10-K

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, 2013

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 29, 2013, 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 reduceddisclosure 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	11
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	23
Signatures	29
Index to Financial Statements and Financial Statement Schedules	30

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FORWARD-LOOKING INFORMATION

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

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind 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.

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PART I:

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

GENERAL

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

The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of UGI Utilities, UGI Penn Natural Gas, Inc. (“PNG”), and UGI Central Penn Gas, Inc. (“CPG”). Gas Utility serves approximately 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 2013” and “Fiscal 2012” refer to the fiscal years ended September 30, 2013 and September 30, 2012, respectively.

GAS UTILITY

Service Area; Revenue Analysis

Gas Utility is authorized to distribute natural gas to approximately 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 85% of Gas Utility's 12,000 miles of gas mains, with bare steel pipe comprising approximately 11% and cast iron pipe comprising approximately 4% 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 2013 was approximately 192.1 billion cubic feet (“bcf”). System sales of gas accounted for approximately 29% of system throughput, while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for approximately 71% 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.

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Gas Supply Contracts

During Fiscal 2013, Gas Utility purchased approximately 77.7 bcf of natural gas for sale to core-market customers (principally comprised of firm- residential, commercial and industrial customers that purchase their gas from Gas Utility (“retail core-market”)) and off-system sales customers. Approximately 74% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 26% of gas purchased by Gas Utility was supplied by approximately 36 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 1 year. 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 2013, nearly 65% of Gas Utility's sales volume was supplied, and over 85% 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. Since the 1980s, larger commercial and industrial customers have been able 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, as well as the frequency and duration of interruptions. See “Gas Utility and Electric Utility Regulation and Rates - Gas Utility Rates.”

Approximately 34% of Gas Utility's commercial and industrial customers' annual throughput volume, including certain customers served under interruptible rates, have locations that afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. Gas Utility has approximately 30 of such customers with transportation contracts extending beyond Fiscal 2013. 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 2014. 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 2013, Gas Utility supplied transportation service to 4 major co-generation installations and 6 electric generation facilities. Gas Utility continues to seek new residential, commercial and industrial customers for both firm and interruptible service. In Fiscal 2013, Gas Utility connected approximately 1,900 new commercial and industrial customers. In the residential market sector, Gas Utility connected over 15,000 residential heating customers during Fiscal 2013. Nearly 8,800 of these customers converted to natural gas 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 2013.

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

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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 2013, approximately 55% of sales volume came from residential customers, 33% from commercial customers, and 12% from industrial and other customers.

Sources of Supply

In accordance with Electric Utility’s default service settlement with the PUC effective January 1, 2010, Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with 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 2013, 5 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 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 electric generation supplier. In Fiscal 2013, 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 Rate Plan (“DSR Plan”) approved by the PUC. Consistent with the terms of the DSR 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: (1) rates designed to recover purchased gas costs (“PGCs”) and electric default service costs; and (2) 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

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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

UGI Gas has two PGC rates: (1) applicable to small, firm, retail core-market customers consisting of the residential and small commercial and industrial classes; and (2) applicable to firm, contractual, high-load factor customers served on three separate rates. The most recent general base rate increase for UGI Gas became effective in 1995. In accordance with a statutory mechanism, a rate increase for UGI Gas’ retail core-market customers became effective October 1, 2000 along with a PGC variable credit equal to a portion of the margin received from customers served under interruptible rates to the extent such interruptible customers use third-party pipeline capacity contracted for by UGI Gas for retail core-market customers.

PNG and CPG each have one PGC rate applicable to all customers. On August 11, 2011, the PUC approved CPG’s base rate case settlement agreement, which resulted in an $8.9 million base rate operating revenue increase for CPG. The increase became effective on August 30, 2011. On June 21, 2012, the PUC reversed its earlier decision related to the $0.9 million increase in revenues associated with the Energy Efficiency and Conservation Plan filed by CPG as part of the August 11, 2011 base rate case settlement. As a result, $0.9 million of base rate operating revenue that was collected as part of this plan has been refunded to customers. On August 27, 2009, the PUC approved PNG’s base rate case settlement agreement, which resulted in a $19.75 million base rate operating revenue increase for PNG, effective August 28, 2009.

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 1 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 6 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.

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 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. 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 (1) default service tariff rules, (2) a reconcilable default service cost rate recovery mechanism to recover the cost of acquiring default service supplies, (3) 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 (4) 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.

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In an order entered on February 15, 2013, the PUC announced that it plans to seek legislative changes that would end the default service obligations of Pennsylvania electric distribution companies. In October 2013, a Senate bill was proposed to terminate default service obligations in Pennsylvania effective June 1, 2015. Under the proposed legislation, customers who do not select a retail electricity supplier would be assigned a supplier.

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 federal Resource Conservation and Recovery Act, CERCLA 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, 2013, UGI Utilities had approximately 1,400 employees.

BUSINESS SEGMENT INFORMATION

The table stating the amounts of revenues, operating income and identifiable assets attributable to UGI Utilities’ operating segments for the 2013, 2012 and 2011 fiscal years appears in Note 15 to Consolidated Financial Statements included in this Report and is incorporated herein by reference.

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ITEM 1A. RISK FACTORS

Decreases in the demand for natural gas and electricity because ofwarmer-than-normal heating season weather could adversely affect our resultsof operations, financial condition and cash flows because our rate structuredoes 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 customerconservation, may result in reduced demand for our energy products andservices.

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 andadversely 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 interestrate 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 ourliquidity.

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

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

Our ability to manage operational risk with respect to our transmission and distribution systems is critical to our financial results. Our business also faces several risks, including the breakdown or failure of or damage to equipment or processes (especially due to severe weather or natural disasters), accidents and other factors. Operation of our transmission and distribution systems below our expectations may result in lost revenues or increased expenses, including higher maintenance costs.

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Our need to comply with comprehensive, complex, and sometimes unpredictablegovernment regulations may increase our costs and limit our revenue growth,which may result in reduced earnings.

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.

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 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 may be unable to respond effectively to competition, which may adverselyaffect our operating results.

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.

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

Our business operations are subject to all of the operating hazards and risks normally incidental to the handling, storage and distribution of combustible products, such as natural gas. These risks could result in substantial losses due to personal injury and/or loss of life, and severe damage to and destruction of property and equipment arising from explosions and other catastrophic events, including acts of terrorism. As a result, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. 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 affectedby 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

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implement GHG emission controls or reductions.

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 couldreduce our net income.

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

• the discovery of presently unknown conditions;

• changes in environmental laws and regulations;

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURES

None.

PART II:

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

Market Information

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

Dividends

Cash dividends declared on the Company’s Common Stock totaled $59.0 million in Fiscal 2013, $70.6 million in Fiscal 2012 and $99.5 million in Fiscal 2011.

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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 2013 reflect temperatures based upon heating degree days that were essentially normal compared with temperatures in Fiscal 2012 that were significantly warmer than normal. In addition, during Fiscal 2013 Gas Utility experienced strong customer growth as continuing low natural gas prices and high heating oil prices resulted in continuing high numbers of conversions from oil to natural gas.

Our net income in Fiscal 2013 was $102.1 million, an increase of $14.2 million (16.2%) from Fiscal 2012 net income of $87.9 million. Temperatures in the Gas Utility service territory in Fiscal 2013 based upon heating degree days were 0.5% warmer than normal and approximately 18.2% colder than Fiscal 2012. The significantly colder weather increased Gas Utility core market volumes and associated core market margin. The benefit of the greater total Gas Utility margin was reduced in part by higher Gas Utility operating and administrative expenses.

Electric Utility’s kilowatt-hour sales in Fiscal 2013 were 1.8% higher than in Fiscal 2012 on heating degree day weather that was approximately 17% colder. The colder Fiscal 2013 heating-season weather increased sales to Electric Utility heating customers. Notwithstanding the higher Fiscal 2013 kilowatt-hour sales and higher total margin, Fiscal 2013 Electric Utility operating results were slightly lower than the prior year reflecting higher operating and administrative expenses including incremental costs early in the fiscal year associated with Hurricane Sandy.

We believe that we have sufficient liquidity in the form of cash generated from operations and our revolving credit facility to fund business operations in Fiscal 2014.

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare the Company’s results of operations for Fiscal 2013, Fiscal 2012 and the year ended September 30, 2011 (“Fiscal 2011”).

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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) 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	%

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 $5.4 million and $5.3 million during Fiscal 2013 and Fiscal 2012, 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 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 and high 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 $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). 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 gas was $407.3 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.

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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.

Consolidated Interest Expense and Income Taxes. Our consolidated 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 (see “Income Tax Matters” below).

Fiscal 2012 Compared with Fiscal 2011

							Increase
(Millions of dollars)	2012			2011			(Decrease)
Gas Utility:
Revenues	$	785.4		$	1,026.4		$	(241.0	)	(23.5	)%
Total margin (a)	$	382.8		$	415.8		$	(33.0	)	(7.9	)%
Operating income	$	172.2		$	199.6		$	(27.4	)	(13.7	)%
Income before income taxes	$	132.0		$	159.3		$	(27.3	)	(17.1	)%
System throughput — bcf
Core market	59.2			70.4			(11.2		)	(15.9	)%
Total	177.6			173.2			4.4			2.5	%
Degree days —% (warmer) colder than normal (b)	(16.3		)%	3.5		%	—			—
Electric Utility:
Revenues	$	97.1		$	109.1		$	(12.0	)	(11.0	)%
Total margin (a)	$	35.3		$	35.1		$	0.2		0.6	%
Operating income	$	12.6		$	11.4		$	1.2		10.5	%
Income before income taxes	$	10.3		$	9.0		$	1.3		14.4	%
Distribution sales — gwh	974.6			994.7			(20.1		)	(2.0	)%

(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 $5.3 million in Fiscal 2012 and $6.1 million in Fiscal 2011. 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 2012 based upon heating degree days were 16.3% warmer than normal and approximately 18.7% warmer than the prior year. Total distribution system throughput was slightly higher than last year, notwithstanding the significantly warmer weather, principally reflecting greater throughput to certain non-weather-

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sensitive low-margin interruptible delivery service customers. Excluding total volumes to interruptible delivery service customers, Gas Utility system throughput declined 14.3 bcf in Fiscal 2012 principally reflecting the effects of the significantly warmer weather on throughput to core market customers (11.2 bcf) and lower firm delivery service volumes.

Gas Utility revenues decreased $241.0 million during Fiscal 2012 principally reflecting a decline in revenues from retail core-market customers ($169.4 million) and lower revenues from off-system sales ($68.1 million). The decrease in retail core-market revenues principally reflects the effects on gas cost recovery revenues of the lower retail core market volumes ($91.9 million) and lower average PGC rates resulting from lower natural gas prices ($43.2 million). Gas Utility’s cost of gas was $402.5 million in Fiscal 2012 compared with $610.6 million in Fiscal 2011 reflecting the previously mentioned lower retail core-market sales ($91.9 million), the lower average PGC rates ($43.2 million) and the above mentioned lower off-system sales.

Gas Utility total margin decreased $33.0 million in Fiscal 2012. The decrease principally reflects lower core-market total margin ($27.7 million) and firm delivery service total margin ($4.8 million). Fiscal 2012 Gas Utility total margin includes a full year of incremental margin from the August 2011 base rate increase at CPG of approximately $9.0 million.

The decreases in Gas Utility operating income and income before income taxes during Fiscal 2012 principally reflects the previously mentioned decrease in total margin ($33.0 million) partially offset by lower operating and administrative expenses.

Electric Utility. Electric Utility’s kilowatt-hour sales in Fiscal 2012 were 2.0% lower than in Fiscal 2011 on heating degree day weather that was 18.5% warmer. The warmer weather reduced sales to Electric Utility heating customers. Electric Utility revenues were $12.0 million less than Fiscal 2011 principally as a result of lower average Default Service (“DS”) rates and, to a lesser extent, the lower sales volumes. Under DS rates, differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to default service customers. Electric Utility cost of sales declined to $56.5 million in Fiscal 2012 compared to $67.9 million in Fiscal 2011 principally reflecting the effects of lower average DS rates and, to a lesser extent, the effects of the lower sales.

Electric Utility total margin in Fiscal 2012 was about equal to Fiscal 2011 principally reflecting the negative effects of the lower sales offset by lower revenue-related gross receipts taxes. Electric Utility Fiscal 2012 operating income and income before income taxes were slightly greater than the prior year as the lower total margin was more than offset by lower operating and administrative expenses.

Consolidated Interest Expense and Income Taxes. Our consolidated interest expense in Fiscal 2012 was about equal to interest expense in Fiscal 2011 on comparable levels of debt. Our effective tax rate in Fiscal 2012 was slightly higher than in Fiscal 2011 as the prior year tax rate reflected the regulatory effects of greater state tax depreciation (see “Income Tax Matters” below).

FINANCIAL CONDITION AND LIQUIDITY

Capitalization and Liquidity

UGI Utilities’ total debt outstanding was $659.5 million at September 30, 2013, which includes $17.5 million of bank loans outstanding, compared with total debt outstanding of $609.2 million at September 30, 2012, which includes $9.2 million of bank loans outstanding. UGI Utilities’ total long-term debt outstanding at September 30, 2013, comprises $275 million of Senior Notes, $192 million of Medium-Term Notes and $175 million outstanding under a term loan facility.

In September 2013, UGI Utilities entered into a 364-day term loan credit agreement (“Term Loan Credit Agreement”) with a bank comprising a $175 million unsecured term loan facility. The Term Loan Credit Agreement bears interest at the eurodollar rate for the interest period selected, plus a margin of 0.60%. The Term Loan Credit Agreement terminates on September 22, 2014, but UGI Utilities may prepay the loan in whole or in part, without any penalty. UGI Utilities borrowed $175 million on September 30, 2013, under the Term Loan Credit Agreement which cash proceeds were used to repay UGI Utilities’ $108 million 6.375% Senior Notes due September 30, 2013, and for other general corporate purposes. On October 30, 2013, UGI Utilities entered into a Note Purchase Agreement which provides for the private placement of $175 million aggregate principal amount of 4.98% Senior Notes due March 26, 2044. UGI Utilities expects to issue $175 million face amount of 4.98% Senior Notes in March 2014 and use the net proceeds to repay then-outstanding borrowings under the Term Loan Credit Agreement. Because the Company has the intent and ability to refinance the Term Loan Credit Agreement on a long-term basis, amounts outstanding under the Term Loan Credit Agreement are classified as long-term on the September 30, 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 UGI Utilities Credit Agreement are classified as bank loans. During Fiscal 2013 and Fiscal 2012, average daily bank loan borrowings under credit

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agreements were $25.6 million and $16.2 million, respectively, and peak bank loan borrowings totaled $79.0 million and $71 million, respectively. Peak bank loan 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. Both the Credit Agreement and the Term Loan Credit Agreement require 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, 2013.

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 2014. 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 $169.9 million in Fiscal 2013, $209.7 million in Fiscal 2012 and $220.8 million in Fiscal 2011. Cash provided by operating activities before changes in operating working capital was $196.7 million in Fiscal 2013, $185.3 million in Fiscal 2012 and $206.9 million in Fiscal 2011. The higher cash flow before changes in operating working capital in Fiscal 2013 compared to Fiscal 2012 reflects in large part the higher operating results The lower cash flow before changes in operating working capital in Fiscal 2012 compared to Fiscal 2011 principally reflects the lower operating results and greater pension plan contributions. Changes in operating working capital (used) provided $(26.8) million of cash in Fiscal 2013, $24.5 million of cash in Fiscal 2012 and $13.9 million of cash in Fiscal 2011. The significant use of cash in Fiscal 2013 from changes in operating working capital compared to the source of cash from changes in operating working capital in Fiscal 2012 reflects, among other things, greater cash required to fund changes in accounts receivable resulting from the higher sales and changes in natural gas inventories. The increase in cash provided by changes in operating working capital in Fiscal 2012 compared to Fiscal 2011 reflects, among other things, the effects of lower natural gas costs on accounts receivable and inventories and the timing of payments for income taxes partially offset by greater cash used to fund changes in accounts payable and lower cash from deferred fuel recoveries.

Investing activities. Cash used by investing activities was $159.2 million in Fiscal 2013, $114.7 million in Fiscal 2012, and $102.0 million in Fiscal 2011. The recent year increases in capital expenditures principally reflects higher Gas Utility capital expenditures for infrastructure improvements and customer growth. Fiscal 2013 investing activities cash flow includes a $3.2 million increase in restricted cash in futures brokerage accounts compared to a $4.3 million decrease in Fiscal 2011 and a $0.4 million decrease in Fiscal 2011. 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 $7.3 million in Fiscal 2013, $101.0 million in Fiscal 2012 and $115.8 million in Fiscal 2011. Financing activities cash flows are primarily the result of issuances and repayments of long-term debt, revolving credit agreement borrowings, cash dividends to UGI, and capital contributions from UGI. During Fiscal 2013, net bank loan borrowings totaled $8.3 million compared to net borrowings of $9.2 million in Fiscal 2012 and $17 million of net repayments in Fiscal 2011.

Capital Expenditures

In the following table, we present capital expenditures by business segment for Fiscal 2013, Fiscal 2012 and Fiscal 2011. We also provide amounts we expect to spend in Fiscal 2014. We expect to finance a substantial portion of Fiscal 2014 capital expenditures from cash generated by operations and the remainder from borrowings under our Credit Agreement.

(Millions of dollars)	2014		2013		2012		2011
	(estimate)
Gas Utility	$	131.4	$	144.4	$	109.0	$	91.3
Electric Utility	8.0		6.7		5.1		7.5
	$	139.4	$	151.1	$	114.1	$	98.8

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The increase in Gas Utility capital expenditures in Fiscal 2013 includes greater main replacement and system improvement capital expenditures.

Contractual Cash Obligations and Commitments

UGI Utilities has contractual cash obligations that extend beyond Fiscal 2013, 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, 2013:

	Payments Due by Period
			Fiscal		Fiscal		Fiscal
(Millions of dollars)	Total		2014		2015 - 2016		2017 - 2018		Thereafter
Long-term debt (a)	$	642.0	$	—	$	267.0	$	60.0	$	315.0
Interest on long-term fixed rate debt (b)	515.1		33.3		70.2		40.2		371.4
Derivative financial instruments (c)	6.7		6.7		—		—		—
Operating leases	20.4		5.5		8.9		4.7		1.3
Gas Utility and Electric Utility supply, storage and transportation contracts	586.7		190.6		181.2		100.6		114.3
Total	$	1,770.9	$	236.1	$	527.3	$	205.5	$	802.0

(a) Based upon stated maturity dates. UGI Utilities’ $175 million Term Loan Credit Agreement borrowings that are anticipated to be refinanced in March 2014 are presented in the table above under “Thereafter.”

(b) Based upon stated interest rates.

(c) Represents sum of amounts due from us if derivative financial instruments were settled at the September 30, 2013, amounts reflected in the Consolidated Balance Sheet.

The components of the other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2013, 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 2014 of approximately $17.9 million. Contributions to the pension plan in years beyond Fiscal 2014 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 $398.2 million and $351.5 million at September 30, 2013 and 2012, respectively. At September 30, 2013 and 2012, the underfunded positions of the Pension Plan, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plan’s assets, were $88.3 million and $192.1 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 2014 of approximately $17.9 million. Pre-tax pension cost associated with the Pension Plan in Fiscal 2013 was $17.9 million. Pre-tax pension cost associated with Pension Plan in Fiscal 2014 is expected to be approximately $9.8 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, 2013, we have recorded cumulative after-tax charges to stockholder’s equity of $5.3 million and regulatory assets of $94.5 million in order to reflect the funded status of our pension and postretirement benefit plans.

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For a more detailed discussion of the Pension Plans and other postretirement benefit plans, see Note 9 to Consolidated Financial Statements.

Income Tax Matters

In 2010, U.S. federal tax legislation was enacted that allowed taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of calendar 2011, when such property was placed in service before 2012. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers were also permitted to fully deduct such qualifying capital expenditures for Pennsylvania state corporate net income tax purposes. Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits from accelerated tax depreciation. UGI Utilities’ Fiscal 2012 and Fiscal 2011 effective income tax rates reflects the beneficial effects of this greater state tax depreciation.

REGULATORY MATTERS

Allentown, Pennsylvania Natural Gas Incident. On February 19, 2013, the PUC entered a final order (the “Final Order”) settling all regulatory compliance issues pertaining to a natural gas explosion on February 9, 2011 in Allentown, PA. The Final Order requires UGI Utilities to (i) pay a civil penalty in the amount of $0.5 million; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

CPG Base Rate Filing. On August 11, 2011, the PUC approved a settlement agreement with CPG that resulted in an increase in annual base rate revenues of $8.0 million as well as $0.9 million in revenues per year to fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). The increase became effective August 30, 2011. During Fiscal 2012, the PUC reversed its earlier decision related to the $0.9 million increase in revenue associated with the Energy and Efficiency Conservation Program and required CPG to refund revenue it had collected for that program.

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 right of way located in Delmar Township, Pennsylvania (“TL-96 line”) to UGI Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI.   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.

On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011, the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets transferred was $10.9 million which amount, net of related deferred taxes of $0.3 million, is reflected as a dividend of net assets on the Fiscal 2011 Consolidated Statement of Stockholder’s Equity. Compliance with the provisions of the PUC Order approving the transfer of the storage assets did not have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011, transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.

On December 1, 2010, PNG filed an application with the PUC for expedited review and approval of the transfer of a 9 mile natural gas pipeline, related facilities, and right of way located in Mehoopany, Pennsylvania (the “Auburn Line”) to Energy Services. The PUC approved the transfer and in September 2011 the Auburn Line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the Auburn Line was $1.1 million which amount, net of related deferred taxes of $0.2 million, is reflected as a dividend of net assets on the Fiscal 2011 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

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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 currently scheduled to terminate at the end of 2013. 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, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14.0 million and $15.0 million, respectively. Because CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites, 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 getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At September 30, 2012, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

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

We cannot predict with certainty the final results of any of the MGP matters referenced above. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows.

For additional information on the MGP site outside of Pennsylvania currently subject to third-party claim, see Note 12 to Consolidated Financial Statements.

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.

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From time to time, UGI Utilities is a party to Storage Contract Administration Agreements (“SCAAs”) with Energy Services. At September 30, 2013, UGI Utilities was a party to three three-year SCAAs with Energy Services one of which expired October 31, 2013, 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 $45.8 million, $24.3 million and $35.2 million in Fiscal 2013, Fiscal 2012 and Fiscal 2011, 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 $16.5 million and 15.0 million at September 30, 2013 and 2012, respectively. Effective November 1, 2013, 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, 2013, comprising approximately 10.4 bcf of natural gas, was $42.0 million. The carrying value of these gas storage inventories at September 30, 2012, comprising approximately 7.6 bcf of natural gas, was $21.2 million.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during Fiscal 2013, Fiscal 2012 and Fiscal 2011 totaled $32.5 million, $30.8 million and $30.1 million, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2013, Fiscal 2012 and Fiscal 2011, revenues associated with sales to Energy Services totaled $69.1 million, $65.7 million and $85.7 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 2013, Fiscal 2012 and Fiscal 2011, such purchases totaled $77.0 million, $53.4 million and $53.6 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, 2013, Gas Utility had $3.2 million of restricted cash associated with natural gas futures accounts with brokers. At September 30, 2012, Gas Utility had no restricted cash in brokerage accounts. At September 30, 2013 and 2012, the fair values of our natural gas futures and option contracts were (losses) gains of ($1.7) million and $5.3 million, respectively.

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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 FTRs and forward electricity purchase contracts, associated with our Electric Utility operations. At September 30, 2013 and 2012, the fair values of Electric Utility’s electricity supply contracts were losses of $4.8 million and $9.2 million, respectively. The fair values of FTRs at September 30, 2013 and 2012, 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, 2013 and 2012, 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 2013 and Fiscal 2012, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.3 million in each of those years.

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 $28.1 million and $36.9 million at September 30, 2013 and 2012, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $32.0 million and $42.2 million at September 30, 2013 and 2012, 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, 2013.

The fair values of unsettled IRPAs held at September 30, 2012, were losses of $30.5 million.

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, Significant Accounting Policies, which discusses the significant accounting policies that we have selected from acceptable alternatives.

Impairment of Goodwill. 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. Gas Utility has goodwill resulting from purchase business combinations. In accordance with GAAP, Gas Utility is required to perform goodwill impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. Historically, we determine the fair value of our Gas Utility for purposes of the goodwill impairment test using an income approach. For purposes of the income approach, fair value is determined based upon the the present value of estimated future cash flows discounted at an appropriate risk-adjusted rate. Cash flow estimates used to establish fair values involve management judgments based on a broad range of information and historical results. We use our internal forecasts to estimate future cash flows and include an estimate of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. 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. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill which would adversely impact our results of operations. The Company adopted new accounting guidance regarding goodwill impairment during Fiscal 2012 which permits us, in certain

21

circumstances, to 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, 2013, our goodwill totaled $182.1 million. We did not record any impairments of goodwill during Fiscal 2013, Fiscal 2012 or Fiscal 2011.

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, 2013, UGI Utilities net property, plant and equipment totaled $1,574.1 million and we recorded depreciation expense of $52.3 million during Fiscal 2013.

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, 2013, our regulatory assets totaled $244.9 million. For additional information on our regulatory assets, see Note 4 to the Consolidated Financial Statements.

Pension Plan Assumptions. Pension Plan assumptions are significant inputs to the actuarial models that measure benefit obligations and pension expense. The costs 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. 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 $1.7 million in Fiscal 2014. A decrease in the discount rate of 50 basis points to a rate of 4.70% would result in an increase in pre-tax pension cost of approximately $2.9 million in Fiscal 2014. 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 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 the end of the period covered by this Report, 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

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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, 2013, 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, 2013, 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 2013 and Fiscal 2012 were as follows:

	2013		2012
Audit Fees	$	851,600	$	892,400
Audit-Related Fees	-0-		-0-
Tax Fees	-0-		-0-
All Other Fees	-0-		-0-
Total Fees for Services Provided	$	851,600	$	892,400

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 all 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.

PART IV:

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents filed as part of this report:

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(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, 2013 and 2012

Consolidated Statements of Income for the fiscal years ended September 30, 2013, 2012 and 2011

Consolidated Statements of Comprehensive Income for the years ended September 30, 2013, 2012 and 2011

Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2013, 2012 and 2011

Consolidated Statements of Stockholder’s Equity for the fiscal years ended September 30, 2013, 2012 and 2011

Notes to Consolidated Financial Statements

(2) Financial Statement Schedule:

For the years ended September 30, 2013, 2012 and 2011

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):

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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

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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.	UGI	Registration Statement No. 333-186178 (1/24/2013)	99.1
10.4**	UGI Corporation 2009 Deferral Plan Amended and Restated Effective June 1, 2010.	UGI	Form 10-Q (6/30/10)	10.1
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 January 1, 2009.	UGI	Form 10-K (9/30/09)	10.11
10.7**	Amendment 2009-1 to the UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan as Amended and Restated effective January 1, 2009.	UGI	Form 10-Q (12/31/09)	10.1
10.8**	UGI Corporation 2009 Supplemental Executive Retirement Plan For New Employees.	UGI	Form 10-Q (12/31/09)	10.2
10.9**	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
10.10**	UGI Utilities, Inc. Executive Annual Bonus Plan, effective as of October 1, 2006, as amended as of November 16, 2012.	Utilities	Form 10-Q (3/31/13)	10.2
10.11**	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2013.	UGI	Form 10-Q (3/31/13)	10.8
10.12**	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2013.	Utilities	Form 10-Q (3/31/13)	10.1

26

Incorporation by Reference

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.13**	UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Employees, dated January 24, 2013.	UGI	Form 10-Q (3/31/13)	10.4
10.14**	UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Utilities Employees, dated January 24, 2013.	UGI	Form 10-Q (3/31/13)	10.3
10.15**	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
10.16	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
10.17	FSS Service Agreement No. 79028 dated March 29, 2012 between Columbia Gas Transmission, LLC and UGI Utilities, Inc.	Utilities	Form 10-Q (3/31/12)	10.2
10.18	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
10.19	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
10.20	SST Service Agreement No. 79133 dated March 29, 2012 between Columbia Gas Transmission, LLC and UGI Utilities, Inc.	Utilities	Form 10-Q (3/31/12)	10.1
10.21	Letter Agreement, dated as of June 10, 2013, amending SST Service Agreement No. 79133, dated March 29, 2012, between Columbia Gas Transmission, LLC and UGI Utilities, Inc.	Utilities	Form 10-Q (6/30/13)	10.3

27

Incorporation by Reference

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.22	FTS Service Agreement No. 46284 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004, between Columbia Transmission Corporation and UGI Utilities, Inc.	Utilities	Form 10-Q (3/31/11)	10.2
10.23	FTS Service Agreement No. 46284, dated July 23, 2013, between Columbia Gas Transmission, LLC and UGI Utilities, Inc.	Utilities	Form 8-K (7/23/13)	10.1
10.24	Term Loan Credit Agreement dated September 23, 2013 by and between UGI Utilities, Inc. and JPMorgan Chase Bank, N.A., as administrative agent.	Utilities	Form 8-K (9/23/13)	10.1
*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, 2013 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, 2013 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, 2013, 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.

28

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:	December 16, 2013	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 December 16, 2013 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/ Lon R. Greenberg	Chairman and Director
Lon R. Greenberg
/s/ John L. Walsh	Vice Chairman and Director
John L. Walsh
/s/ Donald E. Brown	Vice President - Finance and Chief Financial Officer
Donald E. Brown	(Principal Financial Officer)
/s/ Matthew J. Nolan	Controller
Matthew J. Nolan	(Principal Accounting Officer)
/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 2013.

29

UGI UTILITIES, INC.

FINANCIAL INFORMATION

FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K

YEAR ENDED SEPTEMBER 30, 2013

UGI UTILITIES, INC.

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE

	Pages
Financial Statements:
Report of Independent Registered Public Accounting Firm	31
Consolidated Balance Sheets as of September 30, 2013 and 2012	32
Consolidated Statements of Income for the years ended September 30, 2013, 2012 and 2011	34
Consolidated Statements of Comprehensive Income for the years ended September 30, 2013, 2012 and 2011	35
Consolidated Statements of Cash Flows for the years ended September 30, 2013, 2012 and 2011	36
Consolidated Statements of Stockholder’s Equity for the years ended September 30, 2013, 2012 and 2011	37
Notes to Consolidated Financial Statements	38 to 62
Financial Statement Schedule:
For the years ended September 30, 2013, 2012 and 2011:
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.

30

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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2013 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, 2013, 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

December 16, 2013

31

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)

	September 30,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	4,707		$	1,259
Restricted cash	3,181			—
Accounts receivable (less allowances for doubtful accounts of $5,519 and $3,588, respectively)	53,341			47,362
Accounts receivable — related parties	3,497			4,571
Accrued utility revenues	18,868			16,911
Inventories	89,661			67,334
Deferred income taxes	14,165			19,430
Income taxes recoverable	—			9,461
Regulatory assets	8,217			6,473
Derivative financial instruments	43			5,468
Prepaid expenses & other current assets	15,862			19,852
Total current assets	211,542			198,121
Property, plant and equipment	2,427,810			2,295,669
Less accumulated depreciation and amortization	(853,675		)	(815,720		)
Net property, plant and equipment	1,574,135			1,479,949
Goodwill	182,145			182,145
Regulatory assets	236,694			331,932
Other assets	5,806			4,026
Total assets	$	2,210,322		$	2,196,173
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	—		$	133,000
Bank loans	17,500			9,200
Accounts payable — trade	51,970			46,754
Accounts payable — related parties	12,487			10,192
Employee compensation and benefits accrued	13,664			10,902
Interest accrued	11,281			22,766
Customer deposits and advances	40,307			49,806
Derivative financial instruments	6,677			36,011
Deferred fuel refunds	8,283			4,435
Pension and postretirement benefit obligations	17,885			15,802
Other current liabilities	27,459			31,816
Total current liabilities	207,513			370,684
Long-term debt	642,000			467,000
Deferred income taxes	436,810			390,046
Deferred investment tax credits	4,270			4,612
Pension and other postretirement benefit obligations	72,505			179,056
Other noncurrent liabilities	55,610			56,262

32

Total liabilities	1,418,708			1,467,660
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	470,098			468,692
Retained earnings	269,977			229,379
Accumulated other comprehensive loss	(8,720		)	(29,817		)
Total common stockholder’s equity	791,614			728,513
Total liabilities and stockholder’s equity	$	2,210,322		$	2,196,173

See accompanying notes to consolidated financial statements.

33

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of dollars)

	Year Ended September 30,
	2013			2012			2011
Revenues	$	940,712		$	884,333		$	1,137,366
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	465,996			459,079			678,500
Operating and administrative expenses	188,266			165,479			176,922
Operating and administrative expenses — related parties	8,366			9,326			12,125
Taxes other than income taxes	16,877			17,263			16,616
Depreciation	52,298			49,702			49,917
Amortization	3,418			3,090			2,629
Other income, net	(4,828		)	(4,989		)	(10,764		)
	730,393			698,950			925,945
Operating income	210,319			185,383			211,421
Interest expense	39,309			42,412			42,728
Income before income taxes	171,010			142,971			168,693
Income taxes	68,912			55,073			63,497
Net income	$	102,098		$	87,898		$	105,196

See accompanying notes to consolidated financial statements.

34

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)

	Year Ended September 30,
	2013		2012			2011
Net income	$	102,098	$	87,898		$	105,196
Net gains (losses) on derivative instruments (net of tax of $(10,746), $4,783 and $7,712, respectively)	15,153		(6,744		)	(10,874		)
Reclassifications of net losses on derivative instruments (net of tax of $(334), $(766) and $(483), respectively)	471		1,111			681
Benefit plans (net of tax of $(3,325), $1,948 and $479, respectively)	4,689		(2,745		)	(674		)
Reclassifications of benefit plans actuarial losses and prior service costs to net income (net of tax of $(555), $(333) and $(304), respectively)	784		394			430
Other comprehensive income (loss)	$	21,097	$	(7,984	)	$	(10,437	)
Comprehensive income	$	123,195	$	79,914		$	94,759

See accompanying notes to consolidated financial statements.

35

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)

	Year Ended September 30,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	102,098		$	87,898		$	105,196
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	55,716			52,792			52,546
Deferred income taxes, net	35,281			53,247			50,823
Pension expense, net of contributions paid	(4,450		)	(17,431		)	(6,292		)
Provision for uncollectible accounts	9,584			6,286			9,137
Other, net	(1,560		)	2,490			(4,526		)
Net change in:
Accounts receivable and accrued utility revenues	(16,446		)	5,461			(4,583		)
Inventories	(22,327		)	36,929			14,596
Deferred fuel costs, net of changes in unsettled derivatives	9,321			(8,190		)	12,842
Accounts payable	7,511			(6,718		)	9,229
Other current assets	13,598			(5,063		)	(3,817		)
Other current liabilities	(18,413		)	2,041			(14,401		)
Net cash provided by operating activities	169,913			209,742			220,750
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(151,090		)	(114,090		)	(98,856		)
Net costs of property, plant and equipment disposals	(4,925		)	(4,922		)	(3,537		)
(Increase) decrease in restricted cash	(3,181		)	4,308			390
Net cash used by investing activities	(159,196		)	(114,704		)	(102,003		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(58,975		)	(70,615		)	(99,490		)
Increase (decrease) in bank loans	8,300			9,200			(17,000		)
Issuances of long-term debt	175,000			—			—
Repayments of long-term debt	(133,000		)	(40,000		)	—
Excess tax benefits from equity-based payment arrangements	1,406			369			692
Net cash used by financing activities	(7,269		)	(101,046		)	(115,798		)
Cash and cash equivalents increase (decrease)	$	3,448		$	(6,008	)	$	2,949
CASH AND CASH EQUIVALENTS:
End of year	$	4,707		$	1,259		$	7,267
Beginning of year	1,259			7,267			4,318
Increase (decrease)	$	3,448		$	(6,008	)	$	2,949
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for:
Interest	$	49,460		$	29,902		$	39,151
Income taxes	$	18,376		$	6,728		$	13,856

See accompanying notes to consolidated financial statements.

36

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(Thousands of dollars)

	Year Ended September 30,
	2013			2012			2011
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	$	229,379		$	212,096		$	217,960
Net income	102,098			87,898			105,196
Cash dividends — Common Stock	(58,975		)	(70,615		)	(99,490		)
Dividends of net assets	(2,525		)	—			(11,570		)
Balance, end of year	$	269,977		$	229,379		$	212,096
Additional paid-in capital
Balance, beginning of year	$	468,692		$	468,323		$	467,631
Excess tax benefits on equity-based compensation	1,406			369			692
Balance, end of year	$	470,098		$	468,692		$	468,323
Accumulated other comprehensive income (loss)
Balance, beginning of year	$	(29,817	)	$	(21,833	)	$	(11,396	)
Net gains (losses) on derivative instruments	15,153			(6,744		)	(10,874		)
Reclassifications of net losses on derivative instruments	471			1,111			681
Benefit plans, principally actuarial gains (losses)	4,689			(2,745		)	(674		)
Reclassifications of benefit plans actuarial losses and prior service costs	784			394			430
Balance, end of year	$	(8,720	)	$	(29,817	)	$	(21,833	)
Total UGI Utilities, Inc. stockholder’s equity	$	791,614		$	728,513		$	718,845

See accompanying notes to consolidated financial statements.

37

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

1. NATURE OF OPERATIONS

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.

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. 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.

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. 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, see Note 4.

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. 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. Fair value measurements require that we assume that the transaction occurs in the principal market for the asset or liability or in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount

38

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

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. Instruments categorized in Level 1 consist of our exchange-traded commodity futures and option contracts and non exchange-traded electricity forward contracts whose underlying is identical to an exchange-traded electricity contract.

• 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 inactive markets, 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. Instruments categorized in Level 2 include financial transmission rights (“FTRs”) and non exchange-traded electricity forward contracts not qualifying for Level 1.

• Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 2013 or 2012.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. See Note 13 for additional information on fair value measurements.

Derivative Instruments

We account for derivative instruments and hedging activities in accordance with guidance provided by the FASB which requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. 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. 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 related supplemental information required by GAAP, 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.

39

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.

Correction of Error. During the three months ended September 30, 2013, we identified an error in the classification of deferred income tax assets on the September 30, 2012, Consolidated Balance Sheet. We evaluated the impact of the error and have determined that such error is not material. We have revised the September 30, 2012, Consolidated Balance Sheet to correct the error which revision decreased the following Consolidated Balance Sheet items by $27,006: current deferred income taxes; total current assets and total assets; long-term deferred income tax liabilities; total liabilities; and total liabilities and stockholder’s equity.

Comprehensive Income

The components of AOCI at September 30, 2013 and 2012, follow:

	Postretirement Benefit Plans			Derivative Instruments Net Losses			Total
September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
September 30, 2012	$	(10,756	)	$	(19,061	)	$	(29,817	)

Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally reflects gains and losses on derivative instruments accounted for as cash flow hedges and changes in actuarial gains and losses on postretirement benefit plans. Other comprehensive income (loss) for all periods presented includes reclassifications of net losses on interest rate protection agreements (“IRPAs”).

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 which 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

40

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.3% in Fiscal 2013, 2.2% in Fiscal 2012 and 2.3% in Fiscal 2011. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.4% in Fiscal 2013, 2.4% in Fiscal 2012 and 2.6% in Fiscal 2011. When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes.

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. 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. GAAP also permits us under certain circumstances to assess qualitative factors to determine that it is not more likely than not that the fair value of a reporting unit is less than its carrying value. No provisions for goodwill impairments were recorded during Fiscal 2013, Fiscal 2012 or Fiscal 2011.

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 2013, Fiscal 2012 or Fiscal 2011.

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.

Environmental Matters

We are subject to environmental laws and regulations intended to mitigate or remove the effect 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.

41

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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, and 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

New Accounting Standards Not Yet Adopted

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued new accounting guidance regarding disclosures for items reclassified out of AOCI. The new disclosure guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2012. The new disclosures are to be applied prospectively, and early adoption is permitted. We will adopt the new guidance in Fiscal 2014. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities. In December 2011 (and amended in January 2013), the FASB issued new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods, and is required to be applied retrospectively. We will adopt the new guidance in Fiscal 2014. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

42

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:

	2013		2012
Regulatory assets:
Income taxes recoverable	$	106,069	$	103,172
Underfunded pension and postretirement plans	94,515		188,222
Environmental costs	17,054		16,812
Deferred fuel and power costs	8,283		11,602
Removal costs, net	13,333		12,718
Other	5,657		5,879
Total regulatory assets	$	244,911	$	338,405
Regulatory liabilities:
Postretirement benefits	$	16,497	$	13,147
Environmental overcollections	2,552		2,883
Deferred fuel and power refunds	8,283		4,435
State tax benefits — distribution system repairs	8,453		7,385
Other	1,502		494
Total regulatory liabilities	$	37,287	$	28,344

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 deferredtaxes 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 50 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). UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites. PNG and CPG are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2013, 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 delivery service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative financial 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

43

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

financial instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at September 30, 2013 and 2012, were $(1,743) and $5,303, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not qualify for the normal purchases and normal sales exception under GAAP related to derivative financial instruments, these 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, 2013 and 2012, the fair values of Electric Utility’s electricity supply contracts were losses of $4,759 and $9,207, respectively, which amounts are reflected in current derivative financial instruments and other noncurrent liabilities on the Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs. FTRs are derivative financial 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. At September 30, 2013 and 2012, such gains or losses were not material.

Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. At September 30, 2013, UGI Utilities expects to recover these costs over periods of 1 to 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 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, 2013, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 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

Allentown, Pennsylvania Natural Gas Incident. On February 19, 2013, the PUC entered a final order (the “Final Order”) settling all regulatory compliance issues pertaining to a natural gas explosion on February 9, 2011, in Allentown, PA. The Final Order requires UGI Utilities to (i) pay a civil penalty in the amount of $500; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

44

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

CPG Base Rate Filing. On August 11, 2011, the PUC approved a settlement agreement with CPG that resulted in an increase in annual base rate revenues of $8,000 as well as $900 in revenues per year to fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). The increase became effective August 30, 2011. During Fiscal 2012, the PUC reversed its earlier decision related to the $900 increase in revenue associated with the Energy and Efficiency Conservation Program and required CPG to refund revenue it had collected for that program.

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 right of way located in Delmar Township, Pennsylvania (“TL-96 line”) to 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 on the Fiscal 2013 Consolidated Statement of Stockholder’s Equity.

On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of UGI Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011, the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets transferred was $10,949 which amount, net of related deferred taxes of $308, is reflected as a dividend of net assets on the Fiscal 2011 Consolidated Statement of Stockholder’s Equity. Compliance with the provisions of the PUC Order approving the transfer of the storage assets did not have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.

On December 1, 2010, PNG filed an application with the PUC for expedited review and approval of the transfer of a 9 mile natural gas pipeline, related facilities, and right of way located in Mehoopany, Pennsylvania (the “Auburn Line”) to Energy Services. The PUC approved the transfer and in September 2011 the Auburn Line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the Auburn Line was $1,109 which amount, net of related deferred taxes of $180, is reflected as a dividend of net assets on the Fiscal 2011 Consolidated Statement of Stockholder’s Equity.

5. INVENTORIES

Inventories comprise the following at September 30:

	2013		2012
Gas Utility natural gas	$	78,950	$	57,663
Materials, supplies and other	10,711		9,671
Total inventories	$	89,661	$	67,334

At September 30, 2013, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”) with Energy Services, Inc. (“Energy Services”), a second-tier, wholly owned subsidiary of UGI, one of which expired in October 2013 and two of which expire in October 2015. 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 represent a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivables (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, 2013 and 2012, comprising 11.0 billion cubic feet (“bcf”) and 11.4 bcf of natural gas was $44,366 and $32,627, respectively. At September 30, 2013 and 2012, UGI Utilities held a total of $16,500 and $22,500, 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, 2013, UGI Utilities entered into two new SCAAs having terms of one and three years (see Note 17).

45

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

6. PROPERTY, PLANT AND EQUIPMENT

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

	2013		2012
Distribution	$	2,162,580	$	2,047,780
Transmission	86,623		85,430
General and other, including construction in process	178,607		162,459
Total property, plant and equipment	$	2,427,810	$	2,295,669

7. DEBT

Long-term debt comprises the following at September 30:

	2013		2012
Term Loan Credit Agreement	$	175,000	$	—
Senior Notes:
6.375%, due September 2013	—		108,000
5.75%, due September 2016	175,000		175,000
6.21%, due September 2036	100,000		100,000
Medium-Term Notes:
5.37%, due August 2013	—		25,000
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		600,000
Less: current maturities	—		(133,000		)
Total long-term debt due after one year	$	642,000	$	467,000

Principal payments on long-term debt during the next five fiscal years is as follows: $0 is due in Fiscal 2014; $20,000 is due in Fiscal 2015; $247,000 is due in Fiscal 2016; $20,000 is due in Fiscal 2017; and $40,000 is due in Fiscal 2018. The $175,000 outstanding under the Term Loan Credit Agreement that is expected to be refinanced on a long-term basis prior to its maturity and is excluded from these repayment amounts (see below).

In September 2013, UGI Utilities entered into a 364-day term loan credit agreement (“Term Loan Credit Agreement”) with a bank comprising a $175,000 unsecured term loan facility. The Term Loan Credit Agreement bears interest at the eurodollar rate for the interest period selected, plus a margin of 0.60%. The Term Loan Credit Agreement terminates on September 22, 2014, but UGI Utilities may prepay the loan in whole or in part, without penalty. UGI Utilities borrowed $175,000 on September 30, 2013, under the Term Loan Credit Agreement which cash proceeds were used to repay UGI Utilities’ $108,0006.375% Senior Notes due September 30, 2013, and for other general corporate purposes. On October 30, 2013, UGI Utilities entered into a Note Purchase Agreement which provides for the private placement of $175,000 aggregate principal amount of 4.98% Senior Notes due March 26, 2044. UGI Utilities expects to issue $175,000 face amount of 4.98% Senior Notes in March 2014 and use the net proceeds to repay then-outstanding borrowings under the Term Loan Credit Agreement. Because the Company has the intent and ability to refinance the Term Loan Credit Agreement on a long-term basis, amounts outstanding under the Term Loan Credit Agreement are classified as long-term on the September 30, 2013, Consolidated Balance Sheet.

46

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

UGI Utilities has an unsecured credit agreement (the “UGI Utilities 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 UGI Utilities 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 UGI Utilities Credit Agreement, which we classify as bank loans on the Consolidated Balance Sheets, totaling $17,500 and $9,200 at September 30, 2013 and 2012, respectively. The weighted-average interest rates on the UGI Utilities Credit Agreement borrowings at September 30, 2013 and 2012 were 1.18% and 1.21%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the UGI Utilities Credit Agreement, totaled $2,000 at September 30, 2013 and 2012.

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

8. INCOME TAXES

The provisions for income taxes consist of the following:

	2013			2012			2011
Current expense (benefit):
Federal	$	21,807		$	(909	)	$	10,447
State	11,824			2,735			2,227
Total current expense	33,631			1,826			12,674
Deferred expense:
Federal	33,349			48,336			48,967
State	2,274			5,257			2,207
Investment tax credit amortization	(342		)	(346		)	(351		)
Total income tax expense	$	68,912		$	55,073		$	63,497

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

	2013		2012		2011
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Difference in tax rate due to:
State income taxes, net of federal	5.4		4.1		1.6
Other, net	(0.1	)	(0.6	)	1.0
Effective tax rate	40.3	%	38.5	%	37.6	%

Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2013, Fiscal 2012 and Fiscal 2011, the beneficial effects of state tax flow through of accelerated depreciation reduced tax expense by $1,538, $3,198 and $7,926, respectively. The state tax flow through amounts in Fiscal 2012 and Fiscal 2011 reflect 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.

47

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:

	2013			2012
Excess book basis over tax basis of property, plant and equipment	$	362,259		$	330,937
Goodwill	31,516			26,998
Regulatory assets	101,622			140,416
Other	949			601
Gross deferred tax liabilities	496,346			498,952
Pension plan liabilities	(35,996		)	(72,652		)
Allowance for doubtful accounts	(2,290		)	(1,489		)
Deferred investment tax credits	(1,772		)	(1,914		)
Employee-related expenses	(5,850		)	(4,859		)
Regulatory liabilities	(15,472		)	(11,761		)
Environmental liabilities	(7,002		)	(7,195		)
Derivative financial instruments	(3,397		)	(16,264		)
Other	(1,922		)	(12,202		)
Gross deferred tax assets	(73,701		)	(128,336		)
Net deferred tax liabilities	$	422,645		$	370,616

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 2009.

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, 2013, we have $18,271 of Pennsylvania net operating loss carryforwards that expire through 2029.

During Fiscal 2013, Fiscal 2012 and Fiscal 2011, interest (income) expense of $0, $(209) and $219, respectively, was recognized in income taxes in the Consolidated Statements of Income. As of September 30, 2013, we have unrecognized income tax benefits totaling $1,143 including related accrued interest of $56. If these unrecognized tax benefits were subsequently recognized, $56 would be recorded as a benefit to income taxes on the consolidated statement of income and, therefore, would impact the effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. Included in the balance at September 30, 2013, are $1,087 of tax positions for which the deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, the disallowance of the current deduction would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. There is an expected change in unrecognized tax benefits and related interest in the next twelve months in the amount of $43.

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

Balance at September 30, 2010	$	4,194
Additions for tax positions of the current year	920
Settlements with tax authorities	(216		)
Balance at September 30, 2011	4,898
Additions for tax positions of prior years	81
Settlements with tax authorities	(3,931		)
Balance at September 30, 2012	1,048
Additions for tax positions of prior years	39
Balance at September 30, 2013	$	1,087

In accordance with accounting guidance regarding uncertain tax positions, during Fiscal 2013 and Fiscal 2012, the Company added $39 and $124, respectively, to its liability for unrecognized tax benefits including interest related to its change in method

48

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. However, because this tax matter relates only to the timing of deductibility, we have recorded an offsetting deferred tax asset of an equal amount. 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 currently sponsor one 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”). In addition, we 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 other postretirement plans as of September 30, 2013 and 2012. 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.

49

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

	Pension Benefits						Other Postretirement Benefits
	2013			2012			2013			2012
Change in benefit obligations:
Benefit obligations — beginning of year	$	543,605		$	456,714		$	14,560		$	13,333
Service cost	9,385			8,063			223			162
Interest cost	22,784			24,095			587			665
Actuarial (gain) loss	(69,112		)	74,676			(1,881		)	1,464
Plan amendments	993			—			(1,836		)	—
Benefits paid	(21,187		)	(19,943		)	(965		)	(1,064		)
Benefit obligations — end of year	$	486,468		$	543,605		$	10,688		$	14,560
Change in plan assets:
Fair value of plan assets — beginning of year	$	351,543		$	289,764		$	11,205		$	9,805
Actual gain on assets	45,450			50,550			1,117			1,741
Employer contributions	22,365			31,172			366			723
Benefits paid	(21,187		)	(19,943		)	(965		)	(1,064		)
Fair value of plan assets — end of year	$	398,171		$	351,543		$	11,723		$	11,205
Funded status of the plans — end of year	$	(88,297	)	$	(192,062	)	$	1,035		$	(3,355	)
(Liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	$	—		$	—		$	3,252		$	—
Unfunded liabilities — included in other current liabilities	(17,885		)	(15,802		)	(372		)	(654		)
Unfunded liabilities — included in other noncurrent liabilities	(70,412		)	(176,260		)	(1,844		)	(2,701		)
Net amount recognized	$	(88,297	)	$	(192,062	)	$	1,036		$	(3,355	)
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	$	222		$	152		$	(74	)	$	(79	)
Net actuarial loss (gain)	9,113			18,099			(222		)	164
Total	$	9,335		$	18,251		$	(296	)	$	85
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	$	2,223		$	1,550		$	(4,286	)	$	(2,766	)
Net actuarial loss	91,275			184,464			3,586			5,815
Total	$	93,498		$	186,014		$	(700	)	$	3,049

In Fiscal 2014, we estimate that we will amortize approximately $6,800 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 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 the current and expected asset allocations as well as historical and expected returns on various categories of plan assets as further described below.

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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:	2013		2012		2011 (a)		2013		2012		2011
Discount rate - benefit obligations	5.20	%	4.20	%	5.30	%	5.10% - 5.40%		4.10% - 4.30%		5.30	%
Discount rate - benefit cost	4.20	%	5.30	%	5.00	%	4.10% - 4.30%		5.30	%	5.00	%
Expected return on plan assets	7.75	%	7.75	%	8.00	%	5.00	%	5.20	%	5.50	%
Rate of increase in salary levels	3.25	%	3.25	%	3.50	%	3.25	%	3.25	%	3.50	%

(a) Effective December 31, 2010, we merged our then-existing two U.S. defined benefit pension plans (“Pension Plans Merger”) to form the Pension Plan. The discount rates used during Fiscal 2011 to calculate pension expense were rates of 5.0% through December 31, 2010 (the date of the Pension Plans Merger) and 5.5% for the remainder of Fiscal 2011.

The ABOs for the Pension Plan were $451,228 and $496,395 as of September 30, 2013 and 2012, respectively. Included in the end of year Pension Plan PBOs above are $44,161 at September 30, 2013, and $48,570 at September 30, 2012, relating to employees of UGI and certain of its other subsidiaries. Included in the end of year other postretirement plans ABOs above are $787 at September 30, 2013, and $869 at September 30, 2012, 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
	2013			2012			2011			2013			2012			2011
Service cost	$	8,211		$	7,025		$	7,176		$	205		$	152		$	202
Interest cost	20,783			22,376			22,047			557			639			678
Expected return on assets	(24,791		)	(23,762		)	(23,937		)	(529		)	(481		)	(523		)
Curtailment gain	—			—			—			—			—			(3,245		)
Amortization of:
Prior service cost (benefit)	249			249			302			(420		)	(422		)	(694		)
Actuarial loss	13,463			7,853			6,838			336			355			427
Net benefit cost (income)	17,915			13,741			12,426			149			243			(3,155		)
Change in associated regulatory liabilities	—			—			—			3,302			3,188			3,138
Benefit cost (income) after change in regulatory liabilities	$	17,915		$	13,741		$	12,426		$	3,451		$	3,431		$	(17	)

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 2013, Fiscal 2012 and Fiscal 2011, we made contributions to the Pension Plan of $22,365, $31,172 and $18,718, respectively. We believe that in Fiscal 2014 we will be required to make contributions to the Pension Plan of approximately $17,900.

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 determined under GAAP. The difference between such amounts 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 2014 is not expected to be material.

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

	Pension Benefits		Other Postretirement Benefits
Fiscal 2014	$	23,021	$	1,006
Fiscal 2015	24,095		813
Fiscal 2016	25,238		769
Fiscal 2017	26,451		706
Fiscal 2018	27,744		676
Fiscal 2019 - 2023	155,907		3,156

The assumed health care cost trend rates for Fiscal 2013 are 7.0% decreasing to 5.0% in Fiscal 2017. The assumed health care cost trend rates as of September 30, 2013, are 7.5% decreasing to 5.0% in Fiscal 2019. A one percentage point change in these assumed health care cost trend rates would not have had a material impact on Fiscal 2013 other postretirement benefit cost or the September 30, 2013, other postretirement benefit ABO.

We also sponsor unfunded and non-qualified supplemental executive retirement income plans. At September 30, 2013 and 2012, the projected benefit obligations of these plan were $3,550 and $2,507, respectively. We recorded expense for these plans of $498 in Fiscal 2013, $255 in Fiscal 2012 and $583 in Fiscal 2011.

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 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:	2013		2012		Allocation		Range
Equity investments:
Domestic	57.5	%	53.5	%	52.5	%	40.0% - 65.0%
International	11.1	%	10.5	%	12.5	%	7.5% - 17.5%
Total	68.6	%	64.0	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	31.4	%	36.0	%	35.0	%	30.0% - 40.0%
Total	100.0	%	100.0	%	100.0	%

					Target
	Actual				Asset		Permitted
VEBA:	2013		2012		Allocation		Range
Domestic equity investments	65.6	%	68.5	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	34.4	%	31.5	%	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. Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 8.2% and 7.5% of Pension Plan assets at September 30, 2013 and 2012, respectively.

GAAP establishes a hierarchy that prioritizes fair value measurements based upon the inputs and valuation techniques used to measure fair value. This fair value hierarchy groups assets into three levels, as described in Note 2. We maximize the use of

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

observable inputs and minimize the use of unobservable inputs when determining fair value. The fair values of 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 Pension Plan’s assets at September 30, 2013 and 2012, by asset class are as follows:

	Pension Plan
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total
September 30, 2013:
Domestic 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
September 30, 2012:
Equity investments:
S&P 500 Index equity mutual funds	$	118,922	$	—	$	—	$	118,922
Small and Midcap equity mutual funds	42,876		—		—		42,876
UGI Corporation Common Stock	26,445		—		—		26,445
Total domestic equity investments	188,243		—		—		188,243
International index equity mutual funds	36,908		—		—		36,908
Fixed income investments:
Bond index mutual funds	123,332		—		—		123,332
Cash equivalents	—		3,060		—		3,060
Total fixed income investments	123,332		3,060		—		126,392
Total	$	348,483	$	3,060	$	—	$	351,543

The fair values of the VEBA trust assets at September 30, 2013 and 2012, by asset class are as follows:

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

	VEBA
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total
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
September 30, 2012:
S&P 500 Index equity mutual fund	$	7,678	$	—	$	—	$	7,678
Bond index mutual fund	3,366		—		—		3,366
Cash equivalents	—		161		—		161
Total	$	11,044	$	161	$	—	$	11,205

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

Defined Contribution Plan

We sponsor a 401(k) savings plan for eligible employees (“Utilities Savings Plan”). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. The Utilities Savings Plan provides for employer matching contributions. Those employees hired after December 31, 2008, who are not eligible to participate in the Pension Plan receive employer matching contributions at a higher rate. The cost of benefits under the Utilities Savings Plan totaled $1,762 in Fiscal 2013, $1,690 in Fiscal 2012 and $1,820 in Fiscal 2011.

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, 2013 or 2012.

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. Under these plans, 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 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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 $1,078 ($631 after-tax) during Fiscal 2013; $783 ($458 after-tax) during Fiscal 2012; and $1,110 ($650 after-tax) during Fiscal 2011.

As of September 30, 2013, there was $682 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 2.0 years. As of September 30, 2013, there was a total of $758 of unrecognized compensation expense associated with 61,331 UGI Unit awards that is expected to be recognized over a weighted average period of 1.9 years. At September 30, 2013 and 2012, total liabilities of $360 and $143, respectively, associated with UGI Unit awards are reflected in other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheets.

The following table summarizes UGI Unit award activity for Fiscal 2013:

	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, 2012	68,633		$	29.72	24,130		$	28.78	44,503		$	30.23
Granted	20,800		$	38.27	1,797		$	38.27	19,003		$	38.27
Vested	—		$	—	13,768		$	26.24	(13,768	)	$	26.24
Forfeited	(9,069	)	$	33.65	—		$	—	(9,069	)	$	33.65
Performance criteria not met	(7,679	)	$	22.72	(7,679	)	$	22.72	—		$	—
Unit awards paid	(11,354	)	$	22.72	(11,354	)	$	22.72	—		$	—
September 30, 2013	61,331		$	34.21	20,662		$	33.49	40,669		$	34.57

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 $6,270 in Fiscal 2013, $6,362 in Fiscal 2012 and $5,221 in Fiscal 2011.

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: 2014— $5,518; 2015 — $4,682; 2016 — $4,220; 2017 — $2,684; 2018 — $1,992; after 2018 — $1,301.

Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation, natural gas storage and peaking service which Gas Utility may terminate at various dates through 2025. 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 2014.

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2013, for fiscal years ending September 30 are as follows: 2014 — $190,606; 2015 — $105,317; 2016 — $75,903; 2017 — $56,152; 2018 — $44,409; after 2018 — $114,263.

Contingencies

Environmental Matters

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 $1,800 and $1,100, respectively, in any calendar year. The CPG-COA is currently scheduled to terminate at the end of 2013 and is expected to be renewed prior to its expiration. 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, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14,019 and $14,979, respectively. Because CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites, 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.

The Company 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, 2013, 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 it 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.

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount or range of possible clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska

56

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012. There have been no recent developments in this matter.

Other Matters

We cannot predict with certainty the final results of any environmental claim or legal action described above. However, it is reasonably possible that such a claim could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, that may be recovered by such a claim or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. In addition to the matter described above, there are other pending claims and legal actions arising in the normal course of our businesses. While the results of these other pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, the final outcome of such other matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

13. FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of September 30, 2013 and 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
September 30, 2013
Assets:
Derivative financial instruments
Commodity contracts	$	43		$	—		$	—	$	43
Liabilities:
Derivative financial instruments
Commodity contracts	$	(2,162	)	$	(4,515	)	$	—	$	(6,677	)
September 30, 2012
Assets:
Derivative financial instruments
Commodity contracts	$	5,468		$	—		$	—	$	5,468
Liabilities:
Derivative financial instruments
Commodity contracts	$	(671	)	$	(8,766	)	$	—	$	(9,437	)
Interest rate contracts	$	—		$	(30,522	)	$	—	$	(30,522	)

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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, 2013, were $642,000 and $699,929, respectively. The carrying amount and estimated fair value of our long-term debt (including current maturities) at September 30, 2012, were $600,000 and $700,708, 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. DISCLOSURES ABOUT 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.

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, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 15.0 million dekatherms and 19.2 million dekatherms, respectively. At September 30, 2013, the maximum period over which Gas Utility is 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 these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At September 30, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $4,759 and $9,207, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the accompanying Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At September 30, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 245.8 million kilowatt hours and 570.4 million kilowatt hours, respectively. At September 30, 2013, the maximum period over which these contracts extend is 8 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly auctions. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, 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, 2013 and 2012, the volumes associated with Electric Utility FTRs totaled 189.3 million kilowatt hours and 189.7 million kilowatt hours, respectively.

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. The volumes of gasoline under these contracts were not material for all periods presented.

58

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Interest Rate Risk

Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in AOCI, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. As of September 30, 2013 we had no unsettled IRPAs. As of September 30, 2012, the total notional amounts of our unsettled IRPA contracts was $173,000.

UGI Utilities reclassified pre-tax losses of $682 from AOCI into income during Fiscal 2012 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 Consolidated Statements of Income. The amounts of derivative gains and losses on cash flow hedges representing ineffectiveness were not material for all periods presented.

At September 30, 2013, 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 $2,680.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2013, Gas Utility’s restricted cash in brokerage accounts totaled $3,181. At September 30, 2012, Gas Utility had no restricted cash in brokerage accounts.

The following table provides information regarding the balance sheet location and fair values of derivative assets and liabilities existing as of September 30, 2013 and 2012:

	Derivative Assets					Derivative Liabilities
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Interest rate contracts		$	—	$	—	Derivative financial instruments and Other noncurrent liabilities	$	—		$	(30,522	)
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	31		5,303		Derivative financial instruments and Other noncurrent liabilities	(6,677		)	(9,437		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	12		165			—			—
Total Derivatives		$	43	$	5,468		$	(6,677	)	$	(39,959	)

59

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

The following table provides information on the effects of derivative instruments on the Consolidated Statements of Income and changes in AOCI for Fiscal 2013 and 2012:

	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013		2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	25,898	$	(11,528	)	$	(805	)	$	(1,847	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain Recognized in Income											Location of Gain Recognized in Income
	2013		2012
Commodity contracts	$	45	$	223								Operating expenses/other income, net

We are also a party to a number of 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.

60

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
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		—
2011
Revenues	$	1,137,366	$	1,026,397	$	109,145	$	1,824
Cost of sales	678,500		610,635		67,865		—
Depreciation and amortization	52,546		48,350		4,196		—
Operating income	211,421		199,643		11,384		394
Interest expense	42,728		40,374		2,354		—
Income before income taxes	168,693		159,269		9,030		394
Total assets	2,169,348		2,028,705		140,643		—
Goodwill	182,145		182,145		—		—
Capital expenditures	98,856		91,328		7,528		—

16. OTHER INCOME, NET

Other income, net, comprises the following:

	2013		2012		2011
Non-tariff service income	$	2,706	$	2,653	$	6,422
Interest income	500		572		467
Postretirement benefit plan curtailment gain	—		—		3,245
Other, net	1,622		1,764		630
Total other income, net	$	4,828	$	4,989	$	10,764

61

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

17. 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 SCAAs with Energy Services. At September 30, 2013, UGI Utilities was a party to threethree-year SCAAs with Energy Services one of which expired October 31, 2013, 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 $45,843, $24,344 and $35,231 in Fiscal 2013, Fiscal 2012 and Fiscal 2011, 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 $16,500 and $15,000 at September 30, 2013 and 2012, respectively. Effective November 1, 2013, 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, 2013, comprising approximately 10.4 bcf bcf of natural gas, was $41,988. The carrying value of these gas storage inventories at September 30, 2012, comprising approximately 7.6 bcf of natural gas, was $21,217. Effective November 1, 2013, UGI Utilities entered into a new SCAA with Energy Services having a term of one year.

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 2013, Fiscal 2012 and Fiscal 2011 totaled $32,526, $30,752 and $30,093, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2013, Fiscal 2012 and Fiscal 2011, revenues associated with sales to Energy Services totaled $69,087, $65,705 and $85,655, 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 2013, Fiscal 2012 and Fiscal 2011, such purchases totaled $77,017, $53,435 and $53,617, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

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.

62

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

	December 31,				March 31,				June 30,				September 30,
	2012		2011		2013		2012		2013		2012		2013		2012
Revenues	$	273,797	$	280,641	$	395,901	$	345,802	$	148,798	$	143,644	$	122,216	$	114,246
Operating income	$	72,564	$	64,605	$	109,230	$	88,447	$	18,878	$	25,300	$	9,647	$	7,031
Net income (loss)	$	36,812	$	32,668	$	58,259	$	47,871	$	5,373	$	8,460	$	1,654	$	(1,101	)

63

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, 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
September 30, 2011
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	7,072	$	9,137	$	(9,841	)	(1)	$	6,368

(1) Uncollectible accounts written off, net of recoveries

S- 1

EXHIBIT INDEX

Exhibit No.	Description
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

EX-12.1

UGI UTILITIES INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1

(Thousands of dollars)

	Year Ended September 30,
	2013		2012		2011		2010		2009
Earnings:
Earnings before income taxes	$	171,010	$	142,971	$	168,693	$	147,183	$	125,554
Interest expense	39,309		42,412		42,728		42,336		43,918
Amortization of debt discount and
expense	731		814		1,060		627		625
Estimated interest component of rental
expense	2,090		2,121		1,740		1,912		1,965
	$	213,140	$	188,318	$	214,221	$	192,058	$	172,062
Fixed Charges:
Interest expense	$	39,309	$	42,412	$	42,728	$	42,336	$	43,918
Amortization of debt discount and
expense	731		814		1,060		627		625
Allowance for funds used during
construction (capitalized interest)	286		10		90		74		160
Estimated interest component of rental
expense	2,090		2,121		1,740		1,912		1,965
	$	42,416	$	45,357	$	45,618	$	44,949	$	46,668
Ratio of earnings to fixed charges	5.02		4.15		4.70		4.27		3.69

EX-23

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 reportdated December 16, 2013 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

December 16, 2013

EX-31.1

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:	December 16, 2013
		/s/ Robert F. Beard
		Robert F. Beard President and Chief Executive Officer

EX-31.2

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:	December 16, 2013
		/s/ Donald E. Brown
		Donald E. Brown Vice President - Finance and Chief Financial Officer

EX-32

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, 2011 (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:	December 16, 2013	Date:	December 16, 2013

XML

Quarterly Data (unaudited) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Quarterly Financial Data [Abstract]
Revenues	$ 122,216	$ 148,798	$ 395,901	$ 273,797	$ 114,246	$ 143,644	$ 345,802	$ 280,641	$ 940,712	$ 884,333	$ 1,137,366
Operating income	9,647	18,878	109,230	72,564	7,031	25,300	88,447	64,605	210,319	185,383	211,421
Net income (loss)	$ 1,654	$ 5,373	$ 58,259	$ 36,812	$ (1,101)	$ 8,460	$ 47,871	$ 32,668	$ 102,098	$ 87,898	$ 105,196

XML

Employee Retirement Plans

12 Months Ended

Sep. 30, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Employee Retirement Plans

EMPLOYEE RETIREMENT PLANS

Defined Benefit Pension and Other Postretirement Plans

We currently sponsor one 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”). In addition, we 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 other postretirement plans as of September 30, 2013 and 2012. 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
	2013			2012			2013			2012
Change in benefit obligations:
Benefit obligations — beginning of year	$	543,605		$	456,714		$	14,560		$	13,333
Service cost	9,385			8,063			223			162
Interest cost	22,784			24,095			587			665
Actuarial (gain) loss	(69,112		)	74,676			(1,881		)	1,464
Plan amendments	993			—			(1,836		)	—
Benefits paid	(21,187		)	(19,943		)	(965		)	(1,064		)
Benefit obligations — end of year	$	486,468		$	543,605		$	10,688		$	14,560
Change in plan assets:
Fair value of plan assets — beginning of year	$	351,543		$	289,764		$	11,205		$	9,805
Actual gain on assets	45,450			50,550			1,117			1,741
Employer contributions	22,365			31,172			366			723
Benefits paid	(21,187		)	(19,943		)	(965		)	(1,064		)
Fair value of plan assets — end of year	$	398,171		$	351,543		$	11,723		$	11,205
Funded status of the plans — end of year	$	(88,297	)	$	(192,062	)	$	1,035		$	(3,355	)
(Liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	$	—		$	—		$	3,252		$	—
Unfunded liabilities — included in other current liabilities	(17,885		)	(15,802		)	(372		)	(654		)
Unfunded liabilities — included in other noncurrent liabilities	(70,412		)	(176,260		)	(1,844		)	(2,701		)
Net amount recognized	$	(88,297	)	$	(192,062	)	$	1,036		$	(3,355	)
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	$	222		$	152		$	(74	)	$	(79	)
Net actuarial loss (gain)	9,113			18,099			(222		)	164
Total	$	9,335		$	18,251		$	(296	)	$	85
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	$	2,223		$	1,550		$	(4,286	)	$	(2,766	)
Net actuarial loss	91,275			184,464			3,586			5,815
Total	$	93,498		$	186,014		$	(700	)	$	3,049

In Fiscal 2014, we estimate that we will amortize approximately $6,800 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 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 the current and expected asset allocations as well as historical and expected returns on various categories of plan assets as further described below.

	Pension Benefits						Other Postretirement Benefits
Weighted-average assumptions:	2013		2012		2011 (a)		2013		2012		2011
Discount rate - benefit obligations	5.20	%	4.20	%	5.30	%	5.10% - 5.40%		4.10% - 4.30%		5.30	%
Discount rate - benefit cost	4.20	%	5.30	%	5.00	%	4.10% - 4.30%		5.30	%	5.00	%
Expected return on plan assets	7.75	%	7.75	%	8.00	%	5.00	%	5.20	%	5.50	%
Rate of increase in salary levels	3.25	%	3.25	%	3.50	%	3.25	%	3.25	%	3.50	%

(a) Effective December 31, 2010, we merged our then-existing two U.S. defined benefit pension plans (“Pension Plans Merger”) to form the Pension Plan. The discount rates used during Fiscal 2011 to calculate pension expense were rates of 5.0% through December 31, 2010 (the date of the Pension Plans Merger) and 5.5% for the remainder of Fiscal 2011.

The ABOs for the Pension Plan were $451,228 and $496,395 as of September 30, 2013 and 2012, respectively. Included in the end of year Pension Plan PBOs above are $44,161 at September 30, 2013, and $48,570 at September 30, 2012, relating to employees of UGI and certain of its other subsidiaries. Included in the end of year other postretirement plans ABOs above are $787 at September 30, 2013, and $869 at September 30, 2012, 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
	2013			2012			2011			2013			2012			2011
Service cost	$	8,211		$	7,025		$	7,176		$	205		$	152		$	202
Interest cost	20,783			22,376			22,047			557			639			678
Expected return on assets	(24,791		)	(23,762		)	(23,937		)	(529		)	(481		)	(523		)
Curtailment gain	—			—			—			—			—			(3,245		)
Amortization of:
Prior service cost (benefit)	249			249			302			(420		)	(422		)	(694		)
Actuarial loss	13,463			7,853			6,838			336			355			427
Net benefit cost (income)	17,915			13,741			12,426			149			243			(3,155		)
Change in associated regulatory liabilities	—			—			—			3,302			3,188			3,138
Benefit cost (income) after change in regulatory liabilities	$	17,915		$	13,741		$	12,426		$	3,451		$	3,431		$	(17	)

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 2013, Fiscal 2012 and Fiscal 2011, we made contributions to the Pension Plan of $22,365, $31,172 and $18,718, respectively. We believe that in Fiscal 2014 we will be required to make contributions to the Pension Plan of approximately $17,900.

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 determined under GAAP. The difference between such amounts 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 2014 is not expected to be material.

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

	Pension Benefits		Other Postretirement Benefits
Fiscal 2014	$	23,021	$	1,006
Fiscal 2015	24,095		813
Fiscal 2016	25,238		769
Fiscal 2017	26,451		706
Fiscal 2018	27,744		676
Fiscal 2019 - 2023	155,907		3,156

The assumed health care cost trend rates for Fiscal 2013 are 7.0% decreasing to 5.0% in Fiscal 2017. The assumed health care cost trend rates as of September 30, 2013, are 7.5% decreasing to 5.0% in Fiscal 2019. A one percentage point change in these assumed health care cost trend rates would not have had a material impact on Fiscal 2013 other postretirement benefit cost or the September 30, 2013, other postretirement benefit ABO.

We also sponsor unfunded and non-qualified supplemental executive retirement income plans. At September 30, 2013 and 2012, the projected benefit obligations of these plan were $3,550 and $2,507, respectively. We recorded expense for these plans of $498 in Fiscal 2013, $255 in Fiscal 2012 and $583 in Fiscal 2011.

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 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:	2013		2012		Allocation		Range
Equity investments:
Domestic	57.5	%	53.5	%	52.5	%	40.0% - 65.0%
International	11.1	%	10.5	%	12.5	%	7.5% - 17.5%
Total	68.6	%	64.0	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	31.4	%	36.0	%	35.0	%	30.0% - 40.0%
Total	100.0	%	100.0	%	100.0	%

					Target
	Actual				Asset		Permitted
VEBA:	2013		2012		Allocation		Range
Domestic equity investments	65.6	%	68.5	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	34.4	%	31.5	%	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. Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 8.2% and 7.5% of Pension Plan assets at September 30, 2013 and 2012, respectively.

GAAP establishes a hierarchy that prioritizes fair value measurements based upon the inputs and valuation techniques used to measure fair value. This fair value hierarchy groups assets into three levels, as described in Note 2. We maximize the use of observable inputs and minimize the use of unobservable inputs when determining fair value. The fair values of 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 Pension Plan’s assets at September 30, 2013 and 2012, by asset class are as follows:

	Pension Plan
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total
September 30, 2013:
Domestic 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
September 30, 2012:
Equity investments:
S&P 500 Index equity mutual funds	$	118,922	$	—	$	—	$	118,922
Small and Midcap equity mutual funds	42,876		—		—		42,876
UGI Corporation Common Stock	26,445		—		—		26,445
Total domestic equity investments	188,243		—		—		188,243
International index equity mutual funds	36,908		—		—		36,908
Fixed income investments:
Bond index mutual funds	123,332		—		—		123,332
Cash equivalents	—		3,060		—		3,060
Total fixed income investments	123,332		3,060		—		126,392
Total	$	348,483	$	3,060	$	—	$	351,543

The fair values of the VEBA trust assets at September 30, 2013 and 2012, by asset class are as follows:

	VEBA
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total
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
September 30, 2012:
S&P 500 Index equity mutual fund	$	7,678	$	—	$	—	$	7,678
Bond index mutual fund	3,366		—		—		3,366
Cash equivalents	—		161		—		161
Total	$	11,044	$	161	$	—	$	11,205

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

Defined Contribution Plan

We sponsor a 401(k) savings plan for eligible employees (“Utilities Savings Plan”). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. The Utilities Savings Plan provides for employer matching contributions. Those employees hired after December 31, 2008, who are not eligible to participate in the Pension Plan receive employer matching contributions at a higher rate. The cost of benefits under the Utilities Savings Plan totaled $1,762 in Fiscal 2013, $1,690 in Fiscal 2012 and $1,820 in Fiscal 2011.

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Income Taxes (Deferred tax liabilities (assets)) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Deferred tax liabilities (assets)
Excess book basis over tax basis of property, plant and equipment	$ 362,259	$ 330,937
Goodwill	31,516	26,998
Regulatory assets	101,622	140,416
Other	949	601
Gross deferred tax liabilities	496,346	498,952
Pension plan liabilities	(35,996)	(72,652)
Allowance for doubtful accounts	(2,290)	(1,489)
Deferred investment tax credits	(1,772)	(1,914)
Employee-related expenses	(5,850)	(4,859)
Regulatory liabilities	(15,472)	(11,761)
Environmental liabilities	(7,002)	(7,195)
Derivative financial instruments	(3,397)	(16,264)
Other	(1,922)	(12,202)
Gross deferred tax assets	(73,701)	(128,336)
Net deferred tax liabilities	$ 422,645	$ 370,616

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Consolidated Statements of Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Income Statement [Abstract]
Revenues	$ 940,712	$ 884,333	$ 1,137,366
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	465,996	459,079	678,500
Operating and administrative expenses	188,266	165,479	176,922
Operating and administrative expenses — related parties	8,366	9,326	12,125
Taxes other than income taxes	16,877	17,263	16,616
Depreciation	52,298	49,702	49,917
Amortization	3,418	3,090	2,629
Other income, net	(4,828)	(4,989)	(10,764)
Costs and expenses	730,393	698,950	925,945
Operating income	210,319	185,383	211,421
Interest expense	39,309	42,412	42,728
Income before income taxes	171,010	142,971	168,693
Income taxes	68,912	55,073	63,497
Net income	$ 102,098	$ 87,898	$ 105,196

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Significant Accounting Policies

12 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Significant Accounting Policies

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.

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. 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, see Note 4.

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. 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. Fair value measurements require that we assume that the transaction occurs in the principal market for the asset or liability or in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

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. Instruments categorized in Level 1 consist of our exchange-traded commodity futures and option contracts and non exchange-traded electricity forward contracts whose underlying is identical to an exchange-traded electricity contract.

• 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 inactive markets, 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. Instruments categorized in Level 2 include financial transmission rights (“FTRs”) and non exchange-traded electricity forward contracts not qualifying for Level 1.

• Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 2013 or 2012.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. See Note 13 for additional information on fair value measurements.

Derivative Instruments

We account for derivative instruments and hedging activities in accordance with guidance provided by the FASB which requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. 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. 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 related supplemental information required by GAAP, 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.

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.

Correction of Error. During the three months ended September 30, 2013, we identified an error in the classification of deferred income tax assets on the September 30, 2012, Consolidated Balance Sheet. We evaluated the impact of the error and have determined that such error is not material. We have revised the September 30, 2012, Consolidated Balance Sheet to correct the error which revision decreased the following Consolidated Balance Sheet items by $27,006: current deferred income taxes; total current assets and total assets; long-term deferred income tax liabilities; total liabilities; and total liabilities and stockholder’s equity.

Comprehensive Income

The components of AOCI at September 30, 2013 and 2012, follow:

	Postretirement Benefit Plans			Derivative Instruments Net Losses			Total
September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
September 30, 2012	$	(10,756	)	$	(19,061	)	$	(29,817	)

Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally reflects gains and losses on derivative instruments accounted for as cash flow hedges and changes in actuarial gains and losses on postretirement benefit plans. Other comprehensive income (loss) for all periods presented includes reclassifications of net losses on interest rate protection agreements (“IRPAs”).

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 which 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.

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 2013, 2.2% in Fiscal 2012 and 2.3% in Fiscal 2011. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.4% in Fiscal 2013, 2.4% in Fiscal 2012 and 2.6% in Fiscal 2011. When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes.

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. 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. GAAP also permits us under certain circumstances to assess qualitative factors to determine that it is not more likely than not that the fair value of a reporting unit is less than its carrying value. No provisions for goodwill impairments were recorded during Fiscal 2013, Fiscal 2012 or Fiscal 2011.

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 2013, Fiscal 2012 or Fiscal 2011.

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.

Environmental Matters

We are subject to environmental laws and regulations intended to mitigate or remove the effect 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, and 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.

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Other Income, Net

12 Months Ended

Sep. 30, 2013

Other Income [Abstract]

Other Income, Net

OTHER INCOME, NET

Other income, net, comprises the following:

	2013		2012		2011
Non-tariff service income	$	2,706	$	2,653	$	6,422
Interest income	500		572		467
Postretirement benefit plan curtailment gain	—		—		3,245
Other, net	1,622		1,764		630
Total other income, net	$	4,828	$	4,989	$	10,764

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Commitments and Contingencies (Contingencies) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			12 Months Ended
	Sep. 30, 2013 Environmental Issue [Member]	Sep. 30, 2013 CPG Manufactured Gas Plant Properties and PNG Manufactured Gas Plant Properties [Member] Environmental Remediation Expense [Member]	Sep. 30, 2012 CPG Manufactured Gas Plant Properties and PNG Manufactured Gas Plant Properties [Member] Environmental Remediation Expense [Member]	Sep. 30, 2013 CPG MGP [Member] Environmental Remediation Expense [Member]	Sep. 30, 2013 PNG MGP [Member] Environmental Remediation Expense [Member]	Sep. 30, 2013 PNG MGP [Member] Environmental Issue [Member]
Contingencies [Line Items]
Environmental expenditures				$ 1,800	$ 1,100
Option to termination agreement by either party effective at end of any period						2 years
Accrued liabilities for environmental investigation and remediation costs related to CPG-COA and PNG-COA		$ 14,019	$ 14,979
Base Year for Determination of Investigation and Remediation Cost	5 years

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Employee Retirement Plans (Reconciliations) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
(Liabilities) recorded in the balance sheet:
Unfunded liabilities — included in other current liabilities	$ (17,885)	$ (15,802)
Unfunded liabilities — included in other noncurrent liabilities	(72,505)	(179,056)
Pension Benefits [Member]
Change in benefit obligations:
Benefit obligations - beginning of the year	543,605	456,714
Service cost	9,385	8,063
Interest cost	22,784	24,095
Actuarial loss (gain)	(69,112)	74,676
Plan amendments	993	0
Benefits paid	(21,187)	(19,943)
Benefit obligations - end of the year	486,468	543,605	456,714
Change in plan assets:
Fair value of plan assets - beginning of year	351,543	289,764
Actual gain on assets	45,450	50,550
Employer contributions	22,365	31,172	18,718
Benefits paid	(21,187)	(19,943)
Fair value of plan assets - end of year	398,171	351,543	289,764
Funded status of the plans - end of the year	(88,297)	(192,062)
(Liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	0	0
Unfunded liabilities — included in other current liabilities	(17,885)	(15,802)
Unfunded liabilities — included in other noncurrent liabilities	(70,412)	(176,260)
Net amount recognized	(88,297)	(192,062)
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	222	152
Net actuarial loss (gain)	9,113	18,099
Total	9,335	18,251
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	2,223	1,550
Net actuarial loss	91,275	184,464
Total	93,498	186,014
Other Postretirement Benefits [Member]
Change in benefit obligations:
Benefit obligations - beginning of the year	14,560	13,333
Service cost	223	162
Interest cost	587	665
Actuarial loss (gain)	(1,881)	1,464
Plan amendments	(1,836)	0
Benefits paid	(965)	(1,064)
Benefit obligations - end of the year	10,688	14,560
Change in plan assets:
Fair value of plan assets - beginning of year	11,205	9,805
Actual gain on assets	1,117	1,741
Employer contributions	366	723
Benefits paid	(965)	(1,064)
Fair value of plan assets - end of year	11,723	11,205
Funded status of the plans - end of the year	1,035	(3,355)
(Liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	3,252	0
Unfunded liabilities — included in other current liabilities	(372)	(654)
Unfunded liabilities — included in other noncurrent liabilities	(1,844)	(2,701)
Net amount recognized	1,036	(3,355)
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	(74)	(79)
Net actuarial loss (gain)	(222)	164
Total	(296)	85
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	(4,286)	(2,766)
Net actuarial loss	3,586	5,815
Total	$ (700)	$ 3,049

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Series Preferred Stock

12 Months Ended

Sep. 30, 2013

Series Preferred Stock [Abstract]

Series Preferred Stock

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, 2013 or 2012.

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Property Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Property, Plant and Equipment [Line Items]
Utilities	$ 2,427,810	$ 2,295,669
Distribution [Member]
Property, Plant and Equipment [Line Items]
Utilities	2,162,580	2,047,780
Transmission [Member]
Property, Plant and Equipment [Line Items]
Utilities	86,623	85,430
General and other, including contruction in process [Member]
Property, Plant and Equipment [Line Items]
Utilities	$ 178,607	$ 162,459

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Employee Retirement Plans (Weighted-average assumptions) (Details)	3 Months Ended	9 Months Ended		12 Months Ended
	Dec. 31, 2010	Sep. 30, 2011		Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Pension Plans [Member]
Weighted-average assumptions:
Discount rate - benefit obligations		5.30%	[1]	5.20%	4.20%	5.30%	[1]
Discount rate - benefit cost	5.00%	5.50%		4.20%	5.30%	5.00%	[1]
Expected return on plan assets				7.75%	7.75%	8.00%	[1]
Rate of increase in salary levels				3.25%	3.25%	3.50%	[1]
Other Postretirement Benefits [Member]
Weighted-average assumptions:
Discount rate - benefit obligations		5.30%				5.30%
Discount rate - benefit cost					5.30%	5.00%
Expected return on plan assets				5.00%	5.20%	5.50%
Rate of increase in salary levels				3.25%	3.25%	3.50%
Minimum [Member] | Other Postretirement Benefits [Member]
Weighted-average assumptions:
Discount rate - benefit obligations				5.10%	4.10%
Discount rate - benefit cost				4.10%
Maximum [Member] | Other Postretirement Benefits [Member]
Weighted-average assumptions:
Discount rate - benefit obligations				5.40%	4.30%
Discount rate - benefit cost				4.30%

[1] were rates of 5.0% through December 31, 2010 (the date of the Pension Plans Merger) and 5.5%

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Disclosures About Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Balance sheet location and fair value of derivative assets and liabilities

The following table provides information regarding the balance sheet location and fair values of derivative assets and liabilities existing as of September 30, 2013 and 2012:

	Derivative Assets					Derivative Liabilities
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Interest rate contracts		$	—	$	—	Derivative financial instruments and Other noncurrent liabilities	$	—		$	(30,522	)
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	31		5,303		Derivative financial instruments and Other noncurrent liabilities	(6,677		)	(9,437		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	12		165			—			—
Total Derivatives		$	43	$	5,468		$	(6,677	)	$	(39,959	)

Effects of derivative instruments on the Consolidated Statements of Income and changes in AOCI

The following table provides information on the effects of derivative instruments on the Consolidated Statements of Income and changes in AOCI for Fiscal 2013 and 2012:

	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013		2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	25,898	$	(11,528	)	$	(805	)	$	(1,847	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain Recognized in Income											Location of Gain Recognized in Income
	2013		2012
Commodity contracts	$	45	$	223								Operating expenses/other income, net

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Valuation and Qualifying Accounts

12 Months Ended

Sep. 30, 2013

Valuation and Qualifying Accounts [Abstract]

Valuation and Qualifying Accounts

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, 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
September 30, 2011
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	7,072	$	9,137	$	(9,841	)	(1)	$	6,368

(1) Uncollectible accounts written off, net of recoveries

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Quarterly Data (unaudited)

12 Months Ended

Sep. 30, 2013

Quarterly Financial Data [Abstract]

Quarterly Data (unaudited)

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,
	2012		2011		2013		2012		2013		2012		2013		2012
Revenues	$	273,797	$	280,641	$	395,901	$	345,802	$	148,798	$	143,644	$	122,216	$	114,246
Operating income	$	72,564	$	64,605	$	109,230	$	88,447	$	18,878	$	25,300	$	9,647	$	7,031
Net income (loss)	$	36,812	$	32,668	$	58,259	$	47,871	$	5,373	$	8,460	$	1,654	$	(1,101	)

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Inventories (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Inventory, Net [Abstract]
Total inventories	$ 89,661	$ 67,334
Gas Utility natural gas [Member]
Inventory, Net [Abstract]
Total inventories	78,950	57,663
Materials, supplies and other [Member]
Inventory, Net [Abstract]
Total inventories	$ 10,711	$ 9,671

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Income Taxes (Tables)

12 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Provisions for income taxes

The provisions for income taxes consist of the following:

	2013			2012			2011
Current expense (benefit):
Federal	$	21,807		$	(909	)	$	10,447
State	11,824			2,735			2,227
Total current expense	33,631			1,826			12,674
Deferred expense:
Federal	33,349			48,336			48,967
State	2,274			5,257			2,207
Investment tax credit amortization	(342		)	(346		)	(351		)
Total income tax expense	$	68,912		$	55,073		$	63,497

A reconciliation from the U.S. federal statutory tax rate to our effective tax rate

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

	2013		2012		2011
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Difference in tax rate due to:
State income taxes, net of federal	5.4		4.1		1.6
Other, net	(0.1	)	(0.6	)	1.0
Effective tax rate	40.3	%	38.5	%	37.6	%

Deferred tax liabilities (assets)

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

	2013			2012
Excess book basis over tax basis of property, plant and equipment	$	362,259		$	330,937
Goodwill	31,516			26,998
Regulatory assets	101,622			140,416
Other	949			601
Gross deferred tax liabilities	496,346			498,952
Pension plan liabilities	(35,996		)	(72,652		)
Allowance for doubtful accounts	(2,290		)	(1,489		)
Deferred investment tax credits	(1,772		)	(1,914		)
Employee-related expenses	(5,850		)	(4,859		)
Regulatory liabilities	(15,472		)	(11,761		)
Environmental liabilities	(7,002		)	(7,195		)
Derivative financial instruments	(3,397		)	(16,264		)
Other	(1,922		)	(12,202		)
Gross deferred tax assets	(73,701		)	(128,336		)
Net deferred tax liabilities	$	422,645		$	370,616

Reconciliation of beginning and ending amount of unrecognized tax benefit

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

Balance at September 30, 2010	$	4,194
Additions for tax positions of the current year	920
Settlements with tax authorities	(216		)
Balance at September 30, 2011	4,898
Additions for tax positions of prior years	81
Settlements with tax authorities	(3,931		)
Balance at September 30, 2012	1,048
Additions for tax positions of prior years	39
Balance at September 30, 2013	$	1,087

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Other Income, Net (Tables)

12 Months Ended

Sep. 30, 2013

Other Income [Abstract]

Other income, net

Other income, net, comprises the following:

	2013		2012		2011
Non-tariff service income	$	2,706	$	2,653	$	6,422
Interest income	500		572		467
Postretirement benefit plan curtailment gain	—		—		3,245
Other, net	1,622		1,764		630
Total other income, net	$	4,828	$	4,989	$	10,764

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Debt (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Long-term Debt
Carrying value long-term debt	$ 642,000	$ 600,000
Less: current maturities	0	(133,000)
Total long-term debt due after one year	642,000	467,000
Term Loan Credit Agreement [Member]
Long-term Debt
Carrying value long-term debt	175,000	0
6.375%, due September 2013 [Member] | Senior Notes [Member]
Long-term Debt
Carrying value long-term debt	0	108,000
Debt Instrument, Interest Rate, Stated Percentage	6.375%
5.75%, due September 2016 [Member] | Senior Notes [Member]
Long-term Debt
Carrying value long-term debt	175,000	175,000
Debt Instrument, Interest Rate, Stated Percentage	5.75%
6.21%, due September 2036 [Member] | Senior Notes [Member]
Long-term Debt
Carrying value long-term debt	100,000	100,000
Debt Instrument, Interest Rate, Stated Percentage	6.21%
5.53%, due September 2012 [Member] | Medium-term Notes [Member]
Long-term Debt
Debt Instrument, Interest Rate, Stated Percentage	5.53%
5.37%, due August 2013 [Member] | Medium-term Notes [Member]
Long-term Debt
Carrying value long-term debt	0	25,000
Debt Instrument, Interest Rate, Stated Percentage	5.37%
5.16%, due May 2015 [Member] | Medium-term Notes [Member]
Long-term Debt
Carrying value long-term debt	20,000	20,000
Debt Instrument, Interest Rate, Stated Percentage	5.16%
7.37%, due October 2015 [Member] | Medium-term Notes [Member]
Long-term Debt
Carrying value long-term debt	22,000	22,000
Debt Instrument, Interest Rate, Stated Percentage	7.37%
5.64%, due December 2015 [Member] | Medium-term Notes [Member]
Long-term Debt
Carrying value long-term debt	50,000	50,000
Debt Instrument, Interest Rate, Stated Percentage	5.64%
6.17%, due June 2017 [Member] | Medium-term Notes [Member]
Long-term Debt
Carrying value long-term debt	20,000	20,000
Debt Instrument, Interest Rate, Stated Percentage	6.17%
7.25%, due November 2017 [Member] | Medium-term Notes [Member]
Long-term Debt
Carrying value long-term debt	20,000	20,000
Debt Instrument, Interest Rate, Stated Percentage	7.25%
5.67%, due January 2018 [Member] | Medium-term Notes [Member]
Long-term Debt
Carrying value long-term debt	20,000	20,000
Debt Instrument, Interest Rate, Stated Percentage	5.67%
6.50%, due August 2033 [Member] | Medium-term Notes [Member]
Long-term Debt
Carrying value long-term debt	20,000	20,000
Debt Instrument, Interest Rate, Stated Percentage	6.50%
6.13%, due October 2034 [Member] | Medium-term Notes [Member]
Long-term Debt
Carrying value long-term debt	$ 20,000	$ 20,000
Debt Instrument, Interest Rate, Stated Percentage	6.13%

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Inventories (Tables)

12 Months Ended

Sep. 30, 2013

Inventory Disclosure [Abstract]

Inventories

Inventories comprise the following at September 30:

	2013		2012
Gas Utility natural gas	$	78,950	$	57,663
Materials, supplies and other	10,711		9,671
Total inventories	$	89,661	$	67,334

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Equity-Based Compensation (Details) (USD $)	12 Months Ended
	Sep. 30, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Equity-based Units, beginning balance	68,633
Number of UGI Units, Granted	20,800
Number of UGI Units, Vested	0
Number of UGI Units, Forfeited	(9,069)
Number of UGI Units, performance criteria not met	(7,679)
Number of UGI Units, unit awards paid	(11,354)
Number of Equity-based Units, ending balance	61,331
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, beginning of period	$ 29.72
Weighted Average Grant Date Fair Value, Granted	$ 38.27
Weighted Average Grant Date Fair Value, Vested
Weighted Average Grant Date Fair Value, Forfeited	$ 33.65
Weighted Average Grant Date Fair Value, performance criteria not met	$ 22.72
Weighted Average Grant Date Fair Value, unit awards paid	$ 22.72
Weighted Average Grant Date Fair Value, end of period	$ 34.21
Vested [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Equity-based Units, beginning balance	24,130
Number of UGI Units, Granted	1,797
Number of UGI Units, Vested	(13,768)
Number of UGI Units, Forfeited	0
Number of UGI Units, performance criteria not met	(7,679)
Number of UGI Units, unit awards paid	(11,354)
Number of Equity-based Units, ending balance	20,662
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, beginning of period	$ 28.78
Weighted Average Grant Date Fair Value, Granted	$ 38.27
Weighted Average Grant Date Fair Value, Vested	$ 26.24
Weighted Average Grant Date Fair Value, Forfeited	$ 0.00
Weighted Average Grant Date Fair Value, performance criteria not met	$ 22.72
Weighted Average Grant Date Fair Value, unit awards paid	$ 22.72
Weighted Average Grant Date Fair Value, end of period	$ 33.49
Non-Vested [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Equity-based Units, beginning balance	44,503
Number of UGI Units, Granted	19,003
Number of UGI Units, Vested	(13,768)
Number of UGI Units, Forfeited	(9,069)
Number of UGI Units, performance criteria not met	0
Number of UGI Units, unit awards paid
Number of Equity-based Units, ending balance	40,669
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, beginning of period	$ 30.23
Weighted Average Grant Date Fair Value, Granted	$ 38.27
Weighted Average Grant Date Fair Value, Vested	$ 26.24
Weighted Average Grant Date Fair Value, Forfeited	$ 33.65
Weighted Average Grant Date Fair Value, performance criteria not met	$ 0.00
Weighted Average Grant Date Fair Value, unit awards paid
Weighted Average Grant Date Fair Value, end of period	$ 34.57

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Disclosures About Derivative Instruments and Hedging Activities Textual (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Derivative [Line Items]
Fair values of electric utility's forward purchase power agreements	$ 6,677	$ 39,959
Interest rate cash flow hedge loss to be reclassified during next 12 months, net	(2,680)
Restricted Cash in brokerage accounts	3,181	0
Electric Utility electric transmission congestion [Member]
Derivative [Line Items]
Notional amount (in units)	189,300,000	189,700,000
Gas Utility [Member]
Derivative [Line Items]
Notional amount (in units)	15,000,000	19,200,000
Maximum Length of Time Hedged in Price Risk Cash Flow Hedges	12 months
Electric Utility - Forward Contract [Member]
Derivative [Line Items]
Notional amount (in units)	245,800,000	570,400,000
Maximum Length of Time Hedged in Price Risk Cash Flow Hedges	8 months
Fair values of electric utility's forward purchase power agreements	4,759	9,207
Interest Rate Swap [Member]
Derivative [Line Items]
Underlying variable rate debt	0	173,000
Recorded loss amount included in Other Income, Net	$ (682)

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Series Preferred Stock (Details)	Sep. 30, 2013
Series Preferred Stock [Abstract]
Preferred Stock, Authorized	2,000,000

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Significant Accounting Policies Textuals (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2013 Gas Utility [Member]	Sep. 30, 2012 Gas Utility [Member]	Sep. 30, 2011 Gas Utility [Member]	Sep. 30, 2013 Electric Utility [Member]	Sep. 30, 2012 Electric Utility [Member]	Sep. 30, 2011 Electric Utility [Member]
Accounting Policies [Abstract]
Error in the classification of deferred income tax assets, amount	$ 27,006
Property, Plant and Equipment [Line Items]
Depreciation expense as percentage of related average depreciable base		2.30%	2.20%	2.30%	2.40%	2.40%	2.60%

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Fair Value Measurements Textual (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 642,000	$ 600,000
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 699,929	$ 700,708

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Related Party Transactions

12 Months Ended

Sep. 30, 2013

Related Party Transactions [Abstract]

Related Party Transactions

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 SCAAs with Energy Services. At September 30, 2013, UGI Utilities was a party to threethree-year SCAAs with Energy Services one of which expired October 31, 2013, 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 $45,843, $24,344 and $35,231 in Fiscal 2013, Fiscal 2012 and Fiscal 2011, 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 $16,500 and $15,000 at September 30, 2013 and 2012, respectively. Effective November 1, 2013, 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, 2013, comprising approximately 10.4 bcf bcf of natural gas, was $41,988. The carrying value of these gas storage inventories at September 30, 2012, comprising approximately 7.6 bcf of natural gas, was $21,217. Effective November 1, 2013, UGI Utilities entered into a new SCAA with Energy Services having a term of one year.

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 2013, Fiscal 2012 and Fiscal 2011 totaled $32,526, $30,752 and $30,093, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2013, Fiscal 2012 and Fiscal 2011, revenues associated with sales to Energy Services totaled $69,087, $65,705 and $85,655, 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 2013, Fiscal 2012 and Fiscal 2011, such purchases totaled $77,017, $53,435 and $53,617, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Fair value of derivative instruments, net of tax	$ (10,746)	$ 4,783	$ 7,712
Reclassifications of net losses (gains) on derivative instruments, net of tax	(334)	(766)	(483)
Benefits plans, net of tax	(3,325)	1,948	479
Reclassification on benefits plans actuarial, net of tax	(555)	(333)	(304)
Reclassification of pension plans actuarial, net of tax	$ 0	$ 0	$ 0

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Consolidated Statements of Shareholders' Equity (USD $) In Thousands, unless otherwise specified	Total	Common stock, without par value	Retained earnings	Additional paid-in capital	Accumulated other comprehensive income (loss)
Balance, beginning of year at Sep. 30, 2010		$ 60,259	$ 217,960	$ 467,631	$ (11,396)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	105,196		105,196
Cash dividends — Common Stock			(99,490)
Dividends of net assets			(11,570)
Excess tax benefits on equity-based compensation				692
Net gains (losses) on derivative instruments	(10,874)				(10,874)
Reclassifications of net losses on derivative instruments	681				681
Benefit plans, principally actuarial gains (losses)					(674)
Reclassifications of benefit plans actuarial losses and prior service costs	430				430
Balance, end of year at Sep. 30, 2011	718,845	60,259	212,096	468,323	(21,833)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	87,898		87,898
Cash dividends — Common Stock			(70,615)
Dividends of net assets			0
Excess tax benefits on equity-based compensation				369
Net gains (losses) on derivative instruments	(6,744)				(6,744)
Reclassifications of net losses on derivative instruments	1,111				1,111
Benefit plans, principally actuarial gains (losses)					(2,745)
Reclassifications of benefit plans actuarial losses and prior service costs	394				394
Balance, end of year at Sep. 30, 2012	728,513	60,259	229,379	468,692	(29,817)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	102,098		102,098
Cash dividends — Common Stock			(58,975)
Dividends of net assets			(2,525)
Excess tax benefits on equity-based compensation				1,406
Net gains (losses) on derivative instruments	15,153				15,153
Reclassifications of net losses on derivative instruments	471				471
Benefit plans, principally actuarial gains (losses)					4,689
Reclassifications of benefit plans actuarial losses and prior service costs	784				784
Balance, end of year at Sep. 30, 2013	$ 791,614	$ 60,259	$ 269,977	$ 470,098	$ (8,720)

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Accounting Changes

12 Months Ended

Sep. 30, 2013

Accounting Changes and Error Corrections [Abstract]

Accounting Changes

ACCOUNTING CHANGES

New Accounting Standards Not Yet Adopted

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued new accounting guidance regarding disclosures for items reclassified out of AOCI. The new disclosure guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2012. The new disclosures are to be applied prospectively, and early adoption is permitted. We will adopt the new guidance in Fiscal 2014. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities. In December 2011 (and amended in January 2013), the FASB issued new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods, and is required to be applied retrospectively. We will adopt the new guidance in Fiscal 2014. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2013 Segment	Sep. 30, 2012	Sep. 30, 2011
Segment Reporting [Abstract]
Number of reportable segments (in segments)									2
Segment Reporting Information [Line Items]
Revenues	$ 122,216	$ 148,798	$ 395,901	$ 273,797	$ 114,246	$ 143,644	$ 345,802	$ 280,641	$ 940,712	$ 884,333	$ 1,137,366
Cost of sales									465,996	459,079	678,500
Depreciation and amortization									55,716	52,792	52,546
Operating income	9,647	18,878	109,230	72,564	7,031	25,300	88,447	64,605	210,319	185,383	211,421
Interest expense									39,309	42,412	42,728
Income before income taxes									171,010	142,971	168,693
Total assets	2,210,322				2,196,173				2,210,322	2,196,173	2,169,348
Goodwill	182,145				182,145				182,145	182,145	182,145
Capital expenditures									151,090	114,090	98,856
Gas Utility [Member]
Segment Reporting Information [Line Items]
Revenues									839,050	785,375	1,026,397
Cost of sales									407,222	402,534	610,635
Depreciation and amortization									51,698	48,992	48,350
Operating income									198,352	172,164	199,643
Interest expense									37,280	40,139	40,374
Income before income taxes									161,072	132,025	159,269
Total assets	2,068,955				2,045,480				2,068,955	2,045,480	2,028,705
Goodwill	182,145				182,145				182,145	182,145	182,145
Capital expenditures									144,399	109,020	91,328
Electric Utility [Member]
Segment Reporting Information [Line Items]
Revenues									99,986	97,130	109,145
Cost of sales									58,774	56,545	67,865
Depreciation and amortization									4,018	3,800	4,196
Operating income									11,385	12,610	11,384
Interest expense									2,029	2,273	2,354
Income before income taxes									9,356	10,337	9,030
Total assets	141,367				150,693				141,367	150,693	140,643
Goodwill	0				0				0	0	0
Capital expenditures									6,691	5,070	7,528
Other [Member]
Segment Reporting Information [Line Items]
Revenues									1,676	1,828	1,824
Cost of sales									0	0	0
Depreciation and amortization									0	0	0
Operating income									582	609	394
Interest expense									0	0	0
Income before income taxes									582	609	394
Total assets	0				0				0	0	0
Goodwill	0				0				0	0	0
Capital expenditures									$ 0	$ 0	$ 0

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Nature of Operations

12 Months Ended

Sep. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

NATURE OF OPERATIONS

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.

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.

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Quarterly Data (unaudited) (Tables)

12 Months Ended

Sep. 30, 2013

Quarterly Financial Data [Abstract]

Schedule of Quarterly Financial Information

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,
	2012		2011		2013		2012		2013		2012		2013		2012
Revenues	$	273,797	$	280,641	$	395,901	$	345,802	$	148,798	$	143,644	$	122,216	$	114,246
Operating income	$	72,564	$	64,605	$	109,230	$	88,447	$	18,878	$	25,300	$	9,647	$	7,031
Net income (loss)	$	36,812	$	32,668	$	58,259	$	47,871	$	5,373	$	8,460	$	1,654	$	(1,101	)

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Significant Accounting Policies (Policies)

12 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Basis Of Presentation

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.

Principles of Consolidation

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

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. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulator.

Fair Value Measurements

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. 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. Fair value measurements require that we assume that the transaction occurs in the principal market for the asset or liability or in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

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. Instruments categorized in Level 1 consist of our exchange-traded commodity futures and option contracts and non exchange-traded electricity forward contracts whose underlying is identical to an exchange-traded electricity contract.

• 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 inactive markets, 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. Instruments categorized in Level 2 include financial transmission rights (“FTRs”) and non exchange-traded electricity forward contracts not qualifying for Level 1.

• Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 2013 or 2012.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. See Note 13 for additional information on fair value measurements.

Derivative Instruments

Derivative Instruments

We account for derivative instruments and hedging activities in accordance with guidance provided by the FASB which requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. 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. 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 related supplemental information required by GAAP, see Note 14.

Revenue Recognition

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.

Income Taxes

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.

Correction of Error

Correction of Error. During the three months ended September 30, 2013, we identified an error in the classification of deferred income tax assets on the September 30, 2012, Consolidated Balance Sheet. We evaluated the impact of the error and have determined that such error is not material. We have revised the September 30, 2012, Consolidated Balance Sheet to correct the error which revision decreased the following Consolidated Balance Sheet items by $27,006: current deferred income taxes; total current assets and total assets; long-term deferred income tax liabilities; total liabilities; and total liabilities and stockholder’s equity.

Comprehensive Income/Presentation of Comprehensive Income

Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally reflects gains and losses on derivative instruments accounted for as cash flow hedges and changes in actuarial gains and losses on postretirement benefit plans. Other comprehensive income (loss) for all periods presented includes reclassifications of net losses on interest rate protection agreements (“IRPAs”).

Cash and Cash Equivalents

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

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

Inventories

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

Property, Plant and Equipment and Related Depreciation

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

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.3% in Fiscal 2013, 2.2% in Fiscal 2012 and 2.3% in Fiscal 2011. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.4% in Fiscal 2013, 2.4% in Fiscal 2012 and 2.6% in Fiscal 2011. When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes.

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

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. 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.

Impairment of Long-Lived Assets

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.

Employee Retirement Plans

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

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.

Environmental Matters

Environmental Matters

We are subject to environmental laws and regulations intended to mitigate or remove the effect 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, and 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.

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Property Plant and Equipment (Tables)

12 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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

	2013		2012
Distribution	$	2,162,580	$	2,047,780
Transmission	86,623		85,430
General and other, including construction in process	178,607		162,459
Total property, plant and equipment	$	2,427,810	$	2,295,669

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Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash Flow Hedging [Member] | Interest expense | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in AOCI	$ 25,898	$ (11,528)
Gain (Loss) Reclassified from AOCI into Income	(805)	(1,847)
Derivatives Not Designated as Hedging Instruments [Member] | Operating expenses/other income, net
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income	$ 45	$ 223

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Fair Value Measurements (Tables)

12 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Financial assets and financial liabilities that are measured at fair value on a recurring basis

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of September 30, 2013 and 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
September 30, 2013
Assets:
Derivative financial instruments
Commodity contracts	$	43		$	—		$	—	$	43
Liabilities:
Derivative financial instruments
Commodity contracts	$	(2,162	)	$	(4,515	)	$	—	$	(6,677	)
September 30, 2012
Assets:
Derivative financial instruments
Commodity contracts	$	5,468		$	—		$	—	$	5,468
Liabilities:
Derivative financial instruments
Commodity contracts	$	(671	)	$	(8,766	)	$	—	$	(9,437	)
Interest rate contracts	$	—		$	(30,522	)	$	—	$	(30,522	)

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Disclosures About Derivative Instruments and Hedging Activities (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Derivatives, Fair Value [Line Items]
Total Derivatives Assets	$ 43	$ 5,468
Total Derivatives Liability	(6,677)	(39,959)
Interest rate contracts [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Assets	0	0
Interest rate contracts [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments and Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Liability	0	(30,522)
Commodity contracts [Member] | Accounted for Under ASC 980 [Member] | Derivative Financial Instruments [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Assets	31	5,303
Commodity contracts [Member] | Accounted for Under ASC 980 [Member] | Derivative Financial Instruments and Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Liability	(6,677)	(9,437)
Commodity contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Liability	0	0
Commodity contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Derivative Financial Instruments [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Assets	$ 12	$ 165

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Income Taxes Textual (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Income Tax Disclosure [Abstract]
Investment Income, Interest	$ 0	$ (209)	$ 219
Accrued interest included in unrecognized income tax benefits	56
Unrecognized tax benefits if recognized would impact the reported effective tax rate	56
Tax positions for which the deductibility is highly certain but uncertainty about the timing	1,087
Income Taxes [Line Items]
Operating Loss Carryforwards	18,271
Unrecognized income tax benefits	1,087	1,048	4,898	4,194
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions	39	124
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	43
Accrued Interest Included [Member]
Income Taxes [Line Items]
Unrecognized income tax benefits	1,143
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Income Tax Expense (Benefit), Accelerated Depreciation	$ (1,538)	$ (3,198)	$ (7,926)

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Debt Textual (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Maturities of Long-term Debt [Abstract]
Due in Fiscal 9/30/2013	$ 0
Due in Fiscal 9/30/2014	20,000
Due in Fiscal 9/30/2015	247,000
Due in Fiscal 9/30/2016	20,000
Due in Fiscal 9/30/2017	40,000
Debt Instrument [Line Items]
Long-term Debt	642,000	600,000
UGI Utilities 2011 Credit Agreement [Member]
Debt Instrument [Line Items]
Credit agreement	300,000
Borrowings outstanding, amount	17,500	9,200
Line of Credit Facility, Interest Rate at Period End	1.18%	1.21%
Credit agreement outstanding, amount	2,000	2,000
Letter of Credit [Member] | UGI Utilities 2011 Credit Agreement [Member]
Debt Instrument [Line Items]
Revolving credit agreement sublimit for letters of credit	100,000
Minimum [Member] | UGI Utilities 2011 Credit Agreement [Member]
Debt Instrument [Line Items]
Margin on term loan base rate borrowings	0.00%
Maximum [Member] | UGI Utilities 2011 Credit Agreement [Member]
Debt Instrument [Line Items]
Margin on term loan base rate borrowings	2.00%
Term Loan Credit Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt	175,000	0
Margin on term loan base rate borrowings	0.60%
Debt Instrument, Term	364 days
Senior Notes [Member] | 6.375%, due September 2013 [Member]
Debt Instrument [Line Items]
Long-term Debt	0	108,000
Debt Instrument, Interest Rate, Stated Percentage	6.375%
Senior Notes [Member] | Senior Notes due March 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 175,000
Debt Instrument, Interest Rate, Stated Percentage	4.98%

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Regulatory Assets and Liabilities and Regulatory Matters Textual (Details) (USD $)	0 Months Ended					12 Months Ended			3 Months Ended	0 Months Ended
	Oct. 21, 2010	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Dec. 01, 2010 mi	Sep. 30, 2013 UGI Central Penn Gas Inc [Member]	Sep. 30, 2013 Minimum [Member]	Sep. 30, 2013 Maximum [Member]	Mar. 31, 2012 UGI Storage Company [Member] UGI Central Penn Gas Inc [Member]	Oct. 03, 2012 Allentown, Pennsylvania Natural Gas Explosion [Member] Damage from Natural Gas Explosion [Member]	Feb. 19, 2013 Revised Penalty [Member] Allentown Incident [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Average remaining depreciable lives of the associated property							1 year	50 years
Unrealized gains (losses) on derivative financial instruments contracts		$ (1,743,000)	$ 5,303,000
Fair value of electric utility electricity supply contracts		4,759,000	9,207,000
Minimum period to recover costs related to other regulatory assets		1 year
Maximum period to recover costs related to other regulatory assets		5 years
Penalty Assessed											500
Site Contingency, Accelerated Time Frame Replacing Remainder of Cast-Iron Mains										14 years
Loss Contingency, Agreement Permitted To Retain Current Timeframe for Replacing The Remainder of Their Bare Steel Mains										30 years
Additional base rate revenue using for increased distribution rates per settlement agreement						8,000,000
Base rate revenue increase for use in CPG's Energy and Efficiency Program						900,000
Reversal of Previous Increase in Base Rate Revenue						900,000
Net book value of the Auburn line		2,650,000			1,109,000
Agreement To Charge Customers, Period	3 years
Net book value of the storage facility assets				10,949,000
Deferred Tax Assets, Regulatory Assets and Liabilities		$ 384		$ 308,000	$ 180,000
Storage agreement, term									1 year
Approval of the transfer length of natural gas pipeline (in miles)					9

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Current assets:
Allowances for doubtful accounts on accounts receivable	$ 5,519	$ 3,588
Common stockholder’s equity:
Common stock, par value	$ 2.25	$ 2.25
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares issued	26,781,785	26,781,785
Common stock, shares outstanding	26,781,785	26,781,785

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Property Plant and Equipment

12 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

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

	2013		2012
Distribution	$	2,162,580	$	2,047,780
Transmission	86,623		85,430
General and other, including construction in process	178,607		162,459
Total property, plant and equipment	$	2,427,810	$	2,295,669

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Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net income	$ 102,098	$ 87,898	$ 105,196
Net gains (losses) on derivative instruments (net of tax of $(10,746), $4,783 and $7,712, respectively)	15,153	(6,744)	(10,874)
Reclassifications of net losses on derivative instruments (net of tax of $(334), $(766) and $(483), respectively)	471	1,111	681
Benefit plans (net of tax of $(3,325), $1,948 and $479, respectively)	4,689	(2,745)	(674)
Reclassifications of benefit plans actuarial losses and prior service costs to net income (net of tax of $(555), $(333) and $(304), respectively)	784	394	430
Other comprehensive income (loss)	21,097	(7,984)	(10,437)
Comprehensive income	$ 123,195	$ 79,914	$ 94,759

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Employee Retirement Plans (Net periodic pension expense and other postretirement benefit costs) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Pension Benefits [Member]
Components of Net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	$ 9,385	$ 8,063
Interest cost	22,784	24,095
Other Postretirement Benefits [Member]
Components of Net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	223	162
Interest cost	587	665
UGI Utilities Employees [Member] | Pension Benefits [Member]
Components of Net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	8,211	7,025	7,176
Interest cost	20,783	22,376	22,047
Expected return on assets	(24,791)	(23,762)	(23,937)
Curtailment gain	0	0	0
Amortization of:
Prior service cost (benefit)	249	249	302
Actuarial loss	13,463	7,853	6,838
Net benefit cost (income)	17,915	13,741	12,426
Change in associated regulatory liabilities	0	0	0
Benefit cost (income) after change in regulatory liabilities	17,915	13,741	12,426
UGI Utilities Employees [Member] | Other Postretirement Benefits [Member]
Components of Net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	205	152	202
Interest cost	557	639	678
Expected return on assets	(529)	(481)	(523)
Curtailment gain	0	0	(3,245)
Amortization of:
Prior service cost (benefit)	(420)	(422)	(694)
Actuarial loss	336	355	427
Net benefit cost (income)	149	243	(3,155)
Change in associated regulatory liabilities	3,302	3,188	3,138
Benefit cost (income) after change in regulatory liabilities	$ 3,451	$ 3,431	$ (17)

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Current assets:
Cash and cash equivalents	$ 4,707	$ 1,259
Restricted cash	3,181	0
Accounts receivable (less allowances for doubtful accounts of $5,519 and $3,588, respectively)	53,341	47,362
Accounts receivable — related parties	3,497	4,571
Accrued utility revenues	18,868	16,911
Inventories	89,661	67,334
Deferred income taxes	14,165	19,430
Income taxes recoverable	0	9,461
Regulatory assets	8,217	6,473
Derivative financial instruments	43	5,468
Prepaid expenses & other current assets	15,862	19,852
Total current assets	211,542	198,121
Property, plant and equipment	2,427,810	2,295,669
Less accumulated depreciation and amortization	(853,675)	(815,720)
Net property, plant and equipment	1,574,135	1,479,949
Goodwill	182,145	182,145
Regulatory assets	236,694	331,932
Other assets	5,806	4,026
Total assets	2,210,322	2,196,173
Current liabilities:
Current maturities of long-term debt	0	133,000
Bank loans	17,500	9,200
Accounts payable — trade	51,970	46,754
Accounts payable — related parties	12,487	10,192
Employee compensation and benefits accrued	13,664	10,902
Interest accrued	11,281	22,766
Customer deposits and advances	40,307	49,806
Derivative financial instruments	6,677	36,011
Deferred fuel refunds	8,283	4,435
Pension and postretirement benefit obligations	17,885	15,802
Other current liabilities	27,459	31,816
Total current liabilities	207,513	370,684
Long-term debt	642,000	467,000
Deferred income taxes	436,810	390,046
Deferred investment tax credits	4,270	4,612
Pension and other postretirement benefit obligations	72,505	179,056
Other noncurrent liabilities	55,610	56,262
Total liabilities	1,418,708	1,467,660
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	470,098	468,692
Retained earnings	269,977	229,379
Accumulated other comprehensive loss	(8,720)	(29,817)
Total common stockholder’s equity	791,614	728,513
Total liabilities and stockholder’s equity	$ 2,210,322	$ 2,196,173

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Income Taxes (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Current expense (benefit):
Federal	$ 21,807	$ (909)	$ 10,447
State	11,824	2,735	2,227
Total current expense (benefit)	33,631	1,826	12,674
Deferred Federal Income Tax Expense (Benefit)	33,349	48,336	48,967
Deferred State and Local Income Tax Expense (Benefit)	2,274	5,257	2,207
Investment tax credit amortization	(342)	(346)	(351)
Total income tax expense	$ 68,912	$ 55,073	$ 63,497

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Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2013 UGI Energy Services, Inc. [Member]	Sep. 30, 2012 UGI Energy Services, Inc. [Member]	Sep. 30, 2011 UGI Energy Services, Inc. [Member]	Sep. 30, 2013 SCAAs [Member] UGI Energy Services, Inc. [Member] Storage_Agreement	Sep. 30, 2012 SCAAs [Member] UGI Energy Services, Inc. [Member]	Sep. 30, 2011 SCAAs [Member] UGI Energy Services, Inc. [Member]	Sep. 30, 2013 Exclusive of transactions pursuant SCAAs [Member] UGI Energy Services, Inc. [Member]	Sep. 30, 2012 Exclusive of transactions pursuant SCAAs [Member] UGI Energy Services, Inc. [Member]	Sep. 30, 2011 Exclusive of transactions pursuant SCAAs [Member] UGI Energy Services, Inc. [Member]	Sep. 30, 2013 Other current liabilities [Member] SCAAs [Member] UGI Energy Services, Inc. [Member]	Sep. 30, 2012 Other current liabilities [Member] SCAAs [Member] UGI Energy Services, Inc. [Member]	Sep. 30, 2013 Inventories [Member] UGI Energy Services, Inc. [Member] ft3	Sep. 30, 2012 Inventories [Member] UGI Energy Services, Inc. [Member] ft3	Sep. 30, 2013 SCAAs [Member] Storage_Agreement	Nov. 01, 2013 SCAAs [Member] New Storage Agreement [Member]	Nov. 01, 2013 UGI Energy Services, Inc. [Member] SCAAs [Member] New Storage Agreement [Member]
Related Party Transaction [Line Items]
Number of storage agreements							3										3
Storage agreement, term (in years)							3 years											3 years	1 year
Related party costs incurred	$ 8,366	$ 9,326	$ 12,125				$ 45,843	$ 24,344	$ 35,231	$ 32,526	$ 30,752	$ 30,093
Related party security deposits													16,500	15,000
Volume of gas storage inventory (in bcf of natural gas)															10,400,000,000	7,600,000,000
Natural gas storage inventory, related parties, current															41,988	21,217
Revenue from related parties				69,087	65,705	85,655
Purchases from related party				$ 77,017	$ 53,435	$ 53,617

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Significant Accounting Policies (Tables)

12 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Components of AOCI

The components of AOCI at September 30, 2013 and 2012, follow:

	Postretirement Benefit Plans			Derivative Instruments Net Losses			Total
September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
September 30, 2012	$	(10,756	)	$	(19,061	)	$	(29,817	)

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Segment Information

12 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Segment Information

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.

Financial information by business segment follows:

	Total		Gas Utility		Electric Utility		Other
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		—
2011
Revenues	$	1,137,366	$	1,026,397	$	109,145	$	1,824
Cost of sales	678,500		610,635		67,865		—
Depreciation and amortization	52,546		48,350		4,196		—
Operating income	211,421		199,643		11,384		394
Interest expense	42,728		40,374		2,354		—
Income before income taxes	168,693		159,269		9,030		394
Total assets	2,169,348		2,028,705		140,643		—
Goodwill	182,145		182,145		—		—
Capital expenditures	98,856		91,328		7,528		—

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Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 244,911	$ 338,405
Regulatory Liabilities	37,287	28,344
Postretirement benefits [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	16,497	13,147
Environmental overcollections [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	2,552	2,883
Deferred fuel and power refunds [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	8,283	4,435
State tax benefits - distribution system repairs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	8,453	7,385
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	1,502	494
Income taxes recoverable [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	106,069	103,172
Underfunded pension and postretirement plans [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	94,515	188,222
Environmental costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	17,054	16,812
Deferred fuel and power costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	8,283	11,602
Removal costs, net [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	13,333	12,718
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 5,657	$ 5,879

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Valuation and Qualifying Accounts (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
Valuation and Qualifying Accounts [Abstract]
Insurance Indemnification Receivables	$ 735		$ 6,291		$ 8,163
Allowance for Doubtful Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance	3,588		6,368		7,072
Charged to costs and expenses	9,584		6,286		9,137
Other	(7,653)	[1]	(9,066)	[1]	(9,841)	[1]
Ending Balance	5,519		3,588		6,368
Property and Casualty Liability [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance	26,951	[2]	34,080	[2]	33,465
Charged to costs and expenses	(1,338)		1,614		10,173
Valuation allowances and reserves, deductions on other adjustment	(7,220)	[2]	(8,359)	[2]	(9,558)	[2]
Other Adjustments	1,402	[2]
Ending Balance	$ 19,795	[2]	$ 26,951	[2]	$ 34,080	[2]

[1] Uncollectible accounts written off, net of recoveries

[2] s

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Income Taxes (Reconciliation of the beginning and ending amounts of unrecognized tax benefits) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Reconciliation of beginning and ending amount of unrecognized tax benefit
Beginning Balance	$ 1,048	$ 4,898	$ 4,194
Additions for tax positions of the current year			920
Additions for tax positions of prior years	39	81
Settlements with tax authorities		(3,931)	(216)
Ending Balance	$ 1,087	$ 1,048	$ 4,898

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Equity-Based Compensation Textual (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested, Number of Equity-based Units	61,331	68,633
Share Based Compensation Types, Excluding Stock Options [Member] | UGI Omnibus Equity Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	10 years
Options can be exercised	no later than ten years from the grant date
Performance Unit [Member] | UGI Units and UGI Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated share-based compensation expense	$ 1,078	$ 783	$ 1,110
Allocated share-based compensation expense, after-tax	631	458	650
Performance Unit [Member] | UGI Units and UGI Stock Options [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percent of target award paid to grantee	0.00%
Performance Unit [Member] | UGI Units and UGI Stock Options [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percent of target award paid to grantee	200.00%
Performance Unit [Member] | UGI Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested awards, total compensation cost not yet recognized	682
Nonvested awards, total compensation cost not yet recognized, period for recognition	2 years
Performance Unit [Member] | UGI Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested awards, total compensation cost not yet recognized	758
Nonvested awards, total compensation cost not yet recognized, period for recognition	1 year 10 months 24 days
Nonvested, Number of Equity-based Units	61,331
Performance Unit [Member] | UGI Units [Member] | Other current liabilities [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred compensation arrangements, liability, current	360
Performance Unit [Member] | UGI Units [Member] | Other noncurrent liabilities [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred compensation arrangements, liability, classified, noncurrent		$ 143

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Segment Information (Tables)

12 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Segment Information

Financial information by business segment follows:

	Total		Gas Utility		Electric Utility		Other
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		—
2011
Revenues	$	1,137,366	$	1,026,397	$	109,145	$	1,824
Cost of sales	678,500		610,635		67,865		—
Depreciation and amortization	52,546		48,350		4,196		—
Operating income	211,421		199,643		11,384		394
Interest expense	42,728		40,374		2,354		—
Income before income taxes	168,693		159,269		9,030		394
Total assets	2,169,348		2,028,705		140,643		—
Goodwill	182,145		182,145		—		—
Capital expenditures	98,856		91,328		7,528		—

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Employee Retirement Plans (Tables)

12 Months Ended

Sep. 30, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Change in Pension Benefits and Other postretirement benefits Obligations, plan assets, and the funded status

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 other postretirement plans as of September 30, 2013 and 2012. 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
	2013			2012			2013			2012
Change in benefit obligations:
Benefit obligations — beginning of year	$	543,605		$	456,714		$	14,560		$	13,333
Service cost	9,385			8,063			223			162
Interest cost	22,784			24,095			587			665
Actuarial (gain) loss	(69,112		)	74,676			(1,881		)	1,464
Plan amendments	993			—			(1,836		)	—
Benefits paid	(21,187		)	(19,943		)	(965		)	(1,064		)
Benefit obligations — end of year	$	486,468		$	543,605		$	10,688		$	14,560
Change in plan assets:
Fair value of plan assets — beginning of year	$	351,543		$	289,764		$	11,205		$	9,805
Actual gain on assets	45,450			50,550			1,117			1,741
Employer contributions	22,365			31,172			366			723
Benefits paid	(21,187		)	(19,943		)	(965		)	(1,064		)
Fair value of plan assets — end of year	$	398,171		$	351,543		$	11,723		$	11,205
Funded status of the plans — end of year	$	(88,297	)	$	(192,062	)	$	1,035		$	(3,355	)
(Liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	$	—		$	—		$	3,252		$	—
Unfunded liabilities — included in other current liabilities	(17,885		)	(15,802		)	(372		)	(654		)
Unfunded liabilities — included in other noncurrent liabilities	(70,412		)	(176,260		)	(1,844		)	(2,701		)
Net amount recognized	$	(88,297	)	$	(192,062	)	$	1,036		$	(3,355	)
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	$	222		$	152		$	(74	)	$	(79	)
Net actuarial loss (gain)	9,113			18,099			(222		)	164
Total	$	9,335		$	18,251		$	(296	)	$	85
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	$	2,223		$	1,550		$	(4,286	)	$	(2,766	)
Net actuarial loss	91,275			184,464			3,586			5,815
Total	$	93,498		$	186,014		$	(700	)	$	3,049

Actuarial assumptions for our domestic plans

The expected rate of return on assets assumption is based on the current and expected asset allocations as well as historical and expected returns on various categories of plan assets as further described below.

	Pension Benefits						Other Postretirement Benefits
Weighted-average assumptions:	2013		2012		2011 (a)		2013		2012		2011
Discount rate - benefit obligations	5.20	%	4.20	%	5.30	%	5.10% - 5.40%		4.10% - 4.30%		5.30	%
Discount rate - benefit cost	4.20	%	5.30	%	5.00	%	4.10% - 4.30%		5.30	%	5.00	%
Expected return on plan assets	7.75	%	7.75	%	8.00	%	5.00	%	5.20	%	5.50	%
Rate of increase in salary levels	3.25	%	3.25	%	3.50	%	3.25	%	3.25	%	3.50	%

(a) Effective December 31, 2010, we merged our then-existing two U.S. defined benefit pension plans (“Pension Plans Merger”) to form the Pension Plan. The discount rates used during Fiscal 2011 to calculate pension expense were rates of 5.0% through December 31, 2010 (the date of the Pension Plans Merger) and 5.5%

Component of net periodic pension expense and other postretirement benefit costs

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

	Pension Benefits									Other Postretirement Benefits
	2013			2012			2011			2013			2012			2011
Service cost	$	8,211		$	7,025		$	7,176		$	205		$	152		$	202
Interest cost	20,783			22,376			22,047			557			639			678
Expected return on assets	(24,791		)	(23,762		)	(23,937		)	(529		)	(481		)	(523		)
Curtailment gain	—			—			—			—			—			(3,245		)
Amortization of:
Prior service cost (benefit)	249			249			302			(420		)	(422		)	(694		)
Actuarial loss	13,463			7,853			6,838			336			355			427
Net benefit cost (income)	17,915			13,741			12,426			149			243			(3,155		)
Change in associated regulatory liabilities	—			—			—			3,302			3,188			3,138
Benefit cost (income) after change in regulatory liabilities	$	17,915		$	13,741		$	12,426		$	3,451		$	3,431		$	(17	)

Expected payments for pension benefits and other postretirement welfare benefits

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

	Pension Benefits		Other Postretirement Benefits
Fiscal 2014	$	23,021	$	1,006
Fiscal 2015	24,095		813
Fiscal 2016	25,238		769
Fiscal 2017	26,451		706
Fiscal 2018	27,744		676
Fiscal 2019 - 2023	155,907		3,156

Pension Plans

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:	2013		2012		Allocation		Range
Equity investments:
Domestic	57.5	%	53.5	%	52.5	%	40.0% - 65.0%
International	11.1	%	10.5	%	12.5	%	7.5% - 17.5%
Total	68.6	%	64.0	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	31.4	%	36.0	%	35.0	%	30.0% - 40.0%
Total	100.0	%	100.0	%	100.0	%

					Target
	Actual				Asset		Permitted
VEBA:	2013		2012		Allocation		Range
Domestic equity investments	65.6	%	68.5	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	34.4	%	31.5	%	35.0	%	30.0% - 40.0%
Total	100.0	%	100.0	%	100.0	%

Fair value of U.S. pension plan and VEBA trust assets

The fair values of the Pension Plan’s assets at September 30, 2013 and 2012, by asset class are as follows:

	Pension Plan
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total
September 30, 2013:
Domestic 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
September 30, 2012:
Equity investments:
S&P 500 Index equity mutual funds	$	118,922	$	—	$	—	$	118,922
Small and Midcap equity mutual funds	42,876		—		—		42,876
UGI Corporation Common Stock	26,445		—		—		26,445
Total domestic equity investments	188,243		—		—		188,243
International index equity mutual funds	36,908		—		—		36,908
Fixed income investments:
Bond index mutual funds	123,332		—		—		123,332
Cash equivalents	—		3,060		—		3,060
Total fixed income investments	123,332		3,060		—		126,392
Total	$	348,483	$	3,060	$	—	$	351,543

The fair values of the VEBA trust assets at September 30, 2013 and 2012, by asset class are as follows:

	VEBA
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total
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
September 30, 2012:
S&P 500 Index equity mutual fund	$	7,678	$	—	$	—	$	7,678
Bond index mutual fund	3,366		—		—		3,366
Cash equivalents	—		161		—		161
Total	$	11,044	$	161	$	—	$	11,205

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Equity-Based Compensation (Tables)

12 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

UGI unit award activity

The following table summarizes UGI Unit award activity for Fiscal 2013:

	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, 2012	68,633		$	29.72	24,130		$	28.78	44,503		$	30.23
Granted	20,800		$	38.27	1,797		$	38.27	19,003		$	38.27
Vested	—		$	—	13,768		$	26.24	(13,768	)	$	26.24
Forfeited	(9,069	)	$	33.65	—		$	—	(9,069	)	$	33.65
Performance criteria not met	(7,679	)	$	22.72	(7,679	)	$	22.72	—		$	—
Unit awards paid	(11,354	)	$	22.72	(11,354	)	$	22.72	—		$	—
September 30, 2013	61,331		$	34.21	20,662		$	33.49	40,669		$	34.57

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Inventories

12 Months Ended

Sep. 30, 2013

Inventory Disclosure [Abstract]

Inventories

INVENTORIES

Inventories comprise the following at September 30:

	2013		2012
Gas Utility natural gas	$	78,950	$	57,663
Materials, supplies and other	10,711		9,671
Total inventories	$	89,661	$	67,334

At September 30, 2013, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”) with Energy Services, Inc. (“Energy Services”), a second-tier, wholly owned subsidiary of UGI, one of which expired in October 2013 and two of which expire in October 2015. 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 represent a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivables (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, 2013 and 2012, comprising 11.0 billion cubic feet (“bcf”) and 11.4 bcf of natural gas was $44,366 and $32,627, respectively. At September 30, 2013 and 2012, UGI Utilities held a total of $16,500 and $22,500, 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, 2013, UGI Utilities entered into two new SCAAs having terms of one and three years (see Note 17).

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Employee Retirement Plans Textual (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Defined Benefit Plan Disclosure [Line Items]
Amortization of net actuarial losses for Fiscal 2013	$ (6,800)
Amortization of net prior service credits for Fiscal 2013	(300)
Projected benefit obligations of unfunded and non qualified supplemental executive retirement plans	3,550	2,507
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans	498	255	583
The aggregate holdings of all qualifying employer securities not to exceed the fair value of trust assets at the time of purchase	10.00%
Percentage of UGI Common Stock represented Pension Plan Assets	8.20%	7.50%
Cost of benefits under the 401(k) savings plan	1,762	1,690	1,820
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
ABO for the Pension Plans	451,228	496,395
Benefit obligations	486,468	543,605	456,714
Expected contribution to pensions plans in next twelve months	(17,900)
Pension Benefits [Member] | Employees of UGI and Certain of its Other Subsidiaries [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligations	44,161	48,570
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligations	10,688	14,560	13,333
Other Postretirement Benefits [Member] | Employees of UGI and Certain of its Other Subsidiaries [Member]
Defined Benefit Plan Disclosure [Line Items]
ABO for the Pension Plans	$ 787	$ 869
Fiscal 2017 [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Assumed domestic health care cost range	7.00%
Fiscal 2017 [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Assumed domestic health care cost range	5.00%
Fiscal 2019 [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Assumed domestic health care cost range	7.50%
Fiscal 2019 [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Assumed domestic health care cost range	5.00%

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Regulatory Assets and Liabilities and Regulatory Matters (Tables)

12 Months Ended

Sep. 30, 2013

Regulated Operations [Abstract]

Regulatory assets and liabilities associated with Gas Utility and Electric Utility

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

	2013		2012
Regulatory assets:
Income taxes recoverable	$	106,069	$	103,172
Underfunded pension and postretirement plans	94,515		188,222
Environmental costs	17,054		16,812
Deferred fuel and power costs	8,283		11,602
Removal costs, net	13,333		12,718
Other	5,657		5,879
Total regulatory assets	$	244,911	$	338,405
Regulatory liabilities:
Postretirement benefits	$	16,497	$	13,147
Environmental overcollections	2,552		2,883
Deferred fuel and power refunds	8,283		4,435
State tax benefits — distribution system repairs	8,453		7,385
Other	1,502		494
Total regulatory liabilities	$	37,287	$	28,344

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Significant Accounting Policies (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Components of AOCI
Postretirement Benefit Plans	$ (5,283)	$ (10,756)
Derivative Instruments Net Losses	(3,437)	(19,061)
Total	$ (8,720)	$ (29,817)

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Income Taxes

12 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Income Taxes

The provisions for income taxes consist of the following:

	2013			2012			2011
Current expense (benefit):
Federal	$	21,807		$	(909	)	$	10,447
State	11,824			2,735			2,227
Total current expense	33,631			1,826			12,674
Deferred expense:
Federal	33,349			48,336			48,967
State	2,274			5,257			2,207
Investment tax credit amortization	(342		)	(346		)	(351		)
Total income tax expense	$	68,912		$	55,073		$	63,497

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

	2013		2012		2011
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Difference in tax rate due to:
State income taxes, net of federal	5.4		4.1		1.6
Other, net	(0.1	)	(0.6	)	1.0
Effective tax rate	40.3	%	38.5	%	37.6	%

Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2013, Fiscal 2012 and Fiscal 2011, the beneficial effects of state tax flow through of accelerated depreciation reduced tax expense by $1,538, $3,198 and $7,926, respectively. The state tax flow through amounts in Fiscal 2012 and Fiscal 2011 reflect 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.

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

	2013			2012
Excess book basis over tax basis of property, plant and equipment	$	362,259		$	330,937
Goodwill	31,516			26,998
Regulatory assets	101,622			140,416
Other	949			601
Gross deferred tax liabilities	496,346			498,952
Pension plan liabilities	(35,996		)	(72,652		)
Allowance for doubtful accounts	(2,290		)	(1,489		)
Deferred investment tax credits	(1,772		)	(1,914		)
Employee-related expenses	(5,850		)	(4,859		)
Regulatory liabilities	(15,472		)	(11,761		)
Environmental liabilities	(7,002		)	(7,195		)
Derivative financial instruments	(3,397		)	(16,264		)
Other	(1,922		)	(12,202		)
Gross deferred tax assets	(73,701		)	(128,336		)
Net deferred tax liabilities	$	422,645		$	370,616

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 2009.

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, 2013, we have $18,271 of Pennsylvania net operating loss carryforwards that expire through 2029.

During Fiscal 2013, Fiscal 2012 and Fiscal 2011, interest (income) expense of $0, $(209) and $219, respectively, was recognized in income taxes in the Consolidated Statements of Income. As of September 30, 2013, we have unrecognized income tax benefits totaling $1,143 including related accrued interest of $56. If these unrecognized tax benefits were subsequently recognized, $56 would be recorded as a benefit to income taxes on the consolidated statement of income and, therefore, would impact the effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. Included in the balance at September 30, 2013, are $1,087 of tax positions for which the deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, the disallowance of the current deduction would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. There is an expected change in unrecognized tax benefits and related interest in the next twelve months in the amount of $43.

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

Balance at September 30, 2010	$	4,194
Additions for tax positions of the current year	920
Settlements with tax authorities	(216		)
Balance at September 30, 2011	4,898
Additions for tax positions of prior years	81
Settlements with tax authorities	(3,931		)
Balance at September 30, 2012	1,048
Additions for tax positions of prior years	39
Balance at September 30, 2013	$	1,087

In accordance with accounting guidance regarding uncertain tax positions, during Fiscal 2013 and Fiscal 2012, the Company added $39 and $124, respectively, 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 beginning with the tax year ended September 30, 2009. However, because this tax matter relates only to the timing of deductibility, we have recorded an offsetting deferred tax asset of an equal amount. For further information regarding the regulatory impact of this change, see Note 4.

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Other Income, Net (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Component of Other Income, Nonoperating [Line Items]
Other Operating Income	$ 4,828	$ 4,989	$ 10,764
Non-tariff service income [Member]
Component of Other Income, Nonoperating [Line Items]
Total other income, net	2,706	2,653	6,422
Interest income [Member]
Component of Other Income, Nonoperating [Line Items]
Total other income, net	500	572	467
Postretirement benefit plan curtailment gain [Member]
Component of Other Income, Nonoperating [Line Items]
Total other income, net	0	0	3,245
Other [Member]
Component of Other Income, Nonoperating [Line Items]
Total other income, net	$ 1,622	$ 1,764	$ 630

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Regulatory Assets and Liabilities and Regulatory Matters

12 Months Ended

Sep. 30, 2013

Regulated Operations [Abstract]

Regulatory Assets and Liabilities and Regulatory Matters

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:

	2013		2012
Regulatory assets:
Income taxes recoverable	$	106,069	$	103,172
Underfunded pension and postretirement plans	94,515		188,222
Environmental costs	17,054		16,812
Deferred fuel and power costs	8,283		11,602
Removal costs, net	13,333		12,718
Other	5,657		5,879
Total regulatory assets	$	244,911	$	338,405
Regulatory liabilities:
Postretirement benefits	$	16,497	$	13,147
Environmental overcollections	2,552		2,883
Deferred fuel and power refunds	8,283		4,435
State tax benefits — distribution system repairs	8,453		7,385
Other	1,502		494
Total regulatory liabilities	$	37,287	$	28,344

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 deferredtaxes 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 50 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). UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites. PNG and CPG are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2013, 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 delivery service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative financial 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 financial instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at September 30, 2013 and 2012, were $(1,743) and $5,303, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not qualify for the normal purchases and normal sales exception under GAAP related to derivative financial instruments, these 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, 2013 and 2012, the fair values of Electric Utility’s electricity supply contracts were losses of $4,759 and $9,207, respectively, which amounts are reflected in current derivative financial instruments and other noncurrent liabilities on the Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs. FTRs are derivative financial 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. At September 30, 2013 and 2012, such gains or losses were not material.

Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. At September 30, 2013, UGI Utilities expects to recover these costs over periods of 1 to 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 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, 2013, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 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

Allentown, Pennsylvania Natural Gas Incident. On February 19, 2013, the PUC entered a final order (the “Final Order”) settling all regulatory compliance issues pertaining to a natural gas explosion on February 9, 2011, in Allentown, PA. The Final Order requires UGI Utilities to (i) pay a civil penalty in the amount of $500; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

CPG Base Rate Filing. On August 11, 2011, the PUC approved a settlement agreement with CPG that resulted in an increase in annual base rate revenues of $8,000 as well as $900 in revenues per year to fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). The increase became effective August 30, 2011. During Fiscal 2012, the PUC reversed its earlier decision related to the $900 increase in revenue associated with the Energy and Efficiency Conservation Program and required CPG to refund revenue it had collected for that program.

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 right of way located in Delmar Township, Pennsylvania (“TL-96 line”) to 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 on the Fiscal 2013 Consolidated Statement of Stockholder’s Equity.

On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of UGI Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011, the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets transferred was $10,949 which amount, net of related deferred taxes of $308, is reflected as a dividend of net assets on the Fiscal 2011 Consolidated Statement of Stockholder’s Equity. Compliance with the provisions of the PUC Order approving the transfer of the storage assets did not have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.

On December 1, 2010, PNG filed an application with the PUC for expedited review and approval of the transfer of a 9 mile natural gas pipeline, related facilities, and right of way located in Mehoopany, Pennsylvania (the “Auburn Line”) to Energy Services. The PUC approved the transfer and in September 2011 the Auburn Line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the Auburn Line was $1,109 which amount, net of related deferred taxes of $180, is reflected as a dividend of net assets on the Fiscal 2011 Consolidated Statement of Stockholder’s Equity.

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 102,098	$ 87,898	$ 105,196
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	55,716	52,792	52,546
Deferred income taxes, net	35,281	53,247	50,823
Pension expense, net of contributions paid	(4,450)	(17,431)	(6,292)
Provision for uncollectible accounts	9,584	6,286	9,137
Other, net	(1,560)	2,490	(4,526)
Net change in:
Accounts receivable and accrued utility revenues	(16,446)	5,461	(4,583)
Inventories	(22,327)	36,929	14,596
Deferred fuel costs, net of changes in unsettled derivatives	9,321	(8,190)	12,842
Accounts payable	7,511	(6,718)	9,229
Other current assets	13,598	(5,063)	(3,817)
Other current liabilities	(18,413)	2,041	(14,401)
Net cash provided by operating activities	169,913	209,742	220,750
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(151,090)	(114,090)	(98,856)
Net costs of property, plant and equipment disposals	(4,925)	(4,922)	(3,537)
(Increase) decrease in restricted cash	(3,181)	4,308	390
Net cash used by investing activities	(159,196)	(114,704)	(102,003)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(58,975)	(70,615)	(99,490)
Increase (decrease) in bank loans	8,300	9,200	(17,000)
Issuances of long-term debt	175,000	0	0
Repayments of long-term debt	(133,000)	(40,000)	0
Excess tax benefits from equity-based payment arrangements	1,406	369	692
Net cash used by financing activities	(7,269)	(101,046)	(115,798)
Cash and cash equivalents increase (decrease)	3,448	(6,008)	2,949
CASH AND CASH EQUIVALENTS:
End of year	4,707	1,259	7,267
Beginning of year	1,259	7,267	4,318
Increase (decrease)	3,448	(6,008)	2,949
Cash paid for:
Interest	49,460	29,902	39,151
Income taxes	$ 18,376	$ 6,728	$ 13,856

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Income Taxes (Reconciliation from US federal statutory tax rate to UGU effective tax rate) (Details)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate
U.S. federal statutory tax rate	35.00%	35.00%	35.00%
Difference in tax rate due to:
State income taxes, net of federal benefit	5.40%	4.10%	1.60%
Other, net	(0.10%)	(0.60%)	1.00%
Effective tax rate	40.30%	38.50%	37.60%

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Inventories Textuals (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013 ft3	Sep. 30, 2012 ft3	Sep. 30, 2013 SCAAs [Member] Storage_Agreement	Sep. 30, 2013 SCAAs [Member] Expires in October 2012 [Member] Storage_Agreement	Sep. 30, 2013 SCAAs [Member] Expires in October 2013 [Member] Storage_Agreement	Sep. 30, 2013 Other current liabilities [Member] SCAAs [Member]	Sep. 30, 2012 Other current liabilities [Member] SCAAs [Member]	Nov. 01, 2013 New Storage Agreement [Member] SCAAs [Member]	Nov. 01, 2013 New Storage Agreement [Member] SCAAs [Member] UGI Energy Services, Inc. [Member]
Public Utilities, Inventory [Line Items]
Number of storage agreements			3	1	2
Security Deposit Liability						$ 16,500	$ 22,500
Storage agreement, term (in years)								3 years	1 year
Inventory, Net [Abstract]
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)	11,000,000,000	11,400,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates	$ 44,366	$ 32,627

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Debt (Tables)

12 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Composition of Long Term Debt

Long-term debt comprises the following at September 30:

	2013		2012
Term Loan Credit Agreement	$	175,000	$	—
Senior Notes:
6.375%, due September 2013	—		108,000
5.75%, due September 2016	175,000		175,000
6.21%, due September 2036	100,000		100,000
Medium-Term Notes:
5.37%, due August 2013	—		25,000
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		600,000
Less: current maturities	—		(133,000		)
Total long-term debt due after one year	$	642,000	$	467,000

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Commitments and Contingencies (Commitments) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Commitments and Contingencies Disclosure [Abstract]
Aggregate rental expense for leases	$ 6,270	$ 6,362	$ 5,221
Minimum future payments under operating leases
2014	5,518
2015	4,682
2016	4,220
2017	2,684
2018	1,992
After 2018	1,301
Contractual obligations under suplly, storage and service agreements
2014	190,606
2015	105,317
2016	75,903
2017	56,152
2018	44,409
After 2018	$ 114,263

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Employee Retirement Plans (Expected payments for pension benefits and other postretirement welfare benefits) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013
Pension Benefits [Member]
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Fiscal 2013	$ 23,021
Fiscal 2014	24,095
Fiscal 2015	25,238
Fiscal 2016	26,451
Fiscal 2017	27,744
Fiscal 2018 - 2022	155,907
Other Postretirement Benefits [Member]
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Fiscal 2013	1,006
Fiscal 2014	813
Fiscal 2015	769
Fiscal 2016	706
Fiscal 2017	676
Fiscal 2018 - 2022	$ 3,156

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Equity-Based Compensation

12 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity-Based Compensation

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. Under these plans, 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 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 $1,078 ($631 after-tax) during Fiscal 2013; $783 ($458 after-tax) during Fiscal 2012; and $1,110 ($650 after-tax) during Fiscal 2011.

As of September 30, 2013, there was $682 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 2.0 years. As of September 30, 2013, there was a total of $758 of unrecognized compensation expense associated with 61,331 UGI Unit awards that is expected to be recognized over a weighted average period of 1.9 years. At September 30, 2013 and 2012, total liabilities of $360 and $143, respectively, associated with UGI Unit awards are reflected in other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheets.

The following table summarizes UGI Unit award activity for Fiscal 2013:

	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, 2012	68,633		$	29.72	24,130		$	28.78	44,503		$	30.23
Granted	20,800		$	38.27	1,797		$	38.27	19,003		$	38.27
Vested	—		$	—	13,768		$	26.24	(13,768	)	$	26.24
Forfeited	(9,069	)	$	33.65	—		$	—	(9,069	)	$	33.65
Performance criteria not met	(7,679	)	$	22.72	(7,679	)	$	22.72	—		$	—
Unit awards paid	(11,354	)	$	22.72	(11,354	)	$	22.72	—		$	—
September 30, 2013	61,331		$	34.21	20,662		$	33.49	40,669		$	34.57

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Debt

12 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Debt

DEBT

Long-term debt comprises the following at September 30:

	2013		2012
Term Loan Credit Agreement	$	175,000	$	—
Senior Notes:
6.375%, due September 2013	—		108,000
5.75%, due September 2016	175,000		175,000
6.21%, due September 2036	100,000		100,000
Medium-Term Notes:
5.37%, due August 2013	—		25,000
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		600,000
Less: current maturities	—		(133,000		)
Total long-term debt due after one year	$	642,000	$	467,000

Principal payments on long-term debt during the next five fiscal years is as follows: $0 is due in Fiscal 2014; $20,000 is due in Fiscal 2015; $247,000 is due in Fiscal 2016; $20,000 is due in Fiscal 2017; and $40,000 is due in Fiscal 2018. The $175,000 outstanding under the Term Loan Credit Agreement that is expected to be refinanced on a long-term basis prior to its maturity and is excluded from these repayment amounts (see below).

In September 2013, UGI Utilities entered into a 364-day term loan credit agreement (“Term Loan Credit Agreement”) with a bank comprising a $175,000 unsecured term loan facility. The Term Loan Credit Agreement bears interest at the eurodollar rate for the interest period selected, plus a margin of 0.60%. The Term Loan Credit Agreement terminates on September 22, 2014, but UGI Utilities may prepay the loan in whole or in part, without penalty. UGI Utilities borrowed $175,000 on September 30, 2013, under the Term Loan Credit Agreement which cash proceeds were used to repay UGI Utilities’ $108,0006.375% Senior Notes due September 30, 2013, and for other general corporate purposes. On October 30, 2013, UGI Utilities entered into a Note Purchase Agreement which provides for the private placement of $175,000 aggregate principal amount of 4.98% Senior Notes due March 26, 2044. UGI Utilities expects to issue $175,000 face amount of 4.98% Senior Notes in March 2014 and use the net proceeds to repay then-outstanding borrowings under the Term Loan Credit Agreement. Because the Company has the intent and ability to refinance the Term Loan Credit Agreement on a long-term basis, amounts outstanding under the Term Loan Credit Agreement are classified as long-term on the September 30, 2013, Consolidated Balance Sheet.

UGI Utilities has an unsecured credit agreement (the “UGI Utilities 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 UGI Utilities 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 UGI Utilities Credit Agreement, which we classify as bank loans on the Consolidated Balance Sheets, totaling $17,500 and $9,200 at September 30, 2013 and 2012, respectively. The weighted-average interest rates on the UGI Utilities Credit Agreement borrowings at September 30, 2013 and 2012 were 1.18% and 1.21%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the UGI Utilities Credit Agreement, totaled $2,000 at September 30, 2013 and 2012.

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

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Fair Value Measurements (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 43	$ 5,468
Derivative financial instruments, liabilities	(6,677)	(9,437)
Commodity contracts [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	43	5,468
Derivative financial instruments, liabilities	(2,162)	(671)
Commodity contracts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0	0
Derivative financial instruments, liabilities	(4,515)	(8,766)
Commodity contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0	0
Derivative financial instruments, liabilities	0	0
Interest rate contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities		(30,522)
Interest rate contracts [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities		0
Interest rate contracts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities		(30,522)
Interest rate contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities		$ 0

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Disclosures About Derivative Instruments and Hedging Activities

12 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Disclosures About Derivative Instruments and Hedging Activities

DISCLOSURES ABOUT 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.

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, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 15.0 million dekatherms and 19.2 million dekatherms, respectively. At September 30, 2013, the maximum period over which Gas Utility is 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 these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At September 30, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $4,759 and $9,207, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the accompanying Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At September 30, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 245.8 million kilowatt hours and 570.4 million kilowatt hours, respectively. At September 30, 2013, the maximum period over which these contracts extend is 8 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly auctions. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, 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, 2013 and 2012, the volumes associated with Electric Utility FTRs totaled 189.3 million kilowatt hours and 189.7 million kilowatt hours, respectively.

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. The volumes of gasoline under these contracts 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 interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in AOCI, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. As of September 30, 2013 we had no unsettled IRPAs. As of September 30, 2012, the total notional amounts of our unsettled IRPA contracts was $173,000.

UGI Utilities reclassified pre-tax losses of $682 from AOCI into income during Fiscal 2012 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 Consolidated Statements of Income. The amounts of derivative gains and losses on cash flow hedges representing ineffectiveness were not material for all periods presented.

At September 30, 2013, 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 $2,680.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2013, Gas Utility’s restricted cash in brokerage accounts totaled $3,181. At September 30, 2012, Gas Utility had no restricted cash in brokerage accounts.

The following table provides information regarding the balance sheet location and fair values of derivative assets and liabilities existing as of September 30, 2013 and 2012:

	Derivative Assets					Derivative Liabilities
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Interest rate contracts		$	—	$	—	Derivative financial instruments and Other noncurrent liabilities	$	—		$	(30,522	)
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	31		5,303		Derivative financial instruments and Other noncurrent liabilities	(6,677		)	(9,437		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	12		165			—			—
Total Derivatives		$	43	$	5,468		$	(6,677	)	$	(39,959	)

The following table provides information on the effects of derivative instruments on the Consolidated Statements of Income and changes in AOCI for Fiscal 2013 and 2012:

	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013		2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	25,898	$	(11,528	)	$	(805	)	$	(1,847	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain Recognized in Income											Location of Gain Recognized in Income
	2013		2012
Commodity contracts	$	45	$	223								Operating expenses/other income, net

We are also a party to a number of 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.

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Commitments and Contingencies

12 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 $6,270 in Fiscal 2013, $6,362 in Fiscal 2012 and $5,221 in Fiscal 2011.

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: 2014— $5,518; 2015 — $4,682; 2016 — $4,220; 2017 — $2,684; 2018 — $1,992; after 2018 — $1,301.

Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation, natural gas storage and peaking service which Gas Utility may terminate at various dates through 2025. 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 2014.

Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2013, for fiscal years ending September 30 are as follows: 2014 — $190,606; 2015 — $105,317; 2016 — $75,903; 2017 — $56,152; 2018 — $44,409; after 2018 — $114,263.

Contingencies

Environmental Matters

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 $1,800 and $1,100, respectively, in any calendar year. The CPG-COA is currently scheduled to terminate at the end of 2013 and is expected to be renewed prior to its expiration. 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, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14,019 and $14,979, respectively. Because CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites, 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.

The Company 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, 2013, 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 it 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.

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount or range of possible clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012. There have been no recent developments in this matter.

Other Matters

We cannot predict with certainty the final results of any environmental claim or legal action described above. However, it is reasonably possible that such a claim could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, that may be recovered by such a claim or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. In addition to the matter described above, there are other pending claims and legal actions arising in the normal course of our businesses. While the results of these other pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, the final outcome of such other matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

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Document and Entity Information Document (USD $)	12 Months Ended
	Sep. 30, 2013	Nov. 29, 2013	Mar. 31, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	0000100548
Document Type	10-K
Document Period End Date	Sep. 30, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		26,781,785
Entity Public Float			$ 0

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Fair Value Measurements

12 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of September 30, 2013 and 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
September 30, 2013
Assets:
Derivative financial instruments
Commodity contracts	$	43		$	—		$	—	$	43
Liabilities:
Derivative financial instruments
Commodity contracts	$	(2,162	)	$	(4,515	)	$	—	$	(6,677	)
September 30, 2012
Assets:
Derivative financial instruments
Commodity contracts	$	5,468		$	—		$	—	$	5,468
Liabilities:
Derivative financial instruments
Commodity contracts	$	(671	)	$	(8,766	)	$	—	$	(9,437	)
Interest rate contracts	$	—		$	(30,522	)	$	—	$	(30,522	)

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, 2013, were $642,000 and $699,929, respectively. The carrying amount and estimated fair value of our long-term debt (including current maturities) at September 30, 2012, were $600,000 and $700,708, 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).

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Employee Retirement Plans (Fair values of pension plans' assets and VEBA trust assets) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Pension Benefits [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	$ 398,171	$ 351,543	$ 289,764
Pension Benefits [Member] | S&P 500 Index equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	141,774	118,922
Pension Benefits [Member] | Small and Midcap equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	54,528	42,876
Pension Benefits [Member] | UGI Corporation Common Stock [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	32,551	26,445
Pension Benefits [Member] | Domestic [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	228,853	188,243
Pension Benefits [Member] | International [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	44,452	36,908
Pension Benefits [Member] | Bond index mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	120,906	123,332
Pension Benefits [Member] | Cash equivalents [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	3,960	3,060
Pension Benefits [Member] | Fixed income [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	124,866	126,392
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	394,211	348,483
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | S&P 500 Index equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	141,774	118,922
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Small and Midcap equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	54,528	42,876
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | UGI Corporation Common Stock [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	32,551	26,445
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Domestic [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	228,853	188,243
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | International [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	44,452	36,908
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Bond index mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	120,906	123,332
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Cash equivalents [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed income [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	120,906	123,332
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	3,960	3,060
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | S&P 500 Index equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Small and Midcap equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | UGI Corporation Common Stock [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Domestic [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | International [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Bond index mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Cash equivalents [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	3,960	3,060
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed income [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	3,960	3,060
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | S&P 500 Index equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Small and Midcap equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | UGI Corporation Common Stock [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Domestic [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | International [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Bond index mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Cash equivalents [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed income [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
VEBA Trust [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	11,723	11,205
VEBA Trust [Member] | S&P 500 Index equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	7,693	7,678
VEBA Trust [Member] | Bond index mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	3,794	3,366
VEBA Trust [Member] | Cash equivalents [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	236	161
VEBA Trust [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	11,487	11,044
VEBA Trust [Member] | Fair Value, Inputs, Level 1 [Member] | S&P 500 Index equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	7,693	7,678
VEBA Trust [Member] | Fair Value, Inputs, Level 1 [Member] | Bond index mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	3,794	3,366
VEBA Trust [Member] | Fair Value, Inputs, Level 1 [Member] | Cash equivalents [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
VEBA Trust [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	236	161
VEBA Trust [Member] | Fair Value, Inputs, Level 2 [Member] | S&P 500 Index equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
VEBA Trust [Member] | Fair Value, Inputs, Level 2 [Member] | Bond index mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
VEBA Trust [Member] | Fair Value, Inputs, Level 2 [Member] | Cash equivalents [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	236	161
VEBA Trust [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
VEBA Trust [Member] | Fair Value, Inputs, Level 3 [Member] | S&P 500 Index equity mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
VEBA Trust [Member] | Fair Value, Inputs, Level 3 [Member] | Bond index mutual funds [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	0	0
VEBA Trust [Member] | Fair Value, Inputs, Level 3 [Member] | Cash equivalents [Member]
Fair Value of Pension Plan Assets
Fair Value of Plan Assets	$ 0	$ 0

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Employee Retirement Plans (Targets, target ranges and actual allocations for the Company Pension Plans’ and VEBA trust assets) (Details)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual Pension Plan	100.00%	100.00%
Target Asset Allocation	100.00%
Pension Benefits [Member] | Domestic [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual Pension Plan	57.50%	53.50%
Target Asset Allocation	52.50%
Permitted Range - Minimum	40.00%
Permitted Range - Maximum	65.00%
Pension Benefits [Member] | International [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual Pension Plan	11.10%	10.50%
Target Asset Allocation	12.50%
Permitted Range - Minimum	7.50%
Permitted Range - Maximum	17.50%
Pension Benefits [Member] | Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual Pension Plan	68.60%	64.00%
Target Asset Allocation	65.00%
Permitted Range - Minimum	60.00%
Permitted Range - Maximum	70.00%
Pension Benefits [Member] | Fixed income funds and cash equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual Pension Plan	31.40%	36.00%
Target Asset Allocation	35.00%
Permitted Range - Minimum	30.00%
Permitted Range - Maximum	40.00%
VEBA Trust [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual Pension Plan	100.00%	100.00%
Target Asset Allocation	100.00%
VEBA Trust [Member] | Domestic [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual Pension Plan	65.60%	68.50%
Target Asset Allocation	65.00%
Permitted Range - Minimum	60.00%
Permitted Range - Maximum	70.00%
VEBA Trust [Member] | Fixed income funds and cash equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual Pension Plan	34.40%	31.50%
Target Asset Allocation	35.00%
Permitted Range - Minimum	30.00%
Permitted Range - Maximum	40.00%