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 whichthat 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, natural disasters 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.attack; and (18) continued analysis of recent tax legislation.

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.

UGI Utilities, Inc. (“UGI Utilities” or the “Company”) is a public utility company that owns and operates threea natural gas distribution utilitiesutility division that operates in Pennsylvania and portions of one Maryland county (“Gas Utility”) and an electric utility division that operates in Pennsylvania. We arePennsylvania (“Electric Utility”). The Company is 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, which prior to October 1, 2018, was comprised of UGI Utilities and two separate, wholly owned natural gas distribution utility subsidiaries, UGI Penn Natural Gas, Inc. (“PNG”), and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG have been consolidated by merger effective October 1, 2018 (the “Utilities Merger”), with UGI Utilities as the surviving entity. Gas Utility serves over 635,000more than 642,000 customers in eastern and central Pennsylvania and more than five hundred500 customers in portions of one Maryland county. UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas”. TheGas.” 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”PAPUC”) and, with respect to its several hundred customers in Maryland, the Maryland Public Service Commission.Commission (“MDPSC”). Electric Utility is regulated by the PUC.PAPUC.

UGI Utilities was incorporated in Pennsylvania in 1925. Our executive offices are located at 2525 N. 12th Street, Suite 360, Reading, Pennsylvania 19612, and our telephone number is (610) 796-3400. In this report, the terms “Company” and “UGI Utilities,” as well as the terms, “our,” “we,” and “its,” are sometimes used to refer to UGI Utilities, Inc. or, collectively UGI Utilities, Inc. and its consolidated subsidiaries. The terms “Fiscal 2018”,2019,” “Fiscal 2017”,2018,” “Fiscal 2016”2017” and “Fiscal 2015”2016” refer to the fiscal years ended September 30, 2019, September 30, 2018, September 30, 2017 September 30, 2016 and September 30, 2015,2016, respectively.

Gas Utility provides natural gas distribution services to over 635,000more than 642,000 customers in certificated portions of 44 eastern and central Pennsylvania counties through its distribution system. Contemporary materials, such as plastic or coated steel, comprise approximately 90% of Gas Utility's 12,300 miles of gas mains, with bare steel pipe comprising approximately 8% and cast iron pipe comprising approximately 2% of Gas Utility's gas mains. In accordance with Gas Utility’s agreement with the PUC,PAPUC, Gas Utility will replace the cast iron portion of its gas mains by March 2027 and the bare steel portion of its gas mains by September 2041. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock Haven, Pittston, Pottsville, and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility's service area are major production centers for basic industries such as specialty metals, aluminum, glass, and paper product manufacturing.manufacturing, and several power generation facilities. 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 20172018 was approximately 243264 billion cubic feet (“bcf”). System sales of gas accounted for approximately 23% of system throughput, while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for approximately 77% of system throughput.

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 Marcellus, Gulf Coast, Mid-Continent, Appalachian and MarcellusAppalachian sources. For its transportation and storage functions, Gas Utility has long-term agreements with a number of pipeline companies, including Texas Eastern Transmission, LP, Columbia Gas Transmission, LLC, Transcontinental Gas Pipeline Company, LLC, Dominion Transmission, Inc., ANR Pipeline Company, and Tennessee Gas Pipeline Company, L.L.C.

During Fiscal 2017,2018, Gas Utility purchased approximately 77.292.8 bcf of natural gas for sale to retail core-market customers (principally comprised of firm- residential, commercial and industrial customers that purchase their gas from Gas Utility (“retail core-market”)) and off-system sales customers. Eighty-five percent (85%)Nearly 94% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 15%6% of gas purchased by Gas Utility was supplied by approximately 3510 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.

Because many of its customers use gas for heating purposes, Gas Utility’s sales are seasonal. For Fiscal 2017,2018, approximately 60%59% of Gas Utility's sales volume was supplied, and approximately 90%96% of Gas Utility’s operating income was earned, during the peak heating season from October through March.

Natural gas is a fuel that competes with electricity and oil and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of the equipment. Natural gas generally benefits from a competitive price advantage over oil, electricity, and propane, although the price gap between natural gas and oil narrowed in recent years due to a reduction in the price of oil.years. 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.

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

Approximately 40%42% of Gas Utility’s annual throughput volume for commercial and industrial customers includes non-interruptible customers with firm rates with locations that afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. In addition, more than 20%nearly 17% of Gas Utility’s annual throughput volume for commercial and industrial customers is from customers who are served under interruptible rates and are also in a location near an interstate pipeline. Gas Utility has 38 such customers, 3435 of which have transportation contracts extending beyond Fiscal 2018.2019. The majority of these customers are served under transportation contracts having 3- to 10-year20-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.

Gas Utility anticipates having adequate pipeline capacity, peaking services, and other sources of supply available to it to meet the full requirements of all firm customers on its system through Fiscal 2018.2019. Supply mix is diversified, market priced, and delivered pursuant to a number of long-term and short-term primary firm transportation and storage arrangements, including transportation contracts held by some of Gas Utility's larger customers.

During Fiscal 2017,2018, Gas Utility supplied transportation service to nine10 electric generation facilities and installed new service to onethree co-generation facility.facilities. Gas Utility continues to seek new residential, commercial, and industrial customers for both firm and interruptible service. In Fiscal 2017,2018, Gas Utility connected approximately 2,0001,900 new commercial and industrial customers. In the residential market sector, Gas Utility added over 12,000 residential heating customers during Fiscal 2017.2018. Approximately 65%54% of these customers converted to natural gas heating from other energy sources, mainly oil and electricity. New home construction and existing non-heating gas customers who added gas heating systems to replace other energy sources primarily accounted for the other residential heating connections in Fiscal 2017.

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

Electric Utility supplies electric service to approximately 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania through a system consisting of over 2,200 miles of transmission and distribution lines and 13 substations. For Fiscal 2017,2018, approximately 55%56% of sales volume came from residential customers, 33%32% from commercial customers, and 12% from industrial and other customers.

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.PAPUC. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures” and Note 4 to Consolidated Financial Statements. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers. During Fiscal 2017, eleven2018, twelve retail electric generation suppliers provided energy for customers representing approximately 26%24% of Electric Utility’s sales volume. See “Gas Utility and Electric Utility Regulation and Rates - Electric Utility Rates.”

As a result of the Electricity Generation Customer Choice and Competition Act (“ECC Act”), all Pennsylvania retail electric customers have the ability to choose their retail electric generation supplier. Under the ECC Act and Act 129 of 2008, which revised the default service requirements contained in Chapter 28 of the Public Utility Code, Electric Utility remains the “default service” provider for its customers who do not choose an alternate retail electric generation supplier. In Fiscal 2017,2018, 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 PUCPAPUC 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.PAPUC. 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.”

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

In January 2016, UGI GasUtilities filed a request with the PUCPAPUC for its first gas base rate increase in over 21 years. On October 14, 2016, the PUCPAPUC approved a settlement that was effective October 19, 2016 and resulted in a $27.0 million increase in annual base rate revenues. The settlement permitted UGI Gasthe Company 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 GasThe Company was also permitted to implement a new Technology and Economic Development Rider to provide additional flexibility in establishing the rates of smaller volume commercial and industrial customers to encourage cost-effective load growth.

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

On February 20, 2014, the PUCPAPUC 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 UtilityEach of the Company’s gas businesses 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 PUCPAPUC 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-grantedPAPUC-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.PAPUC. 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.PAPUC.

The PUCPrior to the merger effective October 1, 2018, the PAPUC approved LTIIPs for UGI Gas, PNG, and CPG in 2014, and on June 30, 2016, approved a revised LTIIP for these entities that increasesincreased the projected spend on DSIC-eligible property for the 2016-2018 period from approximately $266.3 million to $402.8 million. On August 2, 2018, the PAPUC approved one-year extensions through December 31, 2019 to the existing UGI Gas, PNG and CPG LTIIPs. The PUCmodified LTIIPs provide for approximately $185.0 million of projected spend on DSIC-eligible property during calendar year 2019. The PAPUC 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.respectively. On March 31, 2016, PNG and CPG filed petitions with the PUCPAPUC seeking to increase the cap on their DSIC rate mechanisms from five percent to ten percent of billed distribution revenues. On May 10, 2017, the PUCPAPUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration of aneach company’s LTIIP filing in 2018.filing.

On November 9, 2016, UGI Gas received PUCPAPUC approval to establish a DSIC tariff mechanism effective January 1, 2017.  Revenues collected pursuant to the mechanism will be2017, subject to refund and recoupment based on the PUC’sPAPUC’s final resolution of certain matters set aside for hearing before an Administrative Law Judge.  To commence recovery of revenue under the mechanism,Those matters were subsequently resolved in a PAPUC Order entered on July 13, 2017, and UGI Gas must first placecommenced collections under its natural gas DSIC on July 1, 2018.

Currently, UGI South and UGI Central are collecting DSIC revenues, while UGI North will resume DSIC revenue collection once the UGI North rate district places into service a threshold level of DSIC-eligibleDSIC eligible plant agreed upon in the settlement of its more recent base rate case.  Achievement of that threshold is likely to occur in Fiscal 2018.

The gas service tariffs forof UGI Gas, PNG, and CPG containGas’ rate districts include 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 sellsells to theirits customers. PGC rates are reviewed and approved annually by the PUC.PAPUC. UGI Gas, PNG, and CPGGas’ rate districts 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 PUCPAPUC and are subject to review during the next annual PGC filing. Each proposed annual PGC rate is required to be filed with the PUCPAPUC six months prior to its effective date. During this period, the PUCPAPUC 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 PUCPAPUC 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 CPGGas’ rate districts may assignrelease or sell to and recover from alternative natural gas suppliers the costs of gas supply contracts and transportation capacity acquired to serve the needs of smaller volume customers who elect to receive their natural gas supply service from an alternative supplier.

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

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.

On January 26, 2018, Electric Utility is permittedfiled a request with the PAPUC for its first base rate increase in over 22 years. On October 25, 2018, the PAPUC entered an Opinion and Order authorizing a $3.2 million increase in annual base distribution rates effective October 27, 2018. The PAPUC also authorized Electric Utility to recover prudentlyestablish a new reconcilable surcharge to permit the timely recovery of the costs of universal service programs designed to assist low income customers and required the Company to refund approximately $0.21 million of tax benefits and associated interest relating to the Tax Cuts and Jobs Act (the “TCJA”) through a one time bill credit.

Electric Utility’s tariff includes rates, applicable to so-called “default service” customers who do not obtain electric generation service from an alternative supplier, incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a PAPUC-approved supply plan filed with the PUC. UGI Utilities’ electric utility operationsplan. These default service rates are subjectreconcilable, may be adjusted quarterly, and are designed to regulation by the PUC as to rates, terms and conditions of service, accounting matters, issuance of securities, contracts and other arrangements with affiliated entities, electric safety and various other matters. The most recent general base rate increase forpermit Electric Utility became effective in 1996. PUCto recover the full costs of providing default service regulations became applicable toin a full and timely manner. Electric Utility’s provisionUtility has received PAPUC approval of its current default service effective January 1, 2010rules and Electric Utility, consistent with these regulations, has received PUC approvalsupply plan through May 31, 2021 of (i)2021. Electric Utility’s default service tariff rules, (ii) a reconcilable default service cost raterates include recovery mechanism to recoverof costs associated with compliance with the cost of acquiring default service supplies, (iii) a plan for meeting the post-2009 requirements of the

Alternative Energy Portfolio Standards Act (“AEPS Act”), which requires Electric Utility to directly or indirectly acquire certain percentages of its supplies from designated alternative energy sources, and (iv) a reconcilable AEPS Act cost recovery rate mechanism to recover the costs of complying with AEPS Act requirements applicable to default service supplies for service rendered through May 31, 2021. Under these rules, default service rates for most customers are adjusted quarterly. sources.

On August 16, 2017, Electric Utility filed a Petition for Approval of its initial LTIIP with the PUCPAPUC for the 2018-2022 time period.period, which was approved by a PAPUC Opinion and Order entered on December 21, 2017. Electric Utility’s projected annual investment in distribution infrastructure replacement will bewas approximately $7.6 million beginning in Fiscal 2018, increasingand will increase to $8.3 million by the fiscal year ending September 30, 2022. With the completion of its base rate case, Electric Utility is now eligible to file for permission to implement a DSIC.

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.

In addition to regulation by the PUCPAPUC 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.substances. See Note 12 to Consolidated Financial Statements.

At September 30, 2017,2018, UGI Utilities had over 1,625approximately 1,670 employees.

The table stating the amounts of revenues, operating income and identifiable assets attributable to UGI Utilities’ operating segments for theFiscal 2018, Fiscal 2017 2016 and 2015 fiscal yearsFiscal 2016 appears in Note 16 to Consolidated Financial Statements included in this Report and is incorporated herein by reference.

Our Gas Utility and Electric Utility distribution operations are subject to regulation by the PUC.PAPUC. The PUC,PAPUC, 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 PUCPAPUC to increase base rates that they chargecharged to 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,PAPUC, 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 of these and other incidents, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business.business, including regulatory investigations, claims, lawsuits and other proceedings. Additionally, environmental contamination could result in future legal proceedings. There can be no assurance that our insurance coverage will be adequate to protect us from all material expenses related to pending and future claims or that such levels of insurance would be available in the future at economical prices. Moreover, defense and settlement costs may be substantial, even with respect to claims and investigations that have no merit. If we cannot resolve these matters favorably, our business, financial condition, results of operations and future prospects may be materially adversely affected.

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.factors, including as a result of overpressurization of or damage to natural gas pipelines. Operation of our transmission and distribution systems below our expectations may result in lost revenues or increased expenses, including higher maintenance costs.costs, civil litigation and the risk of regulatory penalties.

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:

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

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, andor 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.

Moreover, the efficient execution of our business is dependent upon the proper functioning of its internal systems, such as the information technology systems that support our underlying business processes.  Any significant failure or malfunction of such information technology systems may result in disruptions of our operations.  In addition, the effectiveness of our internal controls could be adversely affected if we encounter unforeseen problems with respect to the operation of our information technology systems. While we have purchased cyber security insurance, there are no assurances that the coverage would be adequate in relation to any incurred losses.

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.conservation and attrition. 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 volatilityVolatility 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

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.

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

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

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

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.

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

Cash dividends declared on the Company’s Common Stock totaled $50.0 million in Fiscal 2018, $57.7 million in Fiscal 2017, and $47.0 million in Fiscal 2016, and $65.6 million in Fiscal 2015.2016.

The higher levels ofFiscal 2018 Gas Utility capital expenditures ininclude amounts associated with construction of a new headquarters building. Fiscal 2017 and Fiscal 2016, as well as those2019 estimated for Fiscal 2018, reflect greatercapital expenditures at Gas Utility include slightly higher main replacement and system improvement capital expenditures, increasesexpenditures associated with buildings and grounds improvements, and IT expenditures associated with the replacement of an Enterprise Risk Management (“ERP”) system. The increase in new businessestimated Fiscal 2019 Electric Utility capital expenditures includes infrastructure replacement and expected investments in new information technology projects.upgrade expenditures and facility improvements.

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”).

On August 31, 2017, all active parties supported the filing ofPAPUC approved a previously filed Joint Petition for Approval of Settlement of all issues with the PUC providing for an $11.3 million PNG annual base distribution rate increase. On August 31, 2017,increase for PNG (now the PUC approved the Joint Petition and theUGI North rate district of Gas Utility). The increase became effective October 20, 2017.

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

Distribution System Improvement Charge. On April 14, 2012,State legislation became effective enablingpermits 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 on eligible capital investments as an alternative ratemaking mechanism providing for a company from a DSIC charge is the eliminationmore timely cost of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating torecovery of qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a generalexpenditures between base rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at 5% of distribution charges billed to customers.cases.

PNG and CPG received PUCPAPUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero, beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from 5% to 10% of billed distribution revenues. On May 10, 2017, the PUCPAPUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-termLong-Term Infrastructure Improvement Plan filingfiling. PNG’s DSIC has been reset to zero as a result of its most recent base rate case. The DSIC rate for PNG will resume under the UGI North rate district upon exceeding the threshold amount of DSIC-eligible plant in 2018.service agreed upon in the settlement of its most recent base rate case.

OnIn November 9, 2016, UGI Gas received PUCPAPUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recoverbegan recovering revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess ofeffective July 1, 2018, as it exceeded the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.case during the third quarter of Fiscal 2018.

EachPrior to the Utilities Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, has entered intowere subject to a consent order and agreement (“COA”) with the DEPPennsylvania Department of Environmental Protection (“PADEP”) to address the remediation of specified former MGPsMGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the merger, UGI Utilities, as the successor to CPG and PNG, are eachis required to either obtain a certain number of points per calendar year based on defined eligible

environmental investigatory and/or remedial activities at the MGPs and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation, to plug specified natural gas wells.cost cap of the three COAs, in the aggregate, is $5.4 million. The COA environmental costs caps are $2.5 million, $1.8 million and $1.1 million, for UGI Utilities, CPG and PNG, respectively. Thethree COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018,2020, and 2019, respectively.2020. At September 30, 2018 and 2017, and 2016, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $54.3$51.0 million and $55.1$54.3 million, respectively. UGI Utilities CPG and PNG havehas recorded associated regulatory assets for these costs because recovery of these costs from customers is probable. (See Note 4 to the Consolidated Financial Statements).

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 PUCPAPUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. UGI Utilities also engages in other services with various other affiliates pursuant to arrangements authorized by the PAPUC using similar allocation or market-based pricing methods. 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 PUCPAPUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities during Fiscal 2018, Fiscal 2017 and Fiscal 2016 and Fiscal 2015 totaled $5.3 million, $4.3 million $5.1 million and $3.2$5.1 million, respectively.

From time to time, UGI Utilities is a party to SCAAsstorage contract administrative agreements (“SCAAs”) with UGI Energy Services, LLC (“Energy Services”) which have terms of up to three years. At September 30, 2017,2018, UGI Utilities was a party to four SCAAs with Energy Services, and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs during Fiscal 2018, Fiscal 2017 and Fiscal 2016 and Fiscal 2015 totaling $19.9 million, $21.4 million $12.7 million and $16.8$12.7 million, respectively. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. During Fiscal 2018, Fiscal 2017 and Fiscal 2016, and Fiscal 2015, these payments totaled $2.8 million, $2.7 million $2.0 million and $2.3$2.0 million, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. At September 30, 20172018 and 2016,2017, the amounts of such security deposits, which are included in “Other current liabilities” on the Consolidated Balance Sheets, were $11.0 million and $8.1 million, respectively.million.

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 2018, Fiscal 2017 and Fiscal 2016 and Fiscal 2015 totaled $93.6 million, $76.0 million $63.3 million and $47.8$63.3 million, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During Fiscal 2018, Fiscal 2017 and Fiscal 2016, and Fiscal 2015, revenues associated with such sales to Energy Services totaled $103.7 million, $50.9 million $30.7 million and $79.2$30.7 million, respectively. Also from time to time, UGI Utilities purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During Fiscal 2018, Fiscal 2017 and Fiscal 2016, and Fiscal 2015, such purchases totaled $156.8 million, $84.4 million $35.1 million and $85.4$35.1 million, respectively.

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.

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 PGCpurchased gas cost (“PGC”) rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At September 30, 2017,2018, Gas Utility had $3.0$1.2 million of restricted cash in brokerage accounts. At September 30, 2017,2018, the fair values of our natural gas futures and option contracts were not material.gains of $2.9 million.

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 DSdefault service (“DS”) rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations. At September 30, 2017,2018, all of our Electric Utility’s forward electricity purchase contracts were subject to the normal purchase and normal sale (“NPNS”) exception. At September 30, 2017, the fair values of FTRs were not material.

In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures contracts are recorded at fair value with changes in fair value reflected in “Operating and administrative expenses” on the Consolidated Statements of Income. The amount of unrealized gains on these contracts and associated volumes under contract at September 30, 20172018 were not material.

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 agreementAgreement and UGI Utilities Term Loan. The Credit Agreement provides for interest rates on borrowings that are indexed to short-term market interest rates. Based upon the average level of borrowings outstanding under these agreements in Fiscal 2017,2018, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.8approximately $1.8 million. The UGI Utilities’ Term Loan also has a variable interest rate. In July 2018, UGI Utilities entered into a forward-starting, amortizing, pay-fixed, receive-variable interest rate swap

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$86 million at September 30, 2017.2018. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of approximately $118$105 million at September 30, 2017.2018.

In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). There were no unsettled IRPAs outstanding at September 30, 2017.2018.

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

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.

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

“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.

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.

The aggregate fees billed by Ernst & Young LLP, the Company’s independent registered public accounting firm in Fiscal 20172018 and Fiscal 2016,2017, were as follows:

(1) Audit fees for Fiscal 20172018 and Fiscal 20162017 were for audit services, including (i) the annual audit of the consolidated financial statements of the Company, (ii) regulatory-basis financial statements, and (iii) review of the interim financial statements included in the Quarterly Reports on Form 10-Q of the Company.

(2) Audit-Related Fees for Fiscal 2018 and 2017 related to pre-implementation reviews of the Company’s new information technology system.

(3) Tax Fees for Fiscal 2018 and 2017 were for tax compliance or advisory services at the Company.

(4) All Other Fees for Fiscal 2018 and 2017 were for software license fees services provided for the implementation of ASC 606.

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

in accordance with the Audit Committee’s pre-approval policy.

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