Ugi Utilities 10K 2011 Annual report

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, 2011

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 þ No ¨

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 14, 2011, there were 26,781,785 shares of UGI Utilities, Inc. Common Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI Corporation.

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

TABLE OF CONTENTS



	Page

Forward-Looking Information	3

PART I:

Items 1. and 2. Business and Properties	4

Item 1A. Risk Factors	9

Item 1B. Unresolved Staff Comments	11

Item 3. Legal Proceedings	11

PART II:

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

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	23

Item 8. Financial Statements and Supplementary Data	23

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	23

Item 9A. Controls and Procedures	23

Item 9B. Other Information	24

PART III:

Item 14. Principal Accounting Fees and Services	24

PART IV:

Item 15. Exhibits and Financial Statement Schedules	24

Signatures	29

Index to Financial Statements and Financial Statement Schedules	F- 1

Exhibit 12.1
Exhibit 23
Exhibit 31.1
Exhibit 31.2
Exhibit 32

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,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

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

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

PART I:

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

GENERAL

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

The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of UGI Utilities, UGI Penn Natural Gas, Inc. (“PNG”), and UGI Central Penn Gas, Inc. (“CPG”). Gas Utility serves approximately 575,000 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;” PNG's natural gas distribution utility is referred to as “PNG Gas;” and CPG's natural gas distribution utility is referred to as “CPG 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 2011” and “Fiscal 2010” refer to the fiscal years ended September 30, 2011 and September 30, 2010, respectively.

GAS UTILITY

Service Area; Revenue Analysis

Gas Utility is authorized to distribute natural gas to approximately 575,000 customers in portions of 46 eastern and central Pennsylvania counties through its distribution system of approximately 12,200 miles of gas mains. 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 2011 was approximately 173 billion cubic feet (“bcf”). System sales of gas accounted for approximately 35% of system throughput, while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for approximately 65% 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 5 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 Corporation, Transcontinental Gas Pipeline Corporation, Dominion Transmission, ANR Pipeline and Tennessee Gas Pipeline.

Gas Supply Contracts

During Fiscal 2011, Gas Utility purchased approximately 97.5 bcf of natural gas for sale to core-market customers (principally comprised of firm- residential, commercial and industrial customers who 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 25 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 sales are seasonal. Approximately 60% to 65% of Gas Utility's sales volume is supplied, and approximately 85% to 90% of Gas Utility's operating income is earned, during a typical 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 fuel utilization equipment. Due to the expiration of rate caps for electric utilities serving a significant portion of Gas Utility's service territory, natural gas generally benefits from a competitive price advantage over electricity. However, high efficiency electric heat pumps have led to a decrease in the cost of heating with electricity. Government subsidies currently favor ground source heat pumps over fossil fueled systems. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility responds to this competition with marketing efforts designed to retain 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 which 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 which afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. The majority of customers in this group are served under transportation contracts having 3 to 20 year terms. Included in these two customer groups are 27 customers, most of which are among the 10 largest customers for Gas Utility in terms of annual volumes. All of these customers have contracts, 24 of which extend beyond the 2012 fiscal year. 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 and sources of supply available to it to meet the full requirements of all firm customers on its system through fiscal year 2012. 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 2011, Gas Utility supplied transportation service to 2 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 the residential market sector, Gas Utility connected approximately 10,500 residential heating customers during Fiscal 2011. Approximately 5,500 of these customers, an increase of 34% from Fiscal 2010, converted to natural gas from other energy sources, mainly oil and electricity, largely due to the volatility of oil prices and the elimination of electricity rate caps during Fiscal 2011. 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 2011.

UGI Utilities continues to monitor and participate, where appropriate, in rulemaking and individual rate and tariff proceedings before FERC affecting the rates and the terms and conditions under which Gas Utility transports and stores natural gas. Among these proceedings are those arising out of certain FERC orders and/or pipeline filings which 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 approximately 2,100 miles of transmission and distribution lines and 13 transmission substations. For Fiscal 2011, 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 5 to Consolidated Financial Statements. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers. During Fiscal 2011, 4 electric generation suppliers provided energy for customers representing approximately 20% 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. Electric Utility remains the “default service” provider for its customers who do not choose an alternate electric generation supplier. In Fiscal 2011, 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 costs other than purchased gas costs (“PGCs”) and electric default service costs; and (2) rates designed to recover PGCs and electric default service costs. Rates designed to recover costs other than PGCs and electric default service costs are primarily established in general base rate proceedings. Rates designed to recover PGCs and electric default service costs are established in PGC and electric default service rate proceedings.

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.

Gas Utility Rates

Rates that Gas Utility may charge for gas service come in two forms: 1) rates designed to recover costs other than PGCs; and 2) rates designed to recover PGCs. Rates designed to recover costs other than PGCs are primarily established in general base rate proceedings. Rates designed to recover PGCs are reviewed in PGC rate proceedings. The most recent general base rate increase for UGI Gas became effective in 1995. In accordance with a statutory mechanism, a rate increase for Gas Utility's 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.

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 August 27, 2009, the PUC approved PNG's and CPG's base rate case settlement agreements, which resulted in a $19.75 million base rate operating revenue increase for PNG and a $10 million base rate operating revenue increase for CPG. These increases became effective on 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 which meet that standard. The PGC mechanism also provides for an annual reconciliation.

UGI Gas has two PGC rates: (1) PGC is applicable to small, firm, retail core-market customers consisting of the residential and small commercial and industrial classes; and (2) PGC is applicable to firm, contractual, high-load factor customers served on three separate rates. PNG and CPG each have one PGC rate applicable to all customers.

Electric Utility Rates

The most recent general base rate increase for Electric Utility became effective in 1996. Electric Utility's rates were unbundled into distribution, transmission and generation (POLR or “default service”) components in 1998. In accordance with the POLR Settlements, Electric Utility increased POLR rates annually from 2005 through 2009.

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 approval from the PUC of (1) default service tariff rules applicable for service rendered on or after January 1, 2010, (2) a reconcilable default service cost rate recovery mechanism to recover the cost of acquiring default service supplies for service rendered on or after January 1, 2010, (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 on or after January 1, 2010. Under these rules, default service rates for most customers will be adjusted quarterly.

FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers

Both Gas Utility and Electric Utility are subject to FERC regulations governing the manner in which certain jurisdictional sales or transportation are conducted. Section 4A of the Natural Gas Act and Section 222 of the Federal Power Act 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. FERC has adopted regulations to implement these statutory provisions which apply to interstate transportation and sales by the Electric Utility, and to a much more limited extent, to certain sales and transportation by the Gas Utility that are subject to FERC's jurisdiction. Gas Utility and Electric Utility are subject to certain other regulations and obligations for FERC-regulated activities. 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, PNG and CPG each hold certificates 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 each of them believes are adequate to authorize them to carry on their business in substantially all of the territories to which they now render gas or electric service. Under applicable Pennsylvania law, UGI Utilities, PNG and CPG also have certain rights of eminent domain as well as the right to maintain their facilities in streets and highways in their 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 13 to Consolidated Financial Statements.

Employees

At September 30, 2011, 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 2011, 2010 and 2009 fiscal years appears in Note 16 to Consolidated Financial Statements included in this Report and is incorporated herein by reference.

ITEM 1A. RISK FACTORS

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

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

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

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

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

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

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

The economic recession, decline in the stock market and the low interest rate environment have had a significant impact on our pension liability and funded status. Additional declines in the stock market and valuation of stocks, 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 negative effect on our liquidity.

Depending on the terms of our contracts with suppliers as well as our use of financial instruments including natural gas futures 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 an increased liquidity risk.

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

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

Our need to comply with comprehensive, complex, and sometimes unpredictable government 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 which 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 PNG and CPG will periodically file requests with the PUC to increase base rates that they charge customers. If we are required in a rate proceeding to reduce the rates we charge our utility customers, or if we are unable to obtain approval for timely rate increases from the PUC, particularly when necessary to cover increased costs, our revenue growth will be limited and earnings may decrease.

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

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

As a result of recent natural gas explosions in the United States, including the Company’s February 9, 2011 natural gas explosion in Allentown, Pennsylvania, 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.

On February 9, 2011, a natural gas explosion occurred in Allentown, Pennsylvania which resulted in five deaths, several personal injuries and significant property damage. The PUC is investigating the Allentown accident and we are cooperating with that investigation. Based on a visual inspection, we identified a fracture in a segment of our cast iron natural gas pipeline in the area of the accident. The affected segment of pipeline is undergoing forensic testing by an expert, independent laboratory; however, the cause of the fracture has not yet been determined. We are unable to predict the outcome of the PUC’s investigation, including whether the Company will be found to have violated any law, regulation, PUC order or decision in connection with the Allentown accident.

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

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

There continues to be concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global climate change. 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. In September 2009, the Environmental Protection Agency (“EPA”) issued a final rule establishing a system for mandatory reporting of GHG emissions. In November 2010, the EPA expanded the reach of its GHG reporting requirements to include the petroleum and natural gas industries. Petroleum and natural gas facilities subject to the rule, which include facilities of our natural gas distribution business, were required to begin emissions monitoring in January 2011 and to submit detailed annual reports beginning in March 2012. The rule does not require affected facilities to implement GHG emission controls or reductions.

It is expected that climate change legislation will continue to be part of the legislative and regulatory discussion in the future. The impact of legislation and regulations on us will depend on a number of factors, including (i) what industry sectors would be impacted, (ii) the timing of required compliance, (iii) the overall GHG emissions cap level, (iv) the allocation of emission allowances to specific sources and (v) the costs and opportunities associated with compliance. At this time, we cannot predict the effect that climate change regulation may have on our business, financial condition or results of operations in the future.

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

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


•	the discovery of presently unknown conditions;


•	changes in environmental laws and regulations;


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


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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

For information regarding legal proceedings, including environmental matters, see Note 13 to Consolidated Financial Statements.

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 $99.5 million in Fiscal 2011, $74.0 million in Fiscal 2010, and $61.2 million in Fiscal 2009.

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

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

EXECUTIVE OVERVIEW

Our net income in Fiscal 2011 was $105.2 million, an increase of 16.6% from Fiscal 2010 net income of $90.3 million. The greater net income reflects colder heating-season weather which increased core market volumes and total margin at our Gas Utility. At our Electric Utility, the effects of the colder heating-season weather on kilowatt-hour sales was more than offset by the effects of the absence of margin from electricity sales beginning January 1, 2010 when Electric Utility's default service ("DS") rates became effective. Under DS rates, there is limited power cost risk but Electric Utility no longer records margin from DS electricity sales. Results in Fiscal 2011 also benefited from the regulatory effects of greater state tax depreciation on income taxes (see "Income Tax Matters" below).

Looking ahead, our results in Fiscal 2012 will be influenced by a number of factors including temperatures during the peak heating-season months, the economy's effects on customer growth from new construction and conversion activity and ongoing customer conservation. Fiscal 2012 results will also reflect the full-year's impact of the CPG base rate increase that became effective on August 30, 2011 (see “Regulatory Matters” below).

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

ANALYSIS OF RESULTS OF OPERATIONS

The following results of operations covers Fiscal 2011, Fiscal 2010 and the year ended September 30, 2009 (“Fiscal 2009”).

Fiscal 2011 Compared with Fiscal 2010



							Increase
(Millions of dollars)	2011			2010			(Decrease)
Gas Utility:
Revenues	$	1,026.4		$	1,047.5		$	(21.1	)	(2.0	)%
Total margin (a)	$	415.8		$	394.1		$	21.7		5.5	%
Operating income	$	199.6		$	175.3		$	24.3		13.9	%
Income before income taxes	$	159.3		$	134.8		$	24.5		18.2	%
System throughput — bcf	173.2			153.9			19.3			12.5	%
Degree days — % colder (warmer) than normal (b)	3.5		%	(5.3		)%	—			—
Electric Utility:
Revenues	$	109.1		$	120.2		$	(11.1	)	(9.2	)%
Total margin (a)	$	35.1		$	36.5		$	(1.4	)	(3.8	)%
Operating income	$	11.4		$	13.7		$	(2.3	)	(16.8	)%
Income before income taxes	$	9.0		$	11.9		$	(2.9	)	(24.4	)%
Distribution sales — gwh	994.7			972.6			22.1			2.3	%

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 $6.1 million and $6.6 million during Fiscal 2011 and Fiscal 2010, 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 based upon heating degree days were 3.5% colder than normal in Fiscal 2011 compared with temperatures that were 5.3% warmer than normal in Fiscal 2010. Total distribution system throughput increased 19.3 bcf reflecting higher throughput to certain low-margin interruptible delivery service customers, the effects of the colder weather on core-market and delivery service customers and, to a lesser extent, customer growth from conversion activity. Gas Utility's core-market customers are comprised of firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.

Gas Utility revenues in Fiscal 2011 were lower than in the prior year principally reflecting a decline in revenues from core- market customers ($33.4 million) partially offset by a $14.7 million increase in revenues from low-margin off-system sales. The decrease in core market revenues principally resulted from lower average retail core market PGC rates reflecting lower natural gas prices ($83.5 million) offset by the effects of the higher throughput. Increases or decreases in retail core-market revenues and cost of sales principally result from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility's cost of gas was $610.6 million in Fiscal 2011 compared with $653.4 million in Fiscal 2010 principally reflecting the lower average PGC rates offset in part by an increase in retail core-market sales.

Gas Utility total margin increased $21.7 million in Fiscal 2011. The increase is largely the result of a $21.8 million increase

in core market margin reflecting the increase in core market throughput.

Gas Utility operating income and income before income taxes in Fiscal 2011 increased $24.3 million and $24.5 million, respectively, principally the result of the previously mentioned increase in total margin ($21.7 million) and higher other income ($4.7 million) including a $3.2 million postretirement benefit plan curtailment gain. These increases were partially offset by slightly higher operating and administrative expenses including higher pension expense.

Electric Utility. Electric Utility's kilowatt-hour sales in Fiscal 2011 were 2.3% higher than in Fiscal 2010 on heating degree day weather that was 7.8% colder. Notwithstanding the effects of the colder weather, Electric Utility revenues decreased $11.1 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service and, to a much lesser extent, lower average default service (“DS”) rates compared to the provider of last resort (“POLR”) rates that were in effect through December 31, 2009. Under DS rates, Electric Utility is no longer subject to electricity price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility no longer recovers revenues in excess of actual costs of electricity as was possible under POLR rates and therefore does not earn margin on DS electricity sales. Electric Utility cost of sales declined to $67.9 million in Fiscal 2011 compared to $77.1 million in Fiscal 2010 principally reflecting the effects of the previously mentioned electricity generation supplier customer switching and lower DS rates.

Electric Utility total margin declined $1.4 million in Fiscal 2011, notwithstanding the greater sales, principally reflecting the absence of margin from sales of electricity beginning January 1, 2010.

Electric Utility Fiscal 2011 operating income and income before income taxes declined $2.3 million and $2.9 million, respectively, principally reflecting the previously mentioned lower total margin, higher operating and maintenance expenses and, with respect to income before income taxes, higher allocated interest expense.

Consolidated Interest Expense and Income Taxes. Our consolidated interest expense in Fiscal 2011 was about equal to interest expense in Fiscal 2010. Our effective tax rate in Fiscal 2011 was lower than in Fiscal 2010 principally reflecting the regulatory effects of greater state tax depreciation (as further described below under “Income Tax Matters”).

Fiscal 2010 Compared with Fiscal 2009



							Increase
(Millions of dollars)	2010			2009			(Decrease)
Gas Utility:
Revenues	$	1,047.5		$	1,241.0		$	(193.5	)	(15.6	)%
Total margin (a)	$	394.1		$	387.8		$	6.3		1.6	%
Operating income	$	175.3		$	153.5		$	21.8		14.2	%
Income before income taxes	$	134.8		$	111.3		$	23.5		21.1	%
System throughput — bcf	153.9			149.7			4.2			2.8	%
Degree days —% colder (warmer) than normal (b)	(5.3		)%	4.1		%	—			—
Electric Utility:
Revenues	$	120.2		$	138.5		$	(18.3	)	(13.2	)%
Total margin (a)	$	36.5		$	39.3		$	(2.8	)	(7.1	)%
Operating income	$	13.7		$	15.4		$	(1.7	)	(11.0	)%
Income before income taxes	$	11.9		$	13.7		$	(1.8	)	(13.1	)%
Distribution sales — gwh	972.6			965.7			6.9			0.7	%

(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 $6.6 million in Fiscal 2010 and $7.6 million in Fiscal 2009. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” on the Consolidated Statements of Income.


(b)	Deviation from average heating degree days for the 15-year period 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 based upon heating degree days were 5.3% warmer than normal in Fiscal 2010 compared with temperatures that were 4.1% colder than normal in Fiscal 2009. Total distribution system throughput increased 4.2 bcf in Fiscal 2010, despite the warmer weather, principally reflecting an 8.5 bcf increase in low margin interruptible

delivery service volumes. Gas Utility's core market volumes decreased 6.2 bcf (9.0%) due to the previously mentioned warmer weather and to a lesser extent the sluggish economy and customer conservation.

Gas Utility revenues decreased $193.5 million during Fiscal 2010 principally reflecting a decline in revenues from retail core-market customers ($232.3 million) partially offset by a $29.4 million increase in revenues from low-margin off-system sales. The decrease in retail core-market revenues principally resulted from the effects of lower average PGC rates ($135.0 million) and the lower retail core-market volumes ($125.5 million). These decreases in revenues were partially offset by the effects of the PNG Gas and CPG Gas base operating revenue increases that became effective August 28, 2009. Gas Utility's cost of gas was $653.4 million in Fiscal 2010 compared with $853.2 million in Fiscal 2009 principally reflecting the previously mentioned lower retail core-market sales and average PGC rates ($227.8 million) due to lower natural gas commodity prices.

Notwithstanding the decrease in distribution system volumes, Gas Utility total margin increased $6.3 million in Fiscal 2010. The increase is principally the result of the PNG Gas and CPG Gas base operating revenue increases ($28.2 million) substantially offset by the effect on total margin from the lower core-market volumes.

Gas Utility operating income in Fiscal 2010 increased $21.8 million principally reflecting lower operating and administrative costs ($15.6 million) and the previously mentioned increase in total margin ($6.3 million). Fiscal 2010 operating and administrative costs include, among other things, lower uncollectible accounts and customer assistance expenses ($11.5 million), and lower costs associated with environmental matters ($6.6 million). These decreases were partially offset by higher depreciation expense ($2.2 million) and higher pension expense ($2.1 million). The increase in income before income taxes reflects the previously mentioned higher operating income ($21.8 million) and lower interest expense ($1.6 million) due to lower average bank loan borrowings.

Electric Utility. Temperatures based upon heating degree days in Fiscal 2010 were approximately 6.8% warmer than in Fiscal 2009. The impact on kilowatt-hour sales from the warmer heating-season weather was more than offset by higher air-conditioning related sales from significantly warmer 2010 late spring and summer weather.

Electric Utility revenues decreased $18.3 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity supply portion of their service and, to a lesser extent, lower DS rates effective January 1, 2010. Electric Utility decreased its DS rates effective January 1, 2010 pursuant to a January 22, 2009 settlement of its DS rate filing with the PUC. This reduced average costs to a residential general and residential heating customer by nearly 10% and 4%, respectively, over such costs in Fiscal 2009 and also reduced rates to commercial and industrial customers. Under DS rates, Electric Utility is no longer subject to electric generation price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under previous POLR rates in effect prior to January 1, 2010. Electric Utility cost of sales declined to $77.1 million in Fiscal 2010 compared to $91.6 million in Fiscal 2009 principally reflecting the effects of the previously mentioned generation supplier customer switching and lower purchased power costs. For additional information on Electric Utility DS and POLR service, see Note 5 to Consolidated Financial Statements.

Electric Utility total margin declined $2.8 million in Fiscal 2010 principally reflecting the reduction in margin resulting from the implementation of lower DS rates effective January 1, 2010.

Electric Utility operating income and income before income taxes in Fiscal 2010 were $1.7 million and $1.8 million lower, respectively, than in Fiscal 2009 reflecting the lower total margin ($2.8 million) partially offset by lower operating and administrative expenses ($1.1 million).

Consolidated Interest Expense and Income Taxes. Our consolidated interest expense in Fiscal 2010 was lower than in Fiscal 2009 reflecting lower interest on bank loan borrowings. Our annual estimated effective tax rate in Fiscal 2010 was slightly higher than in Fiscal 2009.

FINANCIAL CONDITION AND LIQUIDITY

Capitalization and Liquidity

UGI Utilities' total debt outstanding was $640 million at September 30, 2011 compared with total debt outstanding of $657 million at September 30, 2010 which included $17 million of bank loan outstanding under UGI Utilities revolving credit agreement. UGI Utilities' total debt outstanding at September 30, 2011 comprises $383 million of Senior Notes and $257 million of Medium-Term Notes.

On May 25, 2011, UGI Utilities entered into an unsecured, revolving credit agreement (the “2011 Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350 million revolving credit agreement dated as of August 11, 2006. The 2011 Credit Agreement expires in May 2012 but may be extended to October 2015 if the Company satisfies certain requirements relating to approval by the PUC. Borrowings under the UGI Utilities 2011 Credit Agreement are classified as bank loans. During Fiscal 2011 and Fiscal 2010, average daily bank loan borrowings under revolving credit agreements were $17.6 million and $69.9 million, respectively, and peak bank loan borrowings totaled $90 million and $203 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 greatest. The 2011 Credit Agreement requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. UGI Utilities was in compliance with this covenant at September 30, 2011.

Based upon cash expected to be generated from operations and borrowings under the 2011 Credit Agreement, management believes the Company will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2011. For additional discussion of UGI Utilities' long-term debt and the 2011 Credit Agreement, see Note 8 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 strongest 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 revolving credit agreement borrowings to manage its seasonal cash flow needs.

Cash provided by operating activities was $220.8 million in Fiscal 2011, $291.6 million in Fiscal 2010 and $176.4 million in Fiscal 2009. Cash provided by operating activities before changes in operating working capital was $206.8 million in Fiscal 2011, $235.0 million in Fiscal 2010 and $187.1 million in Fiscal 2009. The lower cash flow before changes in operating working capital in Fiscal 2011 compared to Fiscal 2010, notwithstanding the increase in net income, includes, among other things, greater funded pension plan contributions and lower noncash charges for deferred income taxes included in the calculation of net income. The greater cash flow before changes in operating working capital in Fiscal 2010 compared to Fiscal 2009 reflects the improved Fiscal 2010 results and greater noncash charges for deferred taxes included in the calculation of net income due in large part to a change in the tax method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets (see “Income Tax Matters” below and Note 9 to Consolidated Financial statements). Changes in operating working capital provided $13.9 million of cash in Fiscal 2011, provided $56.6 million of cash in Fiscal 2010 and used $10.7 million of cash in Fiscal 2009. Among other things, the lower cash flow from changes in operating working capital in Fiscal 2011 compared with Fiscal 2010 reflects lower cash from changes in natural gas inventories partially offset by greater cash from deferred fuel recoveries. The significantly higher cash flow provided by changes in operating working capital in Fiscal 2010 as compared with Fiscal 2009 principally reflects significantly less cash needed to fund purchases of natural gas inventories due to lower natural gas commodity prices.

Investing activities. Cash used by investing activities was $102.0 million in Fiscal 2011, $90.3 million in Fiscal 2010, and $310.4 million in Fiscal 2009. Expenditures for property, plant and equipment increased to $98.9 million in Fiscal 2011 compared with $81.6 million in Fiscal 2010 principally reflecting higher UGI Gas capital expenditures for infrastructure improvements and customer growth. Fiscal 2009 cash flow from investing activities includes net cash used for the acquisition of CPG. It also includes net cash proceeds from the concurrent sale of the assets of Penn Fuel Propane, CPG's wholly owned subsidiary, to AmeriGas OLP. Fiscal 2011 investing activities cash flow includes a $0.4 million increase in restricted cash in futures and options accounts compared to a $4.7 million decrease in Fiscal 2010 and a $34.0 million increase of in Fiscal 2009. Changes in restricted cash in futures brokerage accounts are generally the result of changes in underlying commodity prices.

Financing activities. Cash (used) provided by financing activities was $(115.8) million in Fiscal 2011, $(210.5) million in Fiscal 2010 and $144.1 million in Fiscal 2009. 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 2011, net bank loan repayments totaled $17 million compared to net repayments of $137 million in Fiscal 2010 and net bank loan borrowings of $97 million in Fiscal 2009. The significantly higher net cash from bank loan borrowings in Fiscal 2009 was due in large part to the timing and use of cash contributions made by UGI in September 2008 to fund the CPG Acquisition on October 1, 2008. During Fiscal 2009, we issued $108 million of 6.375% Senior Notes due 2013 and used the proceeds to fund a portion of the acquisition of CPG.

Capital Expenditures

In the following table, we present capital expenditures by business segment for Fiscal 2011, Fiscal 2010 and Fiscal 2009. We also provide amounts we expect to spend in Fiscal 2012. We expect to finance a substantial portion of Fiscal 2012 capital expenditures from cash generated by operations and the remainder from borrowings under our 2011 Credit Agreement.



(Millions of dollars)	2012		2011		2010		2009
	(estimate)
Gas Utility	$	89.1	$	91.4	$	73.5	$	73.8
Electric Utility	5.9		7.5		8.1		5.3
	$	95.0	$	98.9	$	81.6	$	79.1

Contractual Cash Obligations and Commitments

UGI Utilities has contractual cash obligations that extend beyond Fiscal 2011, including scheduled repayments of long-term debt and interest, operating lease obligations, unconditional purchase obligations for pipeline transportation and natural gas storage services, and commitments to purchase natural gas and electricity. The following table presents significant contractual cash obligations under agreements existing as of September 30, 2011:



	Payments Due by Period
			Fiscal		Fiscal		Fiscal
(Millions of dollars)	Total		2012		2013 - 2014		2015 - 2016		Thereafter
Long-term debt (a)	$	640.0	$	40.0	$	133.0	$	267.0	$	200.0
Interest on long-term fixed rate debt (b)	328.6		38.2		64.1		53.1		173.2
Operating leases	18.8		4.8		7.4		4.4		2.2
Gas Utility and Electric Utility supply, storage and transportation contracts	673.9		241.9		203.5		93.2		135.3
Total	$	1,661.3	$	324.9	$	408.0	$	417.7	$	510.7


(a)	Based upon stated maturity dates.


(b)	Based upon stated interest rates.

The components of the other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2011 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 2012 of approximately $27.6 million. Contributions to the our pension plan in years beyond Fiscal 2012 will depend in large part on future returns on pension plan assets.

For additional information on these liabilities see Notes 10 and 13 to Consolidated Financial Statements.

Pension Plans

Effective December 31, 2010, UGI Utilities merged its two defined benefit pension plans 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 surviving plan after the merger, and the two plans prior to the merger, are hereafter referred to as the “Company Pension Plans”).

The fair values of the Company Pension Plans' assets totaled $289.8 million and $287.9 million at September 30, 2011 and 2010, respectively. At September 30, 2011 and 2010, the underfunded positions of the Pension Plans, defined as the excess of the projected benefit obligations (“PBOs”) over the Company Pension Plans' assets, were $167.0 million and $177.1 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 Company Pension Plans during Fiscal 2012 of approximately $27.6 million. Pre-tax pension cost associated with Pension Plans in Fiscal 2011 was $12.4 million. Pre-tax pension cost associated with Company Pension Plans in Fiscal 2012 is expected to be approximately $13.7 million.

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, 2011, we have recorded cumulative after-tax charges to stockholder's equity of $8.4 million and regulatory assets of $150.7 million in order to reflect the funded status of our pension and postretirement benefit plans. For a more detailed discussion of the Pension Plans and other postretirement benefit plans, see Note 10 to Consolidated Financial Statements.

Income Tax Matters

In 2010, U.S. federal tax legislation was enacted that allows 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. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers are 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 2011 effective tax rate reflects the beneficial effects of this greater state tax depreciation. The additional state and federal tax depreciation deductions described above reduces federal and state income taxes otherwise payable and increases UGI Utilities deferred income tax liabilities.

The Company received Internal Revenue Service (“IRS”) consent to change its tax method of accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. The filing of the Company's Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30.2 million which were used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities' Fiscal 2009 stand alone Pennsylvania income tax return also produced a $43.4 million state net operating loss (“NOL”) carryforward. Under current Pennsylvania state income tax law, the NOL stated above can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded. For more information on the change in tax method of accounting, see Note 9 to Consolidated Financial Statements.

REGULATORY MATTERS

PNG and CPG Base Rate Filings. On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 million annually. Among other things, the increased revenues would 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”). On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. On August 11, 2011, the PUC approved the settlement agreement which resulted in an increase in annual base rate revenues of $8.0 million as well as $0.9 million in revenues per year for use in CPG's Energy and Efficiency Conservation Program. The increase became effective August 30, 2011, and did not have a material effect on Fiscal 2011 results.

On January 28, 2009, PNG and CPG filed separate requests with the PUC to increase base operating revenues by $38.1 million annually for PNG and $19.6 million annually for CPG to fund system improvements and operations necessary to maintain safe and reliable natural gas service and energy assistance for low income customers as well as energy conservation programs for all customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on agreements with the opposing parties regarding the requested base operating revenue increases. On August 27, 2009, the PUC approved the settlement agreements which resulted in a $19.8 million increase in annual base operating revenue for PNG Gas and a $10.0 million increase in annual base operating revenue for CPG Gas. The increases became effective August 28, 2009 and did not have a material effect on Fiscal 2009 results.

Electric Utility Default Service Rates. Beginning January 1, 2010, Electric Utility operates under a DS rate mechanism approved by the PUC that allows for full recovery of all DS costs incurred on and after January 1, 2010. Prior to January 1, 2010, the terms and conditions under which Electric Utility provided provider of last resort (“POLR”) service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006. In accordance with the POLR, Electric Utility could increase its POLR rates up to certain limits through December 31, 2009.

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 is not expected to 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 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 terminates 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, 2011 and 2010, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $17.9 million and $21.4 million, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs, and (2) CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At September 30, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

UGI Utilities has been notified of several 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 are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating three claims against it relating to out-of-state sites.

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 sites outside of Pennsylvania currently subject to third-party claims or litigation, see Note 13 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, principally payroll-related services. Amounts billed to these entities by UGI Utilities for all periods presented were not material.

From time to time, UGI Utilities is a party to Storage Contract Administration Agreements ("SCAAs") with Energy Services. At September 30, 2011, UGI Utilities was a party to two three-year SCAAs with Energy Services expiring October 31, 2012 and October 31, 2013 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 $35.2 million, $21.8 million and $55.8 million in Fiscal 2011, Fiscal 2010 and Fiscal 2009, 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, was $15.0 million and $7.5 million at September 30, 2011 and 2010, respectively.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at September 30, 2011, comprising approximately 7.5 bcf feet of natural gas, was $35.7 million. The carrying value of these gas storage inventories at September 30, 2010, comprising approximately 4.1 bcf of natural gas, was $20.7 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 2011, Fiscal 2010 and Fiscal 2009 totaled $30.1 million, $25.9 million and $24.4 million, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2011, Fiscal 2010 and Fiscal 2009, revenues associated with sales to Energy Services totaled $85.7 million, $62.1 million and $30.9 million, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to those transactions already described above) and beginning April 1, 2011, purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under a one-year agreement. During Fiscal 2011, Fiscal 2010 and Fiscal 2009, such purchases totaled $53.6 million, $31.2 million and $17.3 million, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

On October 1, 2008, in conjunction with the CPG Acquisition, CPG’s wholly owned subsidiary CPP sold its assets to AmeriGas OLP, an affiliate of UGI. See Note 4 for additional information regarding this transaction.

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. 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, 2011 and 2010, Gas Utility had $4.3 million and $4.7 million of restricted cash associated with natural gas futures accounts with brokers, respectively. At September 30, 2011 and 2010, the fair values of our natural gas futures and option contracts were losses of $3.1 million and $1.4 million, respectively.

Electric Utility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs through the application of DS rates. Because of this ratemaking mechanism, beginning January 1, 2010 there is limited power cost risk associated with our Electric Utility operations.

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, 2011 and 2010 were not material.

Interest Rate Risk

Our variable-rate debt comprises borrowings under our Revolving 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 2011 and Fiscal 2010, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.2 million and $0.7 million, respectively.

Our long-term debt is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we expect to refinance such debt with new debt having interest rates reflecting then-current market conditions. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of $40.1 million and $50.7 million at September 30, 2011 and 2010, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $45.5 million and $57.7 million at September 30, 2011 and 2010, 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. The fair value of unsettled IRPAs held at September 30, 2011 was $18.6 million. There were no unsettled interest rate protection agreements outstanding as of September 30, 2010.

Our unsettled derivative instruments at September 30, 2011 comprise (1) Gas Utility's exchange-traded natural gas futures and options contracts, which are included in Gas Utility's PGC recovery mechanism; (2) Electric Utility's FTRs and electricity forward contracts, which are included in Electric Utility's DS recovery mechanism; (3) exchange-traded gasoline futures and swap contracts; and IRPAs.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements and related disclosures in compliance with GAAP requires the selection and application of accounting principles appropriate to the relevant facts and circumstances of the Company's operations and the use of estimates made by management. The Company has identified the following critical accounting policies and estimates that are most important to the portrayal of the Company's financial condition and results of operations. 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.

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.

Impairment of Goodwill. Our allocation of the purchase price of acquisitions has resulted in the Company recording goodwill. In accordance with GAAP, a reporting unit with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, management must determine the reporting unit's fair value using quoted market prices or, in the absence of quoted market prices, valuation techniques which use discounted estimates of future cash flows to be generated by the reporting unit. These cash flow estimates involve management judgments based on a broad range of information and historical results. 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. As of September 30, 2011, our goodwill totaled $182.1 million. We did not record any impairments of goodwill during Fiscal 2011, Fiscal 2010 or Fiscal 2009. The Company will adopt new accounting guidance regarding goodwill impairment in Fiscal 2012 (see Note 3 to Consolidated Financial Statements).

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 Gas and CPG Gas 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, 2011, UGI Utilities net property, plant and equipment totaled $1,418.4 million and we recorded depreciation expense of $49.9 million during Fiscal 2011.

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, 2011, our regulatory assets totaled $300.5 million. For additional information on our regulatory assets, see Note 5 to the Consolidated Financial Statements.

Pension Plan Assumptions. The costs of providing benefits under the Company Pension Plans 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 Company Pension Plans 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 Company Pension Plans assets of 50 basis points to a rate of 7.5% would result in an increase in pre-tax pension cost of approximately $1.4 million in Fiscal 2012. A decrease in the discount rate of 50 basis points to a rate of 4.8% would result in an increase in pre-tax pension cost of approximately $2.5 million in Fiscal 2012.

NEWLY ADOPTED AND RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

See Note 3 to Consolidated Financial Statements for a discussion of the effects of accounting guidance we adopted in Fiscal 2011 and recently issued accounting pronouncements not yet adopted.

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 is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, of the Company's internal control over financial reporting using the criteria in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”).

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

Based on its assessment, management has concluded that the Company's internal control over financial reporting was effective as of September 30, 2011, based on the COSO Framework. 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, 2011, 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 2011 and Fiscal 2010 were as follows:



	2011		2010
Audit Fees	$	758,500	$	739,800
Audit-Related Fees	-0-		-0-
Tax Fees	-0-		-0-
All Other Fees	-0-		-0-
Total Fees for Services Provided	$	758,500	$	739,800

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:


(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, 2011 and 2010

Consolidated Statements of Income for the fiscal years ended September 30, 2011, 2010 and 2009

Consolidated Statements of Comprehensive Income for the years ended September 30, 2011, 2010 and 2009

Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2011, 2010 and 2009

Consolidated Statements of Stockholder’s Equity for the fiscal years ended September 30, 2011, 2010 and 2009

Notes to Consolidated Financial Statements


(2)	Financial Statement Schedule:

For the years ended September 30, 2011, 2010 and 2009

II — Valuation and Qualifying Accounts

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


(3)	List of Exhibits:

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

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit
3.1	UGI Utilities' Amended and Restated Articles of Incorporation	Utilities	Registration Statement No. 333-72540 (10/31/01)	3
3.2	Bylaws of UGI Utilities as amended through September 30, 2003	Utilities	Form 10-K (9/30/03)	3.2
4	Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of its long-term debt not required to be filed pursuant to the description of Exhibit 4 contained in Item 601 of Regulation S-K)
4.1	UGI Utilities' Articles of Incorporation and Bylaws referred to in Exhibit Nos. 3.1 and 3.2	UGI	Form 8-B/A (4/17/96)	3.(4)
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

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 January 1, 2009	UGI	Form 10-K (9/30/09)	10.2

10.3**	UGI Corporation 1997 Stock Option and Dividend Equivalent Plan Amended and Restated as of May 24, 2005	UGI	Form 10-K (9/30/10)	10.7

10.4**	UGI Corporation 2000 Stock Incentive Plan Amended and Restated as of May 24, 2005	UGI	Form 10-K (9/30/06)	10.14

10.5**	UGI Corporation 2009 Deferral Plan Amended and Restated Effective June 1, 2010	UGI	Form 10-Q (6/30/10)	10.1

10.6**	UGI Corporation Senior Executive Employee Severance Plan as in effect as of January 1, 2008	UGI	Form 10-Q (3/31/08)	10.1

10.7**	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

10.8**	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

10.9**	UGI Corporation 2009 Supplemental Executive Retirement Plan For New Employees As Amended and Restated as of October 1, 2010	UGI	Form 10-Q (12/31/09)	10.2

10.10**	UGI Utilities, Inc. Senior Executive Employee Severance Plan as in effect as of November 1, 2008	Utilities	Form 10-K (9/30/10)	10.10

10.11**	UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for UGI Employees, dated January 1, 2009	UGI	Form 10-Q (3/31/09)	10.8

10.12**	UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for Utilities Employees, dated January 1, 2009	UGI	Form 10-K (9/30/09)	10.23

10.13**	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2011	UGI	Form 10-K (9/30/11)	10.3

10.14**	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Utilities Employees, dated January 1, 2011	UGI	Form 10-K (9/30/11)	10.3

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.15**	UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Employees, dated January 1, 2009	UGI	Form 10-Q (3/31/09)	10.1

10.16**	UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for Utilities Employees, dated January 1, 2011	UGI	Form 10-K (9/30/11)	10.3

10.17**	Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Messrs. Greenberg and Walsh	UGI	Form 10-Q (6/30/08)	10.3

10.18**	UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006	UGI	Form 10-K (9/30/07)	10.8

10.19**	UGI Utilities, Inc. Executive Annual Bonus Plan effective as of October 1, 2006	Utilities	Form 10-K (9/30/07)	10.5

10.20	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
—
10.21	Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, Inc. effective as of May 1, 2007	Utilities	Form 10-Q (6/30/10)	10.1

10.22	Amendment No. 1 dated November 1, 2004, to the Service Agreement (Rate FSS) dated as of November 1, 1989 between UGI Utilities and Columbia, as modified pursuant to the orders of the Federal Energy Regulatory Commission at Docket No. RS92-5-000 reported at Columbia Gas Transmission Corp., 64 FERC ¶61,060 (1993), order on rehearing, 64 FERC ¶61,365 (1993)	UGI	Form 10-K (9/30/10)	10.6

10.23	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

10.24	SST Service Agreement No. 79133 dated November 1, 2004 between Columbia Gas Transmission Corporation and UGI Utilities, Inc.	Utilities	Form 10-Q (6/30/10)	10.2

10.25	FTS-1 Service Agreement No. 46283 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 between Columbia Gulf Transmission Company and UGI Utilities, Inc.	Utilities	Form 10-Q (3/31/11)	10.10

Incorporation by Reference



Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.26	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

10.27	Amendment to FTS-1 Service Agreement No. 46283 and FTS Service Agreement No. 46284 each dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 dated November 1, 1993	Utilities	Form 10-Q (3/31/11)	10.3

*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, 2011 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, 2011 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, 2011, 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 Lables Linkbase
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase



*	Filed herewith.

**	As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement.
***	XBRL information will be considered to be furnished, not filed, for the first two years of a company's submission of XBRL information.

SIGNATURES

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



		UGI UTILITIES, INC.
Date:	November 21, 2011	By:	/s/ Donald E. Brown
			Donald E. Brown
			Vice President — Finance and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 21, 2011 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/ Stephen D. Ban		Director
Stephen D. Ban

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

/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 2011.

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

*XBRL information will be considered to be furnished, not filed, for the first two years of a company's submission of XBRL information.

UGI UTILITIES, INC.

FINANCIAL INFORMATION

FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K

YEAR ENDED SEPTEMBER 30, 2011

UGI UTILITIES, INC.

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE



		Pages

Financial Statements:

Report of Independent Registered Public Accounting Firm		F- 2

Consolidated Balance Sheets as of September 30, 2011 and 2010		F- 3

Consolidated Statements of Income for the years ended September 30, 2011, 2010 and 2009		F- 5

Consolidated Statements of Comprehensive Income for the years ended September 30, 2011, 2010 and 2009		F- 6

Consolidated Statements of Cash Flows for the years ended September 30, 2011, 2010 and 2009		F- 7

Consolidated Statements of Stockholder’s Equity for the years ended September 30, 2011, 2010 and 2009		F- 8

Notes to Consolidated Financial Statements		F- 9 to F- 33

Financial Statement Schedule:

For the years ended September 30, 2011, 2010 and 2009:

II — Valuation and Qualifying Accounts		S- 1

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

F- 1

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, stockholder's equity and cash flows present fairly, in all material respects, the financial position of UGI Utilities, Inc., and its subsidiaries at September 30, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2011 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) present 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, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

November 21, 2011

F- 2

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)



	September 30,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	7,267		$	4,318
Restricted cash	4,308			4,698
Accounts receivable (less allowances for doubtful accounts of $6,368 and $7,072, respectively)	58,736			64,844
Accounts receivable — related parties	7,048			6,313
Accrued utility revenues	14,807			13,988
Inventories	104,263			118,858
Deferred income taxes	42,528			19,431
Income taxes recoverable	9,430			11,814
Regulatory assets	8,608			26,100
Derivative financial instruments	68			486
Prepaid expenses & other current assets	15,481			9,303
Total current assets	272,544			280,153
Property, plant and equipment	2,201,021			2,129,324
Less accumulated depreciation and amortization	(782,665		)	(747,354		)
Net property, plant and equipment	1,418,356			1,381,970
Goodwill	182,145			180,145
Regulatory assets	291,847			293,217
Other assets	4,456			4,091
Total assets	$	2,169,348		$	2,139,576
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	40,000		$	—
Bank loans	—			17,000
Accounts payable — trade	53,556			61,297
Accounts payable — related parties	10,108			8,144
Employee compensation and benefits accrued	12,770			12,268
Interest accrued	12,319			11,051
Customer deposits and refunds	54,127			57,465
Derivative financial instruments	11,928			10,564
Deferred fuel refunds	6,578			8,295
Pension and postretirement benefit obligations	28,228			20,303
Other current liabilities	33,405			32,848
Total current liabilities	263,019			239,235
Long-term debt	600,000			640,000
Deferred income taxes	361,468			281,101
Deferred investment tax credits	4,958			5,311
Pension and postretirement benefit obligations	142,248			161,338
Other noncurrent liabilities	78,810			78,137

F- 3



Total liabilities	1,450,503			1,405,122
Commitments and contingencies (note 13)
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	468,323			467,631
Retained earnings	212,096			217,960
Accumulated other comprehensive loss	(21,833		)	(11,396		)
Total common stockholder’s equity	718,845			734,454
Total liabilities and stockholder’s equity	$	2,169,348		$	2,139,576

See accompanying notes to consolidated financial statements.

F- 4

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of dollars)



	Year Ended September 30,
	2011			2010			2009
Revenues	$	1,137,366		$	1,169,539		$	1,381,260
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	678,500			730,502			944,793
Operating and administrative expenses	176,922			169,464			191,263
Operating and administrative expenses — related parties	12,125			14,209			14,964
Taxes other than income taxes	16,616			18,638			16,917
Depreciation	49,917			50,747			48,873
Amortization	2,629			2,729			2,239
Other income, net	(10,764		)	(6,269		)	(7,261		)
	925,945			980,020			1,211,788
Operating income	211,421			189,519			169,472
Interest expense	42,728			42,336			43,918
Income before income taxes	168,693			147,183			125,554
Income taxes	63,497			56,925			46,832
Net income	$	105,196		$	90,258		$	78,722

See accompanying notes to consolidated financial statements.

F- 5

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)



	Year Ended September 30,
	2011			2010			2009
Net income	$	105,196		$	90,258		$	78,722
Net change in fair value of derivative instruments (net of tax of $7,711)	(10,874		)	—			—
Reclassifications of net losses on derivative instruments (net of tax of $(483))	681			681			681
Benefit plans, (net of tax of $479, $11,134 and $29,978, respectively)	(674		)	(15,699		)	(42,270		)
Reclassification of benefit plans actuarial losses and prior service costs (net of tax of $(304), $(2,414) and $(1,617), respectively) to net income	430			3,406			2,281
Reclassification of pension plans actuarial losses and prior service costs (net of tax of $(59,078)) to regulatory assets	—			83,302			—
Comprehensive income	$	94,759		$	161,948		$	39,414

See accompanying notes to consolidated financial statements.

F- 6

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)



	Year Ended September 30,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	105,196		$	90,258		$	78,722
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	52,546			53,476			51,112
Deferred income taxes, net	50,905			63,654			17,530
Pension expense, net of contributions paid	(6,292		)	6,698			7,124
Provision for uncollectible accounts	9,137			10,651			19,193
Other, net	(4,608		)	10,257			13,456
Net change in:
Accounts receivable and accrued utility revenues	(4,583		)	2,847			(15,133		)
Inventories	14,596			77,740			(12,742		)
Deferred fuel costs, net of changes in unsettled derivatives	12,842			(18,500		)	10,272
Accounts payable	9,229			7,424			(19,437		)
Storage agreement security deposits	—			3,500			19,000
Other current assets	(3,817		)	(15,511		)	(1,072		)
Other current liabilities	(14,401		)	(889		)	8,389
Net cash provided by operating activities	220,750			291,605			176,414
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(98,856		)	(81,595		)	(79,084		)
Net costs of property, plant and equipment disposals	(3,537		)	(3,980		)	(5,114		)
Acquisitions of businesses, net of cash acquired	—			—			(292,551		)
Proceeds from sale of CPP	—			—			32,269
Decrease (increase) in restricted cash	390			(4,698		)	34,037
Net cash used by investing activities	(102,003		)	(90,273		)	(310,443		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(99,490		)	(74,008		)	(61,211		)
(Decrease) increase in bank loans	(17,000		)	(137,000		)	97,000
Issuances of long-term debt	—			—			108,000
Excess tax benefits from equity-based payment arrangements	692			471			280
Net cash (used) provided by financing activities	(115,798		)	(210,537		)	144,069
Cash and cash equivalents increase (decrease)	$	2,949		$	(9,205	)	$	10,040
CASH AND CASH EQUIVALENTS:
End of year	$	7,267		$	4,318		$	13,523
Beginning of year	4,318			13,523			3,483
Increase (decrease)	$	2,949		$	(9,205	)	$	10,040
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for:
Interest	$	39,151		$	39,917		$	40,452
Income taxes	$	13,856		$	6,217		$	26,919

See accompanying notes to consolidated financial statements.

F- 7

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(Thousands of dollars)



	Year Ended September 30,
	2011			2010			2009
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	$	217,960		$	201,710		$	184,201
Net income	105,196			90,258			78,722
Cash dividends — Common Stock	(99,490		)	(74,008		)	(61,221		)
Dividends of net assets	(11,570		)	—			—
Other	—			—			8
Balance, end of year	$	212,096		$	217,960		$	201,710

Additional paid-in capital
Balance, beginning of year	$	467,631		$	467,160		$	466,888
Excess tax benefits on equity-based compensation	692			471			272
Balance, end of year	$	468,323		$	467,631		$	467,160

Accumulated other comprehensive income (loss)
Balance, beginning of year	$	(11,396	)	$	(83,086	)	$	(43,778	)
Net change in fair value of derivative instruments	(10,874		)	—			—
Reclassifications of net losses on derivative instruments	681			681			681
Benefit plans, principally actuarial losses	(674		)	(15,699		)	(42,270		)
Reclassifications of benefit plans actuarial losses and prior service costs	430			3,406			2,281
Reclassifications of pension plans actuarial losses and prior service costs to regulatory asset	—			83,302			—
Balance, end of year	$	(21,833	)	$	(11,396	)	$	(83,086	)

Total UGI Utilities, Inc. common stockholder's equity	$	718,845		$	734,454		$	646,043

See accompanying notes to consolidated financial statements.

F- 8

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;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas 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 Gas 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.

Certain prior-year amounts have been reclassified to conform to the current-year presentation. At September 30, 2011, removal costs of depreciable plant and equipment, net of salvage, have been reclassified from accumulated depreciation to regulatory assets on the Consolidated Balance Sheet. Corresponding prior-year amounts have been reclassified (See Note 5).

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 5.

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

F- 9

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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, 2011 or 2010.

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 14 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 15.

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,

F- 10

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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.

Comprehensive Income

The components of AOCI at September 30, 2011 and 2010 follow:



	Postretirement Benefit Plans			Derivative Instruments Net Losses			Total
September 30, 2011	$	(8,377	)	$	(13,456	)	$	(21,833	)
September 30, 2010	$	(8,133	)	$	(3,263	)	$	(11,396	)

Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive (loss) income of $(10,473), $71,690 and $(39,308) for Fiscal 2011, Fiscal 2010 and Fiscal 2009, respectively, 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 in Fiscal 2010 also includes the reclassification of $83,302 of accumulated other comprehensive losses associated with UGI Utilities’ pension plan, principally actuarial losses, to regulatory assets and deferred income taxes as a result of an August 2010 PUC order regarding regulatory treatment of the pension plan’s funded status (see Note 5). Other comprehensive income (loss) for all periods presented also includes reclassifications of net losses on previously settled 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 and option brokerage accounts which are restricted from withdrawal.

UGI Utilities enters into financial transactions to hedge its cost of gas sold to customers. These transactions are conducted pursuant to an approved risk management plan through an account held at MF Global Inc. (“MF Global”). On October 31, 2011, MF Global filed for Chapter 11 bankruptcy and, in conjunction with the automatic stay, the Chicago Mercantile Exchange froze all MF Global-related accounts. As a result of an emergency order entered by the bankruptcy court, the Company's customer segregated margin account and a portion of its cash was transferred to a new broker. The amount of cash currently frozen at MF Global is not material. At this time, the Company is unable to predict the ultimate impact of the bankruptcy, including any regulatory recovery related to any potential losses we may incur.

F- 11

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 2011, 2.5% in Fiscal 2010 and 2.4% in Fiscal 2009. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.6% in Fiscal 2011, 2.6% in Fiscal 2010, and 2.9% in Fiscal 2009. 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. Goodwill is subject to tests for impairment at least annually. We perform goodwill impairment tests more frequently than annually if events or circumstances indicate that the value of goodwill might be impaired. When performing our impairment tests, we use discounted estimates of future cash flows. No provisions for goodwill impairments were recorded during Fiscal 2011, Fiscal 2010 or Fiscal 2009.

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 2011, Fiscal 2010 or Fiscal 2009.

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 10).

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 12.

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

F- 12

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. For further information, see Note 13.

3. ACCOUNTING CHANGES

Adoption of New Accounting Standards

Presentation of Comprehensive Income. In June 2011, the FASB issued Accounting Standards Update ("ASU") 2011-05, “Presentation of Comprehensive Income,” which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) Topic 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. ASU 2011-05 does not change the items that must be reported in other comprehensive income. Additionally, reclassification adjustments between net income and comprehensive income must be shown on the face of the financial statements. On October 21, 2011, the FASB decided to propose a deferral of the new requirement to present reclassification adjustments on the face of the income statement. The change in presentation is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011 with full retrospective application required. Early adoption is permitted. We applied the provisions of the new guidance effective September 30, 2011 (except for the presentation of reclassification adjustments on the face of the statement of net income,) and report the components of comprehensive income in two separate but consecutive statements as permitted by the new guidance.

Business Combinations. Effective October 1, 2009, we adopted new guidance on accounting for business combinations. The new guidance applies to all transactions or other events in which an entity obtains control of one or more businesses. The new guidance establishes, among other things, principles and requirements for how the acquirer (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in a business combination or gain from a bargain purchase; and (3) determines what information with respect to a business combination should be disclosed. The new guidance applies prospectively to business combinations for which the acquisition date is on or after October 1, 2009. Among the more significant changes in accounting for acquisitions are (1) transaction costs are generally expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, are generally recorded at fair value with subsequent adjustments recognized in operations (rather than as adjustments to the purchase price); and (3) decreases in valuation allowances on acquired deferred tax assets are recognized in operations (rather than as decreases in goodwill). The new guidance did not have an impact on our financial statements.

New Accounting Standards Not Yet Adopted

Goodwill Impairment. In September 2011, the FASB issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. The more-likely-than-not threshold is deemed as having a likelihood of more than 50 percent. Previous guidance required an entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance, an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test goodwill annually for impairment. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted. We will adopt the new guidance

F- 13

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

in Fiscal 2012.

Fair Value Measurements. In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments in ASU 2011-04 result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders' equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance is effective for our interim period ending March 31, 2012 and is required to be applied prospectively. We do not expect it will have a material impact on our results of operations or financial condition.

4. ACQUISITION OF PPL GAS UTILITIES CORPORATION

On October 1, 2008, UGI Utilities acquired all of the outstanding stock of PPL Gas Utilities Corporation (now CPG), the natural gas distribution utility of PPL Corporation (“PPL”), for cash consideration of $267,600 plus estimated working capital of $35,370 (the “CPG Acquisition”). Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary, Penn Fuel Propane, LLC (now named UGI Central Penn Propane, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas Propane, L.P. (“AmeriGas OLP”), an affiliate of UGI, for cash consideration of $32,000 plus estimated working capital of $1,621. CPG distributes natural gas to approximately 76,000 customers in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. CPP sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition at closing with a combination of $120,000 cash contributed by UGI on September 25, 2008, proceeds from the issuance on October 1, 2008 of $108,000 principal amount of 6.375% Senior Notes due 2013 and approximately $75,000 of credit agreement borrowings. UGI Utilities used the $33,621 of cash proceeds from the sale of the assets of CPP to AmeriGas OLP to reduce its revolving credit agreement borrowings.

The assets and liabilities resulting from the CPG Acquisition which reflect the final purchase price allocation are included in our Consolidated Balance Sheets at September 30, 2011 and 2010. Pursuant to the CPG Acquisition purchase agreement, the purchase price was subject to adjustment for the difference between the estimated working capital of $35,370 and the actual working capital as of the closing date agreed to by both UGI Utilities and PPL. During Fiscal 2009, UGI Utilities and PPL reached an agreement on the working capital adjustment pursuant to which PPL paid UGI Utilities $9,738 in cash, including interest. Also during Fiscal 2009, UGI Utilities and AmeriGas OLP reached an agreement on the working capital adjustment associated with UGI Utilities’ sale of the assets of CPP to AmeriGas OLP pursuant to which UGI Utilities reimbursed AmeriGas OLP $1,352.

The purchase price of the CPG Acquisition, including transaction fees and expenses and incurred liabilities totaling approximately $2,300, has been allocated to the assets acquired and liabilities assumed as follows:



Current assets less current liabilities	$	22,065
Property, plant and equipment	227,301
Goodwill	18,419
Utility regulatory assets	22,466
Other assets	7,412
Noncurrent liabilities	(34,383		)
Total	$	263,280

The primary item that results in goodwill is the synergies between CPG Gas and our existing utility businesses. Substantially all of the goodwill is deductible for income tax purposes over a fifteen-year period. The operating results of CPG are included in our consolidated results beginning October 1, 2008.

5. REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS

The following regulatory assets and liabilities associated with Utilities are included in our accompanying balance sheets at September 30:

F- 14

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)



	2011		2010
Regulatory assets:
Income taxes recoverable	$	97,947	$	82,525
Underfunded pension and postretirement plans	150,669		159,154
Environmental costs	19,547		22,587
Deferred fuel and power costs	12,163		36,597
Removal costs, net	12,313		12,615
Other	7,816		5,839
Total regulatory assets	$	300,455	$	319,317
Regulatory liabilities:
Postretirement benefits	$	11,476	$	10,472
Environmental overcollections	4,758		7,211
Deferred fuel and power refunds	6,578		8,298
State tax benefits — distribution system repairs	6,282		6,685
Other	736		—
Total regulatory liabilities	$	29,830	$	32,666

Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 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 is 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 represents 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 Gas and PNG Gas expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 13). 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 Gas and CPG Gas are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2011, the period over which PNG Gas and CPG Gas expect to recover these costs will depend upon future remediation activity.

Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and, commencing January 1, 2010, Electric Utility’s default service (“DS”) tariffs (as further described below under “Electric Utility DS Rates”), 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 DS rates 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 losses on such contracts at September 30, 2011 and 2010 were $3,081 and $1,359, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially

F- 15

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility's electricity supply contracts are required to be recorded 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, 2011 and 2010, the fair values of Electric Utility's electricity supply contracts were losses of $8,655 and $19,702, 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 financial transmission rights (“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 commencing January 1, 2010, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power costs or deferred fuel and power refunds. At September 30, 2011 and 2010, 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, 2011, 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.

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. As described in Note 9 below, the Company received IRS consent to change its tax method of accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of these repair and maintenance expenses which expenses 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, 2011, 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

PNG and CPG Base Rate Filings. On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16,500 annually. Among other things, the increased revenues would 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”). On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. On August 11, 2011, the PUC approved the settlement agreement which resulted in an increase in annual base rate revenues of $8,000 as well as $900 in revenues per year for use in CPG's Energy and Efficiency Conservation Program. The increase became effective August 30, 2011 and did not have a material effect on Fiscal 2011 results.

On January 28, 2009, PNG and CPG filed separate requests with the PUC to increase base operating revenues by $38,100 annually for PNG and $19,600 annually for CPG to fund system improvements and operations necessary to maintain safe and

F- 16

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

reliable natural gas service and energy assistance for low income customers as well as energy conservation programs for all customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on agreements with the opposing parties regarding the requested base operating revenue increases. On August 27, 2009, the PUC approved the settlement agreements which resulted in a $19,800 increase in annual base operating revenue for PNG Gas and a $10,000 increase in annual base operating revenue for CPG Gas. The increases became effective August 28, 2009 and did not have a material effect on Fiscal 2009 results.

Electric Utility DS Rates. Prior to January 1, 2010, the terms and conditions under which Electric Utility provided provider of last resort (“POLR”) service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006. In accordance with the POLR Settlement, Electric Utility could increase its POLR rates up to certain limits through December 31, 2009. Beginning January 1, 2010, Electric Utility operates under a DS rate mechanism approved by the PUC that allows for full recovery of all DS costs incurred on and after January 1, 2010.

Transfers of Assets. 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 is not expected to 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 9.0 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.

6. INVENTORIES

Inventories comprise the following at September 30:



	2011		2010
Gas Utility natural gas	$	95,590	$	111,531
Materials, supplies and other	8,673		7,327
Total inventories	$	104,263	$	118,858

At September 30, 2011, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013. Pursuant to these and predecessor 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 receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above. The carrying value of gas storage inventories released under the SCAAs at September 30, 2011 and 2010 comprising 11.5 billion cubic feet (“bcf”) and 12.1 bcf of natural gas was $54,658 and $62,653, respectively.

7. PROPERTY, PLANT AND EQUIPMENT

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

F- 17

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)



	2011		2010
Distribution	$	1,951,889	$	1,865,980
Transmission	83,419		78,190
General and other, including construction in process	165,713		185,154
Total property, plant and equipment	$	2,201,021	$	2,129,324

8. DEBT

Long-term debt comprises the following at September 30:



	2011			2010
Senior Notes:
6.375%, due September 2013	$	108,000		$	108,000
5.75%, due September 2016	175,000			175,000
6.21%, due September 2036	100,000			100,000
Medium-Term Notes:
5.53%, due September 2012	40,000			40,000
5.37%, due August 2013	25,000			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	640,000			640,000
Less: current maturities	(40,000		)	—
Total long-term debt due after one year	$	600,000		$	640,000

Principal payments on long-term debt during the next five fiscal years is as follows: $40,000 is due in Fiscal 2012; $133,000 is due in Fiscal 2013; $0 is due in Fiscal 2014; $20,000 is due in Fiscal 2015; and $247,000 is due in Fiscal 2016.

On May 25, 2011, UGI Utilities entered into an unsecured, revolving credit agreement (the “UGI Utilities 2011 Credit Agreement”) with a group of banks providing for borrowings up to $300,000 (including a $100,000 sublimit for letters of credit) which expires in May 2012 but may be extended to October 2015 if the Company satisfies certain requirements relating to approval by the PUC. Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350,000 revolving credit agreement dated as of August 11, 2006. Under the UGI Utilities 2011 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 its credit agreements, which we classify as bank loans, totaling $17,000 at September 30, 2010. There were no amounts outstanding under its credit agreement at September 30, 2011. The weighted-average interest rates on UGI Utilities' revolving credit agreements borrowings at September 30, 2010 was 3.25%. Issued and outstanding letters of credit, which reduce available borrowings under the UGI Utilities 2011 Credit Agreement, totaled $2,000 at September 30, 2011.

The UGI Utilities 2011 Revolving Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.

F- 18

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

9. INCOME TAXES

The provisions for income taxes consist of the following:



	2011			2010			2009
Current expense:
Federal	$	10,447		$	(8,577	)	$	19,302
State	2,227			1,848			10,000
Total current expense (benefit)	12,674			(6,729		)	29,302
Deferred expense	51,174			64,022			17,898
Investment tax credit amortization	(351		)	(368		)	(368		)
Total income tax expense	$	63,497		$	56,925		$	46,832

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



	2011		2010		2009
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Difference in tax rate due to:
State income taxes, net of federal	1.6		4.3		3.6
Other, net	1.0		(0.6	)	(1.3	)
Effective tax rate	37.6	%	38.7	%	37.3	%

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



	2011			2010
Excess book basis over tax basis of property, plant and equipment	$	293,457		$	248,153
Goodwill	22,446			17,962
Regulatory assets	124,669			127,262
Other	487			1,856
Gross deferred tax liabilities	441,059			395,233
Pension plan liabilities	(62,818		)	(76,103		)
Allowance for doubtful accounts	(2,642		)	(2,934		)
Deferred investment tax credits	(2,057		)	(2,203		)
Employee-related expenses	(8,032		)	(8,771		)
Regulatory liabilities	(12,378		)	(13,336		)
Environmental liabilities	(7,749		)	(7,040		)
Derivative financial instruments	(11,931		)	(5,195		)
Other	(14,512		)	(17,981		)
Gross deferred tax assets	(122,119		)	(133,563		)
Net deferred tax liabilities	$	318,940		$	261,670

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 2008. UGI’s federal income tax return for Fiscal 2009 is currently under audit. Although it is not possible to predict with certainty the timing of the conclusion of UGI’s pending federal tax audit, we anticipate that the Internal Revenue Service’s (“IRS’s”) audit of UGI’s Fiscal 2009 U.S. federal income tax return will likely be completed during Fiscal 2012.

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.

During Fiscal 2011 and 2010, interest income of $219 and $25, respectively, was recognized in income taxes in the

F- 19

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

Consolidated Statements of Income. As of September 30, 2011, we have unrecognized income tax benefits totaling $5,163 including related accrued interest of $265. If these unrecognized tax benefits were subsequently recognized, $211 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, 2011 are $4,837 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. The amount of reasonably possible changes in unrecognized tax benefits and related interest in the next twelve months is a net reduction of approximately $3,391.

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



Balance at September 30, 2008	$	945
Additions for tax positions of the current year	63
Additions for tax positions of prior years	197
Settlements with tax authorities	(571		)
Balance at September 30, 2009	634
Additions for tax positions of the current year	3,907
Additions for tax positions of prior years	9
Settlements with tax authorities	(331		)
Decreases for tax positions related to prior years	(25		)
Balance at September 30, 2010	4,194
Additions for tax positions of the current year	920
Settlements with tax authorities	(216		)
September 30, 2011	$	4,898

The Company received IRS consent to change its tax 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. The filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30,200 which was used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 Pennsylvania income tax return also produced a $43,393 state net operating loss (“NOL”) carryforward. Under current Pennsylvania state income tax law, the NOL can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. As of September 30, 2011, a state net operating loss carryforward of $29,256 remains. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded. The Company’s determination of what constitutes a capital cost versus ordinary expense as it relates to the new tax method will likely be reviewed upon audit by the IRS and may be subject to subsequent adjustment. Accordingly, the status of this tax return position is uncertain at this time. In accordance with accounting guidance regarding uncertain tax positions, during Fiscal 2011 and Fiscal 2010 the Company has added $1,195 and $3,907, respectively, to its liability for unrecognized tax benefits including interest related to this tax method. However, because this tax matter relates only to the timing of tax 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 5.

In 2010, U.S. federal tax legislation was enacted that allows 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. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers are 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 2011 effective tax rate reflects the beneficial effects of this greater state tax depreciation.

10. 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all active and retired employees.

Effective December 31, 2010, we merged our then-existing two defined benefit pension plans ("Pension Plan Merger"). As a result of the Pension Plan Merger and in accordance with GAAP relating to accounting for retirement benefits, the Company remeasured the combined plan's assets and benefit obligations as of December 31, 2010, which decreased pension and postretirement obligations by $46,672; decreased associated regulatory assets by $43,150; and increased pre-tax other comprehensive income by $3,522. The Company's pension plans prior to the Pension Plan Merger, and the Pension Plan after the Pension Plan Merger, are hereafter referred to as the "Company Pension Plans.”

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Company Pension Plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets and the funded status of the Company Pension Plans and other postretirement plans as of September 30, 2011 and 2010. 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
	2011			2010			2011			2010
Change in benefit obligations:
Benefit obligations — beginning of year	$	464,977		$	422,041		$	15,140		$	14,610
Service cost	8,151			8,122			217			186
Interest cost	23,815			23,161			701			772
Actuarial (gain) loss	(20,772		)	29,667			(1,516		)	720
Plan amendments	—			—			(126		)	—
Benefits paid	(19,457		)	(18,014		)	(1,083		)	(1,148		)
Benefit obligations — end of year	$	456,714		$	464,977		$	13,333		$	15,140
Change in plan assets:
Fair value of plan assets — beginning of year	$	287,902		$	276,438		$	10,007		$	9,714
Actual gain on assets	2,601			26,125			149			723
Employer contributions	18,718			3,353			732			718
Benefits paid	(19,457		)	(18,014		)	(1,083		)	(1,148		)
Fair value of plan assets — end of year	$	289,764		$	287,902		$	9,805		$	10,007
Funded status of the plans — end of year	$	(166,950	)	$	(177,075	)	$	(3,528	)	$	(5,133	)
(Liabilities) recorded in the balance sheet:
Unfunded liabilities — included in other current liabilities	$	(27,600	)	$	(20,303	)	$	(628	)	$	—
Unfunded liabilities — included in other noncurrent liabilities	(139,350		)	(156,772		)	(2,898		)	(5,133		)
Net amount recognized	$	(166,950	)	$	(177,075	)	$	(3,526	)	$	(5,133	)
Amounts recorded in stockholder’s equity (pre-tax):
Prior service cost (credit)	$	174		$	24		$	(91	)	$	55
Net actuarial loss (gain)	14,452			13,640			(168		)	192
Total	$	14,626		$	13,664		$	(259	)	$	247
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	$	1,775		$	271		$	(3,188	)	$	(3,420	)
Net actuarial loss	146,899			155,585			6,294			5,915
Total	$	148,674		$	155,856		$	3,106		$	2,495

In Fiscal 2012, we estimate that we will amortize approximately $8,900 of net actuarial losses and $200 of prior service credits from stockholder’s equity and regulatory assets.

Actuarial assumptions are described below. The discount rates at September 30 are used to measure the year-end benefit

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

obligations and the earnings effects for the subsequent year. 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 Plans								Other Postretirement Benefits
Weighted-average assumptions:	2011 (a)		2010		2009		2008		2011		2010		2009		2008
Discount rate	5.3	%	5.0	%	5.5	%	6.8	%	5.3	%	5.0	%	5.5	%	6.8	%
Expected return on plan assets	8.0	%	8.5	%	8.5	%	8.5	%	5.5	%	5.5	%	5.5	%	5.5	%
Rate of increase in salary levels	3.5	%	3.8	%	3.8	%	3.8	%	3.5	%	3.8	%	3.8	%	3.8	%

(a) The discount rate used during Fiscal 2011 to calculate pension expense was a rate of 5.0% through December 31, 2010 (the date of the Utilities Plan Merger) and a rate of 5.5% thereafter.

The ABOs for the Company Pension Plans were $414,985 and $413,814 as of September 30, 2011 and 2010, respectively. Included in the end of year PBOs above are $40,908 at September 30, 2011 and $43,550 at September 30, 2010 relating to employees of UGI and certain of its other subsidiaries. Included in the end of year other postretirement plans ABOs above are $675 at September 30, 2011 and $666 at September 30, 2010 relating to employees of UGI and certain of its other subsidiaries.

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



	Pension Benefits									Other Postretirement Benefits
	2011			2010			2009			2011			2010			2009
Service cost	$	7,176		$	6,980		$	5,975		$	202		$	175		$	131
Interest cost	22,047			21,137			21,326			678			752			820
Expected return on assets	(23,937		)	(23,433		)	(23,794		)	(523		)	(508		)	(523		)
Curtailment gain	—			—			—			(3,245		)	—			—
Amortization of:
Prior service cost (benefit)	302			36			29			(694		)	(406		)	(410		)
Actuarial loss	6,838			5,331			3,588			427			231			88
Net benefit cost (income)	12,426			10,051			7,124			(3,155		)	244			106
Change in associated regulatory liabilities	—			—			—			3,138			3,137			3,271
Benefit cost (income) after change in regulatory liabilities	$	12,426		$	10,051		$	7,124		$	(17	)	$	3,381		$	3,377

Company Pension Plans' assets are held in trust. It is our general policy to fund amounts for pension 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 2011 and 2010, we made contributions to the Company Pension Plans of $18,718 and $3,353, respectively. We did not make any contributions to the Company Pension Plans in Fiscal 2009. We believe that in Fiscal 2012 we will be required to make contributions to the Company Pension Plans of approximately $27,600.

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 2012 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 2012	$	20,551	$	1,591
Fiscal 2013	21,653		1,538
Fiscal 2014	22,823		1,556
Fiscal 2015	24,061		1,551
Fiscal 2016	25,300		1,541
Fiscal 2017 - 2021	145,472		7,801

The assumed health care cost trend rates are 7.5% for Fiscal 2012, decreasing to 5.0% in Fiscal 2017. A one percentage point change in the assumed health care cost trend rate would not have had a material impact on Fiscal 2011 other postretirement benefit cost or the September 30, 2011 other postretirement benefit ABO.

We also sponsor an unfunded and non-qualified supplemental executive retirement income plan. At September 30, 2011 and 2010, the projected benefit obligations of this plan were $2,232 and $3,074, respectively. We recorded expense for this plan of $583 in Fiscal 2011, $249 in Fiscal 2010 and $635 in Fiscal 2009.

Company Pension Plans and VEBA Assets. The assets of the Company Pension Plans 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 Company Pension Plans 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 Company Pension Plans’ and VEBA trust assets at September 30 are as follows:



					Target
	Actual				Asset		Permitted
Pension Plans:	2011		2010		Allocation		Range
Equity investments:
Domestic	49.4	%	56.1	%	52.5	%	40.0% - 65.0%
International	10.7	%	12.2	%	12.5	%	7.5% - 17.5%
Total	60.1	%	68.3	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	39.9	%	31.7	%	35.0	%	30.0% - 40.0%
Total	100.0	%	100.0	%	100.0	%



					Target
	Actual				Asset		Permitted
VEBA:	2011		2010		Allocation		Range
Domestic equity investments	62.2	%	64.9	%	65.0	%	60.0% - 70.0%
Fixed income funds & cash equivalents	37.8	%	35.1	%	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 are indexed to various Morgan Stanley Composite indices. The fixed income investments comprise investments designed to match the duration of the Barclays Capital Aggregate Bond 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 7.6% and 8.3% of Company Pension Plans assets at September 30, 2011 and 2010, respectively. At September 30, 2011, there were no significant concentrations of risk (defined as greater than 10% of the fair value of total assets) associated with any individual company, industry sector or international geographic region.

GAAP establishes a hierarchy that prioritizes fair value measurements based upon the inputs and valuation techniques used

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 Company Pension Plans 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 Company Pension Plans' assets at September 30, 2011 and 2010 by asset class are as follows:



	Company Pension Plans
	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, 2011:
Equity investments:
Domestic	$	143,119	$	—	$	—	$	143,119
International	31,030		—		—		31,030
Fixed income	113,592		—		—		113,592
Cash equivalents	—		2,022		—		2,022
Total	$	287,741	$	2,022	$	—	$	289,763
September 30, 2010:
Equity investments:
Domestic	$	161,485	$	—	$	—	$	161,485
International	35,232		—		—		35,232
Fixed income	88,924		—		—		88,924
Cash equivalents	—		2,261		—		2,261
Total	$	285,641	$	2,261	$	—	$	287,902

The fair values of the VEBA trust assets at September 30, 2011 and 2010 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, 2011:
Domestic equities	$	6,098	$	—	$	—	$	6,098
Fixed income	3,320		—		—		3,320
Cash equivalents	—		388		—		388
Total	$	9,418	$	388	$	—	$	9,806
September 30, 2010:
Domestic equities	$	6,498	$	—	$	—	$	6,498
Fixed income	2,964		—		—		2,964
Cash equivalents	—		545		—		545
Total	$	9,462	$	545	$	—	$	10,007

The expected long-term rates of return on Company Pension Plans and VEBA trust assets have been developed using a best

F- 24

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 Company Pension Plans receive employer matching contributions at a higher rate. The cost of benefits under the Utilities Savings Plan totaled $1,820 in Fiscal 2011, $1,663 in Fiscal 2010 and $1,758 in Fiscal 2009.

11. 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, 2011 or 2010.

12. EQUITY-BASED COMPENSATION

Under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “UGI OECP”), 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” or “Performance Units”) and other equity-based amounts. Under the UGI OECP, the exercise price for options may not be less than the fair market value on the grant date. Awards under the UGI OECP 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 UGI OECP provides that the awards of UGI Units may also provide for the crediting of UGI Common Stock 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 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 UGI market performance conditions. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance and service conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of Performance Units ultimately paid at the end of the performance period (generally three years) may range from 0% to 200% of the target award based upon UGI’s Total Shareholder Return percentile rank relative to companies in the Standard & Poor’s Utilities Index for grants prior to January 1, 2011 and the Russell Midcap Utility Index (excluding telecommunications companies) for grants on or after January 1, 2011.

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 $1,110 ($650 after-tax) during Fiscal 2011; $853 ($499 after-tax) during Fiscal 2010; and $1,142 ($668 after-tax) during Fiscal 2009.

As of September 30, 2011, there was $546 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 2.2 years. As of September 30, 2011, there was a total of $805 of unrecognized compensation expense associated with 59,799 UGI Unit awards that is expected to be recognized over a weighted average period of 2.0 years. At September 30, 2011 and 2010, total liabilities of $327 and $550, respectively, associated with UGI Unit awards are reflected in “Other current liabilities” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.

The following table summarizes UGI Unit award activity for Fiscal 2011:

F- 25

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)



	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, 2010	57,400		$	26.70	21,534		$	28.02	35,866		$	25.92
Granted	22,800		$	35.25	—		$	—	22,800		$	35.25
Vested	—		$	—	14,221		$	29.59	(14,221	)	$	29.59
Forfeited	(2,801	)	$	24.47	—		$	—	(2,801	)	$	24.47
Unit awards paid	(17,600	)	$	30.00	(17,600	)	$	30.00	—		$	—
September 30, 2011	59,799		$	29.10	18,155		$	27.33	41,644		$	29.87

13. 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 $5,221 in Fiscal 2011, $5,737 in Fiscal 2010 and $5,894 in Fiscal 2009.

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: 2012— $4,847; 2013 — $4,275; 2014 — $3,127; 2015 — $2,340; 2016 — $2,106; after September 30, 2016 — $2,246.

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 2022. 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, 2011 for fiscal years ending September 30 are as follows: 2012 — $241,859; 2013 — $117,037; 2014 — $86,440; 2015 — $57,986; 2016 — $35,212; after 2016 — $135,315.

Contingencies

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 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 terminates 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, 2011 and 2010, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $17,917 and $21,385, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of manufactured gas plants (“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

F- 26

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At September 30, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.

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.

South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserts that it has spent approximately $22,000 in remediation costs and paid $26 in third-party claims relating to the site and estimates that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14,000. Trial took place in March 2009 and the court's decision is pending.

Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens Communications Company, now known as Frontier Communications Company (“Frontier”), served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier's predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that they are responsible for an equitable share of any clean up costs Frontier would be required to pay to the City. Frontier alleged that through ownership and control of a subsidiary, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to Frontier's claims. On October 19, 2010, the magistrate judge recommended the Court grant UGI Utilities' motion. On November 19, 2010, the Court affirmed the recommended decision of the magistrate judge granting summary judgment in favor of UGI Utilities. On July 1, 2011, Frontier appealed the Court's decision to the United States Court of Appeals for the First Circuit.

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2,300 and expects to spend another $11,000 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities' alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10,000. KeySpan believes that the cost could be as high as $20,000. There have been no recent developments or facts indicating that this will have a material impact to our results of operations or financial condition.

Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut

F- 27

UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies. The Northeast Companies alleged that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites in Waterbury, CT (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court's decision in favor of UGI Utilities. A second phase of the trial took place in August 2011 to determine what, if any, contamination at Waterbury North is related to UGI Utilities' period of operation. The District Court's decision is pending. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25,000.

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha (“City”) 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 located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of UGI Utilities' predecessor is identified as an owner and operator of the site. The City and MUD has requested that UGI Utilities participate in the clean up of this site. 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 is reviewing the EPA's request and will cooperate with its investigation. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

Other Matters

Allentown, Pennsylvania Natural Gas Explosion. Allentown, Pennsylvania Natural Gas Explosion. On February 9, 2011, a natural gas explosion occurred in Allentown, Pennsylvania which resulted in five deaths, several personal injuries and significant property damage. The PUC is investigating the Allentown accident and UGI Utilities is cooperating with that investigation. Based on a visual inspection, UGI Utilities identified a fracture in a segment of its cast iron natural gas pipeline in the area of the accident. The affected segment of pipeline is undergoing forensic testing by an expert, independent laboratory; however, the cause of the fracture has not yet been determined.

UGI Utilities has received more than one hundred property claims and a handful of personal injury and wrongful death claims as a result of the explosion, although no lawsuits have yet been filed. Many of the claims, including two wrongful death claims and more than fifty percent of the property claims received to date, have been settled. UGI Utilities maintains liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of a $500 deductible, will be recovered through UGI Utilities' insurance. We continue to believe that claims and expenses associated with the explosion will not have a material impact on UGI Utilities' consolidated financial position, results of operations or cash flows.

We cannot predict with certainty the final results of any of the environmental claims or legal actions described 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. In addition to the matters 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 significant effect on our consolidated financial position, results of operations or cash flows.

14. 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, 2011 and 2010:

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)



	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, 2011
Assets:
Derivative financial instruments
Commodity contracts	$	27	$	41	$	—	$	68
Liabilities:
Derivative financial instruments
Commodity contracts	$	4,102	$	7,634	$	—	$	11,736
Interest rate contracts	$	—	$	18,585	$	—	$	18,585

September 30, 2010
Assets:
Derivative financial instruments
Commodity contracts	$	61	$	425	$	—	$	486
Liabilities:
Derivative financial instruments
Commodity contracts	$	3,263	$	17,798	$	—	$	21,061

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.

Other Financial Instruments

The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and 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 at September 30, 2011 were $640,000 and $737,223, respectively. The carrying amount and estimated fair value of our long-term debt at September 30, 2010 were $640,000 and $749,227, 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.

15. 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. 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 2011 and 2010, the volumes of natural gas associated with Gas Utility's unsettled NYMEX natural gas futures and option contracts totaled 15.1 million dekatherms and 19.5 million dekatherms, respectively. At September 30, 2011, the maximum period over which Gas Utility is hedging natural gas market price risk is 13 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 FASB's guidance in ASC 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 5).

Beginning January 1, 2010, Electric Utility's DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At September 30, 2011 and 2010 the fair values of Electric Utility's forward purchase power agreements comprising losses of $8,655 and $19,702, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Consolidated Balance Sheets. In accordance with ASC 980 related to rate regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At September 30, 2011 and 2010, the volumes of Electric Utility's forward electricity purchase contracts was 788.6 million kilowatt hours and 990.7 million kilowatt hours, respectively. At September 30, 2011, the maximum period over which these contracts extend is 32 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM 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. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010 pursuant to the January 22, 2009 settlement of its DS filing with the PUC, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 5). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At September 30, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 208.6 million kilowatt hours and 546.8 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, 2011, the total notional amounts of our unsettled IRPA contracts was $173,000. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of long-term debt forecasted to occur in September 2012 and September 2013.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2011 and 2010, Gas Utility’s restricted cash in brokerage accounts totaled $4,308 and $4,698, respectively.

The following table provides information regarding the balance sheet location and fair values of derivative assets and liabilities existing as of September 30, 2011 and 2010:

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)



	Derivative Assets					Derivative Liabilities
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2011		2010		Location	2011		2010
Derivatives Designated as Hedging Instruments:
						Derivative financial instruments and Other noncurrent liabilities	$	18,585	$	—

Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	$	41	$	425	Derivative financial instruments and Other noncurrent liabilities	11,736		21,061
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	27		61
Total Derivatives		$	68	$	486		$	30,321	$	21,061

During the years ended September 30, 2011 and 2010, the amount of IRPA net losses included in AOCI that were reclassified into net income for both periods totaled $1,164, respectively. During the years ended September 30, 2011 and 2010, the impact of changes in the fair value of FTRs and gasoline futures and swap contracts on our net income was not material.

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.

16. SEGMENT INFORMATION

We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The 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.”

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:

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)



	Total		Gas Utility		Electric Utility		Other
2011
Revenue	$	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		—
2010
Revenue	$	1,169,539	$	1,047,521	$	120,246	$	1,772
Cost of sales	730,502		653,439		77,063		—
Depreciation and amortization	53,476		49,474		4,002		—
Operating income	189,519		175,272		13,676		571
Interest expense	42,336		40,515		1,821		—
Income before income taxes	147,183		134,757		11,855		571
Total assets	2,139,576		1,996,281		143,295		—
Goodwill	180,145		180,145		—		—
Capital expenditures	81,595		73,503		8,092		—
2009
Revenue	$	1,381,260	$	1,240,981	$	138,495	$	1,784
Cost of sales	944,793		853,163		91,630		—
Depreciation and amortization	51,112		47,228		3,884		—
Operating income	169,472		153,457		15,376		639
Interest expense	43,918		42,192		1,726		—
Income before income taxes	125,554		111,265		13,650		639
Total assets	2,030,237		1,917,036		113,201		—
Goodwill	180,145		180,145		—		—
Capital expenditures	79,084		73,825		5,259		—

17. OTHER INCOME, NET

Other income, net, comprises the following:



	2011		2010		2009
Non-tariff service income	$	6,422	$	2,437	$	3,221
Interest income	467		867		288
Postretirement benefit plan curtailment gain	3,245		—		—
Other	630		2,965		3,752
Total other income, net	$	10,764	$	6,269	$	7,261

18. RELATED PARTY TRANSACTIONS

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UGI UTILITIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Thousands of dollars, except per share amounts)

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 Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI's subsidiaries, principally payroll-related services. 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, 2011, UGI Utilities was a party to two three-year SCAAs with Energy Services expiring October 31, 2012 and October 31, 2013 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 $35,231, $21,826 and $55,760 in Fiscal 2011, Fiscal 2010 and Fiscal 2009, 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 $15,000 and $7,500 at September 30, 2011 and 2010, respectively.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at September 30, 2011, comprising approximately 7.5 bcf feet of natural gas, was $35,686. The carrying value of these gas storage inventories at September 30, 2010, comprising approximately 4.1 bcf of natural gas, was $20,749.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2011, Fiscal 2010 and Fiscal 2009, revenues associated with sales to Energy Services totaled $85,655, $62,074 and $30,911, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to those transactions already described above) and beginning April 1, 2011, purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under a one-year agreement. During Fiscal 2011, Fiscal 2010 and Fiscal 2009, such purchases totaled $53,617, $31,157 and $17,268, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

19. QUARTERLY DATA (unaudited)

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



	December 31,				March 31,				June 30,				September 30,
	2010		2009		2011		2010		2011		2010		2011			2010
Revenues	$	350,516	$	362,203	$	484,465	$	477,273	$	172,714	$	175,021	$	129,671		$	155,042
Operating income	$	78,880	$	69,273	$	104,109	$	94,337	$	19,486	$	16,379	$	8,946		$	9,530
Net income (loss)	$	41,074	$	35,163	$	60,163	$	50,612	$	5,478	$	3,604	$	(1,519	)	$	879

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UGI UTILITIES, INC. AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

(Thousands of dollars)



	Balance at beginning of year		Charged to costs and expenses			Other				Balance at end of year
September 30, 2011
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	7,072	$	9,137		$	(9,841	)	⁽¹⁾	$	6,368
Other reserves:
Other, principally environmental and property and casualty liability	$	33,465	$	10,173		$	(9,558	)	⁽³⁾	$	34,080	⁽⁵⁾

September 30, 2010
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	11,384	$	10,651		$	(14,963	)	⁽¹⁾	$	7,072

Other reserves:
Other, principally environmental and property and casualty liability	$	38,707	$	(1,547	)	$	(2,940	)	⁽³⁾	$	33,465	⁽⁵⁾
						$	(755	)	⁽⁴⁾

September 30, 2009
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	10,369	$	19,193		$	(22,735	)	⁽¹⁾	$	11,384
						$	4,557		⁽²⁾
Other reserves:
Other, principally environmental and property and casualty liability	$	16,011	$	2,335		$	18,495		⁽²⁾	$	38,707	⁽⁵⁾
						$	(3,678	)	⁽³⁾
						$	5,544		⁽⁴⁾


(1)	Uncollectible accounts written off, net of recoveries


(2)	Acquisition adjustments


(3)	Payments, net


(4)	Other adjustments


(5)	At September 30, 2011, 2010 and 2009 UGI Utilities had insurance indemnification receivables associated with its property and casualty liabilities totaling $8,163, $882 and $750, respectively.

S- 1

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Avg

Ugi Utilities Inactive 10-K2011 FY Annual report

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