UGI UTILITIES INC (Form: 10-K, Received: 11/28/2014 17:19:17)

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, 2014

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 18, 2014 , 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	9

Item 1B. Unresolved Staff Comments	11

Item 3. Legal Proceedings	11

Item 4. Mine Safety Disclosures	11

PART II:

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	12

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	12

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	22

Item 8. Financial Statements and Supplementary Data	22

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	22

Item 9A. Controls and Procedures	22

Item 9B. Other Information	23

PART III:

Item 14. Principal Accounting Fees and Services	23

PART IV:

Item 15. Exhibits and Financial Statement Schedules	24

Signatures	29

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 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 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) large customer, counterparty or supplier defaults; (11) increased uncollectible accounts expense; (12) liability for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas, including liability in excess of insurance coverage; (13) political, regulatory and economic conditions in the United States; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity market prices resulting in significantly higher cash collateral requirements.

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 600,000 customers in eastern and central Pennsylvania and several 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 2014” and “Fiscal 2013” refer to the fiscal years ended September 30, 2014 and September 30, 2013, respectively.

GAS UTILITY

Service Area; Revenue Analysis

Gas Utility is authorized to distribute natural gas to over 600,000 customers in portions of 46 eastern and central Pennsylvania counties through its distribution system of approximately 12,000 miles of gas mains. Contemporary materials, such as plastic or coated steel, comprise approximately 87% of Gas Utility's 12,000 miles of gas mains, with bare steel pipe comprising approximately 10% 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 March of 2043. 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 several hundred 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 2014 was approximately 208.8 billion cubic feet (“bcf”). System sales of gas accounted for approximately 31% of system throughput, while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for approximately 69% 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 Canadian sources. For the transportation and storage function, Gas Utility has long-term agreements with a number of pipeline companies, including Texas Eastern Transmission Corporation, 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 2014, Gas Utility purchased approximately 84.2 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 90% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 10% of gas purchased by Gas Utility was supplied by approximately 35 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 16 months. Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the months of November through March.

Seasonality

Because many of its customers use gas for heating purposes, Gas Utility’s sales are seasonal. During Fiscal 2014, approximately 65% of Gas Utility's sales volume was supplied, and over 90% of Gas Utility’s operating income was earned, during the peak heating season from October through March.

Competition

Natural gas is a fuel that competes with electricity and oil, and to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of the equipment. Natural gas generally benefits from a competitive price advantage over oil, electricity, and propane. 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 23% of Gas Utility’s annual throughput volume for commercial and industrial customers includes customers with locations that afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. In addition, approximately 31% of Gas Utility’s annual throughput volume for commercial and industrial customers is from customers who are served under interruptible rates and are also in a location near an interstate pipeline. Gas Utility has approximately 26 of such customers with transportation contracts extending beyond fiscal year 2015. 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 2015. Supply mix is diversified, market priced, and delivered pursuant to a number of long-term and short-term firm transportation and storage arrangements, including transportation contracts held by some of Gas Utility's larger customers.

During Fiscal 2014, Gas Utility supplied transportation service to five major co-generation installations and four electric generation facilities. Gas Utility continues to seek new residential, commercial, and industrial customers for both firm and interruptible service. In Fiscal 2014, Gas Utility connected approximately 2,000 new commercial and industrial customers. In the residential market sector, Gas Utility connected nearly 16,000 residential heating customers during Fiscal 2014. Over 12,000 of these customers converted to natural gas heating from other energy sources, mainly oil and electricity. New home construction customers and existing non-heating gas customers who added gas heating systems to replace other energy sources primarily accounted for the other residential heating connections in Fiscal 2014.

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 of supply. Consistent with that objective, UGI Utilities negotiates the terms of firm transportation capacity on all pipelines serving it, arranges for appropriate storage and peak-shaving resources, negotiates with producers for competitively priced gas purchases and aggressively participates in regulatory proceedings related to transportation rights and costs of service.

ELECTRIC UTILITY

Service Area; Sales Analysis

Electric Utility supplies electric service to approximately 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania through a system consisting of over 1,900 miles of transmission and distribution lines and 13 substations. For Fiscal 2014, approximately 56% of sales volume came from residential customers, 32% from commercial customers, and 12% from industrial and other customers.

Sources of Supply

In accordance with Electric Utility’s default service settlement with the PUC effective January 1, 2010, Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with the PUC. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures” and Note 4 to Consolidated Financial Statements. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers. During Fiscal 2014, five retail electric generation suppliers provided energy for customers representing approximately 24% of Electric Utility’s sales volume. See “Gas Utility and Electric Utility Regulation and Rates - Electric Utility Rates.”

Competition

As a result of the Electricity Generation Customer Choice and Competition Act (“ECC Act”), all Pennsylvania retail electric customers have the ability to choose their retail electric generation supplier. Under the ECC Act and Act 129 of 2008, which revised the default service requirements contained in Chapter 28 of the Public Utility Code, Electric Utility remains the “default service” provider for its customers who do not choose an alternate retail electric generation supplier. In Fiscal 2014, 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 a Default Service (“DS”) rate plan approved by the PUC. Consistent with the terms of the DS rate plan, effective January 1, 2010, default service rates are designed to recover all reasonable and prudent costs incurred in providing electricity to default service customers. This recovery, through default service rates, no longer subjects Electric Utility to the risk that actual costs for purchased power will exceed default service revenues. Conversely, effective January 1, 2010, Electric Utility does not have the opportunity to recover revenues in excess of actual power costs. See “Gas Utility and Electric Utility Regulation and Rates - Electric Utility Rates.”

GAS UTILITY AND ELECTRIC UTILITY REGULATION AND RATES

Pennsylvania Public Utility Commission Jurisdiction

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

and electric default service costs. Rates designed to recover PGCs and electric default service costs are reviewed in PGC and electric default service rate proceedings. Rates designed to recover costs other than PGCs and electric default service costs are primarily established in general base rate proceedings.

Gas Utility Rates

The gas service tariffs for UGI Gas, PNG, and CPG contain PGC rates applicable to firm retail rate schedules. These PGC rates permit recovery of substantially all of the prudently incurred costs of natural gas that UGI Gas, PNG, and CPG sell to their customers. PGC rates are reviewed and approved annually by the PUC. UGI Gas, PNG, and CPG may request quarterly or, under certain conditions, monthly adjustments to reflect the actual cost of gas. Quarterly adjustments become effective on one day’s notice to the PUC and are subject to review during the next annual PGC filing. Each proposed annual PGC rate is required to be filed with the PUC six months prior to its effective date. During this period, the PUC holds hearings to determine whether the proposed rate reflects a least-cost fuel procurement policy consistent with the obligation to provide safe, adequate and reliable service. After completion of these hearings, the PUC issues an order permitting the collection of gas costs at levels that meet that standard. The PGC mechanism also provides for an annual reconciliation.

UGI Gas has two PGC rates: (i) applicable to small, firm, retail core-market customers consisting of the residential and small commercial and industrial classes; and (ii) applicable to firm, high-load factor, customers served on three separate rates. PNG and CPG each have one PGC rate applicable to all customers. Base rates for each of UGI Gas, PNG, and CPG were last established in 1995, 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.

Electric Transmission and Wholesale Power Sale Rates

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

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

Electric Utility Rates

In accordance with Electric Utility’s default service settlement with the PUC effective June 1, 2014 through May 31, 2017, Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with the PUC. Electric Utility’s 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.

FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers

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

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

State Tax Surcharge Clauses

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

Utility Franchises

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

Other Government Regulation

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

Employees

At September 30, 2014, UGI Utilities had approximately 1,470 employees.

BUSINESS SEGMENT INFORMATION

The table stating the amounts of revenues, operating income and identifiable assets attributable to UGI Utilities’ operating segments for the 2014, 2013 and 2012 fiscal years appears in Note 15 to Consolidated Financial Statements included in this Report and is incorporated herein by reference.

ITEM 1A. RISK FACTORS

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

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

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

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

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

The volatility in credit and capital markets may create additional risks to our business in the future. We are exposed to financial market risk (including refinancing risk) resulting from, among other things, changes in interest rates and conditions in the credit and capital markets. Developments in the credit markets during the past few years increase our possible exposure to the liquidity, default and credit risks of our suppliers, counterparties associated with derivative financial instruments and our customers. Although we believe that current financial market conditions, if they were to continue for the foreseeable future, will not have a significant impact on our ability to fund our existing operations, such market conditions could restrict our ability to grow, limit the scope of major capital projects if access to credit and capital markets is limited, or adversely affect our operating results.

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

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

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

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

Our transmission and distribution systems may not operate as planned, 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. Our business also faces several risks, including the breakdown or failure of or damage to equipment or processes (especially due to severe weather or natural disasters), accidents and other factors. Operation of our transmission and distribution systems below our expectations may result in lost revenues or increased expenses, including higher maintenance costs.

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

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

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

Regulators may not allow timely recovery of costs for us in the future, 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. There can be no assurance that our insurance 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.

In response to recent natural gas explosions 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 June 2014, the EPA proposed the Clean Power Plan, which will provide standards and guidelines for reducing existing power plants’ GHG emissions and related pollutants by 2030. The Clean Power Plan standards and guidelines are expected to be finalized by June 2015. 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.

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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURES

None.

PART II:

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

Market Information

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

Dividends

Cash dividends declared on the Company’s Common Stock totaled $77.4 million in Fiscal 2014, $59.0 million in Fiscal 2013 and $70.6 million in Fiscal 2012.

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 15 to Consolidated Financial Statements.

EXECUTIVE OVERVIEW

Our results in Fiscal 2014 reflect temperatures based upon heating degree days in our Gas Utility service territory that were 10% colder than normal and almost 11% colder than in Fiscal 2013. During Fiscal 2014, Gas Utility experienced record customer growth as continuing low natural gas prices relative to the price of heating oil resulted in continuing high numbers of conversions from oil to natural gas.

Our net income in Fiscal 2014 was $ 124.1 million, an increase of $22.0 million ( 21.6% ) from Fiscal 2013 net income of $ 102.1 million. The improved results in Fiscal 2014 at our Gas Utility principally reflect the effects on core market volumes of the significantly colder heating-season weather and customer growth. The significantly colder heating-season weather resulted in higher core market volumes and core market total margin. The benefit of the greater total Gas Utility margin was reduced, in part, by higher Gas Utility operating and administrative expenses including greater distribution system maintenance and uncollectible accounts expenses.

Electric Utility’s kilowatt-hour sales in Fiscal 2014 were about equal with the prior year as the colder winter weather’s impact on heating-related sales were offset by the effects of a milder summer on air-conditioning sales. Electric Utility incurred higher distribution system maintenance expenses during Fiscal 2014 primarily related to summer storm damage.

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 2015.

ANALYSIS OF RESULTS OF OPERATIONS

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

Fiscal 2014 Compared with Fiscal 2013



							Increase
(Millions of dollars)	2014			2013			(Decrease)
Gas Utility:
Revenues	$	977.3		$	839.1		$	138.2		16.5	%
Total margin (a)	$	480.6		$	431.8		$	48.8		11.3	%
Operating income	$	236.2		$	198.4		$	37.8		19.1	%
Income before income taxes	$	199.6		$	161.1		$	38.5		23.9	%
System throughput — bcf
Core market	80.4			70.6			9.8			13.9	%
Total	208.8			192.1			16.7			8.7	%
Degree days — % colder (warmer) than normal (b)	10.0		%	(0.5		)%	—			—
Electric Utility:
Revenues	$	108.1		$	100.0		$	8.1		8.1	%
Total margin (a)	$	36.0		$	35.8		$	0.2		0.6	%
Operating income	$	9.7		$	11.4		$	(1.7	)	(14.9	)%
Income before income taxes	$	7.8		$	9.4		$	(1.6	)	(17.0	)%
Distribution sales — gwh	987.3			992.6			(5.3		)	(0.5	)%

bcf — billions of cubic feet.

gwh — millions of kilowatt-hours.

(a)

Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $5.8 million and $5.4 million during Fiscal 2014 and Fiscal 2013 , respectively. For financial statement purposes, revenue-related taxes are included in taxes other than income taxes in the Consolidated Statements of Income.


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

Gas Utility . Temperatures in Gas Utility’s service territory in Fiscal 2014 based upon heating degree days were 10.0% colder than normal and 10.6% colder than Fiscal 2013. Total distribution system throughput increased 16.7 bcf principally reflecting a 9.8 bcf (13.9%) increase in demand from Gas Utility’s core market customers and, to a lesser extent, greater net large firm and interruptible delivery service volumes. Gas Utility system throughput to core market customers was higher than last year principally reflecting the effects of the significantly colder weather and, to a lesser extent, customer growth due principally to conversions from other fuels prompted by sustained lower natural gas prices relative to heating oil prices. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.

Gas Utility revenues increased $138.2 million during Fiscal 2014 principally reflecting higher revenues from core market customers ($83.6 million), higher revenues from off-system sales ($36.4 million) and, to a much lesser extent, higher revenues from large firm delivery service customers on higher throughput ($12.5 million). The increase in core market revenues principally reflects the effects of the higher core market throughput. Increases or decreases in retail core-market revenues and cost of sales principally result from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market

customers have no direct effect on retail core-market margin. Gas Utility’s cost of sales were $496.8 million in Fiscal 2014 compared with $407.2 million in Fiscal 2013 principally reflecting the effects of the greater retail core-market volumes sold ($50.1 million) and the effects of the higher off-system sales ($36.4 million).

Gas Utility total margin increased $48.8 million in Fiscal 2014 principally reflecting higher core market total margin ($33.8 million) and greater large firm delivery service total margin ($10.8 million). The higher core market and large firm delivery service total margin reflects the effects of the previously mentioned colder weather and customer growth.

Gas Utility operating income and income before income taxes during Fiscal 2014 increased $37.8 million and $38.5 million, respectively, over Fiscal 2013. The increase in Gas Utility operating income principally reflects the $48.8 million increase in total margin partially offset by higher operating and administrative expenses. Operating and administrative expenses in Fiscal 2014 were modestly higher than the prior year principally reflecting greater Fiscal 2014 distribution system maintenance expenses ($5.3 million), higher uncollectible accounts expense ($3.0 million) and greater incentive compensation expense partially offset by lower pension expense. The increase in Gas Utility income before income taxes reflects the greater operating income ($37.8 million) and slightly lower interest expense.

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

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

Interest Expense and Income Taxes. Our interest expense in Fiscal 2014 was slightly lower than the prior year principally reflecting lower average interest rates. Our effective income tax rate in Fiscal 2014 was comparable with the prior year.

Fiscal 2013 Compared with Fiscal 2012



							Increase
(Millions of dollars)	2013			2012			(Decrease)
Gas Utility:
Revenues	$	839.1		$	785.4		$	53.7		6.8	%
Total margin (a)	$	431.8		$	382.8		$	49.0		12.8	%
Operating income	$	198.4		$	172.2		$	26.2		15.2	%
Income before income taxes	$	161.1		$	132.0		$	29.1		22.0	%
System throughput — bcf
Core market	70.6			59.2			11.4			19.3	%
Total	192.1			177.6			14.5			8.2	%
Degree days —% (warmer) colder than normal (b)	(0.5		)%	(16.3		)%	—			—
Electric Utility:
Revenues	$	100.0		$	97.1		$	2.9		3.0	%
Total margin (a)	$	35.8		$	35.3		$	0.5		1.4	%
Operating income	$	11.4		$	12.6		$	(1.2	)	(9.5	)%
Income before income taxes	$	9.4		$	10.3		$	(0.9	)	(8.7	)%
Distribution sales — gwh	992.6			974.6			18.0			1.8	%

(a)

Gas Utility’s total margin represents total revenues less cost of sales. Electric Utility’s total margin represents total revenues less cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes of $5.4 million in Fiscal 2013 and $5.3 million in Fiscal 2012 . For financial statement purposes, revenue-related taxes are included in taxes other than income taxes in the Consolidated Statements of Income.


(b)	Deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory.

Gas Utility . Temperatures in the Gas Utility service territory in Fiscal 2013 based upon heating degree days were 0.5% warmer than normal but 18.2% colder than Fiscal 2012. Total distribution system throughput increased principally reflecting significantly higher throughput to core market customers and, to a lesser extent, greater net volumes associated with lower margin firm and interruptible delivery service customers. Gas Utility system throughput to core-market customers was above last year principally reflecting the effects of the significantly colder weather and, to a much lesser extent, customer growth, principally conversions from oil prompted by sustained lower natural gas prices relative to heating oil prices.

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

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

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

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

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

Notwithstanding the increase in total margin, Electric Utility Fiscal 2013 operating income and income before income taxes decreased reflecting greater operating and administrative costs including distribution system repair and maintenance costs principally associated with Hurricane Sandy early in Fiscal 2013.

Interest Expense and Income Taxes . Our interest expense in Fiscal 2013 was $3.1 million lower than in Fiscal 2012 principally reflecting lower average long-term debt outstanding. Our effective tax rate in Fiscal 2013 was slightly higher than in Fiscal 2012 as the prior year tax rate reflected the regulatory effects of greater state tax depreciation.

FINANCIAL CONDITION AND LIQUIDITY

Capitalization and Liquidity

UGI Utilities’ total debt outstanding was $ 728.3 million at September 30, 2014 , which includes $ 86.3 million of short-term borrowings, compared with total debt outstanding of $ 659.5 million at September 30, 2013 , which includes $17.5 million of short-term borrowings. UGI Utilities’ total long-term debt outstanding at September 30, 2014 , comprises $450.0 million of Senior Notes and $192.0 million of Medium-Term Notes.

In March 2014, UGI Utilities issued, in a private placement, $175 million of 4.98% Senior Notes due March 2044 (“4.98% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175 million of borrowings under UGI Utilities’ 364-day Term Loan Credit Agreement. Because the Company had the intent and ability to refinance the Term Loan Credit Agreement on a long-term basis as of September 30, 2013 , amounts outstanding under the Term Loan Credit Agreement were classified as long-term debt on the 2013 Consolidated Balance Sheet.

UGI Utilities has a credit agreement (“Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit) which expires in October 2015. Borrowings under the Credit Agreement are classified as short-term borrowings on the Consolidated Balance Sheets. During Fiscal 2014 and Fiscal 2013 , average daily short-term borrowings under the Credit Agreement were $29.9 million and $25.6 million , respectively, and peak short-term borrowings totaled $86.3 million and $79.0 million , respectively. Peak short-term borrowings typically occur during the heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is generally greatest. The Credit Agreement requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. UGI Utilities was in compliance with this covenant at September 30, 2014 .

Based upon cash expected to be generated from operations and borrowings under the Credit Agreement, management believes the Company will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2015 . For additional discussion of UGI Utilities’ long-term debt and the Credit Agreement, see Note 7 to Consolidated Financial Statements.

Cash Flows

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

Cash provided by operating activities was $188.7 million in Fiscal 2014 , $169.9 million in Fiscal 2013 and $209.7 million in Fiscal 2012 . Cash provided by operating activities before changes in operating working capital was $224.6 million in Fiscal 2014 , $196.7 million in Fiscal 2013 and $185.3 million in Fiscal 2012 . The higher cash flow before changes in operating working capital in Fiscal 2014 compared to Fiscal 2013, and Fiscal 2013 compared with Fiscal 2012, reflects, in large part, the higher year-over-year operating results. Changes in operating working capital (used) provided $(35.9) million of cash in Fiscal 2014 , $(26.8) million of cash in Fiscal 2013 and $24.5 million of cash in Fiscal 2012 .

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

Financing activities. Cash used by financing activities was $8.2 million in Fiscal 2014 , $7.3 million in Fiscal 2013 and $101.0 million in Fiscal 2012 . Financing activities cash flows are primarily the result of issuances and repayments of long-term debt, revolving credit agreement borrowings and cash dividends to UGI. During Fiscal 2014, net short-term borrowings totaled $68.8 million compared to net borrowings of $8.3 million and $9.2 million in Fiscal 2013 and Fiscal 2012, respectively.

Capital Expenditures

In the following table, we present capital expenditures by business segment for Fiscal 2014 , Fiscal 2013 and Fiscal 2012 . We also provide amounts we expect to spend in Fiscal 2015 . We expect to finance a substantial portion of Fiscal 2015 capital expenditures from cash generated by operations and the remainder from borrowings under our Credit Agreement.



(Millions of dollars)	2015		2014		2013		2012
	(estimate)
Gas Utility	$	191.9	$	156.4	$	144.4	$	109.0
Electric Utility	8.6		7.8		6.7		5.1
	$	200.5	$	164.2	$	151.1	$	114.1

The higher levels of Gas Utility capital expenditures in Fiscal 2014 and Fiscal 2013, as well as those estimated for Fiscal 2015, reflect greater main replacement and system improvement capital expenditures and increases in new business capital expenditures.

Contractual Cash Obligations and Commitments

UGI Utilities has contractual cash obligations that extend beyond Fiscal 2014 , 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, 2014 :



	Payments Due by Period
			Fiscal		Fiscal		Fiscal
(Millions of dollars)	Total		2015		2016 - 2017		2018 - 2019		Thereafter
Long-term debt (a)	$	642.0	$	20.0	$	267.0	$	40.0	$	315.0
Interest on long-term fixed rate debt (b)	488.7		36.8		54.7		36.3		360.9
Derivative financial instruments (c)	1.6		1.6		—		—		—
Operating leases	23.2		6.7		10.7		5.1		0.7
Gas Utility and Electric Utility supply, storage and transportation contracts	591.8		204.0		184.2		107.3		96.3
Total	$	1,747.3	$	269.1	$	516.6	$	188.7	$	772.9


(a)	Based upon stated maturity dates.


(b)	Based upon stated interest rates.


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

The components of the other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2014 , principally consist of pension and other postretirement benefit liabilities recorded in accordance with GAAP and estimated obligations for environmental investigation and remediation. These liabilities are not included in the table of Contractual Cash Obligations and Commitments above because they are estimates of future payments and not contractually fixed as to timing or amount. We believe we will be required to make contributions to our pension plan in Fiscal 2015 of approximately $ 1.1 million. Contributions to the pension plan in years beyond Fiscal 2015 will depend in large part on the effects of future returns and interest rates on pension plan assets. For additional information on these liabilities see Notes 9 and 12 to Consolidated Financial Statements.

Pension Plan

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

The fair values of the Pension Plan’s assets totaled $442.5 million and $398.2 million at September 30, 2014 and 2013 , respectively. At September 30, 2014 and 2013 , the underfunded positions of the Pension Plan, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plan’s assets, were $97.3 million and $88.3 million , respectively.

We believe we are in compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations. We anticipate that we will be required to make contributions to the Pension Plan during Fiscal 2015 of approximately $ 1.1 million. Pre-tax pension cost associated with the Pension Plan in Fiscal 2014 was $9.8 million . Pre-tax pension cost associated with Pension Plan in Fiscal 2015 is expected to be approximately $ 9.7 million.

Generally accepted accounting principles (“GAAP”) guidance associated with pension and other postretirement plans generally requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and other postretirement benefit plans with current year changes recognized in shareholder’s equity unless such amounts are subject to regulatory recovery. Through September 30, 2014 , we have recorded cumulative after-tax charges to stockholder’s equity of $6.3 million and regulatory assets of $ 110.1 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

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 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. UGI Gas, PNG, and CPG began connecting customers under the GET Gas program in October 2014.

On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11-mile natural gas pipeline, related facilities and rights of way located in Delmar Township, Pennsylvania (“TL-96 line”) to UGI Energy Services, LLC (which was formerly known as UGI Energy Services, Inc. prior to its merger with and into UGI Energy Services, LLC effective October 1, 2013), a second-tier wholly owned subsidiary of UGI (“Energy Services”). The PUC approved the transfer and in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the TL-96 line was approximately $2.7 million which amount, net of related deferred income taxes of $0.4 million, is reflected as a dividend of net assets on the Fiscal 2013 Consolidated Statement of Stockholder’s Equity.

MANUFACTURED GAS PLANTS

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

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by 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 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 (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs, and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At September 30, 2014, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.

From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by its 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.

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. 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. At September 30, 2014 , UGI Utilities was a party to three SCAAs with Energy Services one of which expired October 31, 2014, and two of which expire October 31, 2015 and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts 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. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $38.3 million, $45.8 million and $24.3 million in Fiscal 2014 , Fiscal 2013 and Fiscal 2012 , respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amount of such security deposits, which amounts are included in other current liabilities on the Consolidated Balance Sheets, were $10.6 million and $16.5 million at September 30, 2014 and 2013 , respectively. Effective November 1, 2014, UGI Utilities entered into a new SCAA with Energy Services having a term of one year.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption inventories. The carrying value of these gas storage inventories at September 30, 2014 and 2013 , comprising approximately 7.7 bcf and 10.4 bcf of natural gas, were $33.1 million and $42.0 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 during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during Fiscal 2014 , Fiscal 2013 and Fiscal 2012 totaled $35.8 million, $32.5 million and $30.8 million, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2014 , Fiscal 2013 and Fiscal 2012 , revenues associated with sales to Energy Services totaled $109.9 million, $69.1 million and $65.7 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 2014 , Fiscal 2013 and Fiscal 2012 , such purchases totaled $128.1 million, $77.0 million and $53.4 million, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

OFF-BALANCE-SHEET ARRANGEMENTS

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

MARKET RISK DISCLOSURES

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

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At September 30, 2014 , Gas Utility had $3.6 million of restricted cash associated with natural gas futures accounts with brokers. At September 30, 2013 , Gas Utility had $3.2 million restricted cash in brokerage accounts. At September 30, 2014 and 2013 , the fair values of our natural gas futures and option contracts were losses of $1.4 million and $1.7 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, 2014 and 2013 , the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $0.3 million and $(4.8) million, respectively. The fair values of FTRs at September 30, 2014 and 2013 , were not material.

In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at September 30, 2014 and 2013 , were not material.

Interest Rate Risk

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

Our variable-rate debt comprises borrowings under our Credit Agreement. This agreement provides for interest rates on borrowings that are indexed to short-term market interest rates. Based upon the average level of borrowings outstanding under these agreements in Fiscal 2014 and Fiscal 2013 , an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.3 million and $0.3 million , respectively.

Our long-term debt is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we expect to refinance such debt with new debt having interest rates reflecting then-current market conditions. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of approximately $53.0 million and $28.0 million at September 30, 2014 and 2013 , 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 $64.0 million and $32.0 million at September 30, 2014 and 2013 , 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, 2014 and 2013 .

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.

Impairment of Goodwill. Our goodwill is the result of business acquisitions.We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. In accordance with GAAP, a 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. 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. 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 more likely than not that the carrying value of a reporting unit is greater than its fair value. As of September 30, 2014 , our goodwill totaled $182.1 million. We did not record any impairments of goodwill during Fiscal 2014 , Fiscal 2013 or Fiscal 2012 .

Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation regarding pending claims and legal actions that arise in the normal course of our businesses. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere and PNG and CPG owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with GAAP, we establish reserves for pending claims and legal actions or environmental remediation obligations when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Reasonable estimates involve management judgments based on a broad range of information and prior experience. These judgments are reviewed quarterly as more information is received and the amounts reserved are updated as necessary. Such estimated reserves may differ materially from the actual 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, 2014 , UGI Utilities net property, plant and equipment totaled $ 1,682.3 million and we recorded depreciation expense of $55.8 million during Fiscal 2014 .

Regulatory Assets and Liabilities. Gas Utility and Electric Utility’s distribution businesses are subject to regulation by the PUC. In accordance with accounting guidance associated with rate-regulated entities, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2014 , our regulatory assets totaled $ 268.2 million. For additional information on our regulatory assets, see Note 4 to Consolidated Financial Statements.

Pension Plan Assumptions. Pension Plan assumptions are significant inputs to the actuarial models that measure 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 the discount rate applied to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase, among others. Assets of the Pension Plan are held in trust and consist principally of equity and fixed income mutual funds and, to a lesser extent, common stock. Changes in plan assumptions as well as fluctuations in actual equity or fixed income market returns could have a material impact on future pension costs. We believe the two most critical assumptions are (1) the expected rate of return on plan assets and (2) the discount rate. A decrease in the expected rate of return on Pension Plans assets of 50 basis points to a rate of 7.25% would result in an increase in pre-tax pension cost of approximately $1.9 million in Fiscal 2015 . A decrease in the discount rate of 50 basis points to a rate of 4.10% would result in an increase in pre-tax pension cost of approximately $3.1 million in Fiscal 2015 . 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, 2014 , 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. 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 using the criteria in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO 1992”).

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

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


(c)	No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter 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 PricewaterhouseCoopers LLP, the Company’s independent registered public accountants, in Fiscal 2014 and Fiscal 2013 were as follows:



	2014		2013
Audit Fees	$	1,070,189	$	851,600
Audit-Related Fees	—		—
Tax Fees	—		—
All Other Fees	—		—
Total Fees for Services Provided	$	1,070,189	$	851,600

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.

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.

As a result of the Audit Committee’s decision to conduct a request for proposal process for audit services during 2014, the Audit Committee selected Ernst & Young LLP as the Company’s independent registered public accounting firm for the 2015 fiscal year.

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

Consolidated Balance Sheets as of September 30, 2014 and 2013

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

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

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

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

Notes to Consolidated Financial Statements


(2)	Financial Statement Schedule:

For the years ended September 30, 2014, 2013 and 2012

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

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.1**	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006.	UGI	Form 8-K (2/27/07)	10.1
10.2**	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 - Terms and Conditions as amended and restated effective November, 2012.	UGI	Form 10-K (9/30/13)	10.2
10.3**	UGI Corporation 2013 Omnibus Incentive Compensation Plan, effective as of January 24, 2013.	UGI	Registration Statement No. 333-186178 (1/24/2013)	99.1
10.4**	UGI Corporation 2009 Deferral Plan, as Amended and Restated effective January 24, 2014.	UGI	Form 10-Q (3/31/14)	10.5
10.5**	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
10.6**	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
10.7**	UGI Corporation 2009 Supplemental Executive Retirement Plan for New Employees, as Amended and Restated effective November 22, 2013.	UGI	Form 10-Q (3/31/14)	10.4
10.8**	UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.	Utilities	Form 10-Q (6/30/13)	10.1
10.9**	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
10.10**	UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2014.	UGI	Form 10-Q (3/31/14)	10.9
10.11**	UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2014.	UGI	Form 10-Q (3/31/14)	10.11

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.12**	UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Employees, dated January 1, 2014.	UGI	Form 10-Q (3/31/14)	10.7
10.13**	UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2014.	UGI	Form 10-Q (3/31/14)	10.12
10.14**	UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006, as amended November 16, 2012.	UGI	Form 10-Q (3/31/13)	10.14
10.15	Credit Agreement, dated as of May 25, 2011 among UGI Utilities, Inc., as borrower, and PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and RBS Citizens, N.A., as joint lead arrangers and joint bookrunners, and PNC Bank, National Association, Citizens Bank of Pennsylvania, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, The Bank of New York Mellon, and the other financial institutions from time to time parties thereto.	Utilities	Form 8-K (5/25/11)	10.1
*10.16	FSS Service Agreement No. 79028 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.
10.17	Firm Storage and Delivery Service Agreement (Rate GSS) dated July 1, 1996 between Transcontinental Gas Pipe Line Corporation and PG Energy.	Utilities	Form 8-K (8/24/06)	10.8
10.18	Service Agreement For Use Under Seller’s GSS Rate Schedule dated July 9, 2012 between Transcontinental Gas Pipe Line Company, LLC and UGI Penn Natural Gas, Inc.	Utilities	Form 10-Q (6/30/12)	10.1
*10.19	SST Service Agreement No. 79133 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit

*12.1	Computation of Ratio of Earnings to Fixed Charges.
14	Code of Ethics for principal executive, financial and accounting officers.	UGI	Form 10-K (9/30/03)	14
*23	Consent of 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, 2014 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2014 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2014, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*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 28, 2014	By:	/s/ Donald E. Brown
			Donald E. Brown
			Vice President — Finance and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 28, 2014 by the following persons on behalf of the Registrant in the capacities indicated.




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

/s/ Donald E. Brown		Vice President — Finance and Chief Financial Officer
Donald E. Brown

/s/ Lon R. Greenberg		Chairman and Director
Lon R. Greenberg

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

/s/ Richard W. Gochnauer		Director
Richard W. Gochnauer

/s/ Frank S. Hermance		Director
Frank S. Hermance

/s/ Ernest E. Jones		Director
Ernest E. Jones

/s/ Anne Pol		Director
Anne Pol

/s/ M. Shawn Puccio		Director
M. Shawn Puccio

/s/ Marvin O. Schlanger		Director
Marvin O. Schlanger

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

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

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

UGI UTILITIES, INC.

FINANCIAL INFORMATION

FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K

YEAR ENDED SEPTEMBER 30, 2014

UGI UTILITIES, INC.

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE



		Pages

Financial Statements:

Report of Independent Registered Public Accounting Firm		F- 2

Consolidated Balance Sheets as of September 30, 2014 and 2013		F- 3

Consolidated Statements of Income for the years ended September 30, 2014, 2013 and 2012		F- 4

Consolidated Statements of Comprehensive Income for the years ended September 30, 2014, 2013 and 2012		F- 5

Consolidated Statements of Cash Flows for the years ended September 30, 2014, 2013 and 2012		F- 6

Consolidated Statements of Stockholder’s Equity for the years ended September 30, 2014, 2013 and 2012		F- 7

Notes to Consolidated Financial Statements		F- 8 to F- 32

Financial Statement Schedule:

For the years ended September 30, 2014, 2013 and 2012:

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

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of stockholder’s equity and of cash flows present fairly, in all material respects, the financial position of UGI Utilities, Inc. and its subsidiaries at September 30, 2014 and 2013 , and the results of their operations and their cash flows for each of the three years in the period 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 appearing under Item 15 (a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2014 , based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

November 28, 2014

F- 2

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)



	September 30,
	2014			2013
ASSETS
Current assets:
Cash and cash equivalents	$	12,401		$	4,707
Restricted cash	3,592			3,181
Accounts receivable (less allowances for doubtful accounts of $6,992 and $5,519, respectively)	65,080			53,341
Accounts receivable — related parties	2,865			3,497
Accrued utility revenues	14,330			18,868
Inventories	95,219			89,661
Deferred income taxes	1,492			14,165
Regulatory assets	13,159			8,217
Derivative instruments	1,028			43
Prepaid expenses & other current assets	18,535			15,862
Total current assets	227,701			211,542
Property, plant and equipment	2,568,552			2,427,810
Less accumulated depreciation and amortization	(886,268		)	(853,675		)
Net property, plant and equipment	1,682,284			1,574,135
Goodwill	182,145			182,145
Regulatory assets	255,007			236,694
Other assets	7,506			5,806
Total assets	$	2,354,643		$	2,210,322
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	20,000		$	—
Short-term borrowings	86,300			17,500
Accounts payable — trade	58,453			51,970
Accounts payable — related parties	11,761			12,487
Employee compensation and benefits accrued	14,647			13,664
Interest accrued	8,908			11,281
Customer deposits and advances	40,401			40,307
Derivative instruments	1,632			6,677
Pension and postretirement benefit obligations	1,100			17,885
Other current liabilities	34,280			35,742
Total current liabilities	277,482			207,513
Long-term debt	622,000			642,000
Deferred income taxes	461,461			436,810
Deferred investment tax credits	3,933			4,270
Pension and other postretirement benefit obligations	98,363			72,505
Other noncurrent liabilities	51,567			55,610
Total liabilities	1,514,806			1,418,708
Commitments and contingencies (Note 12)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)	60,259			60,259
Additional paid-in capital	471,071			470,098
Retained earnings	316,688			269,977
Accumulated other comprehensive loss	(8,181		)	(8,720		)
Total common stockholder’s equity	839,837			791,614
Total liabilities and stockholder’s equity	$	2,354,643		$	2,210,322

See accompanying Notes to Consolidated Financial Statements.

F- 3

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of dollars)



	Year Ended September 30,
	2014			2013			2012
Revenues	$	1,086,889		$	940,712		$	884,333
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	562,942			465,996			459,079
Operating and administrative expenses	195,408			188,266			165,479
Operating and administrative expenses — related parties	10,671			8,366			9,326
Taxes other than income taxes	16,608			16,877			17,263
Depreciation	55,776			52,298			49,702
Amortization	3,443			3,418			3,090
Other income, net	(4,359		)	(4,828		)	(4,989		)
	840,489			730,393			698,950
Operating income	246,400			210,319			185,383
Interest expense	38,471			39,309			42,412
Income before income taxes	207,929			171,010			142,971
Income taxes	83,823			68,912			55,073
Net income	$	124,106		$	102,098		$	87,898

See accompanying Notes to Consolidated Financial Statements.

F- 4

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)



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

See accompanying Notes to Consolidated Financial Statements.

F- 5

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)



	Year Ended September 30,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	124,106		$	102,098		$	87,898
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	59,219			55,716			52,792
Deferred income taxes, net	33,588			35,281			53,247
Pension contributions, net of pension expense	(9,459		)	(4,450		)	(17,431		)
Provision for uncollectible accounts	13,149			9,584			6,286
Other, net	3,998			(1,560		)	2,490
Net change in:
Accounts receivable and accrued utility revenues	(19,718		)	(16,446		)	5,461
Inventories	(5,558		)	(22,327		)	36,929
Deferred fuel costs, net of changes in unsettled derivatives	(17,632		)	9,321			(8,190		)
Accounts payable	5,757			7,511			(6,718		)
Other current assets	362			13,598			(5,063		)
Other current liabilities	864			(18,413		)	2,041
Net cash provided by operating activities	188,676			169,913			209,742
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(164,180		)	(151,090		)	(114,090		)
Net costs of property, plant and equipment disposals	(8,214		)	(4,925		)	(4,922		)
(Increase) decrease in restricted cash	(411		)	(3,181		)	4,308
Net cash used by investing activities	(172,805		)	(159,196		)	(114,704		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(77,395		)	(58,975		)	(70,615		)
Increase in short-term borrowings	68,800			8,300			9,200
Issuances of long-term debt	174,445			175,000			—
Repayments of long-term debt	(175,000		)	(133,000		)	(40,000		)
Excess tax benefits from equity-based payment arrangements	973			1,406			369
Net cash used by financing activities	(8,177		)	(7,269		)	(101,046		)
Cash and cash equivalents increase (decrease)	$	7,694		$	3,448		$	(6,008	)
CASH AND CASH EQUIVALENTS:
End of year	$	12,401		$	4,707		$	1,259
Beginning of year	4,707			1,259			7,267
Increase (decrease)	$	7,694		$	3,448		$	(6,008	)
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for:
Interest	$	34,781		$	49,460		$	29,902
Income taxes	$	54,293		$	18,376		$	6,728

See accompanying Notes to Consolidated Financial Statements.

F- 6

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(Thousands of dollars)



	Year Ended September 30,
	2014			2013			2012
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	$	269,977		$	229,379		$	212,096
Net income	124,106			102,098			87,898
Cash dividends — Common Stock	(77,395		)	(58,975		)	(70,615		)
Dividends of net assets	—			(2,525		)	—
Balance, end of year	$	316,688		$	269,977		$	229,379

Additional paid-in capital
Balance, beginning of year	$	470,098		$	468,692		$	468,323
Excess tax benefits on equity-based compensation	973			1,406			369
Balance, end of year	$	471,071		$	470,098		$	468,692

Accumulated other comprehensive income (loss)
Balance, beginning of year	$	(8,720	)	$	(29,817	)	$	(21,833	)
Net gains (losses) on derivative instruments	—			15,153			(6,744		)
Reclassifications of net losses on derivative instruments	1,567			471			1,111
Benefit plans, principally actuarial (losses) gains	(1,413		)	4,689			(2,745		)
Reclassifications of benefit plans actuarial losses and prior service costs	385			784			394
Balance, end of year	$	(8,181	)	$	(8,720	)	$	(29,817	)

Total UGI Utilities, Inc. stockholder’s equity	$	839,837		$	791,614		$	728,513

See accompanying Notes to Consolidated Financial Statements.

F- 7

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.” PNG also has a heating, ventilation and air-conditioning service business (“UGI Penn HVAC Services, Inc.”) which operates principally in the PNG service territory (“HVAC Business”).

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 all significant intercompany accounts when we consolidate.

Effects of Regulation

UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980 related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period 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.

F- 8

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”) exemption under GAAP and such exemption has been elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.

Substantially all of the gains and losses on derivative instruments used by Gas Utility and Electric Utility are included in regulatory assets and liabilities in accordance with FASB guidance 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 (“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. Certain of our 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 and commodities rendered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered.

We present revenue-related taxes collected from 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.

F- 9

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 generally consistent with income taxes calculated on a separate return basis. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income.

Comprehensive Income

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

Changes in AOCI during Fiscal 2014 are as follows:



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

Amounts in the table above are net of tax.

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

Cash and Cash Equivalents

All 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 market. Substantially all of our inventory is determined on an average cost method.

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.

F- 10

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.3% in Fiscal 2014 , 2.3% in Fiscal 2013 and 2.2% in Fiscal 2012 . Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.5% in Fiscal 2014 , 2.4% in Fiscal 2013 and 2.4% in Fiscal 2012 . 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.

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.

Goodwill

Our goodwill is the result of business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. In accordance with GAAP, a 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. 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. 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 2014 , Fiscal 2013 or Fiscal 2012 .

Impairment of Long-Lived Assets

We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No provisions for impairments were recorded during Fiscal 2014 , Fiscal 2013 or Fiscal 2012 .

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

F- 11

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 is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. For further information, see Note 12 .

3. ACCOUNTING CHANGES

Adoption of New Accounting Standards

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In Fiscal 2014, the Company adopted new accounting guidance regarding disclosures for items reclassified out of AOCI. The disclosures required by the new accounting guidance are included in Note 2 and Note 14 to Consolidated Financial Statements. The new disclosures are applied prospectively. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities. Effective October 1, 2013, the Company adopted new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet as a result of an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new disclosures are applied retroactively to all periods presented. The required disclosures are included in Note 14 to Consolidated Financial Statements. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.

Accounting Standards Not Yet Adopted

Revenue Recognition. In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in ASC 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 company expects to be entitled in exchange for those goods or services. This standard is effective for the Company beginning in fiscal 2018 and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of assessing the impact of the adoption of ASU 2014-09 on its results of operations, cash flows and financial position.

Discontinued Operations. In April 2014, the FASB issued authoritative guidance amending existing requirements for reporting discontinued operations. Under the new guidance, discontinued operations reporting will be limited to disposal transactions that represent strategic shifts having a major effect on operations and financial results. The amended guidance also enhances disclosures and requires assets and liabilities of a discontinued operation to be classified as such for all periods presented in the financial statements. Public entities will apply the amended guidance prospectively to all disposals occurring within annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company will adopt this standard on October 1, 2015. Due to the change in requirements for reporting discontinued operations described above, presentation and disclosure of future disposal transactions after adoption may be different than under current standards.

F- 12

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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:



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


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

Income taxes recoverable . This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of 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. Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 65 years .

Underfunded pension and other postretirement plans . This regulatory asset represents the portion of prior service cost and net actuarial losses 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 represent amounts actually spent by UGI Gas to clean up sites in Pennsylvania as well as the portion of estimated probable future environmental remediation and investigation costs principally at manufactured gas plant (“MGP”) sites that CPG and PNG expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 12 ). Consistent with prior ratemaking treatment, UGI Gas anticipates it will recover in rates, through future base rate proceedings, a five -year average of prudently incurred remediation costs at Pennsylvania sites and UGI Gas is currently amortizing such costs over a five -year period. PNG and CPG are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2014 , the period over which PNG and CPG expect to recover these costs will depend upon future remediation activity.

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

F- 13

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized losses on such contracts at September 30, 2014 and 2013 , were $ (1,363) and $ (1,743) , respectively.

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

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at September 30, 2014 and 2013 , were not material.

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

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

State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, 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 comprise a number of items including, among others, deferred postretirement costs, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2014 , UGI Utilities expects to recover these costs over periods of approximately 1 to 20 years.

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

Other Regulatory Matters

Transfers of Assets . On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11-mile natural gas pipeline, related facilities and rights of way located in Delmar Township, Pennsylvania (“TL-96 line”) to Energy Services, LLC (which is formerly known as UGI Energy Services, Inc. prior to its merger with and into UGI Energy Services, LLC effective October 1, 2013), a second-tier wholly owned subsidiary of UGI (“Energy Services”). The PUC approved the transfer and in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the TL-96 line was approximately $2,650 which amount, net of related deferred income taxes of $384 , is reflected as a dividend of net assets in the Fiscal 2013 Consolidated Statement of Stockholder’s Equity.

F- 14

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

5. INVENTORIES

Inventories comprise the following at September 30:



	2014		2013
Gas Utility natural gas	$	82,664	$	78,950
Materials, supplies and other	12,555		10,711
Total inventories	$	95,219	$	89,661

At September 30, 2014 , UGI Utilities is a party to four principal storage contract administrative agreements (“SCAAs”) having terms of one and three years. Three of the SCAAs are with Energy Services and one of the SCAAs is 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), are included in the caption “Gas Utility natural gas” in the table above.

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

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

6. PROPERTY, PLANT AND EQUIPMENT

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



	2014		2013
Distribution	$	2,294,590	$	2,162,580
Transmission	88,199		86,623
General and other, including construction in process	185,763		178,607
Total property, plant and equipment	$	2,568,552	$	2,427,810

F- 15

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

7. DEBT

Long-term debt comprises the following at September 30:



	2014			2013

Term Loan Credit Agreement	$	—		$	175,000
Senior Notes:
5.75%, due September 2016	175,000			175,000
4.98%, due March 2044	175,000			—
6.21%, due September 2036	100,000			100,000
Medium-Term Notes:
5.16%, due May 2015	20,000			20,000
7.37%, due October 2015	22,000			22,000
5.64%, due December 2015	50,000			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	642,000			642,000
Less: current maturities	(20,000		)	—
Total long-term debt due after one year	$	622,000		$	642,000

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

In March 2014, UGI Utilities issued in a private placement $175,000 of 4.98% Senior Notes due March 2044 (“4.98% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175,000 of borrowings under UGI Utilities’ 364-day Term Loan Credit Agreement. Because the Company had the intent and ability to refinance the Term Loan Credit Agreement on a long-term basis as of September 30, 2013 , amounts outstanding under the Term Loan Credit Agreement were classified as long-term on the 2013 Consolidated Balance Sheet.

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

Restrictive Covenants. The 4.98% 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. The 4.98% 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 therein, 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.

F- 16

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

8. INCOME TAXES

The provisions for income taxes consist of the following:



	2014			2013			2012
Current expense (benefit):
Federal	$	38,786		$	21,807		$	(909	)
State	11,449			11,824			2,735
Total current expense	50,235			33,631			1,826
Deferred expense:
Federal	29,208			33,349			48,336
State	4,717			2,274			5,257
Investment tax credit amortization	(337		)	(342		)	(346		)
Total income tax expense	$	83,823		$	68,912		$	55,073

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



	2014		2013		2012
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Difference in tax rate due to:
State income taxes, net of federal	5.1		5.4		4.1
Other, net	0.2		(0.1	)	(0.6	)
Effective tax rate	40.3	%	40.3	%	38.5	%

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

F- 17

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:



	2014			2013
Excess book basis over tax basis of property, plant and equipment	$	392,839		$	362,259
Goodwill	36,034			31,516
Regulatory assets	109,953			101,622
Other	1,349			949
Gross deferred tax liabilities	540,175			496,346
Pension plan liabilities	(40,461		)	(35,996		)
Allowance for doubtful accounts	(2,903		)	(2,290		)
Deferred investment tax credits	(1,632		)	(1,772		)
Employee-related expenses	(5,630		)	(5,850		)
Regulatory liabilities	(14,836		)	(15,472		)
Environmental liabilities	(4,389		)	(7,002		)
Derivative financial instruments	(6,224		)	(3,397		)
Other	(4,131		)	(1,922		)
Gross deferred tax assets	(80,206		)	(73,701		)
Net deferred tax liabilities	$	459,969		$	422,645

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

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

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

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



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

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

9. EMPLOYEE RETIREMENT PLANS

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

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plan, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets and the funded status of the Pension Plan and

F- 18

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

other postretirement plans as of September 30, 2014 and 2013 . 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
	2014			2013			2014			2013
Change in benefit obligations:
Benefit obligations — beginning of year	$	486,468		$	543,605		$	10,688		$	14,560
Service cost	7,309			9,385			175			223
Interest cost	25,102			22,784			519			587
Actuarial loss (gain)	43,064			(69,112		)	205			(1,881		)
Plan amendments	—			993			—			(1,836		)
Benefits paid	(22,218		)	(21,187		)	(451		)	(965		)
Benefit obligations — end of year	$	539,725		$	486,468		$	11,136		$	10,688
Change in plan assets:
Fair value of plan assets — beginning of year	$	398,171		$	351,543		$	11,723		$	11,205
Actual gain on assets	47,285			45,450			1,434			1,117
Employer contributions	19,227			22,365			142			366
Benefits paid	(22,218		)	(21,187		)	(451		)	(965		)
Fair value of plan assets — end of year	$	442,465		$	398,171		$	12,848		$	11,723
Funded status of the plans — end of year	$	(97,260	)	$	(88,297	)	$	1,712		$	1,035
(Liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	$	—		$	—		$	3,971		$	3,252
Unfunded liabilities — included in other current liabilities	(1,100		)	(17,885		)	(159		)	(372		)
Unfunded liabilities — included in other noncurrent liabilities	(96,160		)	(70,412		)	(2,100		)	(1,845		)
Net amount recognized	$	(97,260	)	$	(88,297	)	$	1,712		$	1,035
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	$	189		$	222		$	(61	)	$	(74	)
Net actuarial loss (gain)	10,662			9,113			(46		)	(222		)
Total	$	10,851		$	9,335		$	(107	)	$	(296	)
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	$	1,908		$	2,223		$	(3,625	)	$	(4,286	)
Net actuarial loss	107,363			91,275			2,616			3,586
Total	$	109,271		$	93,498		$	(1,009	)	$	(700	)

In Fiscal 2015 , we estimate that we will amortize approximately $9,700 of net actuarial losses, primarily associated with Pension Plan, and $300 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- 19

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:	2014		2013		2012		2014		2013		2012
Discount rate - benefit obligations	4.60	%	5.20	%	4.20	%	4.60	%	5.10% - 5.40%		4.10% - 4.30%
Discount rate - benefit cost	5.20	%	4.20	%	5.30	%	5.10% - 5.40%		4.10% - 4.30%		5.30	%
Expected return on plan assets	7.75	%	7.75	%	7.75	%	5.00	%	5.00	%	5.20	%
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 $499,082 and $451,228 as of September 30, 2014 and 2013 , respectively. Included in the end of year Pension Plan PBOs above are $48,758 at September 30, 2014 , and $44,161 at September 30, 2013 , relating to employees of UGI and certain of its other subsidiaries. Included in the end of year other postretirement plans ABOs above are $887 at September 30, 2014 , and $787 at September 30, 2013 , 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
	2014			2013			2012			2014			2013			2012
Service cost	$	6,492		$	8,211		$	7,025		$	162		$	205		$	152
Interest cost	22,885			20,783			22,376			488			557			639
Expected return on assets	(26,599		)	(24,791		)	(23,762		)	(557		)	(529		)	(481		)
Amortization of:
Prior service cost (benefit)	348			249			249			(641		)	(420		)	(422		)
Actuarial loss	6,642			13,463			7,853			116			336			355
Net benefit cost (income)	9,768			17,915			13,741			(432		)	149			243
Change in associated regulatory liabilities	—			—			—			3,704			3,302			3,188
Net benefit cost after change in regulatory liabilities	$	9,768		$	17,915		$	13,741		$	3,272		$	3,451		$	3,431

Pension Plan assets are held in trust. 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 2014 , Fiscal 2013 and Fiscal 2012 , we made contributions to the Pension Plan of $19,227 , $22,365 and $31,172 , respectively. We believe that in Fiscal 2015 we will be required to make contributions to the Pension Plan of approximately $ 1,100 .

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 calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. The required contribution to the VEBA during Fiscal 2015 , 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 2015	$	24,295	$	753
Fiscal 2016	25,425		710
Fiscal 2017	26,692		644
Fiscal 2018	28,051		615
Fiscal 2019	29,298		604
Fiscal 2020 - 2024	164,102		2,875

F- 20

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:



	2014		2013
Health care cost trend rate assumed for next year	7.0	%	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	2019		2019

A one percentage point change in these assumed health care cost trend rates would not have had a material impact on Fiscal 2014 other postretirement benefit cost or the September 30, 2014 , other postretirement benefit ABO.

We also sponsor unfunded and non-qualified supplemental executive retirement income plans. At September 30, 2014 and 2013 , the PBOs of these plan were $2,866 and $3,550 , respectively. We recorded expense for these plans of $372 in Fiscal 2014 , $498 in Fiscal 2013 and $255 in Fiscal 2012 .

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:	2014		2013		Allocation		Range
Equity investments:
Domestic	55.6	%	57.5	%	52.5	%	40.0% - 65.0%
International	11.3	%	11.1	%	12.5	%	7.5% - 17.5%
Total	66.9	%	68.6	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	33.1	%	31.4	%	35.0	%	30.0% - 40.0%
Total	100.0	%	100.0	%	100.0	%



					Target
	Actual				Asset		Permitted
VEBA:	2014		2013		Allocation		Range
Domestic equity investments	67.9	%	65.6	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	32.1	%	34.4	%	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 self-directed portfolio of 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 9.6% and 8.2% of Pension Plan assets at September 30, 2014 and 2013 , respectively.

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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, 2014 and 2013 are as follows:



	Pension Plan
	Level 1		Level 2		Level 3		Total
September 30, 2014:
Domestic equity investments:
S&P 500 Index equity mutual funds	$	152,613	$	—	$	—	$	152,613
Small and midcap equity mutual funds	41,417		—		—		41,417
Smallcap common stocks	9,325		—		—		9,325
UGI Corporation Common Stock	42,502		—		—		42,502
Total domestic equity investments	245,857		—		—		245,857
International index equity mutual funds	49,935		—		—		49,935
Fixed income investments:
Bond index mutual funds	140,949		—		—		140,949
Cash equivalents	—		5,724		—		5,724
Total fixed income investments	140,949		5,724		—		146,673
Total	$	436,741	$	5,724	$	—	$	442,465
September 30, 2013:
Equity investments:
S&P 500 Index equity mutual funds	$	141,774	$	—	$	—	$	141,774
Small and midcap equity mutual funds	54,528		—		—		54,528
UGI Corporation Common Stock	32,551		—		—		32,551
Total domestic equity investments	228,853		—		—		228,853
International index equity mutual funds	44,452		—		—		44,452
Fixed income investments:
Bond index mutual funds	120,906		—		—		120,906
Cash equivalents	—		3,960		—		3,960
Total fixed income investments	120,906		3,960		—		124,866
Total	$	394,211	$	3,960	$	—	$	398,171



	VEBA
	Level 1		Level 2		Level 3		Total
September 30, 2014:
S&P 500 Index equity mutual fund	$	8,719	$	—	$	—	$	8,719
Bond index mutual fund	3,727		—		—		3,727
Cash equivalents	—		402		—		402
Total	$	12,446	$	402	$	—	$	12,848
September 30, 2013:
S&P 500 Index equity mutual fund	$	7,693	$	—	$	—	$	7,693
Bond index mutual fund	3,794		—		—		3,794
Cash equivalents	—		236		—		236
Total	$	11,487	$	236	$	—	$	11,723

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

F- 22

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 $1,916 in Fiscal 2014 , $1,762 in Fiscal 2013 and $1,690 in Fiscal 2012 . 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 was not material in Fiscal 2014, Fiscal 2013 or Fiscal 2012.

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, 2014 or 2013 .

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 (i) companies in the Standard & Poor’s Utilities Index for grants prior to January 1, 2011 and (ii) the Russell Midcap Utility Index, excluding telecommunication companies, for grants on or after January 1, 2011 (each a respective “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 $1,912 ( $1,119 after-tax) during Fiscal 2014 ; $1,078 ( $631 after-tax) during Fiscal 2013 ; and $783 ( $458 after-tax) during Fiscal 2012 .

As of September 30, 2014 , there was $840 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, 2014 , there was a total of $977 of unrecognized compensation expense associated with 84,522 UGI Unit awards that is expected to be recognized over a weighted average period of 1.8 years. At September 30, 2014 and 2013 , total liabilities of $1,285 and $360 , respectively, associated with UGI Unit awards are reflected in other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheets.

F- 23

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

The following table summarizes UGI Unit award activity for Fiscal 2014 (a) :



	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, 2013	91,997		$	22.81	30,993		$	22.33	61,004		$	23.05
Granted	24,975		$	32.59	2,100		$	32.59	22,875		$	32.59
Vested	—		$	—	18,053		$	23.27	(18,053	)	$	23.27
Forfeited	(6,150	)	$	24.50	—		$	—	(6,150	)	$	24.50
Unit awards paid	(26,300	)	$	23.61	(26,300	)	$	23.61	—		$	—
September 30, 2014	84,522		$	25.32	24,846		$	22.52	59,676		$	26.49


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

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 $6,803 in Fiscal 2014 , $6,270 in Fiscal 2013 and $6,362 in Fiscal 2012 .

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: 2015 — $6,665 ; 2016 — $6,170 ; 2017 — $4,545 ; 2018 — $3,673 ; 2019 — $1,396 ; after 2019 — $717 .

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 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 2016.

Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2014 , for fiscal years ending September 30 are as follows: 2015 — $203,975 ; 2016 — $102,378 ; 2017 — $81,820 ; 2018 — $59,320 ; 2019 — $48,020 ; after 2019 — $96,281 .

Contingencies

Environmental Matters

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, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800

F- 24

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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, 2014 and 2013 , our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $10,732 and $14,019 , respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

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 (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five -year average of such prudently incurred remediation costs and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At September 30, 2014 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.

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- 25

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 financial 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, 2014 and 2013 :



	Asset (Liability)
	Level 1			Level 2			Level 3		Total
September 30, 2014
Derivative instruments:
Assets:
Commodity contracts	$	679		$	1,018		$	—	$	1,697
Liabilities:
Commodity contracts	$	(2,095	)	$	(206	)	$	—	$	(2,301	)
September 30, 2013 (a)
Derivative instruments:
Assets:
Commodity contracts	$	92		$	—		$	—	$	92
Liabilities:
Commodity contracts	$	(2,211	)	$	(4,515	)	$	—	$	(6,726	)


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

The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts and certain non exchange-traded electricity forward 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) at September 30, 2014 , were $642,000 and $712,815 , respectively. The carrying amount and estimated fair value of our long-term debt (including current maturities) at September 30, 2013 , were $642,000 and $699,929 , 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 related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations. For more information on the accounting for our derivative instruments, see Note 2 .

F- 26

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 2014 and 2013 , the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 16.9 million dekatherms and 15.0 million dekatherms, respectively. At September 30, 2014 , 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 in accordance with accounting guidance related to rate-regulated entities and reflected in cost of sales through the PGC 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. Because most of these contracts currently do not qualify for the NPNS exception under GAAP, the fair values of these contracts are reflected in current and noncurrent derivative instrument liabilities in the accompanying Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Consolidated Balance Sheets in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS mechanism (see Note 4 ). At September 30, 2014 and 2013 , the volumes of Electric Utility’s forward electricity purchase contracts were 237.0 million kilowatt hours and 245.8 million kilowatt hours, respectively. At September 30, 2014 , the maximum period over which these contracts extend is 8 months.

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 related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 4 ). At September 30, 2014 and 2013 , the total volumes associated with FTRs totaled 232.1 million kilowatt hours and 189.3 million kilowatt hours, respectively. At September 30, 2014 , 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 and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. Associated volumes, fair values and effects on net income were not material for all periods presented.

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 IRPAs. We account for IRPAs as cash flow hedges. As of September 30, 2014 and 2013 , we had no unsettled IRPAs.

During Fiscal 2012, UGI Utilities reclassified pre-tax losses of $682 from AOCI into income as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in other income, net, in the Fiscal 2012 Consolidated Statements of Income.

At September 30, 2014 , the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $2,674 .

Derivative Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2014 , Gas Utility’s restricted cash in brokerage accounts totaled $3,592 . At September 30, 2013 , Gas Utility had $3,181 of restricted cash in brokerage accounts.

F- 27

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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.

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 derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our 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 our derivative assets and liabilities, as well as the effects of offsetting, as of September 30, 2014 and 2013 :



	2014			2013 (a)
Derivative assets:
Derivatives accounted for under ASC 980:
Commodity contracts	$	1,697		$	80

Derivatives not designated as hedging instruments:
Commodity contracts	—			12
Total derivative assets - gross	1,697			92
Gross amounts offset in the balance sheet	(669		)	(49		)
Total derivative assets - net	$	1,028		$	43

Derivative liabilities:
Derivatives accounted for under ASC 980:
Commodity contracts	$	(2,210	)	$	(6,726	)

Derivatives not designated as hedging instruments:
Commodity contracts	(91		)	—
Total derivative liabilities - gross	(2,301		)	(6,726		)
Gross amounts offset in the balance sheet	669			49
Total derivative liabilities - net	$	(1,632	)	$	(6,677	)


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

F- 28

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 on the Consolidated Statements of Income and changes in AOCI for Fiscal 2014 and 2013 :



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

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

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 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. 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 HVAC Business does 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- 29

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
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	$	2,354,643	$	2,214,118	$	140,525	$	—
Goodwill	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	164,180	$	156,425	$	7,755	$	—
2013
Revenues	$	940,712	$	839,050	$	99,986	$	1,676
Cost of sales	$	465,996	$	407,222	$	58,774	$	—
Depreciation and amortization	$	55,716	$	51,698	$	4,018	$	—
Operating income	$	210,319	$	198,352	$	11,385	$	582
Interest expense	39,309		37,280		2,029		—
Income before income taxes	$	171,010	$	161,072	$	9,356	$	582
Total assets	$	2,210,322	$	2,068,955	$	141,367	$	—
Goodwill	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	151,090	$	144,399	$	6,691	$	—
2012
Revenues	$	884,333	$	785,375	$	97,130	$	1,828
Cost of sales	$	459,079	$	402,534	$	56,545	$	—
Depreciation and amortization	$	52,792	$	48,992	$	3,800	$	—
Operating income	$	185,383	$	172,164	$	12,610	$	609
Interest expense	42,412		40,139		2,273		—
Income before income taxes	$	142,971	$	132,025	$	10,337	$	609
Total assets	$	2,196,173	$	2,045,480	$	150,693	$	—
Goodwill	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	114,090	$	109,020	$	5,070	$	—

16. OTHER INCOME, NET

Other income, net, comprises the following:



	2014		2013		2012
Non-tariff service income	$	2,670	$	2,706	$	2,653
Interest income	1,388		500		572
Other, net	301		1,622		1,764
Total other income, net	$	4,359	$	4,828	$	4,989

F- 30

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

17. RELATED PARTY TRANSACTIONS

From time to time, UGI Utilities is a party to SCAAs with Energy Services. At September 30, 2014 , UGI Utilities was a party to three SCAAs with Energy Services one of which expired October 31, 2014, and two of which expire October 31, 2015 and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts 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. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $38,299 , $45,843 and $24,344 in Fiscal 2014 , Fiscal 2013 and Fiscal 2012 , respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amount of such security deposits, which are included in other current liabilities on the Consolidated Balance Sheets, was $10,600 and $16,500 at September 30, 2014 and 2013 , respectively. Effective November 1, 2014, UGI Utilities entered into a new SCAA with Energy Services having a term of one year.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2014 , Fiscal 2013 and Fiscal 2012 , revenues associated with sales to Energy Services totaled $109,913 , $69,087 and $65,705 , 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 2014 , Fiscal 2013 and Fiscal 2012 , such purchases totaled $128,076 , $77,017 and $53,435 , respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

F- 31

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

18. 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,
	2013		2012		2014		2013		2014		2013		2014			2013
Revenues	$	298,899	$	273,797	$	513,956	$	395,901	$	152,694	$	148,798	$	121,340		$	122,216
Operating income	$	85,843	$	72,564	$	137,954	$	109,230	$	19,720	$	18,878	$	2,883		$	9,647
Net income (loss)	$	45,286	$	36,812	$	76,110	$	58,259	$	6,890	$	5,373	$	(4,180	)	$	1,654

F- 32

UGI UTILITIES, INC. AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

(Thousands of dollars)



	Balance at beginning of year		Charged (credited) to costs and expenses		Other				Balance at end of year
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

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

September 30, 2012
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	6,368	$	6,286	$	(9,066	)	⁽¹⁾	$	3,588


(1)	Uncollectible accounts written off, net of recoveries

S- 1

EXHIBIT INDEX



Exhibit No.		Description

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

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

12.1		Computation of Ratio of Earnings to Fixed Charges

23		Consent of PricewaterhouseCoopers LLP

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

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

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

EXHIBIT 10.16

Service Agreement No. 79028

Revision No. 4

FSS SERVICE AGREEMENT

THIS AGREEMENT is made and entered into this 19 day of November, 2014, by and between

COLUMBIA GAS TRANSMISSION, LLC ("Transporter") and UGI UTILITIES INC. ("Shipper").

WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:

Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FSS Rate Schedule and applicable General Terms and Conditions of Transporter's FERC Gas Tariff, Fourth Revised Volume No. 1 ("Tariff"), on file with the Federal Energy Regulatory Commission ("Commission"), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. Transporter shall store quantities of gas for Shipper up to but not exceeding Shipper's Storage Contract Quantity as specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission.

Section 2. Term. Service under this Agreement shall commence as of December 1, 2014, and shall continue in full force and effect until June 30, 2023. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commission's regulations and Transporter's Tariff.

Section 3. Rates . Shipper shall pay Transporter the charges and furnish the Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporter's maximum rate, but not less than Transporter's minimum rate. Such discounted rate may apply to: (a) specified quantities (contract demand or commodity quantities); (b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; (c) quantities during specified time periods; (d) quantities at specified points, locations, or other defined geographical areas; (e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported); (f) production and/or reserves committed by the Shipper; and (g) based on a formula including, but not limited to, published index prices for specific receipt and/or delivery points or other agreed-upon pricing points, provided that the

resulting rate shall be no lower than the minimum nor higher than the maximum applicable rate set forth in the Tariff. In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporter's maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sections. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates, which had been charged under a discount agreement, exceeded rates which ultimately

are found to be just and reasonable.

Section 4. Notices. Notices to Transporter under this Agreement shall be addressed to it at 5151 San Felipe, Suite 2500, Houston, Texas 77056, Attention: Customer Services and notices to Shipper shall be addressed to it at UGI Utilities Inc., 2525 N. 12th Street, Reading, PA 19605, Attention: Claire Neri, until changed by either party by written notice.

Section 5. Superseded Agreements . This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreement(s): FSS No. 79028, Revision No. 3.

UGI UTILITIES INC. COLUMBIA GAS TRANSMISSION, LLC

By By

Title Title

Date Date

Revision No. 4

Appendix A to Service Agreement No. 79028

Under Rate Schedule FSS

between Columbia Gas Transmission, LLC ("Transporter")

and UGI Utilities Inc. ("Shipper")

Storage Contract Quantity



Begin	End	Storage Contract	Maximum Daily Storage
Date	Date	Quantity (Dth)	Quantity (Dth/day)
December 1, 2014	March 31, 2017	6,252,936	114,649
April 1, 2017	March 31, 2020	1,162,536	20,782
April 1, 2020	June 30, 2023	400,000	10,000

_X_ Yes No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring

Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporter's FERC Gas Tariff.

Yes _X_ No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporter's FERC Gas Tariff.


	Yes _X_ No (Check applicable blank) This Service Agreement covers interim capacity sold pursuant to the provisions of General Terms and Conditions Section 4. Right of first refusal rights, if any, applicable to this interim capacity are limited as provided for in General Terms and Conditions Section 4.

Yes _X_ No (Check applicable blank) This Service Agreement covers offsystem capacity sold pursuant to section 47 of the General Terms and Conditions. Right of first refusal rights, if any, applicable to this offsystem capacity are limited as provided for in General Terms and Conditions Section 47.

UGI UTILITIES INC. COLUMBIA GAS TRANSMISSION, LLC

By By

Title Title

Date Date

EXHIBIT 10.19

Service Agreement No. 79133

Revision No. 5

SST SERVICE AGREEMENT

THIS AGREEMENT is made and entered into this 19 day of November, 2014, by and between COLUMBIA GAS TRANSMISSION, LLC ("Transporter") and UGI UTILITIES INC. ("Shipper").

WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:

Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective SST Rate Schedule and applicable General Terms and Conditions of Transporter's FERC Gas Tariff, Fourth Revised Volume No. 1 ("Tariff'), on file with the Federal Energy Regulatory Commission ("Commission"), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission.

Section 3. Rates. Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporter's maximum rate, but not less than Transporter's minimum rate. Such discounted rate may apply to: (a) specified quantities (contract demand or commodity quantities); (b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; (c) quantities during specified time periods; (d) quantities at specified points, locations, or other defined geographical areas; (e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will

be adjusted in a specified relationship to quantities actually transported); (f) production and/or reserves committed by the Shipper; and (g) based on a formula including, but not limited to, published index prices for specific receipt and/or delivery points or other agreed-upon pricing points, provided that the resulting rate shall be no lower than the minimum nor higher than the maximum applicable rate set forth in the Tariff. In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporter's maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sections. However, nothing

contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates, which had been charged under a discount agreement, exceeded rates which ultimately are found to be just and reasonable.

addressed to it at UGI Utilities Inc., 2525 N. 12th Street, Reading, PA 19605, Attention: Claire Neri, until changed by either party by written notice.

Section 5. Superseded Agreements . This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreement(s): SST No. 79133, Revision No. 4.

UGI UTILITIES INC. COLUMBIA GAS TRANSMISSION, LLC

By By

Title Title

Date Date

Revision No. 5

Appendix A to Service Agreement No. 79133

Under Rate Schedule SST

between Columbia Gas Transmission, LLC ("Transporter")

and UGI Utilities Inc. ("Shipper")

Transportation Demand



Begin Date			End Date	Transportation Demand Dth/day	Recurrence Interval
December 1, 2014			March 31,2017	114,649	10/1 - 3/31
December 1, 2014			March 31,2017	57,324	4/1 - 9/30
April 1, 2017			March 31, 2020	20,782	10/1-3/31
April 1, 2017			March 31, 2020	10,391	4/1 - 9/30
April 1, 2020			June 30, 2023	10,000	10/1 - 3/31
April 1, 2020			June 30, 2023	5,000	4/1 - 9/30
				Primary Receipt Points
					Maximum
					Daily
Begin End Scheduling Scheduling Quantity Recurrence
Date	Date	Point No.	Point Name		(Dth/day)	Interval
December 1, 2014	March 31, 2017	STOR	RP Storage Point TCO		114,649	10/1-3/31
December 1, 2014	March 31,2017	STOR	RP Storage Point TCO		57,324	4/1 - 9/30
April 1, 2017	March 31, 2020	STOR	RP Storage Point TCO		20,782	10/1-3/31
April 1,2017	March 31, 2020	STOR	RP Storage Point TCO		10,391	4/1 - 9/30
April 1, 2020	June 30, 2023	STOR	RP Storage Point TCO		10,000	10/1-3/31
April 1, 2020	June 30, 2023	STOR	RP Storage Point TCO		5,000	4/1 - 9/30



Begin Date	End Date	Scheduling Point No.	Scheduling Point Name	Measuring Point No.	Measuring Point Name	Maximum Daily Delivery Obligation (Dth/day) 1/	Design Daily Quantity (Dth/day) 1/	Minimum Delivery Pressure Obligation (psig) 1/	Recurrence Interval
December 1, 2014	March 31,2017	72-23	UGI CORP-23	600012	ROSEDALE	6,170		100	10/1 - 3/31
December 1, 2014	March 31,2017	72-23	UGI CORP-23	600013	TATAMY	7,800		400	10/1 - 3/31
December 1, 2014	March 31,2017	72-23	UGI CORP-23	600018	BOYERTOWN	4,050		400	10/1 - 3/31
December 1, 2014	March 31,2017	72-23	UGI CORP-23	600020	BIRDSBORO	22,422		400	10/1 - 3/31
December 1, 2014	March 31,2017	72-23	UGI CORP-23	600021	TEMPLE	20,811			10/1 - 3/31
December 1, 2014	March 31,2017	72-23	UGI CORP-23	600023	BALLY	11,000			10/1 - 3/31
December 1, 2014	March 31,2017	72-23	UGI CORP-23	600032	DAUPHIN	20,811			10/1 - 3/31
December 1, 2014	March 31,2017	72-23	UGI CORP-23	637254	UGI/CONECTIV	91,180		430	10/1 - 3/31
December 1, 2014	March 31, 2017	72-23	UGI CORP-23	600012	ROSEDALE	4,381		100	4/1 - 9/30
December 1, 2014	March 31, 2017	72-23	UGI CORP-23	600013	TATAMY	5,538		400	4/1 - 9/30
December 1, 2014	March 31,2017	72-23	UGI CORP-23	600018	BOYERTOWN	2,876		400	4/1 - 9/30
December 1, 2014	March 31,2017	72-23	UGI CORP-23	600020	BIRDSBORO	15,902		400	4/1 - 9/30
December 1, 2014	March 31, 2017	72-23	UGI CORP-23	600021	TEMPLE	14,776			4/1 - 9/30
December 1, 2014	March 31,2017	72-23	UGI CORP-23	600023	BALLY	7,810			4/1 - 9/30
December 1, 2014	March 31, 2017	72-23	UGI CORP-23	600032	DAUPHIN	14,776			4/1 - 9/30
December 1, 2014	March 31, 2017	72-23	UGI CORP-23	637254	UGI/CONECTIV	63,440		430	4/1 - 9/30
April 1, 2017	March 31, 2020	72-23	UGI CORP-23	637254	UGI/CONECTIV	6,180		430	10/1 - 3/31
April 1, 2017	March 31, 2020	72-23	UGI CORP-23	600020	BIRDSBORO	41		400	4/1 - 9/30
April 1, 2017	March 31, 2020	72-23	UGI CORP-23	637254	UGI/CONECTIV	3,090		430	4/1 - 9/30



December 1, 2014	March 31, 2017	72-25	UGI CORP-25	600019	MILLWAY	15,376	400	10/1 - 3/31
December 1, 2014	March 31,2017	72-25	UGI CORP-25	600030	HARRISBURG	34,525	400	10/1 - 3/31
December 1, 2014	March 31,2017	72-25	UGI CORP-25	600033	MT. JOY	1,686	100	10/1 - 3/31
December 1, 2014	March 31, 2017	72-25	UGI CORP-25	600036	LITITZ	2,976	300	10/1 - 3/31
December 1, 2014	March 31,2017	72-25	UGI CORP-25	600037	MANHEIM	1,488	150	10/1 - 3/31
December 1, 2014	March 31, 2017	72-25	UGI CORP-25	600038	NEW HOLLAND	23,856	200	10/1 - 3/31



Begin Date	End Date	Scheduling Point No.	Scheduling Point Name	Measuring Point No.	Measuring Point Name	Maximum Daily Delivery Obligation (Dth/day) 1/	Design Daily Quantity (Dth/day) 1/	Minimum Delivery Pressure Obligation (psig) 1/	Recurrence Interval
December 1, 2014	March 31,2017	72-25	UGI CORP-25	603470	MARIETTA	13,800		400	10/1 - 3/31
December 1, 2014	March 31, 2017	72-25	UGI CORP-25	604626	LOCUST POINT	27,700		500	10/1 - 3/31
December 1, 2014	March 31,2017	72-25	UGI CORP-25	630112	UGI Morgantown	2,500		60	10/1 - 3/31
December 1, 2014	March 31, 2017	72-25	UGI CORP-25	600019	MILLWAY	10,917		400	4/1 - 9/30
December 1, 2014	March 31,2017	72-25	UGI CORP-25	600030	HARRISBURG	23,564		400	4/1 - 9/30
December 1, 2014	March 31, 2017	72-25	UGI CORP-25	600033	MT. JOY	1,197		100	4/1 - 9/30
December 1, 2014	March 31,2017	72-25	UGI CORP-25	600036	LITITZ	2,113		300	4/1 - 9/30
December 1, 2014	March 31, 2017	72-25	UGI CORP-25	600037	MANHEIM	1,056		150	4/1 - 9/30
December 1, 2014	March 31,2017	72-25	UGI CORP-25	600038	NEW HOLLAND	16,623		200	4/1 - 9/30
December 1, 2014	March 31, 2017	72-25	UGI CORP-25	603470	MARIETTA	9,798		400	4/1 - 9/30
December 1, 2014	March 31, 2017	72-25	UGI CORP-25	604626	LOCUST POINT	19,667		500	4/1 - 9/30
December 1, 2014	March 31,2017	72-25	UGI CORP-25	630112	UGI Morgantown	1,775		60	4/1 - 9/30
April 1, 2017	June 30, 2023	72-25	UGI CORP-25	600030	HARRISBURG	4,520		400	10/1 - 3/31
April 1, 2017	June 30, 2023	72-25	UGI CORP-25	600038	NEW HOLLAND	1,500		200	10/1 - 3/31



April 1, 2017	June 30, 2023	72-25	UGI CORP-25	600030	HARRISBURG	2,260	400	4/1 - 9/30
April 1, 2017	June 30, 2023	72-25	UGI CORP-25	600038	NEW HOLLAND	750	200	4/1 - 9/30
December 1, 2014	June 30, 2023	C22	EAGLE-25	632170	EAGLE C.S. (74-0000	8,500		10/1 - 3/31
December 1, 2014	June 30, 2023	C22	EAGLE-25	632170	EAGLE C.S. (74-0000	4,250		4/1 - 9/30
December 1, 2014	March 31, 2017	C23	PENNSBURG-23	631929	PENNSBURG (74-000	0		10/1 - 3/31
December 1, 2014	March 31,2017	C23	PENNSBURG-23	631929	PENNSBURG (74-000	0		4/1 - 9/30

Application of MDDOs, DDQs and ADOs, minimum pressure and/or hourly flowrate shall be as follows:

FN01 Transporter's historic practice of providing Shipper flexibility in meeting the hourly variations in its requirements at city-gate delivery points under its service agreements, within the daily firm obligations set forth in Shipper's contracts, will continue unless it becomes inconsistent with the terms of Transporter's FERC Gas Tariff, as that Tariff may be changed from time to time, or unless Transporter issues an operational flow order ("OFO") limiting hourly deliveries in the manner described herein. If such an OFO is issued, Shipper will be entitled to receive hourly deliveries of 110% of 1124\h of the quantity of gas scheduled on a Gas Day,

or such higher quantity as may be specified in the OFO, at its primary delivery points during any five hours falling between 5 a.m. and 9 a.m. eastern clock time or between 5 p.m. and 9 p.m. eastern clock time, respectively, as determined by Shipper (the "Hourly Flow Rate"). Notwithstanding the foregoing, Transporter may sue an OFO directed at Shipper's delivery points and requiring a lower Hourly Flow Rate based upon the occurrence of an event specified in Section 17 of the General Terms and Conditions of Transporter's FERC Gas Tariff that materially affects Transporter's ability to serve Market Areas 23 and/or 25 and requiring the issuance of an OFO specifically limiting the Hourly Flow Rate to Shipper. Transporter reserves the right, if operationally necessary, to require that Shipper take its Hourly Flow Rate at its citygate delivery points on a pro rata basis based on the Maximum Daily Delivery Obligations (MDDOs) at those delivery points.

Unless Measuring Point specific MDDOs are specified in a separate firm service agreement between Transporter and Shipper, Transporter's aggregate MDDO, under this and any other service agreement between Transporter and Shipper, at the Measuring Points listed above shall not exceed the MDDO quantities set forth above for each Measuring Point. In addition, Transporter shall not be obligated on any day to deliver more than the Aggregate Daily Quantities (ADO's) listed below in the Aggregate Areas listed below. The Measuring Points identified above in Group Nos. 1 or 2 are in the Aggregate Areas set forth in greater detail below. Any Measuring Point specific MDDOs in a separate firm service agreement between Transporter and Shipper shall be additive both to the individual Measuring Point MDDOs and to any applicable ADOs set forth herein.

Group No. 1

These Measuring Points are in the Texas Eastern Directs Aggregate Area and the Line 1278 North Aggregate Area:

600021,600023,600032,631929, and 632170

Group No. 2

These Measuring Points are in the Line 1278 North Aggregate Area:

600012, 600013, 600018, 600020, and 637254

Group No. I Aggregate Area Name I ADO

1 Texas Eastern Directs Aggregate Area from November 1-March 31 - 29,311 Dth/day

1 Texas Eastern Directs Aggregate Area from April 1-October 31 - 26,774 Dth/day

1+2 ADO for Aggregate Area Group Nos. 1 and 2 - 114,762 Dth/day

The Master List of Interconnects ("MLI") as defined in Section 1 of the General Terms and Conditions of Transporter's FERC Gas Tariff is incorporated herein by reference for purposes of listing valid secondary interruptible receipt and delivery points.

_X_ Yes No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section

2 of the General Terms and Conditions of Transporter's FERC Gas Tariff.


	Yes _X_ No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporter's FERC Gas Tariff.

Yes _X_ No (Check applicable blank) The MDDOs, ADOs, and/or DDQs set forth in Appendix A to Shipper's _________ Service Agreement No.________ are

incorporated herein by reference.


	Yes _X_ No (Check applicable blank) This Service Agreement covers interim capacity sold pursuant to the provisions of General Terms and Conditions Section 4. Right of first refusal rights, if any, applicable to this interim capacity are limited as provided for in General Terms and Conditions Section 4.


	Yes _X_ No (Check applicable blank) This Service Agreement covers offsystem capacity sold pursuant to Section 47 of the General Terms and Conditions. Right of first refusal rights, if any, applicable to this offsystem capacity are limited as provided for in General Terms and Conditions Section 47.

UGI UTILITIES INC. COLUMBIA GAS TRANSMISSION, LLC

By By

Title Title

Date Date

UGI UTILITIES INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1

(Thousands of dollars)



	Year Ended September 30,
	2014		2013		2012		2011		2010
Earnings:
Earnings before income taxes	$	207,929	$	171,010	$	142,971	$	168,693	$	147,183
Interest expense	38,471		39,309		42,412		42,728		42,336
Amortization of debt discount and
expense	575		731		814		1,060		627
Estimated interest component of rental
expense	2,398		2,090		2,121		1,740		1,912
	$	249,373	$	213,140	$	188,318	$	214,221	$	192,058

Fixed Charges:
Interest expense	$	38,471	$	39,309	$	42,412	$	42,728	$	42,336
Amortization of debt discount and
expense	575		731		814		1,060		627
Allowance for funds used during
construction (capitalized interest)	227		286		10		90		74
Estimated interest component of rental
expense	2,398		2,090		2,121		1,740		1,912
	$	41,671	$	42,416	$	45,357	$	45,618	$	44,949

Ratio of earnings to fixed charges	5.98		5.02		4.15		4.70		4.27

Exhibit 23

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, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10‑K.

/s/PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

November 28, 2014

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 28, 2014
		/s/ Robert F. Beard
		Robert F. Beard President and Chief Executive Officer

EXHIBIT 31.2

CERTIFICATION

I, Donald E. Brown, 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 28, 2014
		/s/ Donald E. Brown
		Donald E. Brown 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, Donald E. Brown, 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, 2014 (the “Form 10-K”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and


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

* * *



CHIEF EXECUTIVE OFFICER		CHIEF FINANCIAL OFFICER

/s/ Robert F. Beard		/s/ Donald E. Brown
Robert F. Beard		Donald E. Brown

Date:	November 28, 2014	Date:	November 28, 2014