million and $~~398.2~~463.4 million at September 30, ~~2014~~2017 and ~~2013~~2016, respectively. At September 30, ~~2014~~2017 and ~~2013~~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 $~~97.3~~141.2 million and $~~88.3~~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. ~~We anticipate that we will be required to make~~Required minimum contributions to the Pension Plan ~~during~~in Fiscal ~~2015~~ ~~of approximately $1.1~~ ~~million.~~2018 are not expected to be material. Pre-tax pension cost associated with the Pension Plan in Fiscal ~~2014~~2017 was $~~9.8~~15.4 million. Pre-tax pension cost associated with Pension Plan in Fiscal ~~2015~~2018 is expected to be approximately $~~9.7~~$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, ~~2014~~2017, we have recorded cumulative after-tax charges to stockholder’s equity of ~~$6.3~~$9.0 million and regulatory assets of $~~110.1~~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.

~~REGULATORY MATTERS~~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 ~~February 20, 2014,~~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 ~~entered an order approving a Growth Extension Tariff (“GET Gas”) program under which UGI Gas,~~ permission, the DSIC is capped at 5% of distribution charges billed to customers.

PNG and CPG may invest up to $5 million per year for five years 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 payreceived PUC approval on a ~~monthly surcharge over a 10-year period to cover the cost of the extension. UGI Gas,~~DSIC tariff, initially set at zero, in 2014. PNG and CPG began ~~connecting customers under~~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 ~~GET Gas program~~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 ~~October 2014.~~2018.

On ~~February~~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, ~~2012, CPG filed an application with~~2017. UGI Gas will be permitted to recover revenue under the ~~PUC~~mechanism for ~~review and approval~~the amount of DSIC-eligible plant placed into service in excess of the ~~transfer~~threshold amount of ~~an 11-mile natural gas pipeline, related facilities and rights~~DSIC-eligible plant agreed upon in the settlement of ~~way located in Delmar Township, Pennsylvania (“TL-96 line”) to UGI Energy Services, LLC (which was formerly known as UGI Energy Services, Inc. prior to~~ its merger with and into UGI Energy Services, LLC effective October 1, 2013), a second-tier wholly owned subsidiary of UGI (“Energy Services”). The PUC approved the transfer and in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the TL-96 line was approximately $2.7 million which amount, net of related deferred income taxes of $0.4 million, is reflected as a dividend of net assets on the Fiscal 2013 Consolidated Statement of Stockholder’s Equity.recent base rate case.

MANUFACTURED GAS PLANTS

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at ~~$1.8 million~~ ~~and~~ ~~$1.1 million~~, respectively, in any calendar year. The CPG-COA is scheduled to terminate at the end of 2018. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At September 30, ~~2014~~ ~~and~~ ~~2013, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled~~ ~~$10.7 million~~ ~~and~~ ~~$14.0 million, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.~~

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. ~~Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by~~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 ~~its~~the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because ~~(1)~~ UGI ~~Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs, and (2)~~Utilities, CPG and PNG ~~are currently receiving regulatory~~receive ratemaking recovery of ~~estimated~~actual environmental investigation and remediation costs associated with ~~Pennsylvania~~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. ~~At September 30, 2014, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.~~

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 ~~its~~a former ~~subsidiaries.~~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 ~~subsidiaries~~subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator

because of its conduct with respect to its subsidiary’s MGP. At September 30, 2017, 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~~“Operating and administrative expenses -— related ~~parties~~parties” in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s ~~subsidiaries.~~subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities ~~for all periods presented were not material.~~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 ~~Storage Contract Administration Agreements (“SCAAs”)~~SCAAs with Energy ~~Services.~~Services which have terms of up to three years. At September 30, ~~2014~~,2017, UGI Utilities was a party to ~~three~~four SCAAs with Energy Services, ~~one of which expired October 31, 2014, and two of which expire October 31, 2015~~ 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, ~~and subject to recall for operational purposes,~~ 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. ~~UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $38.3~~During Fiscal 2017, Fiscal 2016 and Fiscal 2015, these payments totaled $2.7 million, ~~$45.8~~$2.0 million and ~~$24.3~~$2.3 million, ~~in Fiscal 2014, Fiscal 2013 and Fiscal 2012,~~ respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. ~~The amount~~At September 30, 2017 and 2016, the amounts of such security deposits, which ~~amounts~~ are included in ~~other~~“Other current ~~liabilities~~liabilities” on the Consolidated Balance Sheets, were ~~$10.6~~$11.0 million and ~~$16.5~~$8.1 million, ~~at September 30, 2014 and 2013,~~ respectively. ~~Effective November 1, 2014, UGI Utilities entered into a new SCAA with Energy Services having a term of one year.~~

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. The~~“Inventories.” At September 30, 2017 and 2016, the carrying ~~value~~values of these gas storage inventories, at ~~September 30, 2014~~ ~~and~~ ~~2013~~, comprising approximately ~~7.7~~6.8 bcf and ~~10.4~~4.6 bcf of natural gas, were ~~$33.1~~$19.3 million and ~~$42.0~~$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 ~~2014~~,2017, Fiscal ~~2013~~2016 and Fiscal ~~2012~~2015 totaled ~~$35.8~~$76.0 million, ~~$32.5~~$63.3 million and ~~$30.8~~$47.8 million, respectively.

From time to time, ~~the Company~~UGI Utilities sells natural gas or pipeline capacity to Energy Services. During Fiscal ~~2014~~,2017, Fiscal ~~2013~~2016 and Fiscal ~~2012~~,2015, revenues associated with such sales to Energy Services totaled ~~$109.9~~$50.9 million, ~~$69.1~~$30.7 million and ~~$65.7~~$79.2 million, respectively. Also from time to time, ~~the Company~~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 ~~2014~~,2017, Fiscal ~~2013~~2016 and Fiscal ~~2012~~,2015, such purchases totaled ~~$128.1~~$84.4 million, ~~$77.0~~$35.1 million and ~~$53.4~~$85.4 million, respectively. ~~These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.~~

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.

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, ~~2014~~,2017, Gas Utility had ~~$3.6~~$3.0 million of ~~restricted cash associated with natural gas futures accounts with brokers. At~~ ~~September 30, 2013, Gas Utility had~~ ~~$3.2 million~~ restricted cash in brokerage accounts. At September 30, ~~2014~~ ~~and~~ ~~2013~~,2017, the fair values of our natural gas futures and option contracts were ~~losses of $1.4 million and $1.7 million, respectively.~~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, ~~2014~~2017, all of our Electric Utility’s forward electricity purchase contracts were subject to the normal purchase and ~~2013~~,normal sale (“NPNS”) exception. At September 30, 2017, the fair values of ~~Electric Utility’s electricity supply contracts were gains (losses) of~~ ~~$0.3 million~~ ~~and $(4.8) million, respectively. The fair values of~~ FTRs ~~at September 30, 2014 and 2013,~~ were not material.

In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures ~~and swap~~ contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures ~~and swap~~ contracts are recorded at fair value with changes in fair value reflected in ~~other income.~~“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, ~~2014 and 2013,~~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 ~~2014~~ ~~and Fiscal~~ ~~2013~~,2017, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by ~~$0.3 million~~ ~~and $0.3 million, respectively.~~$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 ~~$53.0~~$93 million ~~and~~ ~~$28.0 million~~ at September 30, ~~2014~~ ~~and~~ ~~2013, respectively.~~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 ~~$64.0~~$118 million ~~and~~ ~~$32.0 million~~ at September 30, ~~2014~~ ~~and~~ ~~2013, respectively.~~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, ~~2014 and 2013.~~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, ~~Summary of Significant Accounting Policies,~~ which discusses the significant accounting policies that we have selected from acceptable alternatives.

Goodwill Impairment ~~of Goodwill.~~Evaluation. Our goodwill is the result of Gas Utility business ~~acquisitions.We~~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. ~~In accordance with GAAP, a~~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. WeFrom time to time, we may assess qualitative factors to determine whether it is more likely than not that the fair value of ~~our Gas Utility~~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 ~~unit.~~units. The market approach requires judgment to determine the appropriate valuation multiples. ~~Under certain circumstances, the Company may perform a qualitative approach to determine if it is more likely than not that~~If the carrying ~~value~~amount of a reporting unit ~~is greater than~~exceeds its fair ~~value.~~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, ~~2014~~2017, our goodwill totaled $182.1 million. We did not record any impairments of goodwill ~~during~~in Fiscal ~~2014~~2017, Fiscal ~~2013~~2016 or Fiscal ~~2012~~2015.

Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation ~~regarding pending claims and legal actions~~ that ~~arise~~arises in the normal course of ~~our businesses.~~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 ~~establish reserves for pending claims and legal actions or environmental remediation obligations~~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.~~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. ~~Such~~Our estimated reserves may differ materially from the ~~actual~~ultimate liability and such reserves may change materially as more information becomes ~~available and estimated reserves are adjusted.~~available.

Depreciation of Property, Plant and Equipment. We compute depreciation on UGI Utilities property, plant and equipment on a straight-line basis ~~over~~based upon the ~~average remaining~~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, ~~2014~~2017, UGI Utilities net property, plant and equipment totaled $~~1,682.3~~2,274.5 million and we recorded depreciation expense of $~~55.8~~69.8 million during Fiscal ~~2014~~2017.

Regulatory Assets and Liabilities. Gas Utility and Electric ~~Utility’s distribution businesses~~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, ~~2014~~2017, our regulatory assets and regulatory liabilities totaled $~~268.2~~368.9 ~~million.~~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~~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

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 ~~to a lesser extent, common stock.~~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 ~~Plans~~Plan assets of 50 basis points to a rate of ~~7.25%~~6.90% would result in an increase in pre-tax pension cost of approximately ~~$1.9~~$1.6 million in Fiscal ~~2015~~2018. A decrease in the discount rate of 50 basis points to a rate of ~~4.10%~~3.50% would result in an increase in pre-tax pension cost of approximately ~~$3.1~~$4.0 million in Fiscal ~~2015~~2018. For additional information on our Pension Plan, see Note 9 to Consolidated Financial Statements.

~~Purchase Price Allocations.~~ In the event that the Company enters into a material business combination, in accordance with accounting guidance associated with business combinations, the purchase price is allocated to the various assets and liabilities acquired at their estimated fair value. Fair values of assets acquired and liabilities assumed are based upon available information and we may involve an independent third-party to perform appraisals. Estimating fair values can be complex and subject to significant business judgment and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, if necessary, up to one year from the acquisition date to finalize the purchase price allocation.

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

conducted an assessment, including testing, of the Company’s internal control over financial reporting using the criteria in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO 1992”).

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.

Based on its assessment, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, ~~2014,~~2017, based on the COSO ~~1992. PricewaterhouseCoopers~~2013 Framework. Ernst & Young LLP, ~~the Company’s~~our independent registered public accounting firm, has audited the effectiveness of the Company’s internal control over financial reporting as of September 30, ~~2014,~~2017, as stated in their report, which appears herein.

ITEM 9B. OTHER INFORMATION

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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, ~~2014~~2017 and ~~2013~~2016

Consolidated Statements of Income for the ~~fiscal~~ years ended September 30, ~~2014, 2013~~2017, 2016 and ~~2012~~2015

Consolidated Statements of Comprehensive Income for the years ended September 30, ~~2014, 2013~~2017, 2016 and ~~2012~~2015

Consolidated Statements of Cash Flows for the ~~fiscal~~ years ended September 30, ~~2014, 2013~~2017, 2016 and ~~2012~~2015

Consolidated Statements of Stockholder’s Equity for the ~~fiscal~~ years ended September 30, ~~2014, 2013~~2017, 2016 and ~~2012~~2015

Notes to Consolidated Financial Statements

For the years ended September 30, ~~2014, 2013~~2017, 2016 and ~~2012~~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.

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):

Incorporation by Reference

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

Registrant

Filing

Exhibit

3.1

UGI Utilities’ Amended and Restated Articles of Incorporation.

Utilities

Registration

Statement No.

333-72540

(10/31/01)

UGI Utilities’ Amended and Restated Articles of Incorporation.

Utilities

Registration

Statement No.

333-72540

(10/31/01)

3.2

Bylaws of UGI Utilities as amended through September 30, 2003.

Utilities

Form 10-K

(9/30/03)

3.2

Bylaws of UGI Utilities, Inc., as amended and restated as of July 25, 2017.

Utilities

Form 8-K

(7/25/17)

3.1

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’ Articles of Incorporation and Bylaws referred to in Exhibit Nos. 3.1 and 3.2.

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)

Utilities

Registration

Statement No.

33-77514

(4/8/94)

4(c)

4.3

Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association.

Utilities

Form 8-K

(9/12/06)

4.2

Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association.

Utilities

Form 8-K

(9/12/06)

4.2

4.4

Form of Fixed Rate Medium-Term Note.

Utilities

Form 8-K

(8/26/94)

(4)i

Form of Fixed Rate Medium-Term Note.

Utilities

Form 8-K

(8/26/94)

(4)i

4.5

Form of Fixed Rate Series B Medium-Term Note.

Utilities

Form 8-K

(8/1/96)

4(i)

Form of Fixed Rate Series B Medium-Term Note.

Utilities

Form 8-K

(8/1/96)

4(i)

4.6

Form of Floating Rate Series B Medium-Term Note.

Utilities

Form 8-K

(8/1/96)

4(ii)

Form of Floating Rate Series B Medium-Term Note.

Utilities

Form 8-K

(8/1/96)

4(ii)

4.7

Officer’s Certificate establishing Medium-Term Notes Series.

Utilities

Form 8-K

(8/26/94)

4(iv)

Officer’s Certificate establishing Medium-Term Notes Series.

Utilities

Form 8-K

(8/26/94)

4(iv)

4.8

Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture.

Utilities

Form 8-K

(8/1/96)

4(iv)

Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture.

Utilities

Form 8-K

(8/1/96)

4(iv)

4.9

Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture.

Utilities

Form 8-K

(5/21/02)

4.2

Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture.

Utilities

Form 8-K

(5/21/02)

4.2

4.10

Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes.

Utilities

Form 8-K

(5/21/02)

4.1

Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes.

Utilities

Form 8-K

(5/21/02)

4.1

4.11

Form of Note Purchase Agreement dated October 30, 2013 between the Company and the purchasers listed as signatories thereto.

Utilities

Form 8-K

(10/30/13)

4.1

Form of Note Purchase Agreement dated October 30, 2013 between the Company and the purchasers listed as signatories thereto.

Utilities

Form 8-K

(10/30/13)

4.1

4.12

Note Purchase Agreement dated April 22, 2016 between the Company and the purchasers listed as signatories thereto.

Utilities

Form 8-K

(4/28/16)

4.1

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.1**	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of ~~December~~September 5, ~~2006.~~2014.	UGI	Form ~~8-K~~10-K ~~(2/27/07)~~(9/30/16)	~~10.1~~10.25
10.2**	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of ~~December~~September 5, ~~2006~~2014 - Terms and Conditions as ~~amended and restated~~ effective ~~November, 2012.~~January 1, 2016.	UGI	Form 10-K (9/30/~~13)~~16)	~~10.2~~10.26
10.3**	UGI Corporation 2013 Omnibus Incentive Compensation Plan, effective as of ~~January 24, 2013.~~September 5, 2014.	UGI	~~Registration Statement No. 333-186178 (1/24/2013)~~ Form 10-K (9/30/16)	~~99.1~~10.30
10.4**	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 24, 2017.	UGI	Form 10-Q (6/30/17)	10.5
10.5**	UGI Corporation 2013 Omnibus Incentive Compensation Plan, effective as of September 5, 2014 - Terms and Conditions for Non-Employee Directors effective January 1, 2016.	UGI	Form 10-K (9/30/16)	10.31
10.6**	UGI Corporation 2009 Deferral Plan, as Amended and Restated effective ~~January 24, 2014.~~June 15, 2017.	UGI	Form 10-Q ~~(3/31/14)~~(6/30/17)	~~10.5~~10.6
10.510.7*	UGI Corporation Senior Executive Employee Severance Plan, as amended and restated as of ~~November 16, 2012.~~June 15, 2017.	UGI	Form 10-Q (6/30/~~13)~~17)	~~10.1~~10.7
10.610.8	UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective ~~November 22, 2013.~~April 1, 2015.	~~UGI~~	~~Form 10-Q (3/31/14)~~	~~10.3~~
10.710.9*	UGI Corporation 2009 Supplemental Executive Retirement Plan for New Employees, as Amended and Restated effective ~~November 22, 2013.~~June 15, 2017.	UGI	Form 10-Q ~~(3/31/14)~~	~~10.4~~
10.8**	~~UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.~~	~~Utilities~~	~~Form 10-Q~~ (6/30/~~13)~~17)	10.1
10.910.10*	UGI Utilities, Inc. Executive Annual Bonus Plan, effective as of October 1, 2006, as amended as of November 16, 2012.	Utilities	Form 10-Q (3/31/13)	10.2
10.1010.11*	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, ~~Nonqualified Stock Option~~Performance Unit Grant Letter for UGI and Utilities Employees, dated January 1, ~~2014.~~2017.	UGI	Form 10-Q ~~(3/31/14)~~(6/30/17)	~~10.9~~10.3
10.1110.12*	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for UGI, Utilities and AmeriGas Employees, dated January 1, ~~2014.~~2017.	UGI	Form 10-Q ~~(3/31/14)~~(6/30/17)	~~10.11~~10.2
10.13**	UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended as of July 10, 2017.	Utilities	Form 10-Q (6/30/17)	10.1

Incorporation by Reference

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

Registrant

Filing

Exhibit

10.12**

UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Employees, dated January 1, 2014.

UGI

Form 10-Q (3/31/14)

10.7

10.13**

UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2014.

UGI

Form 10-Q (3/31/14)

10.12

10.14**

UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006, as amended November 16, 2012.

UGI

Form 10-Q (3/31/13)

10.14

UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006, as amended November 16, 2012.

UGI

Form 10-Q (3/31/13)

10.14

10.15

Credit Agreement, dated as of May 25, 2011 among UGI Utilities, Inc., as borrower, and PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and RBS Citizens, N.A., as joint lead arrangers and joint bookrunners, and PNC Bank, National Association, Citizens Bank of Pennsylvania, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, The Bank of New York Mellon, and the other financial institutions from time to time parties thereto.

Utilities

Form 8-K

(5/25/11)

10.1

FSS Service Agreement No. 79028 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.

Utilities

Form 10-K (9/30/14)

10.16

*10.16

FSS Service Agreement No. 79028 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.

10.16

SST Service Agreement No. 79133 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.

Utilities

Form 10-K (9/30/14)

10.19

10.17

Firm Storage and Delivery Service Agreement (Rate GSS) dated July 1, 1996 between Transcontinental Gas Pipe Line Corporation and PG Energy.

Utilities

Form 8-K

(8/24/06)

10.8

Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, LLC, effective November 1, 2015.

Utilities

Form 10-K

(9/30/16)

10.19

10.18

Service Agreement For Use Under Seller’s GSS Rate Schedule dated July 9, 2012 between Transcontinental Gas Pipe Line Company, LLC and UGI Penn Natural Gas, Inc.

Utilities

Form 10-Q

(6/30/12)

10.1

Credit Agreement, dated as of March 27, 2015 among UGI Utilities, Inc., as borrower, PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and Citizens Bank, N.A., as joint lead arrangers and joint bookrunners, and the other financial institutions from time to time parties thereto.

Utilities

Form 8-K (3/27/15)

10.1

*10.19

SST Service Agreement No. 79133 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.

10.19

Credit Agreement, dated October 31, 2017, by and among UGI Utilities, Inc., PNC Bank National Association, as administrative agent, The Bank of New York Mellon, as syndication agent, and certain other lenders named therein.

Utilities

Form 8-K

(10/31/17)

10.1

Incorporation by Reference

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

Registrant

Filing

Exhibit

*12.1

Computation of Ratio of Earnings to Fixed Charges.

Code of Ethics for principal executive, financial and accounting officers.

UGI

Form 10-K

(9/30/03)

Code of Ethics for principal executive, financial and accounting officers.

UGI

Form 10-K

(9/30/03)

*23

Consent of PricewaterhouseCoopers LLP.

Consent of Ernst & Young LLP.

*31.1

Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2014 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2017 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2

Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2014 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2017 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32

Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2014, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2017, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*101.INS

XBRL.Instance

XBRL Instance

*101.SCH

XBRL Taxonomy Extension Schema

*101.CAL

XBRL Taxonomy Extension Calculation Linkbase

*101.DEF

XBRL Taxonomy Extension Definition Linkbase

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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.

EXHIBIT INDEX



Exhibit No.		Description

10.8		UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective April 1, 2015.

12.1		Computation of Ratio of Earnings to Fixed Charges

23		Consent of Ernst & Young LLP.

31.1		Certification by the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act

31.2		Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act

32		Certification by the Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act
101.INS		XBRL Instance
101.SCH		XBRL Taxonomy Extension Schema
101.CAL		XBRL Taxonomy Extension Calculation Linkbase
101.DEF		XBRL Taxonomy Extension Definition Linkbase
101.LAB		XBRL Taxonomy Extension Labels Linkbase
101.PRE		XBRL Taxonomy Extension Presentation Linkbase

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.



		UGI UTILITIES, INC.
Date:	November ~~28, 2014~~21, 2017	By:	/s/ ~~Donald E. Brown~~Daniel J. Platt
			~~Donald E. Brown~~ 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 ~~28, 2014~~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/ ~~Donald E. Brown~~Daniel J. Platt		Vice President — Finance and Chief Financial Officer, Assistant
~~Donald E. Brown~~Daniel J. Platt		Secretary and Treasurer (Principal Financial Officer)

/s/ Megan Mattern		Controller (Principal Accounting Officer)
Megan Mattern

/s/ ~~Lon R. Greenberg~~Marvin O. Schlanger		Chairman and Director
~~Lon R. Greenberg~~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/ ~~Ernest E. Jones~~		~~Director~~
~~Ernest E. Jones~~

~~/s/~~ Anne Pol		Director
Anne Pol

/s/ ~~M. Shawn Puccio~~James B. Stallings, Jr.		Director
~~M. Shawn Puccio~~

~~/s/ Marvin O. Schlanger~~		~~Director~~
~~Marvin O. Schlanger~~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:

No annual report or proxy material was sent to security holders in Fiscal ~~2014.~~2017.

UGI UTILITIES, INC. AND SUBSIDIARIES

FINANCIAL INFORMATION

FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K

YEAR ENDED SEPTEMBER 30, ~~2014~~2017

UGI UTILITIES, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE



		Pages

Financial Statements:

Report of Independent Registered Public Accounting Firm (on Internal Control over Financial Reporting)		F- 2

Report of Independent Registered Public Accounting Firm (on Consolidated Financial Statements and Schedule)		F- 3

Consolidated Balance Sheets as of September 30, ~~2014~~2017 and ~~2013~~2016		F- 34

Consolidated Statements of Income for the years ended September 30, ~~2014, 2013~~2017, 2016 and ~~2012~~2015		F- 45

Consolidated Statements of Comprehensive Income for the years ended September 30, ~~2014, 2013~~2017, 2016 and ~~2012~~2015		F- 56

Consolidated Statements of Cash Flows for the years ended September 30, ~~2014, 2013~~2017, 2016 and ~~2012~~2015		F- 67

Consolidated Statements of Stockholder’s Equity for the years ended September 30, ~~2014, 2013~~2017, 2016 and ~~2012~~2015		F- 78

Notes to Consolidated Financial Statements		F- 89 to F- 3235

Financial Statement Schedule:

For the years ended September 30, ~~2014, 2013~~2017, 2016 and ~~2012:~~2015:

II — Valuation and Qualifying Accounts		S- 1

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

~~F- 1~~

Report of Independent Registered Public Accounting Firm

/s/ ~~PricewaterhouseCoopers~~Ernst & Young LLP

Philadelphia, Pennsylvania

November ~~28, 2014~~21, 2017

Report of Independent Registered Public Accounting Firm

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

/s/ Ernst & Young LLP

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

September 30,
2014 2013
ASSETS
Current assets:
Cash and cash equivalents $ 12,401
$ 4,707
Restricted cash 3,592
3,181
Accounts receivable (less allowances for doubtful accounts of $6,992 and $5,519, respectively) 65,080
53,341
Accounts receivable — related parties 2,865
3,497
Accrued utility revenues 14,330
18,868
Inventories 95,219
89,661
Deferred income taxes 1,492
14,165
Regulatory assets 13,159
8,217
Derivative instruments 1,028
43
Prepaid expenses & other current assets 18,535
15,862
Total current assets 227,701
211,542
Property, plant and equipment 2,568,552
2,427,810
Less accumulated depreciation and amortization (886,268 ) (853,675 )
Net property, plant and equipment 1,682,284
1,574,135
Goodwill 182,145
182,145
Regulatory assets 255,007
236,694
Other assets 7,506
5,806
Total assets $ 2,354,643
$ 2,210,322
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt $ 20,000
$ —
Short-term borrowings 86,300
17,500
Accounts payable — trade 58,453
51,970
Accounts payable — related parties 11,761
12,487
Employee compensation and benefits accrued 14,647
13,664
Interest accrued 8,908
11,281
Customer deposits and advances 40,401
40,307
Derivative instruments 1,632
6,677
Pension and postretirement benefit obligations 1,100
17,885
Other current liabilities 34,280
35,742
Total current liabilities 277,482
207,513
Long-term debt 622,000
642,000
Deferred income taxes 461,461
436,810
Deferred investment tax credits 3,933
4,270
Pension and other postretirement benefit obligations 98,363
72,505
Other noncurrent liabilities 51,567
55,610
Total liabilities 1,514,806
1,418,708
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 471,071
470,098
Retained earnings 316,688
269,977
Accumulated other comprehensive loss (8,181 ) (8,720 )
Total common stockholder’s equity 839,837
791,614
Total liabilities and stockholder’s equity $ 2,354,643
$ 2,210,322

See accompanying Notes to Consolidated Financial Statements.

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of dollars)

See accompanying Notes to Consolidated Financial Statements.

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)

Year Ended September 30,
2014 2013 2012
Net income $ 124,106
$ 102,098
$ 87,898
Net gains (losses) on derivative instruments (net of tax of $0, $(10,746) and $4,783, respectively) —
15,153
(6,744 )
Reclassifications of net losses on derivative instruments (net of tax of $(1,112), $(334) and $(766), respectively) 1,567
471
1,111
Benefit plans (net of tax of $1,002, $(3,325) and $1,948, respectively) (1,413 ) 4,689
(2,745 )
Reclassifications of benefit plans actuarial losses and prior service costs to net income (net of tax of $(274), $(555) and $(333), respectively) 385
784
394
Other comprehensive income (loss) 539
21,097
(7,984 )
Comprehensive income $ 124,645
$ 123,195
$ 79,914



	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.

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)

See accompanying Notes to Consolidated Financial Statements.

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(Thousands of dollars)

See accompanying Notes to Consolidated Financial Statements.

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except ~~per share amounts)~~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 ~~northeastern~~ 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 ~~has~~had a heating, ventilation and air-conditioning service business ~~(“UGI Penn HVAC Services, Inc.”)~~ which ~~operates~~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 ~~sometimes~~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 ~~all significant~~ 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, ~~related to regulated entities whose rates are designed to recover the costs of providing service.~~“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 ~~are amortized into expense~~ and regulatory liabilities are amortized into expense and income over the ~~period~~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, ~~also~~ 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.

~~UGI UTILITIES, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Thousands of dollars, except per share amounts)~~

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.

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:

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 inon the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) ~~exemption~~exception under ~~GAAP and such exemption has been elected.~~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.

~~Substantially~~Gains and losses on substantially all of the ~~gains and losses on~~ derivative instruments used by ~~Gas Utility and Electric Utility~~UGI Utilities (for which NPNS has not been elected) to hedge commodity prices are included in regulatory assets and liabilities in accordance with ~~FASB guidance~~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 ~~value~~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 ~~the~~ 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 ~~of our~~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.

UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service rendered and commodities ~~rendered~~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 ~~from~~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 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.

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except ~~per share amounts)~~where indicated otherwise)

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 ~~generally~~ 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.

~~Comprehensive Income~~

Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally reflects gains (losses) on interest rate protection agreements (“IRPAs”) qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.

~~Changes in AOCI during Fiscal 2014 are as follows:~~

Postretirement
Benefit Plans

Derivative
Instruments
Net Losses
Total
September 30, 2013 $ (5,283 ) $ (3,437 ) $ (8,720 )
Reclassification of benefit plan actuarial losses and prior service cost 385
—
385
Reclassifications of net losses on IRPAs —
1,567
1,567
Benefit plans, principally actuarial gains and losses (1,413 ) —
(1,413 )
September 30, 2014 $ (6,311 ) $ (1,870 ) $ (8,181 )

~~Amounts in the table above are net of tax.~~

~~Reclassifications of net losses on interest rate protection agreements are reflected in interest expense on the Consolidated Statements of Income.~~

Cash and Cash Equivalents

~~All~~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 are classified as cash equivalents.~~purchased.

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

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

~~UGI UTILITIES, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Thousands of dollars, except per share amounts)~~

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis ~~over the estimated average remaining~~based upon projected service lives of the various classes of its depreciable property. ~~Depreciation expense as a percentage~~The estimated useful lives of the ~~related~~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 ~~depreciable base for~~composite depreciation rates at our Gas Utility ~~was 2.3% in Fiscal 2014, 2.3% in Fiscal 2013~~ and ~~2.2% in Fiscal 2012. Depreciation expense as a percentage of the related average depreciable base for~~ Electric Utility ~~was 2.5% in~~for Fiscal ~~2014, 2.4% in Fiscal 2013~~2017, 2016 and ~~2.4% in Fiscal 2012.~~ 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.~~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.

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.

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. ~~In accordance with GAAP, a~~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 and the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of~~value. From time to time, we may assess qualitative factors to determine whether it is more likely than not that ~~goodwill. We determine~~ the fair value of ~~our Gas Utility~~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 ~~value is~~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 ~~the~~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 ~~unit.~~units. The market approach requires judgment to determine the appropriate valuation ~~multiple. Under certain circumstances, the Company may perform a qualitative approach to determine if it is more likely than not that~~multiples. If the carrying ~~value~~amount of a reporting unit ~~is greater than~~exceeds its fair ~~value.~~ 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 ~~2014,~~2017, Fiscal ~~2013~~2016 or Fiscal ~~2012.~~2015.

Impairment of Long-Lived Assets

We evaluate ~~the impairment of~~ 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 ~~2014,~~2017, Fiscal ~~2013~~2016 or Fiscal ~~2012.~~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.

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except ~~per share amounts)~~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 be 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, is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. CPG and PNG ~~are currently receiving regulatory recovery~~receive ratemaking recognition of ~~estimated~~ environmental investigation and remediation costs associated with ~~Pennsylvania~~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 ~~Standards~~Standard

~~Disclosures about Offsetting Assets and Liabilities.~~Employee Share-based Payments. Effective October 1, ~~2013,~~2016, the Company adopted new accounting guidance ~~requiring~~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

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

~~Discontinued Operations.~~ ~~In April 2014, the FASB issued authoritative guidance amending existing requirements for reporting discontinued operations. Under~~ the new guidance, ~~discontinued operations reporting~~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 ~~be limited~~have a material impact on its consolidated financial statements. The Company continues to ~~disposal transactions~~monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue.

4. REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS

The ~~amended guidance also enhances disclosures and requires~~following regulatory assets and liabilities ~~of a discontinued operation to be classified as such for all periods presented~~are included in the financial statements. Public entities will apply the amended guidance prospectively to all disposals occurring within annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company will adopt this standard on October 1, 2015. Due to the change in requirements for reporting discontinued operations described above, presentation and disclosure of future disposal transactions after adoption may be different than under current standards.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

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except ~~per share amounts)~~where indicated otherwise)

~~4. REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS~~

~~The following~~Other than removal costs, UGI Utilities currently does not recover a rate of return on the regulatory assets ~~and liabilities associated with Utilities are~~ included in ~~our accompanying Consolidated Balance Sheets at September 30:~~the table above.

2014 2013
Regulatory assets:
Income taxes recoverable $ 110,709
$ 106,069
Underfunded pension and postretirement plans 110,116
94,515
Environmental costs 14,616
17,054
Deferred fuel and power costs 11,732
8,283
Removal costs, net 16,790
13,333
Other 4,203
5,657
Total regulatory assets $ 268,166
$ 244,911
Regulatory liabilities:
Postretirement benefits $ 18,594
$ 16,497
Environmental overcollections 349
2,552
Deferred fuel and power refunds 306
8,283
State tax benefits — distribution system repairs 10,076
8,453
Other 3,172
1,502
Total regulatory liabilities (a) $ 32,497
$ 37,287


~~(a)~~	~~Regulatory liabilities are recorded in other current and noncurrent liabilities in the Consolidated Balance Sheets.~~

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 ~~prior service cost and~~ 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 ~~amounts actually spent by UGI Gas to clean up sites in Pennsylvania as well as the portion of~~ estimated probable future environmental remediation and investigation costs ~~principally at manufactured gas plant (“MGP”) sites~~ 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 ~~(see Note 12)~~(“DEP”). ~~Consistent with prior ratemaking treatment,~~Pursuant to base rate orders, UGI Gas, anticipates it will recover in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites and UGI Gas is currently amortizing such costs over a five-year period. PNG and CPG ~~are currently recovering~~receive ratemaking recognition of estimated environmental investigation and ~~expect to continue to recover~~remediation costs associated with their environmental ~~remediation~~sites. This ratemaking recognition balances the accumulated difference between historical costs and ~~investigation~~rate recoveries with an estimate of future costs ~~in base rate revenues.~~associated with the sites. At September 30, ~~2014,~~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 ~~— costs and~~ refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses ~~which~~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.

~~F- 13~~

~~UGI UTILITIES, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Thousands of dollars, except per share amounts)~~

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 ~~losses~~gains on such contracts at September 30, ~~2014~~2017 and ~~2013,~~2016, were ~~$(1,363)~~$146 and ~~$(1,743),~~$4,263, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because most of these contracts do not qualify for the normal purchases and normal sales exception under GAAP related to derivative instruments, these electricity supply contracts are recognized on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities. At September 30, 2014 and 2013, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $345 and $(4,759), respectively. These amounts are reflected in current derivative assets and current derivative liabilities on the Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above.

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, ~~2014~~2017 and ~~2013,~~2016, were not material.

~~Removal costs, net.~~ ~~This regulatory asset represents costs incurred, net~~

F- 15

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of ~~salvage, associated with the retirement of depreciable utility plant. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over~~ ~~5 years~~.dollars, except where indicated otherwise)

~~Postretirement benefits~~. Gas Utility and Electric Utility are recovering ongoing postretirement benefit costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI Gas and Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above. In addition, this regulatory liability includes the portion of prior service credits and net actuarial gains associated with certain other postretirement benefit plans.

~~Environmental overcollections.~~ This regulatory liability represents the difference between amounts recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms of a consent order agreement between CPG and the Pennsylvania Department of Environmental Protection (“DEP”) to remediate certain gas plant sites.

State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal ~~income tax expense,~~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, ~~deferred postretirement~~a portion of preliminary stage information technology costs, ~~deferred asset retirement~~energy efficiency conservation costs ~~deferred~~and rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2014, UGI Utilities expects to recover these costs over periods of approximately 1 to 20 years.expenses.

UGI Utilities’ regulatory liabilities relating to postretirement benefits, environmental overcollections and state tax benefits — distribution system repairs are included in other noncurrent liabilities on the Consolidated Balance Sheets. UGI Utilities does not recover a rate of return on its regulatory assets.

Other Regulatory Matters

~~Transfers of Assets~~.Base Rate Filings. On ~~February 1, 2012, CPG~~January 19, 2017, PNG filed ~~an application~~a rate request with the PUC to increase PNG’s annual base operating revenues for ~~review~~residential, commercial and ~~approval of the transfer of an 11-mile~~industrial customers by $21,700 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas ~~pipeline, related facilities and rights~~service. On June 30, 2017, all active parties supported the filing of ~~way located in Delmar Township, Pennsylvania (“TL-96 line”) to Energy Services, LLC (which is formerly known as UGI Energy Services, Inc. prior to its merger~~a Joint Petition for Approval of Settlement of all issues with ~~and into UGI Energy Services, LLC effective October 1, 2013), a second-tier wholly owned subsidiary of UGI (“Energy Services”). The~~the PUC providing for an $11,250 PNG annual base distribution rate increase. On August 31, 2017, the PUC approved the ~~transfer~~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 ~~2013,~~1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the ~~TL-96 line was dividended~~maximum allowable DSIC from 5% to ~~UGI and subsequently contributed~~10% of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to ~~Energy Services. The net book value~~approve an increase of the ~~TL-96 line was approximately $2,650 which~~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 ~~net~~ of ~~related deferred income taxes~~DSIC-eligible plant placed into service in excess of ~~$384, is reflected as a dividend~~the threshold amount of ~~net assets~~DSIC-eligible plant agreed upon in the settlement of its recent base rate case.

Preliminary Stage Information Technology Costs. During Fiscal ~~2013 Consolidated Statement~~2016, we determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of ~~Stockholder’s Equity.~~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- 1416

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except ~~per share amounts)~~where indicated otherwise)

5. INVENTORIES

Inventories comprise the following at September 30:


	2014		2013		2017		2016
Gas Utility natural gas	$	82,664	$	78,950	$	39,486	$	29,223
Materials, supplies and other	12,555		10,711		13,823		13,117
Total inventories	$	95,219	$	89,661	$	53,309	$	42,340

At September 30, ~~2014,~~2017, UGI Utilities iswas a party to ~~four~~five principal storage contract administrative agreements (“SCAAs”) having terms ofranging from one ~~and~~to three years. ~~Three~~Four of the SCAAs ~~are~~were with UGI Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 18), and one of the SCAAs iswas 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)~~replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

The carrying ~~value~~values of gas storage inventories released under the SCAAs at September 30, ~~2014~~2017 and ~~2013,~~2016, comprising ~~11.6~~9.1 billion cubic feet (“bcf”) and ~~11.0~~8.1 bcf of natural gas, were ~~$49,897~~$26,064 and ~~$44,366,~~$18,773, respectively. At September 30, ~~2014~~2017 and ~~2013,~~2016, UGI Utilities held a total of ~~$17,600~~$15,040 and ~~$16,500,~~$19,100, respectively, of security deposits received from its SCAA counterparties. These amounts are included in ~~other~~“Other current ~~liabilities~~liabilities” on the Consolidated Balance Sheets. ~~Effective November 1, 2014, UGI Utilities entered into a new SCAA with Energy Services having a term of one year.~~

For additional information related to the SCAAs with Energy Services, see Note ~~17.~~18.

6. PROPERTY, PLANT AND EQUIPMENT

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

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except ~~per share amounts)~~where indicated otherwise)

Long-term debt comprises the following at September 30:

Principal payments on long-term debt during the next five fiscal years is as follows: $~~20,000~~$40,000 is due in Fiscal ~~2015; $247,000~~ ~~is due in Fiscal~~ ~~2016; $20,000~~ ~~is due in Fiscal~~ ~~2017; $40,000~~ ~~is due in Fiscal~~ ~~2018; and $~~02018; $0 is due in Fiscal 2019. through Fiscal 2022.

~~In March 2014,~~Pursuant to a note purchase agreement, in October 2016, UGI Utilities issued ~~in a private placement $175,000~~$100,000 aggregate principal amount of ~~4.98%~~4.12% Senior Notes due ~~March 2044 (“4.98%~~October 2046 (the “4.12% Senior Notes”). The ~~4.98%~~net proceeds of the issuance of the 4.12% Senior Notes were ~~issued pursuant~~used (1) to ~~a Note Purchase Agreement dated October 30, 2013, between~~provide additional financing for UGI ~~Utilities~~Utilities’ infrastructure replacement and ~~certain note purchasers.~~betterment capital program and information technology initiatives and (2) for general corporate purposes. The ~~4.98%~~4.12% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. ~~The net proceeds~~

UGI Utilities has an unsecured credit agreement (the “Credit Agreement”) with a group of banks providing for borrowings of up to $300,000 (including a $100,000 sublimit for letters of credit) which expires in ~~October 2015.~~March 2020. Under the Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to ~~2.0%~~1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. UGI Utilities had borrowings outstanding under the ~~Credit Agreement,~~credit agreements, which we classify as ~~short-term borrowings~~“Short-term borrowings” on the Consolidated Balance Sheets, totaling ~~$86,300~~$170,000 and ~~$17,500~~$112,500 at September 30, ~~2014~~2017 and ~~2013,~~2016, respectively. The weighted-average interest rates on the ~~Credit Agreement~~credit agreement borrowings at September 30, ~~2014~~2017 and ~~2013~~2016 were ~~1.03%~~2.11% and ~~1.18%~~1.42%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the ~~Credit Agreement,~~credit agreements, totaled ~~$2,000~~$2,009 and $2,009 at September 30, ~~2014~~2017 and ~~2013.~~2016, respectively.

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

~~UGI UTILITIES, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Thousands of dollars, except per share amounts)~~

The provisions for income taxes consist of the following:

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

Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal ~~2014~~2017, Fiscal ~~2013~~2016 and Fiscal ~~2012,~~2015, the beneficial effects of state tax flow through of accelerated depreciation reduced tax expense by $~~1,976~~2,537, $~~1,538~~1,344 and $~~3,198~~1,539, respectively. The higher state tax flow through amount in Fiscal 2012 reflects the impact of 2010 U.S. Federal tax legislation that allowed taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of calendar 2011, when such property is placed in service before 2012. This legislation was also permitted for Pennsylvania state corporate income tax purposes.

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except ~~per share amounts)~~where indicated otherwise)

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

We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. UGI’s federal income tax returns are settled through the tax year ~~2010.~~2013.

We file separate company income tax returns in ~~a number of~~various other states but are subject to state income tax principally in Pennsylvania. Pennsylvania income tax returns are generally subject to examination for a period of three years after the filing of the respective returns. ~~As of September 30, 2014, we have $1,723 of Pennsylvania net operating loss carryforwards that expire through 2029.~~

During Fiscal ~~2014~~2017, Fiscal ~~2013~~2016 and Fiscal ~~2012,~~2015, interest (income) expense of $38(73), $0204 and $~~(209)~~0, respectively, was recognized in income taxes in the Consolidated Statements of Income.

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

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

2014 2013 2012
Unrecognized tax benefits - beginning of year $ 1,087
$ 1,048
$ 4,898
Additions for tax positions of prior years —
39
81
Settlements with tax authorities (1,087 ) —
(3,931 )
Unrecognized tax benefits - end of year $ —
$ 1,087
$ 1,048



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

~~In accordance with accounting guidance regarding uncertain tax positions, during Fiscal~~ ~~2013, the Company added~~ ~~$39~~ to its liability for unrecognized tax benefits including interest related to its change in method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets. For further information regarding the regulatory impact of this change, see Note 4.

9. EMPLOYEE RETIREMENT PLANS

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

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except where indicated otherwise)

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

~~UGI UTILITIES, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Thousands of dollars, except per share amounts)~~



	Page

Forward-Looking Information	3

PART I:

Items 1. and 2. Business and Properties	4

Item 1A. Risk Factors	910

Item 1B. Unresolved Staff Comments	1113

Item 3. Legal Proceedings	1113

Item 4. Mine Safety Disclosures	1113

PART II:

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	1213

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	1213

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	2225

Item 8. Financial Statements and Supplementary Data	2225

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	2225

Item 9A. Controls and Procedures	2225

Item 9B. Other Information	2326

PART III:

Item 14. Principal Accounting Fees and Services	2326

PART IV:

Item 15. Exhibits and Financial Statement Schedules	2427

Item 16. Form 10-K Summary	31

Signatures	2933

Index to Financial Statements and Financial Statement Schedules	F- 1


	2014		2013		2017		2016
Audit Fees(1)	$	1,070,189	$	851,600	$	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	$	1,070,189	$	851,600	$	1,534,396	$	1,313,781


	Year Ended September 30,									Year Ended September 30,
	2014			2013			2012			2017			2016		2015
Revenues	$	1,086,889		$	940,712		$	884,333		$	887,588		$	768,484	$	1,041,581
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	562,942			465,996			459,079			367,279			289,786		510,784
Operating and administrative expenses	195,408			188,266			165,479			199,997			180,842		206,319
Operating and administrative expenses — related parties	10,671			8,366			9,326			12,354			11,863		11,956
Taxes other than income taxes	16,608			16,877			17,263			15,648			15,789		16,134
Depreciation	55,776			52,298			49,702			69,778			64,260		59,841
Amortization	3,443			3,418			3,090			2,554			3,043		3,749
Other income, net	(4,359		)	(4,828		)	(4,989		)
Other operating (income) expense, net										(8,329		)	2,000		(8,869		)
	840,489			730,393			698,950			659,281			567,583		799,914
Operating income	246,400			210,319			185,383			228,307			200,901		241,667
Interest expense	38,471			39,309			42,412			40,212			37,630		41,128
Income before income taxes	207,929			171,010			142,971			188,095			163,271		200,539
Income taxes	83,823			68,912			55,073			72,054			65,898		79,484
Net income	$	124,106		$	102,098		$	87,898		$	116,041		$	97,373	$	121,055


	Year Ended September 30,									Year Ended September 30,
	2014			2013			2012			2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	124,106		$	102,098		$	87,898		$	116,041		$	97,373		$	121,055
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	59,219			55,716			52,792			72,332			67,303			63,590
Deferred income taxes, net	33,588			35,281			53,247			78,568			76,938			29,356
Pension contributions, net of pension expense	(9,459		)	(4,450		)	(17,431		)
Pension contributions, net of pension cost										4,017			1,580			(1,415		)
Settlement of interest rate protection agreements										—			(35,975		)	—
Provision for uncollectible accounts	13,149			9,584			6,286			8,030			7,760			13,498
Other, net	3,998			(1,560		)	2,490			9,664			(10,112		)	3,228
Net change in:
Accounts receivable and accrued utility revenues	(19,718		)	(16,446		)	5,461			(25,253		)	1,120			7,297
Inventories	(5,558		)	(22,327		)	36,929			(10,969		)	9,376			43,503
Deferred fuel costs, net of changes in unsettled derivatives	(17,632		)	9,321			(8,190		)	(15,385		)	(22,740		)	51,778
Accounts payable	5,757			7,511			(6,718		)	2,107			(3,053		)	(7,649		)
Other current assets	362			13,598			(5,063		)	(2,108		)	(70		)	(9,723		)
Other current liabilities	864			(18,413		)	2,041			6,550			15,870			(7,808		)
Net cash provided by operating activities	188,676			169,913			209,742			243,594			205,370			306,710
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(164,180		)	(151,090		)	(114,090		)	(305,311		)	(250,584		)	(203,192		)
Net costs of property, plant and equipment disposals	(8,214		)	(4,925		)	(4,922		)	(12,735		)	(7,940		)	(10,443		)
(Increase) decrease in restricted cash	(411		)	(3,181		)	4,308			(2,463		)	6,019			(3,010		)
Net cash used by investing activities	(172,805		)	(159,196		)	(114,704		)	(320,509		)	(252,505		)	(216,645		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(77,395		)	(58,975		)	(70,615		)	(57,700		)	(47,000		)	(65,600		)
Increase in short-term borrowings	68,800			8,300			9,200
Issuances of long-term debt	174,445			175,000			—
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	(175,000		)	(133,000		)	(40,000		)	(20,000		)	(247,000		)	(20,000		)
Excess tax benefits from equity-based payment arrangements	973			1,406			369			—			1,676			833
Net cash used by financing activities	(8,177		)	(7,269		)	(101,046		)
Net cash provided (used) by financing activities										79,299			46,855			(99,367		)
Cash and cash equivalents increase (decrease)	$	7,694		$	3,448		$	(6,008	)	$	2,384		$	(280	)	$	(9,302	)
CASH AND CASH EQUIVALENTS:
End of year	$	12,401		$	4,707		$	1,259		$	5,203		$	2,819		$	3,099
Beginning of year	4,707			1,259			7,267			2,819			3,099			12,401
Increase (decrease)	$	7,694		$	3,448		$	(6,008	)	$	2,384		$	(280	)	$	(9,302	)
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for:
Cash paid (received) for:
Interest	$	34,781		$	49,460		$	29,902		$	29,449		$	36,155		$	38,405
Income taxes	$	54,293		$	18,376		$	6,728		$	2,080		$	(19,758	)	$	54,427


	2014		2013		2017		2016
Distribution	$	2,294,590	$	2,162,580	$	2,835,339	$	2,634,191
Transmission	88,199		86,623		96,430		93,454
General and other, including construction in process	185,763		178,607
Construction in process					112,563		103,929
General and other					240,997		167,341
Total property, plant and equipment	$	2,568,552	$	2,427,810	$	3,285,329	$	2,998,915



	Postretirement Benefit Plans			Derivative Instruments Net Losses			Total
September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
Reclassification of benefit plan actuarial losses and prior service cost	385			—			385
Reclassifications of net losses on IRPAs	—			1,567			1,567
Benefit plans, principally actuarial gains and losses	(1,413		)	—			(1,413		)
September 30, 2014	$	(6,311	)	$	(1,870	)	$	(8,181	)


(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.


	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013			2017			2016			2017			2016
Change in benefit obligations:
Benefit obligations — beginning of year	$	486,468		$	543,605		$	10,688		$	14,560		$	645,444		$	563,621		$	12,075		$	10,676
Service cost	7,309			9,385			175			223			9,038			7,772			303			198
Interest cost	25,102			22,784			519			587			24,394			25,733			460			483
Actuarial loss (gain)	43,064			(69,112		)	205			(1,881		)
Plan amendments	—			993			—			(1,836		)
Actuarial (gain) loss													(14,575		)	72,418			(512		)	1,117
Benefits paid	(22,218		)	(21,187		)	(451		)	(965		)	(25,056		)	(24,100		)	(422		)	(399		)
Benefit obligations — end of year	$	539,725		$	486,468		$	11,136		$	10,688		$	639,245		$	645,444		$	11,904		$	12,075
Change in plan assets:
Fair value of plan assets — beginning of year	$	398,171		$	351,543		$	11,723		$	11,205		$	463,432		$	430,789		$	13,715		$	12,523
Actual gain on assets	47,285			45,450			1,434			1,117			48,309			46,874			1,333			1,347
Employer contributions	19,227			22,365			142			366			11,395			9,869			85			98
Benefits paid	(22,218		)	(21,187		)	(451		)	(965		)	(25,056		)	(24,100		)	(362		)	(253		)
Fair value of plan assets — end of year	$	442,465		$	398,171		$	12,848		$	11,723		$	498,080		$	463,432		$	14,771		$	13,715
Funded status of the plans — end of year	$	(97,260	)	$	(88,297	)	$	1,712		$	1,035		$	(141,165	)	$	(182,012	)	$	2,867		$	1,640
(Liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	$	—		$	—		$	3,971		$	3,252
Unfunded liabilities — included in other current liabilities	(1,100		)	(17,885		)	(159		)	(372		)
Unfunded liabilities — included in other noncurrent liabilities	(96,160		)	(70,412		)	(2,100		)	(1,845		)
Assets (liabilities) recorded in the balance sheet:
Assets in excess of liabilities – included in other noncurrent assets													$	—		$	—		$	5,382		$	4,139
Unfunded liabilities – included in other noncurrent liabilities													(141,165		)	(182,012		)	(2,514		)	(2,499		)
Net amount recognized	$	(97,260	)	$	(88,297	)	$	1,712		$	1,035		$	(141,165	)	$	(182,012	)	$	2,868		$	1,640
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	$	189		$	222		$	(61	)	$	(74	)	$	105		$	138		$	(23	)	$	(35	)
Net actuarial loss (gain)	10,662			9,113			(46		)	(222		)	15,106			19,866			(46		)	(1		)
Total	$	10,851		$	9,335		$	(107	)	$	(296	)	$	15,211		$	20,004		$	(69	)	$	(36	)
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	$	1,908		$	2,223		$	(3,625	)	$	(4,286	)	$	970		$	1,262		$	(1,605	)	$	(2,247	)
Net actuarial loss	107,363			91,275			2,616			3,586			139,505			180,964			1,192			2,425
Total	$	109,271		$	93,498		$	(1,009	)	$	(700	)	$	140,475		$	182,226		$	(413	)	$	178


	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
Weighted-average assumptions:	2014		2013		2012		2014		2013		2012		2017		2016		2015		2017		2016		2015
Discount rate - benefit obligations	4.60	%	5.20	%	4.20	%	4.60	%	5.10% - 5.40%		4.10% - 4.30%
Discount rate - benefit cost	5.20	%	4.20	%	5.30	%	5.10% - 5.40%		4.10% - 4.30%		5.30	%
Discount rate – benefit obligations													4.00	%	3.80	%	4.60	%	4.00	%	3.80	%	4.70	%
Discount rate – benefit cost													3.80	%	4.60	%	4.60	%	3.80	%	4.70	%	4.60	%
Expected return on plan assets	7.75	%	7.75	%	7.75	%	5.00	%	5.00	%	5.20	%	7.50	%	7.55	%	7.75	%	5.00	%	5.00	%	5.00	%
Rate of increase in salary levels	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%



	Pension Benefits		Other Postretirement Benefits
Fiscal 2015	$	24,295	$	753
Fiscal 2016	25,425		710
Fiscal 2017	26,692		644
Fiscal 2018	28,051		615
Fiscal 2019	29,298		604
Fiscal 2020 - 2024	164,102		2,875


					Target
	Actual				Asset		Permitted	Actual				Target Asset	Permitted
Pension Plan:	2014		2013		Allocation		Range	2017		2016		Allocation	Range
Equity investments:
Domestic	55.6	%	57.5	%	52.5	%	40.0% - 65.0%	55.2	%	54.1	%	52.5%	40.0% – 65.0%
International	11.3	%	11.1	%	12.5	%	7.5% - 17.5%	12.4	%	10.2	%	12.5%	7.5% – 17.5%
Total	66.9	%	68.6	%	65.0	%	60.0% - 70.0%	67.6	%	64.3	%	65.0%	60.0% – 70.0%
Fixed income funds & cash equivalents	33.1	%	31.4	%	35.0	%	30.0% - 40.0%	32.4	%	35.7	%	35.0%	30.0% – 40.0%
Total	100.0	%	100.0	%	100.0	%		100.0	%	100.0	%	100.0%


	Pension Plan								Pension Plan
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Other^(a)		Total
September 30, 2014:
September 30, 2017:
Domestic equity investments:
S&P 500 Index equity mutual funds									$	171,600	$	—	$	—	$	—	$	171,600
Small and midcap equity mutual funds									65,167		—		—		—		65,167
UGI Corporation Common Stock									38,137		—		—		—		38,137
Total domestic equity investments									274,904		—		—		—		274,904
International index equity mutual funds									61,613		—		—		—		61,613
Fixed income investments:
Bond index mutual funds									156,228		—		—		—		156,228
Cash equivalents									—		—		—		5,332		5,332
Total fixed income investments									156,228		—		—		5,332		161,560
Total									$	492,745	$	—	$	—	$	5,332	$	498,077
September 30, 2016:
Equity investments:
S&P 500 Index equity mutual funds	$	152,613	$	—	$	—	$	152,613	$	158,906	$	—	$	—	$	—	$	158,906
Small and midcap equity mutual funds	41,417		—		—		41,417		43,170		—		—		—		43,170
Smallcap common stocks	9,325		—		—		9,325		11,414		—		—		—		11,414
UGI Corporation Common Stock	42,502		—		—		42,502		37,013		—		—		—		37,013
Total domestic equity investments	245,857		—		—		245,857		250,503		—		—		—		250,503
International index equity mutual funds	49,935		—		—		49,935		47,324		—		—		—		47,324
Fixed income investments:
Bond index mutual funds	140,949		—		—		140,949		147,794		—		—		—		147,794
Cash equivalents	—		5,724		—		5,724		—		—		—		17,811		17,811
Total fixed income investments	140,949		5,724		—		146,673		147,794		—		—		17,811		165,605
Total	$	436,741	$	5,724	$	—	$	442,465	$	445,621	$	—	$	—	$	17,811	$	463,432
September 30, 2013:
Equity investments:
S&P 500 Index equity mutual funds	$	141,774	$	—	$	—	$	141,774
Small and midcap equity mutual funds	54,528		—		—		54,528
UGI Corporation Common Stock	32,551		—		—		32,551
Total domestic equity investments	228,853		—		—		228,853
International index equity mutual funds	44,452		—		—		44,452
Fixed income investments:
Bond index mutual funds	120,906		—		—		120,906
Cash equivalents	—		3,960		—		3,960
Total fixed income investments	120,906		3,960		—		124,866
Total	$	394,211	$	3,960	$	—	$	398,171


	VEBA								VEBA
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Other^(a)		Total
September 30, 2014:
September 30, 2017:
S&P 500 Index equity mutual fund	$	8,719	$	—	$	—	$	8,719	$	9,318	$	—	$	—	$	—	$	9,318
Bond index mutual fund	3,727		—		—		3,727		5,044		—		—		—		5,044
Cash equivalents	—		402		—		402		—		—		—		409		409
Total	$	12,446	$	402	$	—	$	12,848	$	14,362	$	—	$	—	$	409	$	14,771
September 30, 2013:
September 30, 2016:
S&P 500 Index equity mutual fund	$	7,693	$	—	$	—	$	7,693	$	9,583	$	—	$	—	$	—	$	9,583
Bond index mutual fund	3,794		—		—		3,794		4,019		—		—		—		4,019
Cash equivalents	—		236		—		236		—		—		—		113		113
Total	$	11,487	$	236	$	—	$	11,723	$	13,602	$	—	$	—	$	113	$	13,715


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


	Total				Vested				Non-Vested				Total				Vested				Non-Vested
	Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)
September 30, 2013	91,997		$	22.81	30,993		$	22.33	61,004		$	23.05
September 30, 2016													57,783		$	34.66	10,316		$	34.31	47,467		$	34.74
Granted	24,975		$	32.59	2,100		$	32.59	22,875		$	32.59	16,425		$	51.42	367		$	51.42	16,058		$	51.42
Vested	—		$	—	18,053		$	23.27	(18,053	)	$	23.27	—		$	—	16,003		$	33.10	(16,003	)	$	33.10
Forfeited	(6,150	)	$	24.50	—		$	—	(6,150	)	$	24.50
Forfeitures & transfers													(1,934	)	$	34.74	—		$	—	(1,934	)	$	34.74
Unit awards paid	(26,300	)	$	23.61	(26,300	)	$	23.61	—		$	—	(20,050	)	$	32.59	(20,050	)	$	32.59	—		$	—
September 30, 2014	84,522		$	25.32	24,846		$	22.52	59,676		$	26.49
September 30, 2017													52,224		$	40.72	6,636		$	37.53	45,588		$	41.19


(3)	List of Exhibits:


~~(a)~~	On July 29, 2014, UGI's Board of Directors approved a three-for-two common stock split. The additional shares were distributed September 5, 2014 to shareholders of record on August 22, 2014. Share and per share amounts above have been retroactively adjusted to reflect the three-for-two stock split.


	Asset (Liability)											Asset (Liability)
	Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
September 30, 2014
September 30, 2017
Derivative instruments:
Assets:
Commodity contracts	$	679		$	1,018		$	—	$	1,697		$	1,735		$	72		$	—	$	1,807
Liabilities:
Commodity contracts	$	(2,095	)	$	(206	)	$	—	$	(2,301	)	$	(1,447	)	$	(73	)	$	—	$	(1,520	)
September 30, 2013 (a)
September 30, 2016
Derivative instruments:
Assets:
Commodity contracts	$	92		$	—		$	—	$	92		$	4,506		$	4		$	—	$	4,510
Liabilities:
Commodity contracts	$	(2,211	)	$	(4,515	)	$	—	$	(6,726	)	$	(263	)	$	(294	)	$	—	$	(557	)


~~(a)~~	~~Certain immaterial amounts have been revised to correct the classification of derivatives.~~



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


	2014			2013 (a)			2017			2016
Derivative assets:
Derivatives accounted for under ASC 980:
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$	1,697		$	80		$	1,665		$	4,472

Derivatives not designated as hedging instruments:
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	—			12			142			38
Total derivative assets - gross	1,697			92
Total derivative assets – gross							1,807			4,510
Gross amounts offset in the balance sheet	(669		)	(49		)	(450		)	(247		)
Total derivative assets - net	$	1,028		$	43
Total derivative assets – net (a)							$	1,357		$	4,263

Derivative liabilities:
Derivatives accounted for under ASC 980:
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$	(2,210	)	$	(6,726	)	$	(1,520	)	$	(499	)

Derivatives not designated as hedging instruments:
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	(91		)	—			—			(58		)
Total derivative liabilities - gross	(2,301		)	(6,726		)
Total derivative liabilities – gross							(1,520		)	(557		)
Gross amounts offset in the balance sheet	669			49			450			247
Total derivative liabilities - net	$	(1,632	)	$	(6,677	)
Total derivative liabilities – net (a)							$	(1,070	)	$	(310	)



	Gain (Loss) Recognized in AOCI							Gain (Loss) Reclassified from AOCI into Income									Location of Gain or
	2014		2013		2012			2014			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—	$	25,898	$	(11,528	)	$	(2,679	)	$	(805	)	$	(1,847	)	Interest expense

	Gain Recognized in Income																Location of Gain
	2014		2013		2012												Recognized in Income
Derivatives Not Designated
as Hedging Instruments:
Commodity contracts	$	—	$	45	$	223											Operating and administrative expenses/other income, net



	Loss Recognized in AOCI								Loss Reclassified from AOCI into Income									Location of
	2017		2016			2015			2017			2016			2015			Loss Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—	$	(28,958	)	$	(7,016	)	$	(3,397	)	$	(2,680	)	$	(2,674	)	Interest expense

	Gain (Loss) Recognized in Income																	Location of Gain (Loss)
	2017		2016			2015												Recognized in Income
Derivatives Not Subject to PGC and DS Mechanisms:
Gasoline contracts	$	174	$	(88	)	$	(761	)										Operating and administrative expenses/other operating income, net



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


	Total		Gas Utility		Electric Utility		Other		Total		Gas Utility		Electric Utility		Other
2014
2017
Revenues	$	1,086,889	$	977,333	$	108,072	$	1,484	$	887,588	$	799,054	$	88,534
Cost of sales	$	562,942	$	496,762	$	66,180	$	—	$	367,279	$	318,210	$	49,069
Depreciation and amortization	$	59,219	$	54,816	$	4,403	$	—	$	72,332	$	67,357	$	4,975
Operating income	$	246,400	$	236,219	$	9,668	$	513	$	228,307	$	219,561	$	8,746
Interest expense	38,471		36,602		1,869		—		$	40,212	$	38,218	$	1,994
Income before income taxes	$	207,929	$	199,617	$	7,799	$	513	$	188,095	$	181,343	$	6,752
Total assets	$	2,354,643	$	2,214,118	$	140,525	$	—	$	2,994,015	$	2,833,423	$	160,592
Goodwill	$	182,145	$	182,145	$	—	$	—	$	182,145	$	182,145	$	—
Capital expenditures	$	164,180	$	156,425	$	7,755	$	—
2013
Capital expenditures (including the effects of accruals)									$	317,722	$	306,243	$	11,479
2016
Revenues	$	940,712	$	839,050	$	99,986	$	1,676	$	768,484	$	677,387	$	91,097
Cost of sales	$	465,996	$	407,222	$	58,774	$	—	$	289,786	$	239,163	$	50,623
Depreciation and amortization	$	55,716	$	51,698	$	4,018	$	—	$	67,303	$	62,451	$	4,852
Operating income	$	210,319	$	198,352	$	11,385	$	582	$	200,901	$	189,412	$	11,489
Interest expense	39,309		37,280		2,029		—		$	37,630	$	35,786	$	1,844
Income before income taxes	$	171,010	$	161,072	$	9,356	$	582	$	163,271	$	153,626	$	9,645
Total assets	$	2,210,322	$	2,068,955	$	141,367	$	—	$	2,743,091	$	2,570,297	$	172,794
Goodwill	$	182,145	$	182,145	$	—	$	—	$	182,145	$	182,145	$	—
Capital expenditures	$	151,090	$	144,399	$	6,691	$	—
2012
Capital expenditures (including the effects of accruals)									$	262,503	$	251,261	$	11,242
2015
Revenues	$	884,333	$	785,375	$	97,130	$	1,828	$	1,041,581	$	933,080	$	107,577	$	924
Cost of sales	$	459,079	$	402,534	$	56,545	$	—	$	510,784	$	448,617	$	62,167	$	—
Depreciation and amortization	$	52,792	$	48,992	$	3,800	$	—	$	63,590	$	58,974	$	4,616	$	—
Operating income	$	185,383	$	172,164	$	12,610	$	609	$	241,667	$	226,485	$	14,153	$	1,029
Interest expense	42,412		40,139		2,273		—		$	41,128	$	39,112	$	2,016	$	—
Income before income taxes	$	142,971	$	132,025	$	10,337	$	609	$	200,539	$	187,373	$	12,137	$	1,029
Total assets	$	2,196,173	$	2,045,480	$	150,693	$	—	$	2,505,984	$	2,360,156	$	145,828	$	—
Goodwill	$	182,145	$	182,145	$	—	$	—	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	114,090	$	109,020	$	5,070	$	—
Capital expenditures (including the effects of accruals)									$	197,684	$	189,671	$	8,013	$	—


	December 31,				March 31,				June 30,				September 30,					December 31,				March 31,				June 30,				September 30,
	2013		2012		2014		2013		2014		2013		2014			2013		2016		2015		2017		2016		2017		2016		2017			2016
Revenues	$	298,899	$	273,797	$	513,956	$	395,901	$	152,694	$	148,798	$	121,340		$	122,216	$	261,413	$	197,982	$	359,940	$	322,047	$	146,692	$	140,283	$	119,543		$	108,172
Operating income	$	85,843	$	72,564	$	137,954	$	109,230	$	19,720	$	18,878	$	2,883		$	9,647	$	82,236	$	48,296	$	116,408	$	114,481	$	27,671	$	29,815	$	1,992		$	8,309
Net income (loss)	$	45,286	$	36,812	$	76,110	$	58,259	$	6,890	$	5,373	$	(4,180	)	$	1,654	$	44,265	$	23,351	$	65,125	$	63,294	$	10,697	$	12,603	$	(4,046	)	$	(1,875	)


	Balance at beginning of year		Charged (credited) to costs and expenses		Other				Balance at end of year		Balance at beginning of year		Charged to costs and expenses		Other				Balance at end of year
September 30, 2014
September 30, 2017
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	5,519	$	13,149	$	(11,676	)	⁽¹⁾	$	6,992	$	3,946	$	8,030	$	(7,924	)	⁽¹⁾	$	4,052

September 30, 2013
September 30, 2016
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	3,588	$	9,584	$	(7,653	)	⁽¹⁾	$	5,519	$	5,599	$	7,760	$	(9,413	)	⁽¹⁾	$	3,946

September 30, 2012
September 30, 2015
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	6,368	$	6,286	$	(9,066	)	⁽¹⁾	$	3,588	$	6,992	$	13,498	$	(14,891	)	⁽¹⁾	$	5,599


⁽¹⁾	Uncollectible accounts written off, net of recoveries



~~Exhibit No.~~		~~Description~~

~~10.16~~		~~FSS Service Agreement No. 79028 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.~~

~~10.19~~		~~SST Service Agreement No. 79133 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.~~

~~12.1~~		~~Computation of Ratio of Earnings to Fixed Charges~~

23		~~Consent of PricewaterhouseCoopers LLP~~

~~31.1~~		~~Certification by the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act~~

~~31.2~~		~~Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act~~

32		~~Certification by the Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act~~
~~101.INS~~		~~XBRL.Instance~~
~~101.SCH~~		~~XBRL Taxonomy Extension Schema~~
~~101.CAL~~		~~XBRL Taxonomy Extension Calculation Linkbase~~
~~101.DEF~~		~~XBRL Taxonomy Extension Definition Linkbase~~
~~101.LAB~~		~~XBRL Taxonomy Extension Labels Linkbase~~
~~101.PRE~~		~~XBRL Taxonomy Extension Presentation Linkbase~~