UGI UTILITIES INC (Form: 10-K, Received: 11/22/2016 17:02:47)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

________________

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2016

Commission file number 1-1398

UGI UTILITIES, INC.

(Exact name of registrant as specified in its charter)



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

P. O. Box 12677, 2525 N. 12 ^th Street, Suite 360

Reading, PA 19612

(Address of Principal Executive Offices) (Zip Code)

(610) 796-3400

(Registrant’s telephone number, including area code)

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

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

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

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer þ	Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ

At November 15, 2016 , there were 26,781,785 shares of UGI Utilities, Inc. Common Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI Corporation.

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

TABLE OF CONTENTS



	Page

Forward-Looking Information	3

PART I:

Items 1. and 2. Business and Properties	4

Item 1A. Risk Factors	10

Item 1B. Unresolved Staff Comments	13

Item 3. Legal Proceedings	13

Item 4. Mine Safety Disclosures	13

PART II:

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	13

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	24

Item 8. Financial Statements and Supplementary Data	24

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	24

Item 9A. Controls and Procedures	25

Item 9B. Other Information	25

PART III:

Item 14. Principal Accounting Fees and Services	25

PART IV:

Item 15. Exhibits and Financial Statement Schedules	26

Signatures	31

Index to Financial Statements and Financial Statement Schedules	F- 1

FORWARD-LOOKING INFORMATION

Information contained in this Annual Report on Form 10-K may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind our Risk Factors included in Item 1A herein and the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability of oil, electricity and natural gas and the capacity to transport them to market areas; (3) changes in laws and regulations, including safety, tax, consumer protection, environmental, and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability for environmental claims; (8) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor relations; (10) customer, counterparty, supplier, or vendor defaults; (11) increased uncollectible accounts expense; (12) liability for uninsured claims and for claims in excess of insurance coverage, including those for personal injury and property damage arising from explosions, terrorism, and other catastrophic events that may result from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas; (13) transmission or distribution system service interruptions; (14) political, regulatory and economic conditions in the United States; (15) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (16) changes in commodity market prices resulting in significantly higher cash collateral requirements; and (17) the interruption, disruption, failure or malfunction of our information technology systems, including due to cyber attack.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

PART I:

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

GENERAL

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

The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of UGI Utilities, UGI Penn Natural Gas, Inc. (“PNG”), and UGI Central Penn Gas, Inc. (“CPG”). Gas Utility serves over 626,000 customers in eastern and central Pennsylvania and more than five hundred customers in portions of one Maryland county. UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas”. The Electric Utility segment (“Electric Utility”) consists of the regulated electric distribution business of UGI Utilities, serving approximately 62,000 customers in northeastern Pennsylvania. Gas Utility is regulated by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to its several hundred customers in Maryland, the Maryland Public Service Commission. Electric Utility is regulated by the PUC.

UGI Utilities was incorporated in Pennsylvania in 1925. Our executive offices are located at P.O. Box 12677, 2525 N. 12th Street, Suite 360, Reading, Pennsylvania 19612, and our telephone number is (610) 796-3400. In this report, the terms “Company” and “UGI Utilities,” as well as the terms, “our,” “we,” and “its,” are sometimes used to refer to UGI Utilities, Inc. or, collectively UGI Utilities, Inc. and its consolidated subsidiaries. The terms “Fiscal 2016,” “Fiscal 2015” and “Fiscal 2014” refer to the fiscal years ended September 30, 2016, September 30, 2015 and September 30, 2014, respectively.

GAS UTILITY

Service Area; Revenue Analysis

Gas Utility provides natural gas distribution services to over 626,000 customers in certificated portions of 44 eastern and central Pennsylvania counties through its distribution system. Contemporary materials, such as plastic or coated steel, comprise approximately 89% of Gas Utility's 12,000 miles of gas mains, with bare steel pipe comprising approximately 8% and cast iron pipe comprising approximately 3% of Gas Utility's gas mains. In accordance with Gas Utility’s agreement with the PUC, Gas Utility will replace the cast iron portion of its gas mains by March of 2027 and the bare steel portion by September 2041. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock Haven, Pittston, Pottsville, and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility's service area are major production centers for basic industries such as specialty metals, aluminum, glass, and paper product manufacturing. Gas Utility also distributes natural gas to more than 500 customers in portions of one Maryland county.

System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2016 was approximately 212.4 billion cubic feet (“bcf”). System sales of gas accounted for approximately 25% of system throughput, while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for approximately 75% of system throughput.

Sources of Supply and Pipeline Capacity

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

Gas Supply Contracts

During Fiscal 2016, Gas Utility purchased approximately 64.7 bcf of natural gas for sale to 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 88% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 12% of gas purchased by Gas Utility was supplied by approximately 30 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 12 months. Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the months of November through March.

Seasonality

Because many of its customers use gas for heating purposes, Gas Utility’s sales are seasonal. For Fiscal 2016, nearly 60% of Gas Utility's sales volume was supplied, and more than 80% of Gas Utility’s operating income was earned, during the peak heating season from October through March.

Competition

Natural gas is a fuel that competes with electricity and oil and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of the equipment. Natural gas generally benefits from a competitive price advantage over oil, electricity, and propane, although the price gap between natural gas and oil narrowed in Fiscal 2016 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 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 31% 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 26% 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 42 such customers, 39 of which have transportation contracts extending beyond fiscal year 2017. The majority of these customers are served under transportation contracts having 3- to 20-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 2017. 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 2016, Gas Utility supplied transportation service to four major co-generation installations and nine electric generation facilities. Gas Utility continues to seek new residential, commercial, and industrial customers for both firm and interruptible service. In Fiscal 2016, Gas Utility connected over 2,300 new commercial and industrial customers. In the residential market sector, Gas Utility added nearly 14,000 residential heating customers during Fiscal 2016. Approximately 30% of these customers were the result of new home construction and approximately 70% of these customers converted to natural gas heating from other energy sources, mainly oil and electricity. 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 2016.

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

ELECTRIC UTILITY

Service Area; Sales Analysis

Electric Utility supplies electric service to approximately 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania through a system consisting of over 2,200 miles of transmission and distribution lines and 13 substations. For Fiscal 2016, approximately 56% of sales volume came from residential customers, 33% from commercial customers, and 11% from industrial and other customers.

Sources of Supply

Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed and approved by the PUC. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures” and Note 4 to Consolidated Financial Statements. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers. During Fiscal 2016, nine retail electric generation suppliers provided energy for customers representing approximately 25% 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 2016, Electric Utility served nearly all of the electric customers within its service territory and is the only regulated electric utility having the right, granted by the PUC or by law, to distribute electricity in its service territory. As an energy source, electricity competes with natural gas, oil, propane, and other heating fuels for residential heating purposes.

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

GAS UTILITY AND ELECTRIC UTILITY REGULATION AND RATES

Pennsylvania Public Utility Commission Jurisdiction

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

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 will result in a $27.0 million increase in annual base rate revenues. The settlement permits 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 will also be 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. The base rates of PNG and CPG were last established in 2009 and 2011, respectively.

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. The PUC has not yet ruled on these petitions.

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 not likely to occur prior to September 30, 2017.

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

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

Electric Transmission and Wholesale Power Sale Rates

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

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

Electric Utility Rates

Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with the PUC. Electric Utility’s 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, 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 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. Under these rules, default service rates for most customers are adjusted quarterly. On April 22, 2016, Electric Utility petitioned the PUC to approve a new default service plan for the period of June 1, 2017 through May 31, 2021. On November 9, 2016, the PUC approved a settlement allowing the Company’s new plan to become effective June 1, 2017.

FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers

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

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, 2016, UGI Utilities had nearly 1,600 employees.

BUSINESS SEGMENT INFORMATION

The table stating the amounts of revenues, operating income and identifiable assets attributable to UGI Utilities’ operating segments for the 2016, 2015 and 2014 fiscal years appears in Note 16 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 by insurance.

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

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

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

As a result of an incident in April 2016, one of the interstate natural gas pipelines that supplies our business experienced physical capacity constraints. In response to this event, we have developed a contingency plan for the Fiscal 2017 winter heating season to obtain additional supply and impose mandatory demand reduction plans to maximize gas system reliability, if needed.

Remediation costs resulting from liability from contamination claims could reduce our net income.

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


•	the discovery of presently unknown conditions;


•	changes in environmental laws and regulations;


•	judicial rejection of our legal defenses to 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.

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

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

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

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

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

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

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

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

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

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

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

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

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

There continues to be concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global warming. In addition to carbon dioxide, greenhouse gases include, among others, methane, a component of natural gas. While 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 the reduction of GHG emissions

in the United States. Although Congress has not enacted federal climate change legislation, the Environmental Protection Agency (“EPA”) has begun adopting and implementing regulations to restrict emissions of GHGs from motor vehicles and certain large stationary sources, and to require reporting of GHG emissions 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. 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, which include facilities of our natural gas distribution business, were required to begin emissions monitoring in 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 August 2015, the EPA finalized the Clean Power Plan rule, which provides standards and guidelines for reducing existing power plants’ GHG emissions and related pollutants by 2030. Under the Clean Power Plan’s standards and guidelines, existing power plants will be required to reduce emissions through a rate-based or a mass-based approach; states began submitting their reduction plans to the EPA in September 2016. The impact of such legislation and regulations will depend on a number of factors, including (i) what industry sectors would be impacted, (ii) the timing of required compliance, (iii) the overall GHG emissions cap level, (iv) the allocation of emission allowances to specific sources and (v) the costs and opportunities associated with compliance. 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.

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 $47.0 million in Fiscal 2016, $65.6 million in Fiscal 2015, and $77.4 million in Fiscal 2014.

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

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

EXECUTIVE OVERVIEW

During Fiscal 2016, temperatures based upon heating degree days in our UGI Utilities Gas Utility and Electric Utility businesses were significantly warmer than normal and the prior year. During the second quarter of Fiscal 2016, which is typically our highest earnings quarter, temperatures in our Pennsylvania-based Gas Utility were nearly 24% warmer than the prior year, and temperatures in the critical heating-season month of December were 37% warmer than normal. As a result, Gas Utility core market volumes and margin were significantly below our expectations and below the prior fiscal year.

Our results in Fiscal 2016 reflect temperatures based upon heating degree days in our Gas Utility service territory that were 13.6% warmer than normal and 17.8% warmer than in Fiscal 2015. Our net income in Fiscal 2016 was $ 97.4 million, a decrease of $23.7 million ( 19.6% ) from Fiscal 2015 net income of $ 121.1 million. Lower results in Fiscal 2016 at our Gas Utility principally reflect the significantly warmer weather on our core market margin. Our Electric Utility’s kilowatt-hour sales in Fiscal 2016 were also lower than the prior year reflecting lower heating-related sales from the warmer heating-season weather. The effects of the warmer weather and lower transmission revenue reduced Electric Utility total margin. The lower UGI Utilities total margin was partially offset by lower Fiscal 2016 operating and administrative expenses.

Notwithstanding the strong earnings headwinds brought on by the warm weather, during Fiscal 2016 we made significant strategic and operational progress in support of our long-term goals. Our Gas Utility business continues to grow despite declines in oil prices during Fiscal 2016 which had the effect of lowering our expected oil to natural gas conversion activity. In addition to growing the number of customers, our Gas Utility executed on its infrastructure replacement and system betterment program with record capital expenditures. In January 2016, UGI Gas filed for its first base rate increase in over 21 years which culminated in a $27 million increase in annual base rate revenues. This increase went into effect in October 2016 and we will see the benefit of this rate increase in Fiscal 2017.

During Fiscal 2016, we completed two long-term debt issuances totaling $300 million and an additional issuance of $100 million in October 2016 after the end of the 2016 fiscal year. The proceeds were used to refinance maturing debt and to provide additional financing for our infrastructure replacement and betterment capital program and our information technology initiatives. These transactions reduced the overall cost of our long-term debt. We believe that we have sufficient liquidity in the forms of cash generated from operations and our revolving credit facility to fund business operations in Fiscal 2017.

ANALYSIS OF RESULTS OF OPERATIONS

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

Fiscal 2016 Compared with Fiscal 2015




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

bcf — billions of cubic feet.

gwh — millions of kilowatt-hours.

(a)

Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and Electric Utility gross receipts taxes, of $4.8 million and $5.6 million during Fiscal 2016 and Fiscal 2015 , respectively. Gross receipt taxes are included in taxes other than income taxes on the Consolidated Statements of Income.


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


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

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

UGI Utilities revenues decreased $273.1 million principally reflecting a $255.7 million decrease in Gas Utility revenues and a $16.5 million decrease in Electric Utility revenues. The lower Gas Utility revenues principally reflect a decrease in core market revenues ($203.1 million) and lower off-system sales revenues ($51.4 million). The $203.1 million decrease in Fiscal 2016 Gas Utility core market revenues reflects the effects of the lower core market throughput ($135.4 million) and lower average PGC rates ($67.7 million). The lower Electric Utility revenues principally resulted from lower DS rates ($8.0 million), lower sales

volumes ($5.4 million) and lower transmission revenue ($2.6 million). Because Gas Utility and Electric Utility are subject to reconcilable PGC and DS recovery mechanisms, increases or decreases in the actual cost of gas or electricity associated with customers who purchase their gas or electricity from UGI Utilities impact revenues and cost of sales but have no direct effect on retail core-market margin (see Note 4 to Consolidated Financial Statements for a discussion of these recovery mechanisms). UGI Utilities cost of sales was $289.8 million in Fiscal 2016 compared with $510.8 million in Fiscal 2015 principally reflecting the combined effects of the lower average Gas Utility PGC rates ($92.3 million), lower cost of sales associated with Gas Utility off-system sales ($51.4 million) and lower Gas Utility retail core-market volumes sold ($67.5 million). Electric Utility cost of sales was $11.5 million lower reflecting lower DS rates ($8.5 million) and the lower volumes sold.

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

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

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

Fiscal 2015 Compared with Fiscal 2014



							Increase
(Millions of dollars)	2015 (c)			2014 (c)			(Decrease)
Gas Utility:
Revenues	$	933.1		$	977.3		$	(44.2	)	(4.5	)%
Total margin (a)	$	484.5		$	480.6		$	3.9		0.8	%
Operating and administrative expenses	$	196.9		$	183.8		$	13.1		7.1	%
Operating income	$	226.5		$	236.2		$	(9.7	)	(4.1	)%
Income before income taxes	$	187.4		$	199.6		$	(12.2	)	(6.1	)%
System throughput — bcf
Core market	81.3			80.4			0.9			1.1	%
Total	213.5			208.8			4.7			2.3	%
Degree days — % colder than normal (b)	6.4		%	10.5		%	—			—
Electric Utility:
Revenues	$	107.6		$	108.1		$	(0.5	)	(0.5	)%
Total margin (a)	$	39.8		$	36.0		$	3.8		10.6	%
Operating and administrative expenses	$	20.4		$	21.3		$	(0.9	)	(4.2	)%
Operating income	$	14.2		$	9.7		$	4.5		46.4	%
Income before income taxes	$	12.1		$	7.8		$	4.3		55.1	%
Distribution sales — gwh	1,010.1			987.3			22.8			2.3	%


(a)	Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and Electric Utility gross receipts taxes, of $5.6 million and $5.8 million during Fiscal 2015 and Fiscal 2014, respectively. Gross receipt taxes are included in taxes other than income taxes on the Consolidated Statements of Income.


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


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

Temperatures in Gas Utility’s service territory in Fiscal 2015 based upon heating degree days were 6.4% colder than normal but 3.7% warmer than in Fiscal 2014. Total Gas Utility distribution system throughput increased 4.7 bcf, notwithstanding the warmer weather, principally reflecting higher large firm delivery service volumes and slightly higher core market volumes reflecting, in large part, a 1.9% year-over-year increase in the number of core market customers. Electric Utility kilowatt-hour sales were 2.3% higher than in the prior year as lower heating-related sales were more than offset by the effects of a warmer Fiscal 2015 summer on air-conditioning sales.

UGI Utilities revenues decreased $45.3 million principally reflecting a $44.2 million decrease in Gas Utility revenues. The decrease in Gas Utility revenues principally reflects lower revenues from off-system sales ($31.8 million) and lower revenues from core market customers ($7.6 million). The decrease in core market revenues principally reflects the effects of lower average PGC rates during Fiscal 2015 partially offset by the slightly higher core market throughput. UGI Utilities’ cost of sales was $510.8 million in Fiscal 2015 compared with $562.9 million in Fiscal 2014 principally reflecting the effects of the lower off-system sales ($31.8 million) and the effects on retail core-market cost of sales of the lower average PGC rates partially offset by slightly higher core market throughput on Gas Utility cost of sales. Electric Utility cost of sales decreased $4.0 million in Fiscal 2015 principally reflecting the effects of lower average DS rates.

UGI Utilities Fiscal 2015 total margin increased $7.0 million principally reflecting higher Gas Utility core market total margin ($4.0 million) on the higher core market sales and higher large firm delivery service total margin ($5.7 million). These increases were partially offset principally by lower margin from Gas Utility interruptible customers ($7.0 million). Electric Utility total margin increased $3.8 million principally reflecting an increase in transmission revenue.

UGI Utilities operating income and income before income taxes during Fiscal 2015 decreased $4.7 million and $7.4 million, respectively. A $9.7 million decrease in Gas Utility operating income, notwithstanding a $3.9 million increase in Gas Utility total margin, principally reflects higher operating and administrative expenses and higher depreciation expense partially offset by an increase in other operating income. Gas Utility Fiscal 2015 operating and administrative expenses were higher than in Fiscal 2014 principally reflecting, among other things, higher Fiscal 2015 Gas Utility distribution system expenses ($4.8 million), and higher Gas Utility employee benefits, uncollectible accounts and other general administrative expenses. Gas Utility depreciation and amortization expense increased $4.2 million reflecting the effects of greater distribution system capital expenditures. Gas Utility other operating income increased $3.4 million reflecting, among other things, incremental income from Gas Utility construction services. Electric Utility Fiscal 2015 operating income increased $4.5 million reflecting the higher Electric Utility total margin ($3.8 million) and lower distribution and uncollectible accounts expense. The $7.4 million decrease in UGI Utilities income before income taxes reflects the lower operating income ($4.7 million) and higher long-term debt interest expense.

Interest Expense and Income Taxes. Our interest expense in Fiscal 2015 was higher than in Fiscal 2014 principally reflecting interest on the 4.98% Senior Notes which were issued in March 2014, the proceeds of which were used to refinance UGI Utilities’ 364-day Term Loan Credit Agreement. Our effective income tax rate in Fiscal 2015 was slightly lower than in the prior year.

FINANCIAL CONDITION AND LIQUIDITY

Capitalization and Liquidity

UGI Utilities’ total debt outstanding was $ 783.9 million at September 30, 2016 , which includes $ 112.5 million of short-term borrowings, compared with total debt outstanding of $ 691.5 million at September 30, 2015 , which includes $71.7 million of short-term borrowings. UGI Utilities’ total long-term debt outstanding at September 30, 2016 , comprises $575.0 million of Senior Notes and $100.0 million of Medium-Term Notes, and is net of $3.6 million of unamortized debt issuance costs.

In April 2016, UGI Utilities entered into a Note Purchase Agreement (the “2016 Note Purchase Agreement”) with a consortium of lenders. Pursuant to the 2016 Note Purchase Agreement, UGI Utilities issued $100 million aggregate principal amount of 2.95% Senior Notes due June 2026 and $200 million aggregate principal amount of 4.12% Senior Notes due September 2046 in June 2016 and September 2016, respectively. In October 2016, UGI Utilities issued $100 million aggregate principal amount of 4.12% Senior Notes due in October 2046. The net proceeds of the issuance of these senior notes were used 1) to repay UGI Utilities’ maturing 5.75% Senior Notes, 7.37% Medium-term notes and 5.64% Medium-term notes; 2) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and information technology initiatives; and 3) for general corporate purposes.

UGI Utilities has a credit agreement (the “Credit Agreement”) with a group of banks providing for borrowings of up to $300 million (including a $100 million sublimit for letters of credit) which expires in March 2020. Borrowings under the Credit Agreement are classified as short-term borrowings on the Consolidated Balance Sheets. During Fiscal 2016 and Fiscal 2015 , average daily short-term borrowings under the Credit Agreement were $150.8 million and $61.7 million , respectively, and peak short-term borrowings totaled $232.0 million and $163.6 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 UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00 . UGI Utilities was in compliance with this covenant at September 30, 2016 .

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 2017 . 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 $205.4 million in Fiscal 2016 , $306.7 million in Fiscal 2015 and $188.7 million in Fiscal 2014 . The decrease 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. The significant increase in cash flow from operating activities in Fiscal 2015 compared with Fiscal 2014 primarily reflects the impact of lower natural gas prices on changes in working capital. Cash provided by operating activities before changes in operating working capital was $204.9 million in Fiscal 2016 , $229.3 million in Fiscal 2015 and $224.6 million in Fiscal 2014 . The lower cash flow before changes in operating working capital in Fiscal 2016 compared to Fiscal 2015 reflects the lower year-over-year operating results and a $36 million cash settlement of interest rate protection agreements, partially offset by an increase in deferred income taxes. Changes in operating working capital provided (used) $0.5 million of cash in Fiscal 2016 , $77.4 million of cash in Fiscal 2015 and $(35.9) million of cash in Fiscal 2014 . The significantly higher cash flow from changes in operating working capital in Fiscal 2015 (compared to Fiscal 2016 and Fiscal 2014) reflects, in large part, the impact of declining natural gas prices on deferred fuel costs overcollections and cash flow from changes in inventories and accounts receivable.

Investing activities. Cash used by investing activities was $252.5 million in Fiscal 2016 , $216.6 million in Fiscal 2015 , and $172.8 million in Fiscal 2014 . The year-over-year increases in capital expenditures during the three-year period principally reflects higher year-over-year Gas Utility capital expenditures for infrastructure replacements, system improvements and information technology. Fiscal 2016 cash flow from investing activities includes a $6.0 million decrease in restricted cash in futures brokerage accounts compared to a $3.0 million increase in Fiscal 2015 and a $0.4 million increase in Fiscal 2014. Changes in restricted cash in futures brokerage accounts are generally the result of changes in underlying commodity prices.

Financing activities. Cash provided (used) by financing activities was $46.9 million in Fiscal 2016 , $(99.4) million in Fiscal 2015 and $(8.2) million in Fiscal 2014 . 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. 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 2016, net short-term borrowings totaled $40.8 million compared to net short-term debt repayments of $14.6 million in Fiscal 2015 and $68.8 million of borrowings in Fiscal 2014. The greater short-term debt repayments in Fiscal 2015 resulted from the significantly higher cash provided by operating activities.

Capital Expenditures

In the following table, we present capital expenditures by business segment for Fiscal 2016 , Fiscal 2015 and Fiscal 2014 . We also provide amounts we expect to spend in Fiscal 2017 . We expect to finance a substantial portion of our Fiscal 2017 capital expenditures from cash generated by operations, borrowings under our Credit Agreement and cash proceeds from long-term debt issued in October 2016.



(Millions of dollars)	2017		2016		2015		2014
	(estimate)
Gas Utility	$	327.1	$	251.3	$	189.7	$	156.4
Electric Utility	11.9		11.2		8.0		7.8
	$	339.0	$	262.5	$	197.7	$	164.2

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

Contractual Cash Obligations and Commitments

UGI Utilities has contractual cash obligations that extend beyond Fiscal 2016 , 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. The following table presents significant contractual cash obligations under agreements existing as of September 30, 2016 :



	Payments Due by Period
			Fiscal		Fiscal		Fiscal
(Millions of dollars)	Total		2017		2018 - 2019		2020 - 2021		Thereafter
Long-term debt (a)	$	675.0	$	20.0	$	40.0	$	—	$	615.0
Interest on long-term fixed rate debt (b)	687.9		32.6		58.7		57.3		539.3
Operating leases	16.2		6.0		8.1		1.9		0.2
UGI Utilities supply, storage and transportation contracts	737.8		205.5		262.4		134.9		135.0
Total	$	2,116.9	$	264.1	$	369.2	$	194.1	$	1,289.5


(a)	Based upon stated maturity dates.


(b)	Based upon stated interest rates.

The components of the other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2016 , principally consist of pension and other postretirement benefit liabilities recorded in accordance with GAAP and estimated obligations for environmental investigation and remediation. These liabilities are not included in the table of Contractual Cash Obligations and Commitments above because they are estimates of future payments and not contractually fixed as to timing or amount. We believe the minimum required contributions to our pension plan in Fiscal 2017 are not expected to be material. Contributions to the pension plan in years beyond Fiscal 2017 will depend in large part on the impacts of future returns on pension plan assets and interest rates on pension plan liabilities. For additional information on these liabilities, see Notes 9 and 12 to Consolidated Financial Statements.

Pension Plan

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

The fair values of the Pension Plan’s assets totaled $463.4 million and $430.8 million at September 30, 2016 and 2015 , respectively. At September 30, 2016 and 2015 , the underfunded positions of the Pension Plan, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plan’s assets, were $182.0 million and $132.8 million , respectively.

We believe we are in compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations. Required minimum contributions to the U.S. Pension Plan in Fiscal 2017 are not expected to be material. Pre-tax pension cost associated with the Pension Plan in Fiscal 2016 was $11.4 million . Pre-tax pension cost associated with Pension Plan in Fiscal 2017 is expected to be approximately $15.4 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, 2016 , we have recorded cumulative after-tax charges to stockholder’s equity of $11.8 million and regulatory assets of $ 183.1 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

UGI Gas Base Rate Filing. 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 $58.6 million. 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 $27.0 million 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 $27.0 million 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 five percent of the amount 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 April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. To date, no action has been taken by the PUC on either of these petitions. The Company cannot predict the timing or outcome of these petitions. On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism effective January 1, 2017. Revenue 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 not likely to occur prior to September 30, 2017.

MANUFACTURED GAS PLANTS

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

UGI Utilities and its subsidiaries have entered into agreements with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania. CPG is party to a Consent Order and Agreement (“CPG-COA”) with the DEP requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which 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, required 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, 2016 and 2015 , our accrued liabilities for estimated environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11.3 million and $13.8 million , respectively. CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable.

properties in Pennsylvania on which MGP related facilities were operated (“UGI Gas MGP Properties”). Under this agreement, required environmental expenditures related to the UGI Gas MGP Properties are capped at $2.5 million in any calendar year. At September 30, 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the UGI Gas-COA totaled $43.7 million . UGI Gas has recorded an associated regulatory asset for these costs because recovery of these costs from customers is probable.

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

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 former subsidiaries. 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 former subsidiaries 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, 2016 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material.

RELATED PARTY TRANSACTIONS

UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities for all periods presented were not material.

From time to time, UGI Utilities is a party to Storage Contract Administration Agreements (“SCAAs”) with Energy Services which have terms of up to three years . At September 30, 2016 , UGI Utilities was a party to one SCAA with Energy Services, and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , these payments were not material. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $12.7 million , $16.8 million and $38.3 million in Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in other current liabilities on the Consolidated Balance Sheets, were $8.1 million and $10.7 million at September 30, 2016 and 2015 , respectively.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption inventories. The carrying values of these gas storage inventories at September 30, 2016 and 2015 , comprising approximately 4.6 bcf and 5.0 bcf of natural gas, were $11.1 million and $12.9 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 2016 , Fiscal 2015 and Fiscal 2014 totaled $63.3 million, $47.8 million and $35.8 million, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , revenues associated with sales to Energy Services totaled $30.7 million, $79.2 million and $109.9 million, respectively. Also from time to time, the Company 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 2016 , Fiscal 2015 and Fiscal 2014 , such purchases totaled $35.1 million, $85.4 million and $128.1 million, respectively.

OFF-BALANCE-SHEET ARRANGEMENTS

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

MARKET RISK DISCLOSURES

Our primary market risk exposures are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.

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, 2016 and 2015 , Gas Utility had $0.6 million and $6.6 million of restricted cash in brokerage accounts, respectively. At September 30, 2016 and 2015 , the fair values of our natural gas futures and option contracts were gains and (losses) of $4.3 million and $(3.3) million, respectively.

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, 2016 , all of our Electric Utility’s forward electricity purchase contracts were subject to the normal purchase and normal sale (“NPNS”) exception.

In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures contracts are recorded at fair value with changes in fair value reflected in operating expenses and other income. The amount of unrealized gains on these contracts and associated volumes under contract at September 30, 2016 and 2015 , 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 2016 and Fiscal 2015 , an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $1.5 million and $0.6 million , respectively.

Our long-term debt is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we expect to refinance such debt with new debt having interest rates reflecting then-current market conditions. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of approximately $93 million and $50 million at September 30, 2016 and 2015 , respectively. A 100 basis point

decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of approximately $115 million and $60 million at September 30, 2016 and 2015 , respectively.

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, 2016 .

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 Evaluation. Our goodwill is the result of Gas Utility business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2016, the Company changed the measurement date for performing its annual goodwill impairment test from September 30 to July 31. This voluntary change in accounting principle, applied prospectively, is preferable as it aligns the annual goodwill impairment test date more closely with the Company’s internal budgeting process and did not delay, accelerate or avoid an impairment of the Company’s goodwill. 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 as determined in the same manner as goodwill is recognized in a business combination. From time to time, we may assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. From time to time, we may bypass the qualitative assessment and perform the first step of the two-step quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine the fair value of our Gas Utility 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. 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 not more likely than not that the carrying value of a reporting unit is greater than its fair value. As of September 30, 2016 , our goodwill totaled $182.1 million. We did not record any impairments of goodwill during Fiscal 2016 , Fiscal 2015 or Fiscal 2014 .

Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation that arises in the normal course of business. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere and PNG and CPG owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with GAAP, we establish reserves for pending litigation or environmental remediation obligations 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. Reasonable estimates involve management judgments based on a broad range of information and prior experience and include an evaluation of the nature of the claim, the procedural status of the matter, the probability or likelihood of success of prosecuting or defending the claim, the information available with respect to the claim, the opinions and views of outside counsel and other advisors, and past experience in similar matters. These judgments are reviewed quarterly as more information is received, and the amounts reserved are updated as necessary. Our estimated reserves may differ materially from the ultimate liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted.

Depreciation of Property, Plant and Equipment. We compute depreciation on UGI Utilities property, plant and equipment on a straight-line basis over the average remaining lives of its various classes of depreciable property. 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, 2016 , UGI Utilities net property, plant and equipment totaled $ 2,023.5 million and we recorded depreciation expense of $64.3 million during Fiscal 2016 .

Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation by the PUC. In accordance with accounting guidance associated with rate-regulated entities, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2016 , our regulatory assets and regulatory liabilities totaled $ 395.1 million and $55.6 million , respectively. For additional information on our regulatory assets and liabilities, see Note 2 and Note 4 to Consolidated Financial Statements.

Pension Plan Assumptions. Pension plan assumptions are significant inputs to the actuarial models that measure pension benefit obligations and pension expense. The cost of providing benefits under the Pension Plan is dependent on historical information such as employee age, length of service, level of compensation and the actual rate of return on plan assets. In addition, certain assumptions relating to the future are used to determine pension expense including mortality assumptions, the discount rate applied 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 much lesser extent, direct investments in common stock including UGI Corporation common stock. Changes in plan assumptions as well as fluctuations in actual equity or fixed income market returns could have a material impact on future pension costs. We believe the two most critical assumptions are (1) the expected rate of return on plan assets and (2) the discount rate. A decrease in the expected rate of return on Pension Plan assets of 50 basis points to a rate of 7.00% would result in an increase in pre-tax pension cost of approximately $2.1 million in Fiscal 2017 . A decrease in the discount rate of 50 basis points to a rate of 3.30% would result in an increase in pre-tax pension cost of approximately $4.0 million in Fiscal 2017 . 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

(a)

The Company’s disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed or submitted under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures, as of September 30, 2016 , were effective at the reasonable assurance level.

(b)

Management’s Annual Report on Internal Control over Financial Reporting . Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, of the Company’s internal control over financial reporting as of September 30, 2016 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO 2013 Framework”).

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

Based on its assessment, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2016 , based on the COSO 2013 Framework. Ernst & Young LLP, our independent registered public accounting firm, has audited the effectiveness of the Company’s internal control over financial reporting as of September 30, 2016 , as stated in their report, which appears herein.


(c)	During the most recent fiscal quarter, no change in the Company’s internal control over financial reporting occurred that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III:

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The aggregate fees billed by Ernst & Young LLP, the Company’s independent registered public accounting firm in Fiscal 2016 and Fiscal 2015, were as follows:



	2016		2015
Audit Fees	$	1,316,526	$	840,850
Audit-Related Fees	0		0
Tax Fees	0		0
All Other Fees	0		0
Total Fees for Services Provided	$	1,316,526	$	840,850

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

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

PART IV:

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


(a)	Documents filed as part of this report:


(1)	Financial Statements:

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

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

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

Report of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP

Consolidated Balance Sheets as of September 30, 2016 and 2015

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

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

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

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

Notes to Consolidated Financial Statements


(2)	Financial Statement Schedule:

For the years ended September 30, 2016 , 2015 and 2014

II — Valuation and Qualifying Accounts

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


(3)	List of Exhibits:

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit
3.1	UGI Utilities’ Amended and Restated Articles of Incorporation.	Utilities	Registration Statement No. 333-72540 (10/31/01)	3
3.2	Bylaws of UGI Utilities as amended through September 30, 2003.	Utilities	Form 10-K (9/30/03)	3.2
4	Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of its long-term debt not required to be filed pursuant to the description of Exhibit 4 contained in Item 601 of Regulation S-K).
4.1	UGI Utilities’ Articles of Incorporation and Bylaws referred to in Exhibit Nos. 3.1 and 3.2.
4.2	Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994.	Utilities	Registration Statement No. 33-77514 (4/8/94)	4(c)
4.3	Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association.	Utilities	Form 8-K (9/12/06)	4.2
4.4	Form of Fixed Rate Medium-Term Note.	Utilities	Form 8-K (8/26/94)	(4)i
4.5	Form of Fixed Rate Series B Medium-Term Note.	Utilities	Form 8-K (8/1/96)	4(i)
4.6	Form of Floating Rate Series B Medium-Term Note.	Utilities	Form 8-K (8/1/96)	4(ii)
4.7	Officer’s Certificate establishing Medium-Term Notes Series.	Utilities	Form 8-K (8/26/94)	4(iv)
4.8	Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture.	Utilities	Form 8-K (8/1/96)	4(iv)
4.9	Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture.	Utilities	Form 8-K (5/21/02)	4.2
4.10	Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes.	Utilities	Form 8-K (5/21/02)	4.1
4.11	Form of Note Purchase Agreement dated October 30, 2013 between the Company and the purchasers listed as signatories thereto.	Utilities	Form 8-K (10/30/13)	4.1
4.12	Note Purchase Agreement dated April 22, 2016 between the Company and the purchasers listed as signatories thereto.	Utilities	Form 8-K (4/28/16)	4.1

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.1**	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of September 5, 2014.	UGI	Form 10-K (9/30/16)	10.25
10.2**	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of September 5, 2014 - Terms and Conditions as effective January 1, 2016.	UGI	Form 10-K (9/30/16)	10.26
10.3**	UGI Corporation 2013 Omnibus Incentive Compensation Plan, effective as of September 5, 2014.	UGI	Form 10-K (9/30/16)	10.30
10.4**	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 28, 2016.	UGI	Form 10-Q (3/31/16)	10.3
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.	UGI	Form 10-Q (3/31/14)	10.5
10.7**	UGI Corporation Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.	UGI	Form 10-Q (6/30/13)	10.1
10.8**	UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective November 22, 2013.	UGI	Form 10-Q (3/31/14)	10.3
10.9**	UGI Corporation 2009 Supplemental Executive Retirement Plan for New Employees, as Amended and Restated effective July 26, 2016.	UGI	Form 10-K (9/30/16)	10.29
10.10**	UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.	Utilities	Form 10-Q (6/30/13)	10.1
10.11**	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
10.12**	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Employees, dated January 1, 2016.	UGI	Form 10-Q (3/31/16)	10.1
10.13**	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2016.	Utilities	Form 10-Q (3/31/16)	10.1
10.14**	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2016.	UGI	Form 10-Q (3/31/16)	10.4
10.15**	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2016.	Utilities	Form 10-Q (3/31/16)	10.2

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.16**	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
10.17	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
10.18	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
*10.19	Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, LLC, effective November 1, 2015.
10.20	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

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit

*12.1	Computation of Ratio of Earnings to Fixed Charges.
14	Code of Ethics for principal executive, financial and accounting officers.	UGI	Form 10-K (9/30/03)	14
*23.1	Consent of Ernst & Young LLP.
*23.2	Consent of PricewaterhouseCoopers 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, 2016 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, 2016 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, 2016, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS	XBRL Instance
*101.SCH	XBRL Taxonomy Extension Schema
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase
*101.DEF	XBRL Taxonomy Extension Definition Linkbase
*101.LAB	XBRL Taxonomy Extension Labels Linkbase
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase



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

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 22, 2016	By:	/s/ Daniel J. Platt
			Daniel J. Platt
			Vice President - Finance and Chief Financial Officer, Assistant Secretary and Treasurer (Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 22, 2016 by the following persons on behalf of the Registrant in the capacities indicated.




Signature		Title
/s/ Robert F. Beard		President and Chief Executive Officer (Principal Executive
Robert F. Beard		Officer) and Director

/s/ Daniel J. Platt		Vice President — Finance and Chief Financial Officer, Assistant
Daniel J. Platt		Secretary and Treasurer (Principal Financial Officer)

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

/s/ Marvin O. Schlanger		Chairman and Director
Marvin O. Schlanger

/s/ John L. Walsh		Vice Chairman and Director
John L. Walsh

/s/ M. Shawn Bort		Director
M. Shawn Bort

/s/ 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/ James B. Stallings, Jr.		Director
James B. Stallings, Jr.

/s/ Roger B. Vincent		Director
Roger B. Vincent

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

No annual report or proxy material was sent to security holders in Fiscal 2016 .

UGI UTILITIES, INC. AND SUBSIDIARIES

FINANCIAL INFORMATION

FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K

YEAR ENDED SEPTEMBER 30, 2016

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) - Ernst & Young LLP		F- 2

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

Report of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP		F- 4

Consolidated Balance Sheets as of September 30, 2016 and 2015		F- 5

Consolidated Statements of Income for the years ended September 30, 2016, 2015 and 2014		F- 6

Consolidated Statements of Comprehensive Income for the years ended September 30, 2016, 2015 and 2014		F- 7

Consolidated Statements of Cash Flows for the years ended September 30, 2016, 2015 and 2014		F- 8

Consolidated Statements of Stockholder’s Equity for the years ended September 30, 2016, 2015 and 2014		F- 9

Notes to Consolidated Financial Statements		F- 10 to F- 35

Financial Statement Schedule:

For the years ended September 30, 2016, 2015 and 2014:

II — Valuation and Qualifying Accounts		S- 1

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

F- 1

Report of Independent Registered Public Accounting Firm

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

We have audited UGI Utilities, Inc. and subsidiaries' internal control over financial reporting as of September 30, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). UGI Utilities, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

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

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

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

In our opinion, UGI Utilities, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of September 30, 2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of UGI Utilities, Inc. and subsidiaries as of September 30, 2016 and 2015, and the related consolidated statements of income, comprehensive income, stockholder’s equity and cash flows for each of the two years in the period ended September 30, 2016 and our report dated November 22, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

November 22, 2016

F- 2

Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying consolidated balance sheets of UGI Utilities, Inc. and subsidiaries as of September 30, 2016 and 2015, and the related consolidated statements of income, comprehensive income, stockholder’s equity and cash flows for each of the two years in the period ended September 30, 2016. Our audits also included the financial statement schedule for each of the two years in the period ended September 30, 2016 listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of UGI Utilities, Inc. and subsidiaries at September 30, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the two years in the period ended September 30, 2016, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), UGI Utilities, Inc. and subsidiaries’ internal control over financial reporting as of September 30, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November 22, 2016, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

November 22, 2016

F- 3

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of UGI Utilities, Inc.:

In our opinion, the consolidated statements of income, of comprehensive income, of cash flows and of stockholder’s equity for the year ended September 30, 2014 present fairly, in all material respects, the results of operations and cash flows of UGI Utilities, Inc. and its subsidiaries for the year ended September 30, 2014, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index as Item 15(a)(2) for the year ended September 30, 2014 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

November 28, 2014

F- 4

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)



	September 30,
	2016			2015
ASSETS
Current assets:
Cash and cash equivalents	$	2,819		$	3,099
Restricted cash	583			6,602
Accounts receivable (less allowances for doubtful accounts of $3,946 and $5,599, respectively)	44,692			55,659
Accounts receivable — related parties	398			1,271
Accrued utility revenues	12,753			12,051
Inventories	42,340			51,716
Deferred income taxes	—			24,694
Prepaid income taxes	1,956			10,026
Regulatory assets	3,208			4,105
Derivative instruments	4,263			934
Prepaid expenses	10,499			9,701
Other current assets	11,510			14,202
Total current assets	135,021			194,060
Property, plant and equipment	2,998,915			2,753,499
Less accumulated depreciation and amortization	(975,374		)	(929,130		)
Net property, plant and equipment	2,023,541			1,824,369
Goodwill	182,145			182,145
Regulatory assets	391,933			300,103
Other assets	10,451			5,307
Total assets	$	2,743,091		$	2,505,984
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	19,986		$	246,893
Short-term borrowings	112,500			71,700
Accounts payable — trade	65,180			58,135
Accounts payable — related parties	3,995			4,430
Employee compensation and benefits accrued	16,323			14,286
Interest accrued	7,605			8,553
Customer deposits and advances	41,391			41,646
Derivative instruments	310			12,591
Regulatory liability - deferred fuel and power refunds	22,299			36,638
Other current liabilities	44,321			38,780
Total current liabilities	333,910			533,652
Long-term debt	651,455			372,913
Deferred income taxes	550,229			512,497
Deferred investment tax credits	3,268			3,597
Pension and other postretirement benefit obligations	184,516			135,003
Other noncurrent liabilities	94,976			57,702
Total liabilities	1,818,354			1,615,364
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			471,904
Retained earnings	422,516			372,143
Accumulated other comprehensive loss	(31,618		)	(13,686		)
Total common stockholder’s equity	924,737			890,620
Total liabilities and stockholder’s equity	$	2,743,091		$	2,505,984

See accompanying Notes to Consolidated Financial Statements.

F- 5

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of dollars)



	Year Ended September 30,
	2016		2015			2014
Revenues	$	768,484	$	1,041,581		$	1,086,889
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	289,786		510,784			562,942
Operating and administrative expenses	180,842		206,319			195,408
Operating and administrative expenses — related parties	11,863		11,956			10,671
Taxes other than income taxes	15,789		16,134			16,608
Depreciation	64,260		59,841			55,776
Amortization	3,043		3,749			3,443
Other expense (income), net	2,000		(8,869		)	(4,359		)
	567,583		799,914			840,489
Operating income	200,901		241,667			246,400
Interest expense	37,630		41,128			38,471
Income before income taxes	163,271		200,539			207,929
Income taxes	65,898		79,484			83,823
Net income	$	97,373	$	121,055		$	124,106

See accompanying Notes to Consolidated Financial Statements.

F- 6

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)



	Year Ended September 30,
	2016			2015			2014
Net income	$	97,373		$	121,055		$	124,106
Net losses on derivative instruments (net of tax of $12,016, $2,911 and $0, respectively)	(16,942		)	(4,105		)	—
Reclassifications of net losses on derivative instruments (net of tax of $(1,112), $(1,109) and $(1,112), respectively)	1,568			1,565			1,567
Benefit plans, principally actuarial losses (net of tax of $2,267, $2,469 and $1,002, respectively)	(3,197		)	(3,482		)	(1,413		)
Reclassifications of benefit plans actuarial losses and net prior service credits (net of tax of $(454), $(367) and $(274), respectively)	639			517			385
Other comprehensive (loss) income	(17,932		)	(5,505		)	539
Comprehensive income	$	79,441		$	115,550		$	124,645

See accompanying Notes to Consolidated Financial Statements.

F- 7

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)



	Year Ended September 30,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	97,373		$	121,055		$	124,106
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	67,303			63,590			59,219
Deferred income taxes, net	76,938			29,356			33,588
Pension contributions, net of pension expense	1,580			(1,415		)	(9,459		)
Settlement of interest rate protection agreements	(35,975		)	—			—
Provision for uncollectible accounts	7,760			13,498			13,149
Other, net	(10,112		)	3,228			3,998
Net change in:
Accounts receivable and accrued utility revenues	1,120			7,297			(19,718		)
Inventories	9,376			43,503			(5,558		)
Deferred fuel costs, net of changes in unsettled derivatives	(22,740		)	51,778			(17,632		)
Accounts payable	(3,053		)	(7,649		)	5,757
Other current assets	(70		)	(9,723		)	362
Other current liabilities	15,870			(7,808		)	864
Net cash provided by operating activities	205,370			306,710			188,676
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(250,584		)	(203,192		)	(164,180		)
Net costs of property, plant and equipment disposals	(7,940		)	(10,443		)	(8,214		)
Decrease (increase) in restricted cash	6,019			(3,010		)	(411		)
Net cash used by investing activities	(252,505		)	(216,645		)	(172,805		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(47,000		)	(65,600		)	(77,395		)
Increase (decrease) in short-term borrowings	40,800			(14,600		)	68,800
Issuances of long-term debt, net of issuance costs	298,379			—			174,445
Repayments of long-term debt	(247,000		)	(20,000		)	(175,000		)
Excess tax benefits from equity-based payment arrangements	1,676			833			973
Net cash provided (used) by financing activities	46,855			(99,367		)	(8,177		)
Cash and cash equivalents (decrease) increase	$	(280	)	$	(9,302	)	$	7,694
CASH AND CASH EQUIVALENTS:
End of year	$	2,819		$	3,099		$	12,401
Beginning of year	3,099			12,401			4,707
(Decrease) increase	$	(280	)	$	(9,302	)	$	7,694
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid (received) for:
Interest	$	36,155		$	38,405		$	34,781
Income taxes	$	(19,758	)	$	54,427		$	54,293

See accompanying Notes to Consolidated Financial Statements.

F- 8

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(Thousands of dollars)



	Year Ended September 30,
	2016			2015			2014
Common stock, without par value
Balance, beginning of year	$	60,259		$	60,259		$	60,259
Balance, end of year	$	60,259		$	60,259		$	60,259

Retained earnings
Balance, beginning of year	$	372,143		$	316,688		$	269,977
Net income	97,373			121,055			124,106
Cash dividends — Common Stock	(47,000		)	(65,600		)	(77,395		)
Balance, end of year	$	422,516		$	372,143		$	316,688

Additional paid-in capital
Balance, beginning of year	$	471,904		$	471,071		$	470,098
Excess tax benefits on equity-based compensation	1,676			833			973
Balance, end of year	$	473,580		$	471,904		$	471,071

Accumulated other comprehensive income (loss)
Balance, beginning of year	$	(13,686	)	$	(8,181	)	$	(8,720	)
Net losses on derivative instruments	(16,942		)	(4,105		)	—
Reclassifications of net losses on derivative instruments	1,568			1,565			1,567
Benefit plans, principally actuarial losses	(3,197		)	(3,482		)	(1,413		)
Reclassifications of benefit plans actuarial losses and net prior service credits	639			517			385
Balance, end of year	$	(31,618	)	$	(13,686	)	$	(8,181	)

Total UGI Utilities, Inc. stockholder’s equity	$	924,737		$	890,620		$	839,837

See accompanying Notes to Consolidated Financial Statements.

F- 9

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 had a heating, ventilation and air-conditioning service business which operated principally in the PNG service territory (“PNG HVAC Business”). The assets of the PNG HVAC Business principally comprising customer contracts were sold on June 1, 2015.

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

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

Principles of Consolidation

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

Effects of Regulation

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

Fair Value Measurements

The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, also on a nonrecurring basis. Fair value measurements performed on a recurring basis principally relate to derivative instruments. 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.

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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.

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


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

•

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


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

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

Derivative Instruments

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

Gains and losses on substantially all of the derivative instruments used by UGI Utilities (for which NPNS has not been elected) to hedge commodity prices are included in regulatory assets and liabilities in accordance with GAAP regarding accounting for rate-regulated entities. Certain of our derivative instruments are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair value 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 other commodity derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments are included in cash flows from operating activities.

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

Revenue Recognition

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

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Accounts Receivable

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

Income Taxes

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

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

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

Cash and Cash Equivalents

All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.

Restricted Cash

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

Inventories

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

Property, Plant and Equipment and Related Depreciation

We record property, plant and equipment at original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. The composite annual rate for depreciable property at our Gas Utility was 2.2% in Fiscal 2016 , 2.2% in Fiscal 2015 and 2.3% in Fiscal 2014 . The composite annual rate for depreciable property at our Electric Utility was 2.5% in Fiscal 2016 , 2.5% in Fiscal 2015 and 2.5% in Fiscal 2014 . When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over 5 years , consistent with the recovery period approved by the PUC.

We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Goodwill

Our goodwill is the result of Gas Utility business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2016, the Company changed the measurement date for performing its annual goodwill impairment test from September 30 to July 31. This voluntary change in accounting principle, applied prospectively, is preferable as it aligns the annual goodwill impairment test date more closely with the Company’s internal budgeting process and did not delay, accelerate or avoid an impairment of the Company’s goodwill.

We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value and the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill. From time to time, we may assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. From time to time, we may bypass the qualitative assessment and perform the first step of the two-step quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine the fair value of our Gas Utility generally based on a weighting of income and market approaches. For purposes of the income approach, fair value is 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 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. 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 the carrying value of a reporting unit is greater than its fair value. No provisions for goodwill impairments were recorded during Fiscal 2016 , Fiscal 2015 or Fiscal 2014 .

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No provisions for impairments were recorded during Fiscal 2016 , Fiscal 2015 or Fiscal 2014 .

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 (“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. We expect to adopt new accounting guidance that simplifies and clarifies certain aspects of the accounting for and presentation of share-based payments during the first quarter of Fiscal 2017 (see Note 3).

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 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, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see Note 12 .

3. ACCOUNTING CHANGES

Adoption of New Accounting Standard

Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. As required, we applied this guidance prospectively and, accordingly, balance sheets prior to Fiscal 2016 have not been reclassified.

Debt Issuance Costs. During the fourth quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of debt issuance costs. This new guidance amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. As required by the new guidance, prior period amounts have been reclassified. As of September 30, 2016 and 2015, the Company has reflected $3,559 and $2,194 of such costs as a reduction to long-term debt, including current maturities, on the Consolidated Balance Sheets.

Accounting Standards Not Yet Adopted

Cash Flow Classification. In August 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” This ASU provides guidance on the classification of certain cash receipts and payments in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The Company expects to adopt the new guidance in Fiscal 2017. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements.

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

Employee Share-Based Payments . In March 2016, the FASB issued ASU No. 2016-09, "Improvements to Employee Share-Based Payment Accounting." This ASU simplifies several aspects of the 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 share-based awards will be recognized as income tax benefit or expense in the income statement and the tax effects of exercised or vested awards will be treated as discrete items in the reporting period in which they occur. The Company expects to adopt the new guidance in the first quarter of Fiscal 2017. The amendment most likely to impact the Company, principally those requiring recognition of excess tax benefits and tax deficiencies in the income statement, will be applied prospectively. Based upon the number of share-based payment

F- 14

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

awards currently outstanding, we do not believe that the adoption of the new guidance will have a material impact on our net income.

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

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our consolidated financial statements.

4. REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS

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



	2016		2015
Regulatory assets:
Income taxes recoverable	$	115,643	$	115,946
Underfunded pension and postretirement plans	183,129		140,762
Environmental costs (a)	59,397		19,983
Removal costs, net	27,956		21,223
Other	9,016		6,294
Total regulatory assets	$	395,141	$	304,208
Regulatory liabilities (b):
Postretirement benefits overcollections	$	17,519	$	19,975
Deferred fuel and power refunds	22,299		36,638
State income tax benefits — distribution system repairs	15,086		13,266
Other	665		1,125
Total regulatory liabilities	$	55,569	$	71,004


(a)	Balance at September 30, 2016, includes amounts associated with UGI Gas’ Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 12 ).


(b)	Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and noncurrent liabilities in the Consolidated Balance Sheets.

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

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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

Environmental costs . Environmental costs principally represent estimated probable future environmental remediation and investigation costs that UGI Gas, CPG and PNG expect to incur, primarily at Manufactured Gas Plant (“MGP”) sites in Pennsylvania, in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection. Pursuant to base rate orders, UGI Gas, PNG and CPG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2016 , 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. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over 5 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, these overcollections will be 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 “UGI Gas Base Rate Filing” below). With respect to Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits is being deferred for future rate refund to customers.

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

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at September 30, 2016 and 2015 , were $ 4,263 and $ (3,262) , respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At September 30, 2016 and 2015 , substantially all Electric Utility forward electricity purchase contracts were subject to the NPNS exception (see Note 14 ).

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, 2016 and 2015 , were not material.

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

Other . Other regulatory assets and liabilities comprise a number of deferred items including, among others, a portion of preliminary stage information technology costs, energy efficiency conservation costs and rate case expenses. At September 30, 2016 , UGI Utilities expects to recover these costs over periods of approximately 1 to 20 years.

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Other Regulatory Matters

Preliminary Stage Information Technology Costs. During the second quarter of Fiscal 2016, we determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during the second quarter of 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.

UGI Gas Base Rate Filing. 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 five percent of the amount 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 April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. To date, no action has been taken by the PUC on either of these petitions. The Company cannot predict the timing or outcome of these petitions. On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism effective January 1, 2017. Revenue 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 not likely to occur prior to September 30, 2017.

5. INVENTORIES

Inventories comprise the following at September 30:



	2016		2015
Gas Utility natural gas	$	29,223	$	37,510
Materials, supplies and other	13,117		14,206
Total inventories	$	42,340	$	51,716

At September 30, 2016 , UGI Utilities was a party to three principal storage contract administrative agreements (“SCAAs”) having terms of three years. One of the SCAAs was with Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 18 ), and two of the SCAAs were with a non-affiliate. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

The carrying value of gas storage inventories released under the SCAAs at September 30, 2016 and 2015 , comprising 8.1 billion cubic feet (“bcf”) and 9.0 bcf of natural gas, were $18,773 and $22,694 , respectively. At September 30, 2016 and 2015 , UGI Utilities held a total of $19,100 and $17,700 , respectively, of security deposits received from its SCAA counterparties. These amounts are included in other current liabilities on the Consolidated Balance Sheets.

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

6. PROPERTY, PLANT AND EQUIPMENT

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



	2016		2015
Distribution	$	2,634,191	$	2,458,080
Transmission	93,454		90,036
General and other, including construction in process	271,270		205,383
Total property, plant and equipment	$	2,998,915	$	2,753,499

7. DEBT

Long-term debt comprises the following at September 30:



	2016			2015
Senior Notes:
4.12%, due September 2046	$	200,000		$	—
5.75%, due September 2016	—			175,000
4.98%, due March 2044	175,000			175,000
2.95%, due June 2026	100,000			—
6.21%, due September 2036	100,000			100,000
Medium-Term Notes:
7.37%, due October 2015	—			22,000
5.64%, due December 2015	—			50,000
6.17%, due June 2017	20,000			20,000
7.25%, due November 2017	20,000			20,000
5.67%, due January 2018	20,000			20,000
6.50%, due August 2033	20,000			20,000
6.13%, due October 2034	20,000			20,000
Total long-term debt	675,000			622,000
Less: unamortized debt issuance costs (a)	(3,559		)	(2,194		)
Less: current maturities	(19,986		)	(246,893		)
Total long-term debt due after one year	$	651,455		$	372,913


(a)	Prior-year amounts reflect the retrospective impact from the adoption of new accounting guidance regarding the classification of debt issuance costs (see Note 3 ).

Principal payments on long-term debt during the next five fiscal years is as follows: $ 20,000 is due in Fiscal 2017 ; $ 40,000 is due in Fiscal 2018 ; $ 0 is due in Fiscal 2019 ; $ 0 is due in Fiscal 2020 ; and $ 0 is due in Fiscal 2021 .

In April 2016, UGI Utilities entered into a Note Purchase Agreement (the “2016 Note Purchase Agreement”) with a consortium of lenders. Pursuant to the 2016 Note Purchase Agreement, UGI Utilities issued $100,000 aggregate principal amount of 2.95% Senior Notes due June 2026 and $200,000 aggregate principal amount of 4.12% Senior Notes due September 2046 in June 2016 and September 2016, respectively. In October 2016, UGI Utilities issued $100,000 aggregate principal amount of 4.12% Senior Notes due in October 2046 pursuant to the 2016 Note Purchase Agreement. The net proceeds of the issuance of these senior notes were used 1) to repay UGI Utilities’ maturing 5.75% Senior Notes, 7.37% Medium-term notes and 5.64% Medium-term notes;

F- 18

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

2) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and the information technology initiatives; and 3) for general corporate purposes. The Utilities Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt.

UGI Utilities has an unsecured credit agreement (the “Credit Agreement”) with a group of banks providing for borrowings of up to $300,000 (including a $100,000 sublimit for letters of credit) which expires in March 2020. Under the Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. UGI Utilities had borrowings outstanding under the credit agreements, which we classify as short-term borrowings on the Consolidated Balance Sheets, totaling $112,500 and $71,700 at September 30, 2016 and 2015 , respectively. The weighted-average interest rates on the credit agreement borrowings at September 30, 2016 and 2015 were 1.42% and 1.07% , respectively. Issued and outstanding letters of credit, which reduce available borrowings under the credit agreements, totaled $2,009 and $2,000 at September 30, 2016 and 2015 , respectively.

Restrictive Covenants. Certain of UGI Utilities Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. These Senior Notes also contain restrictive and financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00 .

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

8. INCOME TAXES

The provisions for income taxes consist of the following:



	2016			2015			2014
Current expense (benefit):
Federal	$	(17,845	)	$	34,990		$	38,786
State	6,805			15,138			11,449
Total current (benefit) expense	(11,040		)	50,128			50,235
Deferred expense (benefit):
Federal	71,005			28,877			29,208
State	6,262			815			4,717
Investment tax credit amortization	(329		)	(336		)	(337		)
Total income tax expense	$	65,898		$	79,484		$	83,823

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



	2016		2015		2014
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Difference in tax rate due to:
State income taxes, net of federal	5.2		5.1		5.1
Other, net	0.2		(0.5	)	0.2
Effective tax rate	40.4	%	39.6	%	40.3	%

Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , the beneficial effects of state tax flow through of accelerated depreciation reduced tax expense by $1,344 , $1,539 and $1,976 , respectively.

F- 19

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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



	2016			2015
Excess book basis over tax basis of property, plant and equipment	$	491,038		$	431,480
Goodwill	45,070			40,552
Derivative financial instruments	948			—
Regulatory assets	149,660			117,420
Other	2,910			2,573
Gross deferred tax liabilities	689,626			592,025
Pension plan liabilities	(74,129		)	(54,444		)
Allowance for doubtful accounts	(1,637		)	(2,809		)
Deferred investment tax credits	(1,356		)	(1,493		)
Employee-related expenses	(5,247		)	(5,637		)
Regulatory liabilities	(16,798		)	(23,958		)
Environmental liabilities	(22,757		)	(6,014		)
Derivative financial instruments	—			(3,501		)
Other	(17,473		)	(6,367		)
Gross deferred tax assets	(139,397		)	(104,223		)
Net deferred tax liabilities	$	550,229		$	487,802

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 2012.

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

During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , interest expense of $204 , $0 and $39 , respectively, was recognized in income taxes in the Consolidated Statements of Income.

As of September 30, 2016 , we have unrecognized income tax benefits totaling $2,055 including related accrued interest of $204 . If these unrecognized tax benefits were subsequently recognized, $711 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:



	2016		2015		2014
Unrecognized tax benefits - beginning of year	$	—	$	—	$	1,087
Additions for tax positions of prior years	2,055		—		—
Additions for tax positions of the current year
Settlements with tax authorities	—		—		(1,087		)
Unrecognized tax benefits - end of year	$	2,055	$	—	$	—

9. EMPLOYEE RETIREMENT PLANS

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

F- 20

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plan, the accumulated benefit obligations (“ABOs”) of the Other Postretirement Plans, plan assets and the funded status of the Pension Plan and Other Postretirement Plans as of September 30, 2016 and 2015 . ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect future compensation.



	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016			2015
Change in benefit obligations:
Benefit obligations — beginning of year	$	563,621		$	539,725		$	10,676		$	11,136
Service cost	7,772			7,863			198			220
Interest cost	25,733			24,656			483			511
Actuarial loss (gain)	72,418			14,667			1,117			(835		)
Benefits paid	(24,100		)	(23,290		)	(399		)	(356		)
Benefit obligations — end of year	$	645,444		$	563,621		$	12,075		$	10,676
Change in plan assets:
Fair value of plan assets — beginning of year	$	430,789		$	442,465		$	12,523		$	12,848
Actual gain (loss) on assets	46,874			483			1,347			(95		)
Employer contributions	9,869			11,131			98			126
Benefits paid	(24,100		)	(23,290		)	(253		)	(356		)
Fair value of plan assets — end of year	$	463,432		$	430,789		$	13,715		$	12,523
Funded status of the plans — end of year	$	(182,012	)	$	(132,832	)	$	1,640		$	1,847
Assets (liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	$	—		$	—		$	4,139		$	4,011
Unfunded liabilities — included in other noncurrent liabilities	(182,012		)	(132,832		)	(2,499		)	(2,164		)
Net amount recognized	$	(182,012	)	$	(132,832	)	$	1,640		$	1,847
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	$	138		$	178		$	(35	)	$	(48	)
Net actuarial loss (gain)	19,866			15,757			(1		)	(158		)
Total	$	20,004		$	15,935		$	(36	)	$	(206	)
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	$	1,262		$	1,570		$	(2,247	)	$	(2,890	)
Net actuarial loss	180,964			138,440			2,425			2,289
Total	$	182,226		$	140,010		$	178		$	(601	)

In Fiscal 2017 , we estimate that we will amortize approximately $16,500 of net actuarial losses, primarily associated with Pension Plan, and $500 of prior service credits from stockholder’s equity and regulatory assets.

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

F- 21

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)



	Pension Benefits						Other Postretirement Benefits
Weighted-average assumptions:	2016		2015		2014		2016		2015		2014
Discount rate - benefit obligations	3.80	%	4.60	%	4.60	%	3.80	%	4.70	%	4.60	%
Discount rate - benefit cost	4.60	%	4.60	%	5.20	%	4.70	%	4.60	%	5.10% - 5.40%
Expected return on plan assets	7.55	%	7.75	%	7.75	%	5.00	%	5.00	%	5.00	%
Rate of increase in salary levels	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%

The ABOs for the Pension Plan were $601,255 and $523,704 as of September 30, 2016 and 2015 , respectively. Included in the end of year Pension Plan PBOs above are $63,847 at September 30, 2016 , and $57,595 at September 30, 2015 , relating to employees of UGI and certain of its other subsidiaries. Included in the end of year Other Postretirement Plans ABOs above are $951 at September 30, 2016 , and $863 at September 30, 2015 , relating to employees of UGI and certain of its other subsidiaries.

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



	Pension Benefits									Other Postretirement Benefits
	2016			2015			2014			2016			2015			2014
Service cost	$	6,927		$	6,962		$	6,492		$	183		$	202		$	162
Interest cost	23,270			22,511			22,885			465			479			488
Expected return on assets	(28,668		)	(28,898		)	(26,599		)	(596		)	(612		)	(557		)
Amortization of:
Prior service cost (benefit)	348			348			348			(641		)	(641		)	(641		)
Actuarial loss	9,571			8,793			6,642			98			122			116
Net benefit cost (income)	11,448			9,716			9,768			(491		)	(450		)	(432		)
Change in associated regulatory liabilities	—			—			—			971			3,740			3,704
Net benefit cost after change in regulatory liabilities	$	11,448		$	9,716		$	9,768		$	480		$	3,290		$	3,272

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Corporation Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , we made contributions to the Pension Plan of $9,869 , $11,131 and $19,227 , respectively. The minimum required contributions in Fiscal 2017 are not expected to be material.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. The required contributions to the VEBA during Fiscal 2017 , if any, are not expected to be material.

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



	Pension Benefits		Other Postretirement Benefits
Fiscal 2017	$	25,980	$	588
Fiscal 2018	27,254		577
Fiscal 2019	28,555		575
Fiscal 2020	29,902		561
Fiscal 2021	31,168		545
Fiscal 2021 - 2025	174,070		2,719

F- 22

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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



	2016		2015
Health care cost trend rate assumed for next year	7.25	%	7.5	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	5.0	%	5.0	%
Fiscal year that the rate reaches the ultimate trend rate	2026		2026

A one percentage point change in these assumed health care cost trend rates would not have had a material impact on Fiscal 2016 other postretirement benefit cost or the September 30, 2016 , other postretirement benefit ABO.

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement income plans. At September 30, 2016 and 2015 , the PBOs of these plans were $3,628 and $2,835 , respectively. We recorded expense for these plans of $353 in Fiscal 2016 , $445 in Fiscal 2015 and $372 in Fiscal 2014 .

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

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



					Target
	Actual				Asset		Permitted
Pension Plan:	2016		2015		Allocation		Range
Equity investments:
Domestic	54.1	%	56.2	%	52.5	%	40.0% - 65.0%
International	10.2	%	10.2	%	12.5	%	7.5% - 17.5%
Total	64.3	%	66.4	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	35.7	%	33.6	%	35.0	%	30.0% - 40.0%
Total	100.0	%	100.0	%	100.0	%



					Target
	Actual				Asset		Permitted
VEBA:	2016		2015		Allocation		Range
Domestic equity investments	69.9	%	67.4	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	30.1	%	32.6	%	35.0	%	30.0% - 40.0%
Total	100.0	%	100.0	%	100.0	%

Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds, and a separately managed account comprising small-cap common stocks. Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 8% and 10.1% of Pension Plan assets at September 30, 2016 and 2015 , respectively.

F- 23

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

The fair values of the Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee. The fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2 , as of September 30, 2016 and 2015 are as follows:



	Pension Plan
	Level 1		Level 2		Level 3		Total
September 30, 2016:
Domestic equity investments:
S&P 500 Index equity mutual funds	$	158,906	$	—	$	—	$	158,906
Small and midcap equity mutual funds	43,170		—		—		43,170
Smallcap common stocks	11,414		—		—		11,414
UGI Corporation Common Stock	37,013		—		—		37,013
Total domestic equity investments	250,503		—		—		250,503
International index equity mutual funds	47,324		—		—		47,324
Fixed income investments:
Bond index mutual funds	147,794		—		—		147,794
Cash equivalents	—		17,811		—		17,811
Total fixed income investments	147,794		17,811		—		165,605
Total	$	445,621	$	17,811	$	—	$	463,432
September 30, 2015:
Equity investments:
S&P 500 Index equity mutual funds	$	147,266	$	—	$	—	$	147,266
Small and midcap equity mutual funds	40,625		—		—		40,625
Smallcap common stocks	10,727		—		—		10,727
UGI Corporation Common Stock	43,419		—		—		43,419
Total domestic equity investments	242,037		—		—		242,037
International index equity mutual funds	43,906		—		—		43,906
Fixed income investments:
Bond index mutual funds	140,776		—		—		140,776
Cash equivalents	—		4,070		—		4,070
Total fixed income investments	140,776		4,070		—		144,846
Total	$	426,719	$	4,070	$	—	$	430,789



	VEBA
	Level 1		Level 2		Level 3		Total
September 30, 2016:
S&P 500 Index equity mutual fund	$	9,583	$	—	$	—	$	9,583
Bond index mutual fund	4,019		—		—		4,019
Cash equivalents	—		113		—		113
Total	$	13,602	$	113	$	—	$	13,715
September 30, 2015:
S&P 500 Index equity mutual fund	$	8,434	$	—	$	—	$	8,434
Bond index mutual fund	3,832		—		—		3,832
Cash equivalents	—		257		—		257
Total	$	12,266	$	257	$	—	$	12,523

F- 24

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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

Defined Contribution Plan. We sponsor a 401(k) savings plan for eligible employees (“Utilities Savings Plan”). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. The Utilities Savings Plan provides for employer matching contributions. Those employees hired after December 31, 2008, who are not eligible to participate in the Pension Plan, receive employer matching contributions at a higher rate. The cost of benefits under the Utilities Savings Plan totaled $2,409 in Fiscal 2016 , $2,162 in Fiscal 2015 and $1,916 in Fiscal 2014 . We also sponsor a nonqualified supplemental defined contribution executive retirement plan. This plan generally provides supplemental benefits to certain executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal Revenue Code. Costs associated with this plan were not material in Fiscal 2016, Fiscal 2015 or Fiscal 2014.

10. SERIES PREFERRED STOCK

We have 2,000,000 shares of Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of Series Preferred Stock outstanding at September 30, 2016 or 2015 .

11. EQUITY-BASED COMPENSATION

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

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

We use a Black-Scholes option-pricing model to estimate the fair value of UGI stock options. We use a Monte Carlo valuation approach to estimate the fair value of UGI Performance Unit awards. We recorded total net pre-tax equity-based compensation expense associated with both UGI Units and UGI stock options of $1,924 ( $1,126 after-tax) during Fiscal 2016 ; $1,847 ( $1,081 after-tax) during Fiscal 2015 ; and $1,912 ( $1,119 after-tax) during Fiscal 2014 .

As of September 30, 2016 , there was $862 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 1.9 years. As of September 30, 2016 , there was a total of $1,104 of unrecognized compensation expense associated with 57,783 UGI Unit awards that is expected to be recognized over a weighted

F- 25

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

average period of 1.8 years. At September 30, 2016 and 2015 , total liabilities of $1,304 and $1,182 , respectively, associated with UGI Unit awards are reflected in other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheets.

The following table summarizes UGI Unit award activity for Fiscal 2016 :



	Total				Vested				Non-Vested
	Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)		Number of UGI Units		Weighted Average Grant Date Fair Value (per Unit)
September 30, 2015	60,583		$	32.01	15,358		$	29.46	45,225		$	32.88
Granted	21,900		$	33.30	1,083		$	32.97	20,817		$	33.32
Vested	—		$	—	15,724		$	26.92	(15,724	)	$	26.92
Forfeitures & transfers	(2,851	)	$	36.53	—		$	—	(2,851	)	$	36.53
Unit awards paid	(21,849	)	$	25.51	(21,849	)	$	25.51	—		$	—
September 30, 2016	57,783		$	34.66	10,316		$	34.31	47,467		$	34.74

12. COMMITMENTS AND CONTINGENCIES

Commitments

We lease various buildings and vehicles, computer and office equipment and other facilities under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $7,669 in Fiscal 2016 , $7,956 in Fiscal 2015 and $6,803 in Fiscal 2014 .

Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year for the fiscal years ending September 30 are as follows: 2017 — $5,984 ; 2018 — $5,016 ; 2019 — $3,048 ; 2020 — $1,314 ; 2021 — $560 ; after 2021 — $209 .

Gas Utility has gas supply agreements with producers and marketers with terms not exceeding 16 months. Gas Utility also has agreements for firm pipeline transportation, natural gas storage and peaking service which Gas Utility may terminate at various dates through Fiscal 2030 . Gas Utility’s costs associated with transportation and storage service agreements are included in its annual PGC filings with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices.

Electric Utility purchases its electricity needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2017 .

Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2016 , for fiscal years ending September 30 are as follows: 2017 — $205,548 ; 2018 — $142,208 ; 2019 — $120,142 ; 2020 — $80,443 ; 2021 — $54,430 ; after 2021 — $134,978 .

Contingencies

Environmental Matters

F- 26

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

UGI Utilities and its subsidiaries have entered into agreements with the DEP to address the remediation of former MGPs in Pennsylvania. CPG is party to a Consent Order and Agreement (“CPG-COA”) with the DEP requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which 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, required environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100 , 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, 2016 and 2015 , our accrued liabilities for estimated environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11,326 and $13,758 , respectively. CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable.

In May 2016, UGI Gas executed a Consent Order and Agreement (“UGI Gas-COA”) with the DEP with an effective date of October 1, 2016. The UGI Gas-COA will terminate in September 2031 if not extended by the parties. The UGI Gas-COA requires UGI Gas to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP related facilities were operated (“UGI Gas MGP Properties”). Under this agreement, required environmental expenditures related to the UGI Gas MGP Properties are capped at $2,500 in any calendar year. At September 30, 2016, our accrued liabilities for estimated environmental investigation and remediation costs related to the UGI Gas-COA totaled $43,737 . UGI Gas has recorded an associated regulatory asset for these costs because recovery of these costs from customers is probable (See Note 4 ).

There are pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

F- 27

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

13. FAIR VALUE MEASUREMENTS

Derivative Instruments

The following table presents, on a gross basis, our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2 , as of September 30, 2016 and 2015 :



	Asset (Liability)
	Level 1			Level 2			Level 3		Total
September 30, 2016
Derivative instruments:
Assets:
Commodity contracts	$	4,506		$	4		$	—	$	4,510
Liabilities:
Commodity contracts	$	(263	)	$	(294	)	$	—	$	(557	)
September 30, 2015
Derivative instruments:
Assets:
Commodity contracts	$	934		$	373		$	—	$	1,307
Liabilities:
Commodity contracts	$	(4,560	)	$	(1,388	)	$	—	$	(5,948	)
Interest rate contracts	$	—		$	(7,016	)	$	—	$	(7,016	)

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

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2016 , were $675,000 and $770,781 , respectively. The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2015 , were $622,000 and $681,415 , respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt (Level 2).

14. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We are exposed to certain market risks associated with our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations. For more information on the accounting for our derivative instruments, see Note 2 .

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by

F- 28

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 2016 and 2015 , the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 18.4 million dekatherms and 18.9 million dekatherms, respectively. At September 30, 2016 , the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 4 ).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At September 30, 2016 and 2015 , a majority of such contracts were subject to the NPNS exception under GAAP.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to customers through the DS mechanism (see Note 4 ). At September 30, 2016 and 2015 , the total volumes associated with FTRs totaled 58.3 million kilowatt hours and 277.1 million kilowatt hours, respectively. At September 30, 2016 , the maximum period over which we are economically hedging electricity congestion is 8 months.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. At September 30, 2016 and 2015 , the gasoline volumes were not material.

Interest Rate Risk

Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. On March 31, 2016, concurrent with the pricing of the Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities settled all of its then-existing IRPA contracts associated with such debt at a loss of $35,975 . Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs has been recorded in AOCI and will be recognized in interest expense as the associated future interest expense impacts earnings. See Note 7 for additional information on the 2016 Note Purchase Agreement. At September 30, 2016 , we had no unsettled IRPAs. At September 30, 2015 , the total notional amount of our debt associated with unsettled IRPA contracts was $250,000 .

At September 30, 2016 , the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,426 .

Derivative Instrument Credit Risk

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2016 and 2015 , restricted cash in brokerage accounts totaled $583 and $6,602 , respectively.

Offsetting Derivative Assets and Liabilities

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

F- 29

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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

Fair Value of Derivative Instruments

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of September 30, 2016 and 2015 :



	2016			2015
Derivative assets:
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	$	4,472		$	1,307
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	38			—
Total derivative assets - gross	4,510			1,307
Gross amounts offset in the balance sheet	(247		)	(373		)
Total derivative assets - net	$	4,263		$	934

Derivative liabilities:
Derivatives designated as hedging instruments:
Interest rate contracts	$	—		$	(7,016	)
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	(499		)	(5,584		)
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	(58		)	(364		)
Total derivative liabilities - gross	(557		)	(12,964		)
Gross amounts offset in the balance sheet	247			373
Total derivative liabilities - net	$	(310	)	$	(12,591	)

F- 30

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Effect of Derivative Instruments

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Consolidated Statements of Income and changes in AOCI for Fiscal 2016 , Fiscal 2015 and Fiscal 2014 :



	Loss Recognized in AOCI								Loss Reclassified from AOCI into Income									Location of
	2016			2015			2014		2016			2015			2014			Loss Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	(28,958	)	$	(7,016	)	$	—	$	(2,680	)	$	(2,674	)	$	(2,679	)	Interest expense

	Loss Recognized in Income																	Location of Loss
	2016			2015			2014											Recognized in Income
Derivatives Not Subject to
PGC and DS Mechanisms:
Gasoline contracts	$	(88	)	$	(761	)	$	—										Operating and administrative expenses/other operating income, net

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

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

15. ACCUMULATED OTHER COMPREHENSIVE INCOME

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

F- 31

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Changes in AOCI, net of tax, during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 are as follows:



	Postretirement Benefit Plans			Derivative Instruments Net Losses			Total
AOCI - September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
Reclassifications of benefit plans actuarial losses and net prior service credits	385			—			385
Reclassifications of net losses on IRPAs	—			1,567			1,567
Benefit plans, principally actuarial losses	(1,413		)	—			(1,413		)
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 net losses on IRPAs are reflected in interest expense on the Consolidated Statements of Income.

16. SEGMENT INFORMATION

We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The PNG HVAC Business, prior to its sale in June 2015, did not meet the quantitative thresholds for separate segment reporting under GAAP relating to business segment reporting and has been included in “Other” below.

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

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

F- 32

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Financial information by business segment follows:



	Total		Gas Utility		Electric Utility		Other
2016
Revenues	$	768,484	$	677,387	$	91,097
Cost of sales	$	289,786	$	239,163	$	50,623
Depreciation and amortization	$	67,303	$	62,451	$	4,852
Operating income	$	200,901	$	189,412	$	11,489
Interest expense	$	37,630	$	35,786	$	1,844
Income before income taxes	$	163,271	$	153,626	$	9,645
Total assets	$	2,743,091	$	2,570,297	$	172,794
Goodwill	$	182,145	$	182,145	$	—
Capital expenditures	$	262,503	$	251,261	$	11,242
2015
Revenues	$	1,041,581	$	933,080	$	107,577	$	924
Cost of sales	$	510,784	$	448,617	$	62,167	$	—
Depreciation and amortization	$	63,590	$	58,974	$	4,616	$	—
Operating income	$	241,667	$	226,485	$	14,153	$	1,029
Interest expense	$	41,128	$	39,112	$	2,016	$	—
Income before income taxes	$	200,539	$	187,373	$	12,137	$	1,029
Total assets	$	2,505,984	$	2,360,156	$	145,828	$	—
Goodwill	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	197,684	$	189,671	$	8,013	$	—
2014
Revenues	$	1,086,889	$	977,333	$	108,072	$	1,484
Cost of sales	$	562,942	$	496,762	$	66,180	$	—
Depreciation and amortization	$	59,219	$	54,816	$	4,403	$	—
Operating income	$	246,400	$	236,219	$	9,668	$	513
Interest expense	$	38,471	$	36,602	$	1,869	$	—
Income before income taxes	$	207,929	$	199,617	$	7,799	$	513
Total assets	$	2,352,143	$	2,211,618	$	140,525	$	—
Goodwill	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	164,180	$	156,425	$	7,755	$	—

17. OTHER OPERATING (EXPENSE) INCOME, NET

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



	2016			2015			2014
Non-tariff service income	$	2,633		$	4,760		$	2,670
Environmental matters	(2,918		)	1,152			297
Construction service income	—			2,175			—
Sale of HVAC Business	—			1,065			—
PGC interest on over (under) collection	(1,740		)	(606		)	1,388
Other, net	25			323			4
Total other operating (expense) income, net	$	(2,000	)	$	8,869		$	4,359

F- 33

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

18. RELATED PARTY TRANSACTIONS

From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years . At September 30, 2016 , UGI Utilities was a party to one SCAA with Energy Services, and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , these payments were not material. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $12,739 , $16,849 and $38,299 in Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in other current liabilities on the Consolidated Balance Sheets, were $8,100 and $10,700 at September 30, 2016 and 2015 , respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , revenues associated with sales to Energy Services totaled $30,743 , $79,182 and $109,913 , respectively. Also from time to time, the Company 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 2016 , Fiscal 2015 and Fiscal 2014 , such purchases totaled $35,067 , $85,383 and $128,076 , respectively.

F- 34

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

19. QUARTERLY DATA (unaudited)

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



	December 31,				March 31,				June 30,				September 30,
	2015		2014		2016		2015		2016		2015		2016			2015
Revenues	$	197,982	$	287,306	$	322,047	$	500,573	$	140,283	$	143,490	$	108,172		$	110,212
Operating income	$	48,296	$	75,640	$	114,481	$	142,699	$	29,815	$	20,184	$	8,309		$	3,144
Net income (loss)	$	23,351	$	38,839	$	63,294	$	79,589	$	12,603	$	7,307	$	(1,875	)	$	(4,680	)

F- 35

UGI UTILITIES, INC. AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

(Thousands of dollars)



	Balance at beginning of year		Charged to costs and expenses		Other				Balance at end of year
September 30, 2016
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	5,599	$	7,760	$	(9,413	)	⁽¹⁾	$	3,946

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

September 30, 2014
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	5,519	$	13,149	$	(11,676	)	⁽¹⁾	$	6,992


(1)	Uncollectible accounts written off, net of recoveries

S- 1

EXHIBIT INDEX



Exhibit No.		Description

10.19		Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, LLC, effective November 1, 2015.
12.1		Computation of Ratio of Earnings to Fixed Charges

23.1		Consent of Ernst & Young LLP.

23.2		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

EXHIBIT 10.19

GAS SUPPLY AND DELIVERY SERVICE AGREEMENT

Contract UGIU-P-1010

THIS Gas Supply and Delivery Service Agreement (this "Agreement") is made and entered into as of November I, 2015 (the "Effective Date"), by and among UGI Utilities, Inc., a Pennsylvania Corporation ("Utility") having an address at 2525 North 12' ^h Street, Suite 360, Reading, PA 19605, and UGI Energy Services, LLC, a Pennsylvania limited liability company ("UGIES"), having an address at One Meridian Boulevard, Suite 2C01, Wyomissing, PA 19610. Utility and UGIES may herein be referred to individually as a "Party" or collectively as the "Parties.”

WHEREAS , Utility is a local distribution company that is principally engaged in the business of distributing natural gas to residential, commercial, and industrial end-use customers located within its service territory of Pennsylvania;

WHEREAS , UGIES is an energy marketer and supplier that is principally engaged in the business of selling natural gas and managing assets for the sale and delivery of natural gas in Pennsylvania and other states; and

WHEREAS , Utility desires to receive, and UGIES has agreed to provide, certain gas supply and related delivery services to Utility, subject to the terms and conditions of this Agreement.

NOW THEREFORE , in consideration of the covenants contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:

SECTION 1. Definitions

1.1 "Day-Ahead Nomination" shall have the meaning set forth in Section 4 hereof.

1.2 "Dekatherm" or "Dth" shall mean one million British Thermal Units (MMBtu).

13 "Delivery Point" or "Delivery Points" shall mean any mutually agreed upon interconnection between Utility's distribution system and: (a) Texas Eastern Transmission ("Texas Eastern"), (b) UGIES's peaking facilities, or (c) PennEast Pipeline; the point(s) of physical interconnection at Transcontinental Pipeline's ("Transco") Master Meter No. 1006691; or any other mutually agreeable delivery points.

1.4 "Firm" shall mean, in reference to a Party's obligation to deliver or receive Natural Gas, the requirement that the full quantity of Natural Gas nominated for receipt or delivery must be delivered or received by the obligated Party, except for reasons for Force Majeure under Section 7 or Waiver of Delivery under Section 3.5.

1.5 "Gas Day" shall refer to the NAESB-defined gas day, which shall be one

continuous twenty-four (24) hour period, commencing at 10:00 a.m. ECT.

1.6 "Maximum Daily Quantity" or "MDQ" shall have the meaning set forth in Section 3.2 hereof.

1.7 "Natural Gas" shall mean any mixture of hydrocarbons and noncombustible

gases in a gaseous state, including vaporized LNG and propane air.

1.8 "Nomination" shall mean a notice provided by Utility to UGIES setting forth its

delivery requirements, pursuant to Section 4 hereof. The Parties shall maintain contacts for twenty-four (24) hours per day, seven (7) days per week, for the purposes of providing and receiving Nominations.

1.9 "Replacement Supply" shall mean Natural Gas quantities obtained by Utility to

replace a portion of a Scheduled Quantity that UG1ES fails to deliver in accordance with a Daily Nomination.

1.10 "Scheduled Quantity" shall mean, for a particular Delivery Day, the quantity of Natural Gas that Utility requests in a Nomination and UGIES confirms.

1.11 "Total Winter Entitlement" or "TWE" shall mean the maximum quantity of Natural Gas that Utility is entitled to receive and UGIES is obligated to deliver on a Firm basis during a Winter Season. The TWE for each Winter Season during the Primary Term shall be as follows:

Winter Season TWE

2015 through 2016 854,895 Dth

2016 through 2017 914,415 Dth

2017 through 2018 1,141,935 Dth

2018 through 2019 1,369,455 Dth

2019 through 2020 1,596,975 Dth

1.12 "Winter Season" shall refer to the period beginning at 10:00 a.m. ECT November 1 and ending at 9:59 a.m. ECT the following March 31.

SECTION 2. Term

This Agreement shall be effective for a period commencing on and including the Delivery Day of November 1, 2015, and expiring on and including the Delivery Day of March 31, 2020 (the "Primary Term"). Utility shall have the right, in its sole discretion, to extend the Agreement for a subsequent five (5) year term (with each such period referred to as a "Rollover Term") by providing written notice to UGIES of its intent to extend the Agreement at least one (I) year prior to the expiration of the Primary Term or any Rollover Tenn. If Utility elects to extend the Agreement for one or more Rollover Terms, the MDQ and all terms and conditions of service shall remain unchanged unless expressly agreed to by the Parties in writing; provided however, that the applicable Reservation Charge for the Rollover Term will be adjusted in accordance with Section 5.3 hereof.

SECTION 3. Character of Service

3.1 Delivery Obligation. UGIES shall sell and deliver and Utility shall have the

option to purchase and the right to receive Natural Gas on any day during the Primary Term and any Rollover Term. UGIES's obligation to deliver and Utility's obligation to receive Natural Gas shall be Firm for any Nomination quantity, up to the applicable MDQ. Service will be provided using UGIES's primary firm pipeline capacity, incremental peaking plant capacity, or a reasonably acceptable asset-backed substitute. UGIES's obligation to deliver and Utility's obligation to receive Natural Gas shall he Firm for any Nomination up to the applicable MDQ. Service will only be subject to interruption for reasons of Force Majeure.

3.2 Maximum Daily Quantity. The "Maximum Daily Quantity" or "MDQ" shall

mean the maximum quantity of Natural Gas that Utility may require UGIES to deliver on a Firm basis, on any day during a Winter Season. The MDQ for each Winter Season during the Primary Tenn shall be as follows:

Winter Season MDQ

2015 through 2016 56,993 Dth

2016 through 2017 60,961 Dth

2017 through 2018 76,129 Dth

2018 through 2019 91,297 Dth

2019 through 2020 106,465 Dth

[Remainder of this page intentionally left blank]

3.3 Allocation of MDQ to Delivery Points. The maximum quantity of Natural Gas that Utility may require UGIES to deliver to the agreed upon Delivery Points on a Firm basis on any day during a Winter Season, up to the applicable MDQ, shall be as follows:



Winter Season	MDQ	Delivery Point(s)
2015 through 2016	Up to 38,993 Dth	Any mutually agreeable interconnection between Utility's distribution system and Texas Eastern
2015 through 2016	Up to 18,000 Dth	Utility's physical interconnection at Transco Meter No. 1006691
2016 through 2017	Up to 42,961 Dth	My mutually agreeable interconnection between Utility's distribution system and Texas Eastern
2016 through 2017	Up to 18,000 Dth	Utility's physical interconnection at Transco Meter No. 1006691
2017 through 2018	Up to 8,129 Dth	Any mutually agreeable interconnection between Utility's distribution system and Texas Eastern
	Up to 18,000 Dth	Utility's physical interconnection at Transco Meter No. 1006691
	Up to 50,000 Dth	Any mutually agreeable interconnection between Utility's distribution system and UGIES's peaking facilities
2018 through 2019	Up to 25,000 Dth	Utility's physical interconnection either at Transco Meter No. 1006691 or any mutually agreeable interconnection between Utility's distribution system and PennEast Pipeline
2018 through 2019	Up to 66,297 Dth	My mutually agreeable interconnection between Utility's distribution system and UGIES's peaking facilities
2019 through 2020	Up to 25,000 Dth	Utility's physical interconnection either at Transco Meter No. 1006691 or any mutually agreeable interconnection between Utility's distribution system and PennEast Pipeline
2019 through 2020	Up to 81,465 Dth	Any mutually agreeable interconnection between Utility's distribution system and UGIES's peaking facilities

3.4 Authorized Overruns. If Utility wishes to overrun its MDQ or TWE on any

Delivery Day, it must request authorization from UGIES in advance. UGIES will authorize and permit such overruns if it reasonably determines that it is operationally feasible to do so. The Parties shall agree in advance on the Commodity Charge to apply to any Natural Gas delivered to Utility in excess of its MDQ or TWE.

3.5 Waiver of Delivery Obligation. On any Delivery Day, Utility shall maintain its

distribution facilities downstream of the Delivery Point(s) in a way that permits UGIES to deliver the Scheduled Quantities, otherwise UGIES shall be relieved of its obligation to deliver the Scheduled Quantities for the period and to the extent that Utility's distribution facilities do not permit such deliveries. Once Utility's distribution facilities have been corrected by Utility, UGIES shall use commercially reasonable efforts to supply the entire amount nominated by Utility for that Delivery Day. Any waiver of delivery obligations pursuant to this Section 3.5 shall not affect Utility's right to receive its TWE during any Winter Season.

SECTION 4. Nomination Procedure

Utility shall have the right, but not the obligation, to make a Day-Ahead Nomination for quantities up to the MDQ on trading days defined by Intercontinental Exchange ("ICE"), for delivery on a subsequent ICE delivery day(s). Utility shall notify UGIES, either verbally or in writing, of the requested quantity by 9:30 a.m. ECT on the ICE trading day.

SECTION 5. Charges

5.1 Reservation Charge. Utility shall pay UGIES a Reservation Charge during the

Primary Term, as follows:



Primary Term	Annual Charge
November 2015 through March 2016	$11,626,572.00
November 2015 through March 2016	$11,399,707.00
November 2017 through March 2018	$11,723,866.00
November 2017 through March 2018	$14,059,738.00
November 2019 through March 2020	$16,395,610.00

The Reservation Charge above shall be paid in five (5) equal installments of due on November 1, December 1, January 1, February 1, and March 1, during each year of the Primary Term, as follows:



Primary Term	Monthly Installment Charge
November 2015 through March 2016	$2,325,314.40
November 2015 through March 2016	$2,279,941.40
November 2017 through March 2018	$2,344,773.20
November 2017 through March 2018	$2,811,947.60
November 2019 through March 2020	$3,279,122.00

The Reservation Charge shall be billed and paid in accordance with Section 6 hereof

5.2 Commodity Charge. Unless Utility elects to lock a fixed price with UGIES in

accordance with paragraph (b), below, Utility shall not be obligated to purchase or receive any Natural Gas from UGIES under this Agreement. For all quantities of Natural Gas sold and delivered by UGIES, Utility shall pay a Commodity Charge, which shall be determined according to the following alternatives:


(a)	For all quantities of Natural Gas delivered to Utility's city gate, made pursuant to a Day-Ahead Nomination up to the MDQ and TWE, Utility shall pay a Commodity Charge equal to the published Platt's Gas Daily index price for Texas Eastern Zone M2, plus the Texas Eastern maximum variable rates from Zone M2 to Zone M3.


(b)	Utility will have the right at any time to lock-in a fixed Commodity Charge for any term and quantity up to the MDQ throughout the Agreement term. The Commodity Charges for locked-in quantities shall be as agreed to by the Parties based on prevailing market conditions at the time the lock-in is made. Utility's right to lock-in a quantity of Natural Gas shall be limited as follows:


(i)	The maximum quantity of Natural Gas for which Utility may lock in a fixed Commodity Charge shall equal the TWE less any quantities previously locked-in for the Winter Season.

(ii)

Unless otherwise agreed, Utility shall notify UGIES of its intention to lock-in the Commodity Charge by no later than 10:00 a.m. ECT on the penultimate trading day for the NYMEX Natural Gas contract to the month in which such lock-in will apply. Such notice shall identify the quantity of Natural Gas to be locked-in for each month of delivery. UG1ES shall promptly communicate to Utility any limitations on the lock-in quantity identified in Utility's notice and the Parties will utilize commercially reasonable efforts to facilitate the lock-in to the extent practicable.


(iii)	If Utility has locked-in a fixed price, Utility shall be required to purchase and take delivery of the quantity of Natural Gas for which a locked-in price is established.

The Commodity Charges determined in accordance with sub-paragraphs (a) and (b) above shall be billed and paid on a monthly basis, in accordance with Section 6.

5.3 Rollover Period Price Adjustment. Utility shall have a Right of First Refusal ("ROFR") to extend the Agreement upon the expiration of the Primary Term or any Rollover Term. In the event that Utility elects to extend the Agreement for one or more Rollover Terms, the Reservation Charge applicable to each Rollover Term shall be escalated based on the U.S. Gross Domestic Product Implicit Price Deflator, using 2019 as the base. For any subsequent term, the escalation fee will be based on the U.S. Gross Domestic Product Implicit Price Deflator using the index from the penultimate year of the subsequent term.

SECTION 6. Billing and Payment

UGIES will invoice Utility each month of the Winter Season for the Reservation Charges due in accordance with Section 5.1, plus any applicable taxes in accordance with Section 10 hereto. UGIES will invoice Utility monthly for all Commodity Charges applicable to service rendered during the prior month, plus any applicable taxes in accordance with Section 10 hereto. Utility shall pay UGIES the full amount of such Commodity Charges and applicable taxes, due no later than the twentieth (20 ^th ) day of the month following Utility's receipt of the invoice. All payments shall be made by Wire Transfer (EFT) to UGIES's banking institution, designated as follows:

Mellon Bank, N.A.

Pittsburgh, PA

Account No. XXXXXXX

ACH No. XXXXXXX

SECTION 7. Force Majeure

7.1 Generally. Except as otherwise set forth herein, deliveries under this Agreement shall be Firm and shall not be subject to curtailment, interruption, or proration, except as the result of Force Majeure. In the event that either UGIES or Utility is unable, wholly or in part, by a Force Majeure event to carry out its obligations under this Agreement, it is agreed that upon such Party's giving notice and full particulars of such Force Majeure event, in accordance with Section 7.4, then the obligations of the Party giving such notice

insofar as they are affected by such Force Majeure event shall be suspended, from the inception, and during the continuance of any inability so caused, but for no longer period. The Party claiming Force Majeure shall not be excused from its responsibility for imbalance charges.

7.2 Included Events. Force Majeure shall include, but not be limited to, the following: (i) physical events such as acts of God, landslides, lightning, earthquakes, fires, storms, or storm warnings, such as hurricanes which result in evacuation of the affected area, floods, washouts, explosions, breakage or accident or necessity of repairs to machinery or equipment or lines of pipe, except as provided in Section 7.3; (ii) interruption and/or curtailment of primary Firm transportation and/or storage by transporters; (iii) acts of others such as strikes, lockouts, or other industrial disturbances, riots, sabotage, terrorist actions, insurrections, or wars; and (iv) governmental actions such as necessity for compliance with any court order, law, statute, ordinance, regulation, or policy having the same effect of law promulgated by a governmental authority having jurisdiction.

7.3 Excluded Events.

(a)

Neither Party shall be entitled to the benefit of the provisions of Force Majeure to the extent that performance is affected by any or all of the following circumstances: (i) the curtailment of interruptible or secondary Firm transportation; (ii) the contractual non-performance or negligence of any affiliate, independent contractor, agent, or employee of UGIES in operating or maintaining any upstream pipeline facilities utilized by UGIES; (iii) the Party claiming excuse failed to remedy the condition and to resume the performance of such covenants or obligations with reasonable dispatch; (iv) economic hardship, to include, without limitation, UGIES's ability to sell Natural Gas at a higher or more advantageous price than the Agreement price, Utility's ability to purchase Natural Gas at a lower or more advantageous price than the Agreement price, or a regulatory agency disallowing, in whole or in part, the pass through costs resulting from this Agreement; (v) the loss of Utility's market(s) or Utility's inability to use or resell Natural Gas purchased hereunder, except, in either case, as provided in Section 7.2; or (vi) the loss or failure of UGIES's gas supply, including but not limited to the failure of LIGIES's gas supply to be delivered to an upstream receipt point on UGIES's pipeline capacity, or depletion of reserves, except, in either case, as provided in Section 7.2.


(b)	In addition to the foregoing, for supplies sourced from local Marcellus production wells, UGIES shall not be entitled to the benefit of Force Majeure to the extent that performance is affected by any or all of the following circumstances: (x) any well failures or freeze-offs; and (y) any failure of conditioning equipment such as regulation, compression, or dehydration equipment.

7.4 Notice. The Party asserting Force Majeure shall provide immediate written notice to the other Party of the occurrence of a Force Majeure event. Notice shall include: (i) a detailed explanation of the event that has occurred; (ii) the known or expected impact on the Party's ability to perform; and (iii) the period of time during which the Party's performance will be impacted. The Party asserting Force Majeure will remedy the Force Majeure event and resume performance of its obligations hereunder as soon as reasonably possible.

SECTION 8. Failure to Deliver or Receive Gas

8.1 Failure to Deliver. Unless otherwise excused by the waiver of a delivery obligation under Section 3.5 or a Force Majeure event under Section 7.2, if UGIES fails to deliver all or a portion of a Scheduled

Quantity on any Delivery Day, UGIES shall pay Utility an amount equal to the difference between: (i) the Nomination quantity for the Delivery Day and (ii) the quantity delivered during such Delivery Day (such difference being the "Deficiency Amount"); times the positive difference between (iii) the applicable Commodity Charge as determined under Section 5.2 hereof and (iv) the cost of Replacement Supply as determined by Utility in a commercially reasonably manner within a reasonable time after UGIES fails to deliver the Deficiency Amount.

8.2 Failure to Receive. Unless otherwise excused by the waiver of a delivery obligation under Section 3.5 or a Force Majeure event under Section 7.2, if Utility fails to take all or a portion of the Scheduled Quantity for the Delivery Day, Utility shall pay UGIES an amount equal to the Deficiency Amount times the positive difference between (i) the applicable Commodity Charge as determined under Section 5.2 hereof and (ii) the price received by UGIES from the sale of the Deficiency Amount as determined by UGIES in a commercially reasonable manner within a reasonable time after Utility fails to take delivery of the Deficiency Amount.

83 Duty to Mitigate. Each Party has an affirmative duty to mitigate in good faith the extent of damages that may arise from the other Party's failure to discharge its receipt or delivery obligations under this Agreement. In the event a Party fails to properly discharge its duty to mitigate, any amounts otherwise due under Sections 8.1 and 8.2 hereunder shall be reduced by an amount that would not have been incurred had such duty been properly discharged.

8.4 Exclusive Remedy. The remedies set forth in Sections 8.1 and 8.2 shall be the exclusive remedies available to a Party for the other Party's failure to discharge its firm receipt or delivery obligation hereunder.

SECTION 9. Indemnification

Except as otherwise limited pursuant to this Agreement, each Party shall indemnify, defend, and hold harmless the other Party, the other Party's officers, employees, shareholders, directors and agents, and their respective successors and assigns from and against any and all third party claims, demands, liabilities, losses, expenses, costs, obligations, recoveries, or damages of any nature whatsoever, whether accrued, absolute, contingent, or otherwise, including, without limitation, court costs and attorneys' fees (whether or not suit is brought) arising out of, resulting from, or relating to: (i) negligence, gross negligence, bad faith actions, or willful misconduct in connection with this Agreement, and (ii) any Natural Gas while it is in the Party's control or possession. This Section 9 shall survive termination of the Agreement.

SECTION 10. Taxes

10.1 Responsibility. Responsibility for payment of all kinds of taxes applicable to Natural Gas sold hereunder shall be allocated as follows:


(a)	OGLES shall pay, or cause to be paid, and Utility shall be held harmless by UGIES, for the payment of all taxes imposed on or with respect to the Natural Gas sold or delivered hereunder by UGIES for which the taxable incident arises or occurs prior to the delivery of Natural Gas to the Delivery Point(s); and


(b)	Utility shall pay or cause to he paid, and UGIES shall be held harmless by Utility, for the payment of all taxes imposed on or with respect to the Natural Gas sold or delivered by UGIES hereunder for which the taxable incident arises or occurs upon delivery or after the Natural Gas is delivered to the Delivery Point(s).

10.2 Reimbursement. If a Party is required to remit or pay taxes that are the other Party's responsibility hereunder (including any tax which would have been incurred by a Party absent this Agreement), the Party responsible for such taxes shall promptly reimburse the other Party therefor.

SECTION 11. Title and Warranties

11.1 Warranty of Title. UGIES hereby warrants good and merchantable title to the Natural Gas sold by it hereunder or the right to sell the same, and warrants that all Natural Gas delivered to Utility shall be free from all liens, encumbrances, and adverse claims. Upon delivery to Utility, title shall be passed to Utility.

11.2 Warranty Disclaimers. Except as expressly stated herein, neither Party provides any warranties to the other, express or implied, including implied warranties of merchantability and fitness for a particular purpose.

SECTION 12. Notices

12.1 Generally. All invoices, payments, and other communications made hereunder shall he delivered to the addresses specified in writing by the Parties from time to time.

12.2 Means of Delivery. Unless a specific means of notice is expressly stated herein, all notices required hereunder may be sent by mutually acceptable means, provided however that (i) notices shall be deemed given on a Business Day by the addressee, (ii) notices sent electronically shall be deemed received upon the sending Party's receipt of confirmation of successful transmission, and (iii) any notice received on a day other than a Business Day or after 5:00 p.m. ECT on a Business Day shall be deemed received at the start of the next following Business Day.

123 Addresses. Notices shall be provided to the Parties at the following addresses: If to UGI Energy Services, LLC, to:

UGI Energy Services, LLC

One Meridian Boulevard, Suite 2C01

Wyomissing, PA 19610

Telephone: (610) 373-7999

Facsimile: (610) 374-4288

Attention: V.P. Gas Supply & Customer Operations

If to UGI Utilities, Inc., to:

UGI Utilities, Inc.

2525 North It Street, Suite 360

Reading, PA 19605

Telephone: (610) 796-3601

Facsimile: (610) 796-3595

Attention: V.P. Supply

SECTION 13. Assignment

This Agreement shall be binding upon and inure to the benefit of the respective successors and assigns of the Parties; provided, however that this Agreement shall not be transferred or assigned, by operation of law or otherwise, by UGIES or Utility without the other Party's prior written consent, which consent shall not be unreasonably withheld or delayed. Notwithstanding the foregoing, either Party may assign its rights and obligations hereunder to any parent, subsidiary, or affiliate, upon prior written notice to the other Party.

SECTION 14. Confidentiality

The existence, terms, and conditions of this Agreement shall be and remain confidential to the extent permitted by law.

SECTION 15. Laws and Regulatory Bodies

15.1 Generally. This Agreement shall be subject to all federal and state laws and to the orders, rules, and regulations of any duly constituted federal or state regulatory body or authority having jurisdiction. The interpretation and enforceability of this Agreement shall be governed by the laws of the Commonwealth of Pennsylvania, without recourse to its conflict of law principles.

15.2 Regulatory Event. In the event that any regulatory body directly or indirectly asserts jurisdiction over the Parties' obligations and, as a result, performance under the Agreement becomes commercially impracticable by either Party ("Regulatory Event"), then the Parties shall negotiate in good faith in order to amend the Agreement (and the Parties' obligations and rights thereunder) to cure the Regulatory Event. In the event that the Regulatory Event cannot be reasonably cured to the satisfaction of the affected Party, the Party so affected shall have the right to terminate the Agreement upon thirty (30) days written notice to the other Party. A regulatory agency disallowing, in whole or in party, the pass through costs resulting from this Agreement shall not constitute a Regulatory Event.

SECTION 16. Dodd-Frank Provisions

16.1 The terms set forth below shall have the meanings ascribed to them:

"CFTC" means the U.S. Commodity Futures Trading Commission.

"CFTC Regulations" means the rules, regulations, orders, supplementary infonnation, guidance, questions and answers, staff letters, and interpretations published or issued by the CFTC, in each applicable case as amended, and when used herein may also include specific citations to Titles, Parts, or Sections of Title 17 of the Code of Federal Regulations without otherwise limiting the applicability of other rules, regulations, orders, supplementary infonnation, guidance, questions and answers, staff letters, and interpretations.

"Commodity Exchange Act" means the U.S. Commodity Exchange Act, as amended, 7 USC Section 1, et seg.

"Commodity Option" means a "Commodity Option" within the meaning of CFTC Regulations.

"SEC" means the U.S. Securities and Exchange Commission.

"Swap" means a "swap" as defined in Section 1a(47) of the Commodity Exchange Act and CFTC Regulations.

"Trade Option" means a Commodity Option between the Parties under the Agreement that meets the conditions contained in CFTC Regulation 32.3(a).

16.2 The Parties shall seek to agree at the time a transaction is executed whether the transaction is a Trade Option or a contract, excluded from the defined term Swap or otherwise exempt from reporting. If a transaction is a Trade Option, each Party shall report the transaction in accordance with CFTC Regulation Part 32 and any applicable CFTC no-action letter. If the Parties cannot agree as to whether a transaction is a Trade Option or otherwise exempt from reporting, then each Party shall make its own determination.

16.3 Each Party warrants and represents that, as of the effective date of this Agreement and on each date that it enters into a transaction subject to this Agreement, that:

(i) It regularly makes or takes delivery of the commodity that is the subject of the transactions that are entered into subject to this Agreement in the ordinary course of its business, and any transaction it enters into subject to this Agreement is entered into in connection with such business;

(ii) To the extent that any transaction entered into subject to this Agreement contains an embedded option, then either the factors determining the exercise of such option are beyond the control of the exercising Party, or if it is the offeree (i.e. Utility) of such option, it is a producer, processor, commercial user of, or a merchant handling the commodity, products, or byproducts thereof, that is/are the subject of the transaction (a "Commercial Party") and that it is entering into the transaction solely for purposes related to its business as such; and if it is the offeror (i.e. UGIES) of such option, it is either a Commercial Party and it is entering into the transaction solely for purposes related to its business as such or it is an "eligible contract participant," as defined in Section la(18) of the Commodity Exchange Act and the rules, regulations, orders, and interpretations of the CFTC and, as applicable, the SEC; and

(iii) It intends to make or take physical delivery of the commodity that is the subject of any transaction it enters into subject to this Agreement, in accordance with the terms and provisions of any applicable confirmations and this Agreement.

16.4 Each Party will promptly notify the other Party if any representation is made by such Party, with respect to the Dodd-Frank Provisions, becomes materially incorrect or misleading in any respect and will promptly update such representation.

SECTION 17. Limitation of Damages

UNLESS EXPRESSLY PROVIDED HEREIN, A PARTY'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY. NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS, OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION, OR OTHERWISE. THIS PARAGRAPH SHALL SURVIVE EXPIRATION OR TERMINATION OF THIS AGREEMENT.

SECTION 18. Miscellaneous

18.1 Waiver. No waiver of any breach hereof shall be held to be a waiver of any other or subsequent beach.

18.2 Set-offs. Each Party reserves to itself all rights, set-offs, counterclaims, and other defenses to which it is or may be entitled to under applicable law.

18.3 Documentation. Each Party shall provide all documents necessary to effectuate this Agreement and the transactions that underlie this Agreement.

18.4 Amendments. This Agreement, including Appendices hereto, may be amended or modified only by a writing signed by duly authorized representatives of both Parties.

18.5 Authorization. Utility and UGIES each represents to the other its respective belief that it has obtained all necessary corporation and regulatory authorizations to execute and perform its obligations under this Agreement.

IN WITNESS THEREOF, the Parties have executed this Agreement in duplicate by their respective duty authorized officers as of the day and year first written above.

UGI UTILITIES, INC.

By: /s/ Robert F. Beard

Name: Robert F. Beard

Title: President

UGI ENERGY SERVICES, LLC

By: /s/ Bradley C. Hall

Name: Bradley C. Hall

Title: President

[Signature Page to Gas Supply and Delivery Agreement]

UGI UTILITIES INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1

(Thousands of dollars)



	Year Ended September 30,
	2016		2015		2014		2013		2012
Earnings:
Earnings before income taxes	$	163,271	$	200,539	$	207,929	$	171,010	$	142,971
Interest expense	37,285		40,400		37,897		38,578		41,599
Amortization of debt discount and
expense	345		728		575		731		814
Estimated interest component of rental
expense	2,512		2,728		2,398		2,090		2,121
	$	203,413	$	244,395	$	248,799	$	212,409	$	187,505

Fixed Charges:
Interest expense	$	37,285	$	40,400	$	37,897	$	38,578	$	41,599
Amortization of debt discount and
expense	345		728		575		731		814
Allowance for funds used during
construction (capitalized interest)	602		407		227		286		10
Estimated interest component of rental
expense	2,512		2,728		2,398		2,090		2,121
	$	40,744	$	44,263	$	41,097	$	41,685	$	44,544

Ratio of earnings to fixed charges	4.99		5.52		6.05		5.10		4.21

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-3 No. 333-150719) of UGI Utilities, Inc. of our reports dated November 22, 2016 , with respect to the consolidated financial statements and schedule of UGI Utilities, Inc., and the effectiveness of internal control over financial reporting of UGI Utilities, Inc., included in this Annual Report (Form 10-K) for the year ended September 30, 2016.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

November 22, 2016

EXHIBIT 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-150719) of UGI Utilities, Inc. of our report dated November 28, 2014 relating to the financial statements and financial statement schedule, which appears in this Form 10‑K.

/s/PricewaterhouseCoopers LLP

Philadelphia, PA

November 22, 2016

EXHIBIT 31.1

CERTIFICATION

I, Robert F. Beard, certify that:


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


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


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


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


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


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


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


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


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


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


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



Date:	November 22, 2016
		/s/ Robert F. Beard
		Robert F. Beard President and Chief Executive Officer

EXHIBIT 31.2

CERTIFICATION

I, Daniel J. Platt, certify that:


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


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


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


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


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


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


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


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


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


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


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



Date:	November 22, 2016
		/s/ Daniel J. Platt
		Daniel J. Platt Vice President - Finance and Chief Financial Officer

EXHIBIT 32

Certification by the Chief Executive Officer and Chief Financial Officer

Relating to a Periodic Report Containing Financial Statements

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


(1)	The Company's annual report on Form 10-K for the period ended September 30, 2016 (the “Form 10-K”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and


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

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CHIEF EXECUTIVE OFFICER		CHIEF FINANCIAL OFFICER

/s/ Robert F. Beard		/s/ Daniel J. Platt
Robert F. Beard		Daniel J. Platt

Date:	November 22, 2016	Date:	November 22, 2016