Filed by Bowne Pure Compliance

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, 2008

Commission file number 1-1398

UGI UTILITIES, INC.

(Exact Name of Registrant as Specified in Its Charter)


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

100 Kachel Boulevard, Suite 400, Green Hills Corporate Center
Reading, PA 19607
(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 o

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 o 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 o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o

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

At September 30, 2008, there were 26,781,785 shares of UGI Utilities 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.

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 natural gas distribution utilities and an electric utility in Pennsylvania. We are a wholly owned subsidiary of UGI Corporation (“UGI”).

On August 24, 2006, UGI Utilities, through its subsidiary UGI Penn Natural Gas, Inc. (“UGIPNG”), acquired the natural gas distribution business of Southern Union Company’s PG Energy Division, which significantly increased our natural gas distribution business in northeastern Pennsylvania. The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of UGI Utilities (“UGI Gas”) and UGIPNG. Gas Utility serves approximately 484,000 customers in eastern and northeastern Pennsylvania. On October 1, 2008, UGI Utilities completed the acquisition of all of the issued and outstanding stock of PPL Gas Utilities Corporation (“PPL Gas”), the natural gas distribution utility of PPL Corporation, and its wholly owned subsidiary, Penn Fuel Propane, LLC (“Penn Fuel Propane”). Immediately following the closing of the acquisition, Penn Fuel Propane sold its retail propane distribution assets to AmeriGas Propane, L.P., an affiliate of UGI. PPL Gas, now known as UGI Central Penn Gas, Inc., distributes natural gas to approximately 76,000 customers in 34 counties in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. Beginning in the 2009 fiscal year, UGI Central Penn Gas, Inc. will be included in the Company’s Gas Utility segment. See Note 14 to the Company’s Consolidated Financial Statements.

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 and Electric Utility are regulated by the Pennsylvania Public Utility Commission (“PUC”).

UGI Utilities was incorporated in Pennsylvania in 1925. Our executive offices are located at 100 Kachel Boulevard, Suite 400, Green Hills Corporate Center, Reading, Pennsylvania 19607, 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 2008” and “Fiscal 2007” refer to the fiscal years ended September 30, 2008 and September 30, 2007, respectively.

GLOBAL CLIMATE CHANGE

There is a growing concern about climate change and the contribution of greenhouse gas emissions, most notably carbon dioxide, to global warming. While some states have adopted laws regulating the emission of greenhouse gases for some industry sectors, there is currently no federal regulation of greenhouse gas emissions in the United States. It is anticipated that federal legislation, likely consisting of a cap and trade system, governing the emission of greenhouse gases will be enacted in the United States in the near future. Since natural gas is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, we anticipate that this will provide us with a competitive advantage over other sources of energy, such as fuel oil and coal, when new climate change regulations become effective. In addition, we are developing a strategy to identify both our greenhouse gas emissions and our energy consumption in order to be in a position to comply with new regulations and to take advantage of any opportunities that may arise from the regulation of such emissions.

GAS UTILITY OPERATIONS

Service Area; Revenue Analysis

Gas Utility is authorized to distribute natural gas to approximately 484,000 customers in portions of 28 eastern and northeastern Pennsylvania counties through its distribution system of approximately 7,860 miles of gas mains. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre 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.

System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2008 was approximately 133.7 billion cubic feet (“bcf”). System sales of gas accounted for approximately 42% of system throughput, while gas transported for residential, commercial and industrial customers (who bought their gas from others) accounted for approximately 58% of system throughput.

Sources of Supply and Pipeline Capacity

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 and Tennessee Gas Pipeline.

Gas Supply Contracts

During Fiscal 2008, Gas Utility purchased approximately 78 bcf of natural gas for sale to retail core market and off-system sales customers. Approximately 87% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 13% of gas purchased by Gas Utility was supplied by approximately 23 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 55% to 60% of Gas Utility’s sales volume is supplied, and approximately 70% to 75% of Gas Utility’s operating income is earned, during the five-month peak heating season from November 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. Electric utilities in Gas Utility’s service area are seeking new load, primarily in the new construction market. In parts of Gas Utility’s service area, electricity may have a competitive price advantage over natural gas due to government regulated rate caps on electricity. Rate caps for electric utilities serving a significant portion of Gas Utility’s service territory are currently scheduled to expire in 2009 and 2010. Additionally, high efficiency electric heat pumps have led to a decrease in the cost of electricity for heating. 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 residential and smaller commercial and industrial customers (“Core Market Customers”), have been afforded this opportunity. As of September 30, 2008, four marketers provide gas supplies to approximately 4,400 of Gas Utility’s Core Market Customers. Gas Utility provides transportation services for its customers who purchase natural gas from others.

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.” In accordance with the PUC’s June 29, 2000 Gas Restructuring Order applicable to UGI Gas, a substantial portion of the margin from certain of these customers (who use pipeline capacity contracted by UGI Gas to serve retail customers) is used to reduce purchased gas cost rates for retail customers. Approximately 27% of UGI Gas’ commercial and industrial customers, including certain customers served under interruptible rates, have locations which afford them the opportunity, although none have exercised it, of seeking transportation service directly from interstate pipelines, thereby bypassing UGI Gas. 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 UGI Gas’ 10 largest customers in terms of annual volumes. All of these customers have contracts, 9 of which extend beyond the 2009 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 2009. 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 2008, Gas Utility supplied transportation service to 2 major co-generation installations and 5 electric generation facilities. Gas Utility continues to pursue opportunities to supply natural gas to electric generation projects located in its service area. Gas Utility also continues to seek new residential, commercial and industrial customers for both firm and interruptible service. In the residential market sector, Gas Utility connected approximately 11,000 residential heating customers during Fiscal 2008. Despite the nationwide slowdown in the real estate market, of those new customers, new home construction accounted for over 4,970 heating customers. If the slowdown in new home construction continues in fiscal year 2009 in Gas Utility’s service area, customer growth may be adversely affected. Customers converting from other energy sources, primarily oil and electricity, and existing non-heating gas customers who have added gas heating systems to replace other energy sources, accounted for the balance of the additions. The number of new commercial and industrial Gas Utility customers was approximately 1,500.

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 2,150 miles of transmission and distribution lines and 13 transmission substations. For Fiscal 2008, approximately 52% of sales volume came from residential customers, 35% from commercial customers and 13% from industrial and other customers. Sales of electricity for residential heating purposes accounted for approximately 19% of total sales of electricity during Fiscal 2008.

Sources of Supply

Electric Utility has no owned generation and, as a result, has third-party generation supply contracts in place for substantially all of its expected energy requirements through December 31, 2009. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers, if any.

As of September 30, 2008, none of Electric Utility’s customers have selected an alternative electricity generation supplier. Electric Utility expects to continue to provide energy to the great majority of its distribution customers for the foreseeable future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures” for a discussion of risks related to Electric Utility’s supply contracts and see “RISK FACTORS- Electricity supplier defaults may adversely affect our results of operations.”

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 provider of last resort (“POLR”) for its customers who do not choose an alternate electric generation supplier. Electric Utility serves 100% 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. Electricity competes with natural gas, oil, propane and other heating fuels for residential heating purposes.

The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service, have been established in a series of PUC-approved settlements (the “POLR Settlements”). Consistent with the terms of the POLR Settlements, Electric Utility’s total average residential heating customer POLR rates were increased in January 2008 by approximately 5.5% over rates in effect during calendar year 2007. Electric Utility has announced its intent to increase average residential heating customer rates in January 2009 by approximately 1.5% over rates in effect during calendar year 2008. For current rates 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.

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. 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

The most recent general base rate increase for UGI Gas became effective in 1995. In accordance with a statutory mechanism, a rate increase for firm- residential, commercial and industrial customers (“retail core-market”) became effective October 1, 2000 along with a Purchased Gas Cost (“PGC”) variable credit equal to a portion of the margin received from customers served under interruptible rates to the extent such interruptible customers use capacity contracted for by UGI Gas for retail core-market customers.

In an order entered on November 30, 2006, the PUC approved a settlement of the UGIPNG base rate proceeding. The settlement authorized UGIPNG to increase natural gas annual base rates by $12.5 million, or approximately 4.0%, effective December 2, 2006. In addition, the settlement provides UGIPNG the ability to recover up to $1.0 million of additional corporate franchise tax through the state tax adjustment surcharge mechanism.

UGI Gas’ and UGIPNG’s gas service tariffs 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 and UGIPNG sells to its customers. PGC rates are reviewed and approved annually by the PUC. UGI Gas and UGIPNG 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. PGC (1) is applicable to small, firm, retail core-market customers consisting of the residential and small commercial and industrial classes; PGC (2) is applicable to firm, contractual, high-load factor customers served on three separate rates. In addition, residential customers maintaining a high load factor may qualify for the PGC (2) rate. As described above, UGI Gas’ PGC rates are adjusted to reflect margins, if any, from interruptible rate customers who do not obtain their own pipeline capacity. UGIPNG has 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 2008 and may implement a further increase effective January 1, 2009. The increase implemented January 1, 2008 raised total average residential heating customer rates by approximately 5.5% over rates in effect during calendar year 2007. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its customers.

PUC default service regulations are applicable to Electric Utility’s provision of default service effective January 1, 2010. Electric Utility, consistent with these regulations, acquired a portion of its default service supplies for certain customer groups for the period of January 1, 2010 through December 31, 2012. Electric Utility is waiting for 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 become effective 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 become effective January 1, 2010.

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 and UGIPNG 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 and UGIPNG 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 8 to the Company’s Consolidated Financial Statements.

Employees

At September 30, 2008, UGI Utilities had approximately 1,200 employees, of which approximately 93% are dedicated to Gas Utility and 7% to Electric Utility. Union employees represent approximately 40% of the total employees.

BUSINESS SEGMENT INFORMATION

The table stating the amounts of revenues, operating income and identifiable assets attributable to UGI Utilities’ operating segments for the 2008, 2007 and 2006 fiscal years appears in Note 10 to the Company’s 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 is generally at its highest during the five-month peak heating season of November through March and is directly affected by the severity of the winter weather. Our rate structure does 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. 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 recent volatility in credit and capital markets may create additional risks to our business in the future. We are exposed to financial market risk resulting from, among things, changes in interest rates and conditions in the credit and capital markets. Recent developments in the credit markets 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 recent 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.

Electricity supplier defaults may adversely affect our results of operations.

Generally, we purchase our power needs from electricity suppliers under fixed-price energy and capacity contracts. Should any of the suppliers under these contracts fail to provide electric power under the terms of these contracts through December 2009, any increases in the cost of replacement power or capacity could negatively impact our results and adversely affect our cash flows because of our inability to recover these potential increases in our current rates. Under PUC default service regulations that became effective in September of 2007, however, any potential increases in the cost of replacement power or capacity resulting from supplier contract defaults for power or capacity to be delivered after 2009 can be recovered through default service rates.

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 or natural gas could create payment obligations for the Company and expose us to an increased liquidity risk.

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, UGI Penn Natural Gas, Inc., or UGI Central Penn Gas, Inc. in the future, which may adversely affect our results of operations.

Our Gas Utility and Electric Utility operations are subject to regulation by the PUC. The PUC, among other things, approves the rates that we, UGIPNG and UGI Central Penn Gas, Inc. may charge to our utility customers, thus impacting the returns that we, UGIPNG and UGI Central Penn Gas, Inc. may earn on the assets that are dedicated to those operations. We expect to file requests with the PUC to increase base rates that we charge customers of UGIPNG and UGI Central Penn Gas, Inc. early in 2009. If we, UGIPNG and/or UGI Central Penn Gas, Inc. are required in a rate proceeding to reduce the rates we charge our utility customers, or if we, UGIPNG and/or UGI Central Penn Gas, Inc. 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.

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

There is a growing concern about climate change and the contribution of greenhouse gas emissions, most notably carbon dioxide, to global warming. In response to this concern, there have been numerous federal legislative proposals in the United States, as well as the enactment or consideration of various state and local laws, aimed at reducing greenhouse gas emissions.

Increased regulation of greenhouse gas emissions, especially in the electric generation and transportation sectors, could impose significant costs on us. While there is currently no federal regulation in the United States that mandates the reduction of greenhouse gas emissions, it is likely that legislation governing such emissions will be enacted in fiscal year 2009 or fiscal year 2010. Until legislation is passed in the United States, it will remain unclear as to (i) what industry sectors would be impacted, (ii) when compliance would be required, (iii) the magnitude of the greenhouse gas emissions reductions that would be required and (iv) the costs and opportunities associated with compliance. At this time, we are uncertain as to the effect climate change regulation may have on our operations, capital expenditures and financial results in the future.

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, severe damage to and destruction of property and equipment. As a result, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. We believe that we are adequately insured for claims in excess of our self-insurance; however, certain types of damages, such as punitive damages and penalties, if any, may not be covered by insurance. 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.

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

Business Overview

UGI Utilities, a wholly owned subsidiary of UGI Corporation, owns and operates two natural gas distribution utilities (“NGDCs”) located in eastern and northeastern Pennsylvania (“UGI Gas” and “PNG Gas,” respectively) and an electric distribution utility located in northeastern Pennsylvania (“Electric Utility”). UGI Gas and PNG Gas are referred to collectively as “Gas Utility.” UGI Gas, PNG Gas and Electric Utility are regulated by the Pennsylvania Public Utility Commission (“PUC”). Because many customers use natural gas and electricity for space heating purposes, Gas Utility’s and to a lesser extent Electric Utility’s results are seasonal with the peak-heating season comprising the months of November through March. On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas Utilities Corporation (now named UGI Central Penn Gas, Inc., “CPG”), a distributor of natural gas to approximately 76,000 customers principally in eastern and central Pennsylvania (the “CPG Acquisition”) (see “Subsequent Event – Acquisition of PPL Gas Utilities Corporation and Penn Fuel Propane, LLC” below and Note 14 to Consolidated Financial Statements).

The following results of operations covers the three fiscal years ended September 30, 2008, 2007 and 2006 (“Fiscal 2008,” “Fiscal 2007” and “Fiscal 2006,” respectively). The results of PNG Gas are included in our consolidated results beginning August 24, 2006, the date PNG Gas was acquired from Southern Union Company (See Note 2 to Consolidated Financial Statements). Consequently, the full-year results of PNG Gas are included in Fiscal 2008 and Fiscal 2007, but Fiscal 2006 only includes PNG Gas results from August 24, 2006. As previously mentioned, on October 1, 2008, UGI Utilities completed the CPG Acquisition. Because the CPG Acquisition occurred after the end of Fiscal 2008, it is not reflected in the accompanying financial statements.

In conducting our business operations, we focus our attention on those factors we believe have a significant effect on the successful operation of our businesses including, among other things, pursuing customer growth and new business opportunities in our service territories and controlling operating costs in order to provide reliable natural gas and electric service to our customers at competitive prices. As a regulated utility company, we also devote considerable effort to complying with regulations to which we are subject and to monitoring and responding to our regulatory environment. Because many of our customers use natural gas and electricity for space heating purposes, year-to-year weather variations can have a significant impact on our results. To a lesser extent, customer behavior in response to increases and volatility in energy costs can also affect our results. Gas Utility is generally not subject to commodity price risk associated with sales of gas to firm- residential, commercial and industrial (“retail core-market”) customers because Gas Utility’s tariffs contain purchased gas cost (“PGC”) rates that permit recovery of substantially all of the prudently incurred costs of natural gas it sells to its customers. These tariffs provide for annual increases or decreases in rates that Gas Utility charges for natural gas sold by it to reflect projected costs of purchased gas. These rates may also be adjusted quarterly, or under certain conditions monthly, to reflect significant changes in the actual cost of gas. We attempt to reduce natural gas product cost volatility through the use of derivative financial instruments such as natural gas futures contracts as well as fixed-price forward contracts and storage services. Because a number of Gas Utility’s non-retail core-market customers have the ability to switch to an alternate fuel at any time, they are served on an interruptible basis. Profitability for these customers is generally affected by the difference between the delivered cost of gas and the delivered cost of the alternate fuel and, to a lesser extent, the frequency and duration of service interruptions. Electric Utility is subject to commodity price risk for electricity as its rates for electric generation under Provider of Last Resort (“POLR”) settlements, effective through December 31, 2009, contain rate caps which provide limited protection against electricity price increases. Management attempts to reduce electric price volatility by entering into fixed-price forward contracts and price swap agreements.

As previously mentioned, operating results for Fiscal 2008 and Fiscal 2007 include the full-year impact of PNG Gas. However, the comparison of operating results for Fiscal 2007 with Fiscal 2006 is significantly affected by the full-year impact of PNG Gas in Fiscal 2007 compared with the partial-year impact of PNG Gas in Fiscal 2006. Our financial results in Fiscal 2008, Fiscal 2007 and Fiscal 2006 reflect weather that was warmer than normal. The warmer than normal weather in Fiscal 2008 and Fiscal 2007 reduced the full earnings benefits we expected from PNG Gas.

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) compares the results of our operations for the three-year period ended September 30, 2008. The MD&A should be read in conjunction with our Consolidated Financial Statements and Notes to Consolidated Financial Statements including the business segment information included in Note 10.

Fiscal 2008 Compared with Fiscal 2007


							Increase
(Millions of dollars)	2008			2007			(Decrease)

Gas Utility:
Revenues	$	1,138.3		$	1,044.9		$	93.4		8.9	%
Total margin (a)	$	307.3		$	303.5		$	3.8		1.3	%
Operating income	$	137.6		$	136.6		$	1.0		0.7	%
Income before income taxes	$	100.5		$	96.7		$	3.8		3.9	%
System throughput — bcf		133.7			131.8			1.9		1.4	%
Degree days — % warmer than normal (b)		5.5	%		4.7	%		—		—

Electric Utility:
Revenues	$	139.2		$	121.9		$	17.3		14.2	%
Total margin (a)	$	47.0		$	47.3		$	(0.3	)	(0.6	)%
Operating income	$	24.4		$	26.0		$	(1.6	)	(6.2	)%
Income before income taxes	$	22.5		$	23.6		$	(1.1	)	(4.7	)%
Distribution sales — gwh		1,004.4			1,010.6			(6.2	)	(0.6	)%


bcf — billions of cubic feet. gwh — millions of kilowatt hours.

(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 $7.9 million in Fiscal 2008 and $6.8 million in Fiscal 2007. 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 30-year period 1975-2004 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 5.5% warmer than normal in Fiscal 2008 compared with temperatures that were 4.7% warmer than normal in Fiscal 2007. Total distribution system throughput increased 1.9 bcf in Fiscal 2008 principally reflecting greater interruptible delivery service volumes (principally volumes associated with low margin cogeneration customers) and an increase in the number of Gas Utility core market customers partially offset by lower average usage per customer due in large part to price-induced customer conservation and a weak economy. Gas Utility’s core market customers principally comprise retail core-market customers, who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial and industrial (“core market transportation”) customers who purchase their gas from alternate suppliers.

Gas Utility revenues increased $93.4 million in Fiscal 2008 principally reflecting a $57.4 million increase in revenues from off-system sales and the effects of higher average PGC rates on retail core-market revenues. Increases or decreases in retail core-market revenues and cost of sales principally result from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of sales was $831.1 million in Fiscal 2008 compared with $741.5 million in Fiscal 2007 principally reflecting the greater off-system sales and the increase in average retail core-market PGC rates.

Gas Utility total margin increased $3.8 million in Fiscal 2008 primarily reflecting modest increases in interruptible delivery service and core market total margin.

The increase in Gas Utility operating income principally reflects the previously mentioned $3.8 million increase in total margin and a $5.3 million increase in other income partially offset by modestly higher operating and administrative expenses. The higher other income reflects in large part greater storage contract fees and a $2.2 million postretirement benefit plan curtailment gain. The increase in operating and administrative expenses includes, among other things, higher environmental legal costs and greater uncollectible accounts expense. Gas Utility income before income taxes also reflects lower interest expense on bank loans.

Electric Utility. Electric Utility’s kilowatt-hour sales in Fiscal 2008 were about equal to Fiscal 2007 on heating-season weather that was slightly warmer and cooling-season weather that was slightly cooler. Electric Utility revenues increased $17.3 million principally as a result of higher POLR rates. Electric Utility cost of sales increased to $84.3 million in Fiscal 2008 from $67.8 million in the prior year principally reflecting higher per-unit purchased power costs.

Electric Utility total margin in Fiscal 2008 was about equal to Fiscal 2007 reflecting the effects of the higher POLR rates offset principally by the higher per-unit purchased power costs and higher revenue-related taxes.

The decrease in Fiscal 2008 Electric Utility operating income reflects slightly higher operating and administrative costs including higher system maintenance and uncollectible accounts expense. Income before income taxes reflects the lower operating income partially offset by lower interest expense on bank loans.

Fiscal 2007 Compared with Fiscal 2006


(Millions of dollars)	2007			2006			Increase

Gas Utility:
Revenues	$	1,044.9		$	724.0		$	320.9	44.3	%
Total margin (a)	$	303.5		$	201.2		$	102.3	50.8	%
Operating income	$	136.6		$	84.2		$	52.4	62.2	%
Income before income taxes	$	96.7		$	62.4		$	34.3	55.0	%
System throughput — bcf		131.8			82.6			49.2	59.6	%
Degree days — % warmer than normal (b)		4.7	%		8.7	%		—	—

Electric Utility:
Revenues	$	121.9		$	98.0		$	23.9	24.4	%
Total margin (a)	$	47.3		$	41.7		$	5.6	13.4	%
Operating income	$	26.0		$	20.7		$	5.3	25.6	%
Income before income taxes	$	23.6		$	18.2		$	5.4	29.7	%
Distribution sales — gwh		1,010.6			1,005.0			5.6	0.6	%


bcf — billions of cubic feet. gwh — millions of kilowatt hours.

(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 $6.8 million in Fiscal 2007 and $5.3 million in Fiscal 2006. 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 30-year period 1975-2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Gas Utility. Temperatures in Gas Utility’s service territory based upon heating degree days were 4.7% warmer than normal in Fiscal 2007 compared with temperatures that were 8.7% warmer than normal in Fiscal 2006. Total distribution system throughput increased 49.2 bcf reflecting a 43.4 bcf increase from the full-year results of PNG Gas and greater UGI Gas distribution system throughput. The greater UGI Gas distribution system throughput primarily reflects (1) greater interruptible delivery service throughput and (2) increased sales to retail core-market customers as a result of the colder Fiscal 2007 weather and year-over-year growth in the number of UGI Gas customers.

Gas Utility revenues increased $320.9 million during Fiscal 2007 principally reflecting $308.9 million of incremental revenues attributable to the full year results of PNG Gas and a $37.5 million increase in UGI Gas revenues from greater low-margin off-system sales. These increases were partially offset by a $30.7 million decrease in revenues from UGI Gas’ retail core-market customers as a result of lower average PGC rates. Gas Utility’s cost of gas was $741.5 million in Fiscal 2007 compared to $522.9 million in Fiscal 2006 largely reflecting the effects of the full-year results of PNG Gas and greater cost of gas associated with the higher UGI Gas off-system sales partially offset by the effects of the previously mentioned lower average UGI Gas PGC rates.

Gas Utility total margin in Fiscal 2007 increased $102.3 million primarily reflecting $93.0 million of incremental margin from the full-year results of PNG Gas and a $9.3 million increase in UGI Gas’ total margin. The increase in UGI Gas’ total margin in Fiscal 2007 principally reflects greater margin from retail core-market customers on higher volumes and higher average interruptible delivery service unit margins reflecting higher natural gas versus oil price spreads.

Gas Utility operating income increased to $136.6 million in Fiscal 2007 from $84.2 million in Fiscal 2006 principally reflecting the previously mentioned increase in total margin and slightly higher other income partially offset by a $39.5 million increase in operating and administrative expenses and $14.1 million higher depreciation and amortization expense. The increase in total operating and administrative expenses and depreciation and amortization expense principally reflects the full-year results of PNG Gas.

The increase in Gas Utility income before income taxes reflects the higher operating income partially offset by an increase of $18.1 million in interest expense. The increase in interest expense is principally due to higher long- and short-term debt outstanding, primarily as a result of the PG Energy Acquisition, and higher short-term interest rates.

Electric Utility. Electric Utility’s Fiscal 2007 kilowatt-hour sales were approximately equal to those of Fiscal 2006. Electric Utility revenues increased $23.9 million in Fiscal 2007 largely reflecting the effects of higher POLR rates. In accordance with the terms of our June 2006 POLR settlement, Electric Utility increased its POLR rates effective January 1, 2007. This increase raised the average cost to residential customers by approximately 35% over costs in effect during calendar year 2006. Electric Utility’s cost of sales increased to $67.8 million in Fiscal 2007 from $51.0 million in Fiscal 2006 principally reflecting higher per unit purchased power costs.

Electric Utility total margin increased $5.6 million during Fiscal 2007 principally reflecting the effects of the higher POLR rates partially offset by the higher per unit purchased power costs.

The increase in Fiscal 2007 Electric Utility operating income and income before income taxes principally reflects the increase in total margin partially offset by slightly higher operating and administrative expenses.

FINANCIAL CONDITION AND LIQUIDITY

Capitalization and Liquidity

UGI Utilities’ total debt outstanding was $589 million at September 30, 2008 compared with total debt outstanding of $702 million at September 30, 2007. Included in these amounts are $57 million and $190 million, respectively, of bank loans outstanding under UGI Utilities’ Revolving Credit Agreement. UGI Utilities’ total debt outstanding at September 30, 2008, other than bank loans, comprises $275 million of Senior Notes and $257 million of Medium-Term Notes. In January 2008, UGI Utilities issued $20 million of 5.67% Medium-Term Notes due January 2018 and used the proceeds to reduce bank loan borrowings under its Revolving Credit Agreement. In conjunction with the previously mentioned October 1, 2008 CPG Acquisition, on September 25, 2008 UGI made a $120 million cash contribution to UGI Utilities. This cash contribution was used by UGI Utilities to reduce its bank loans outstanding. On October 1, 2008, UGI Utilities borrowed under the Revolving Credit Agreement to fund a portion of the CPG Acquisition (see “Subsequent Event – Acquisition of PPL Gas Utilities Corporation and Penn Fuel Propane, LLC” below).

UGI Utilities has a $350 million Revolving Credit Agreement which expires in August 2011. At September 30, 2008 and 2007, there was $57 million and $190 million outstanding under this Revolving Credit Agreement. As previously mentioned, the September 30, 2008 amount outstanding was reduced by the $120 million cash contribution made by UGI on September 25, 2008 to finance a portion of the October 1, 2008 CPG Acquisition. The Revolving Credit Agreement requires UGI Utilities to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. During Fiscal 2008 and Fiscal 2007, peak bank loan borrowings totaled $267 million and $259 million, respectively. Peak bank loan borrowings typically occur during the peak heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is generally greatest. Average daily bank loan borrowings were $121.0 million in Fiscal 2008 and $164.3 million in Fiscal 2007.

UGI Utilities also has a shelf registration statement with the U.S. Securities and Exchange Commission under which it may issue up to an additional $112 million of debt securities subject to the financial ratio covenant in its Revolving Credit Agreement and PUC approval.

Based upon cash expected to be generated from our operations including those of CPG, and borrowings under our Revolving Credit Agreement and our ability to issue public debt, management believes the Company will be able to meet its anticipated contractual and projected cash commitments, including those of CPG, during Fiscal 2009. For additional discussion of UGI Utilities’ long-term debt and Revolving Credit Agreement, see Note 4 to Consolidated Financial Statements.

Effect of Recent Market Conditions

The recent unprecedented volatility in credit and capital markets may create additional risks to our businesses in the future. We are exposed to financial market risk resulting from, among other things, changes in interest rates and conditions in the credit and capital markets. Recent developments in the financial and credit markets increase our possible exposure to the liquidity and credit risks of our suppliers, counterparties associated with derivative financial instruments and our customers.

We believe that we have sufficient liquidity in the form of our Revolving Credit Agreement to fund business operations including the margin deposit requirements of our natural gas futures brokerage accounts resulting from recent steep declines in natural gas prices. Additionally, we do not have any long-term debt maturing in the next several fiscal years and our Revolving Credit Agreement expires in August 2011. Accordingly, we do not believe that recent conditions in the credit and capital markets will have a significant impact on our liquidity. Although we believe that recent financial market conditions will not have a significant impact on our ability to fund our existing operations, such market conditions could restrict our ability to grow through acquisitions or limit the scope of major capital projects if access to credit and capital markets is limited, and could adversely affect our operating results.

We are subject to credit risk relating to the ability of counterparties to meet their contractual payment obligations or the potential non-performance of counterparties to deliver contracted commodities or services at contract prices. We monitor our counterparty credit risk exposure in order to minimize credit risk with any one supplier or financial instrument counterparty. We have a diverse customer base comprising residential, commercial and industrial customers located primarily in Pennsylvania. No single customer represents more than ten percent of our revenues or operating income. Notwithstanding our diverse customer profile, current conditions in the credit markets could affect the ability of some of our customers to pay timely or result in increased customer bankruptcies which may lead to increased bad debts.

We sponsor funded defined benefit pension plans and a postretirement benefit plan. We believe that the oversight of the plans’ investments is rigorous and that our investment strategies are prudent. During Fiscal 2008, actual returns on plans’ investments were significantly below the expected rate of return due to adverse conditions in the financial markets. Reductions in asset values from the lower than expected investment performance resulted in increases in the plans’ unfunded status and, in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (“SFAS 158”), a decrease in shareholders’ equity. Notwithstanding the investment results in Fiscal 2008, we do not expect that we will be required to make significant contributions to the plans in Fiscal 2009. Continued actual returns below the expected rate of return would, however, accelerate the timing and increase the amount of future contributions to these plans beyond Fiscal 2009. Additionally, reduced benefit plan assets would likely result in increased benefit expense in future years.

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 short-term borrowings, primarily borrowings under its Revolving Credit Agreement to manage seasonal cash flow needs.

Cash provided by operating activities was $142.6 million in Fiscal 2008, $133.5 million in Fiscal 2007 and $10.7 million in Fiscal 2006. Cash provided by operating activities before changes in operating working capital was $143.3 million in Fiscal 2008, $150.6 million in Fiscal 2007 and $93.8 million in Fiscal 2006. The significant increase in Fiscal 2007 operating cash flow before changes in working capital as compared with Fiscal 2006 reflects the full-year effects of PNG Gas. Changes in operating working capital used $0.8 million of cash in Fiscal 2008, $17.1 million of cash in Fiscal 2007 and $83.1 million of cash in Fiscal 2006. The greater cash flow from changes in operating working capital in Fiscal 2008 as compared with Fiscal 2007 principally reflects the timing of cash recoveries through Gas Utility’s PGC recovery mechanism in excess of purchased gas costs, including cash from settled gains on natural gas futures contracts, partially offset by the timing of interest payments and payments for accounts payable. The significant decrease in Fiscal 2007 cash used by changes in working capital as compared with Fiscal 2006 principally reflects lower cash required to fund natural gas storage inventories and changes in accounts payable, the timing of interest payments and the absence of $13.5 million of refunds of collateral deposits made in Fiscal 2006. These decreases in cash used were partially offset by the effects of the timing of and increases in natural gas prices on cash receipts from customers.

Investing activities. Cash used by investing activities was $92.3 million in Fiscal 2008, $55.2 million in Fiscal 2007, and $647.8 million in Fiscal 2006. Expenditures for property, plant and equipment were slightly lower in Fiscal 2008 compared with Fiscal 2007 while expenditures for property, plant and equipment increased $15.2 million in Fiscal 2007 compared with Fiscal 2006. The decrease in Fiscal 2008 capital expenditures compared with Fiscal 2007 principally reflects lower Gas Utility capital expenditures associated with its multi-year automated meter reading project. The increase in Fiscal 2007 capital expenditures over Fiscal 2006 reflects in large part the full-year effects of PNG Gas. Cash used by investing activities in Fiscal 2006 includes $585.2 million associated with the PG Energy Acquisition. Cash flow from investing activities in Fiscal 2007 includes the payment of $23.7 million by SU to UGI Utilities associated with a PG Energy Acquisition working capital adjustment (see Note 2 to Consolidated Financial Statements).

Financing activities. Cash used by financing activities was $63.0 million in Fiscal 2008 and $65.0 million in Fiscal 2007 while cash provided by financing activities was $637.4 million in Fiscal 2006. Financing activities cash flows are primarily the result of issuances and repayments of long-term debt, net short-term borrowings (principally borrowings under the Revolving Credit Agreement), cash dividends to UGI, and capital contributions from UGI. In January 2008, UGI Utilities issued $20 million of 5.67% Medium-Term Notes and used the proceeds to reduce Revolving Credit Agreement borrowings. In June 2007, UGI Utilities refinanced $20 million of maturing 7.17% Medium-Term Notes with proceeds from the issuance of $20 million of 6.17% Medium-Term Notes. Long-term debt issued in Fiscal 2006 included $275 million of Senior Notes in conjunction with the PG Energy Acquisition, the refinancing of $50 million of maturing Medium-Term Notes, and a $20 million borrowing under an uncommitted facility in June 2006 which was repaid in September 2006. Fiscal 2006 also includes the repayment of two $35 million short-term borrowings under uncommitted arrangements. Net bank loan (repayments) borrowings totaled $(133.0) million in Fiscal 2008, $(26.0) million in Fiscal 2007, and $204.8 million in Fiscal 2006. As previously mentioned, in connection with the October 1, 2008 CPG Acquisition, UGI made a $120 million cash contribution to UGI Utilities on September 25, 2008. This cash contribution was used by UGI Utilities to reduce bank loan borrowings. On October 1, 2008, UGI Utilities borrowed under its Revolving Credit Agreement to fund a portion of the CPG Acquisition.

UGI Utilities Pension Plans

UGI Utilities sponsors two defined benefit pension plans (“Pension Plans”) for employees of UGI Utilities, UGIPNG, UGI, and certain of UGI’s other subsidiaries. The fair value of Pension Plans’ assets totaled $241.0 million and $290.1 million at September 30, 2008 and 2007, respectively. At September 30, 2008 and 2007, the underfunded position of Pension Plans, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plans’ assets, was $59.6 million and $9.3 million, respectively. The increase in the underfunded status at September 30, 2008 resulted from changes in the fair values of Pension Plans’ assets due to the general decline in the financial markets during Fiscal 2008.

Effective January 1, 2009, participation in Pension Plans will be closed to new hires, rehires or first transfers from affiliates. In lieu of participation in Pension Plans, these employees will receive enhanced benefits under our Company-sponsored 401(k) savings plan. The impact of this change is not expected to have a material effect on Fiscal 2009 postretirement benefit plans’ expense.

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, and we do not anticipate we will be required to make contributions to Pension Plans in Fiscal 2009. Pre-tax pension cost associated with Pension Plans was $0.1 million, $1.9 million and $2.6 million in Fiscal 2008, Fiscal 2007 and Fiscal 2006, respectively. Pre-tax pension cost associated with Pension Plans in Fiscal 2009 is expected to be approximately $2.7 million.

SFAS 158 requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension as well as postretirement benefit plans such as retiree health and life, with current year changes recognized in shareholders’ equity. We adopted SFAS 158 effective September 30, 2007. In accordance with the requirements of SFAS 158, through September 30, 2008 we have recorded cumulative after-tax charges to Common Stockholder’s Equity of $39.2 million in order to reflect the funded status of these plans. For a more detailed discussion of the Pension Plans and other postretirement benefit plans, see Notes 1 and 6 to Consolidated Financial Statements.

Capital Expenditures

In the following table, we present capital expenditures by business segment for Fiscal 2008, Fiscal 2007 and Fiscal 2006. We also provide amounts we expect to spend in Fiscal 2009. We expect to finance a substantial portion of Fiscal 2009 capital expenditures from cash generated by operations and the remainder from borrowings under our Revolving Credit Agreement.


(Millions of dollars)	2009		2008		2007		2006
	(estimate)

Gas Utility	$	74.8	$	58.3	$	66.2	$	49.2
Electric Utility		5.9		6.0		7.2		9.0

	$	80.7	$	64.3	$	73.4	$	58.2

The higher Fiscal 2009 expected Gas Utility expenditures reflects capital expenditures associated with CPG.

Contractual Cash Obligations and Commitments

UGI Utilities has contractual cash obligations that extend beyond Fiscal 2008 including scheduled repayments of long-term debt and interest, operating lease obligations, unconditional purchase obligations for pipeline transportation and natural gas storage services, commitments to purchase natural gas and electricity and derivative instruments. The following table presents significant contractual cash obligations under agreements existing as of September 30, 2008.


	Payments Due by Period
			Fiscal		Fiscal		Fiscal
(Millions of dollars)	Total		2009		2010-2011		2012-2013		Thereafter
Long-term debt (a)	$	532.0	$	—	$	—	$	65.0	$	467.0
Interest on long-term fixed rate debt (b)		412.4		31.6		63.3		62.2		255.3
Operating leases		24.4		5.2		7.3		5.4		6.5
Gas Utility and Electric Utility supply, storage and transportation contracts		998.6		441.2		268.8		136.8		151.8
Derivative financial instruments (c)		23.5		23.5		—		—		—

Total	$	1,990.9	$	501.5	$	339.4	$	269.4	$	880.6


(a)		Based upon stated maturity dates. Excludes $108 million of 6.375% Senior Notes due 2013 issued on October 1, 2008 in connection with the CPG Acquisition.

(b)		Based upon stated interest rates. Excludes interest on $108 million of 6.375% Senior Notes due 2013 issued on October 1, 2008 in connection with the CPG Acquisition.

(c)		Represents the sum of amounts due from us if derivative financial instrument liabilities were settled at the September 30, 2008 amounts reflected in the financial statements.

The components of the other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2008 principally consist of pension and other post employment benefit liabilities recorded in accordance with SFAS 158 and estimated obligations under environmental remediation agreements. 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 of amount. The table above excludes the CPG Acquisition purchase obligation of $303.0 million (see “Subsequent Event — Acquisition of PPL Gas Utilities Corporation and Penn Fuel Propane, LLC” below).

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 UGI’s other 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 totaled $11.8 million in Fiscal 2008, $11.6 million in Fiscal 2007 and $10.7 million in Fiscal 2006 and are classified as operating and administrative expenses — related parties in the Consolidated Statements of Income. 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 were not material.

UGI Utilities has entered into a Storage Contract Administration Agreement (“Storage Agreement”), extending through October 31, 2008, with UGI Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI. Under the Storage Agreement, UGI Utilities has, among other things, released certain storage and transportation contracts to Energy Services for the term of the Storage Agreement. UGI Utilities also transferred certain associated storage inventories upon the commencement of the Storage Agreement, will receive a transfer of storage inventories at the end of the Storage Agreement, and makes payments associated with refilling storage inventories during the term of the Storage Agreement. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the Storage Agreement. UGI Utilities incurred costs associated with the Storage Agreement totaling $111.8 million in Fiscal 2008, $92.7 million in Fiscal 2007 and $85.8 million in Fiscal 2006.

The carrying value of these gas storage inventories at September 30, 2008, comprising approximately 8.3 billion cubic feet of natural gas, was $70.8 million. The carrying value of these gas storage inventories at September 30, 2007, comprising approximately 8.2 billion cubic feet of natural gas, was $66.1 million.

UGI Utilities also has a Gas Supply and Delivery Service Agreement with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to UGI Utilities during the peak heating-season months of November to March. In addition, from time to time, UGI Utilities purchases natural gas or pipeline capacity from Energy Services. The aggregate amount of these transactions during Fiscal 2008, Fiscal 2007 and Fiscal 2006 (exclusive of Storage Agreement transactions described above) totaled $52.6 million, $36.3 million and $15.1 million, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During Fiscal 2008, Fiscal 2007 and Fiscal 2006, revenues associated with sales to Energy Services totaled $66.1 million, $39.6 million, and $14.1 million, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

OFF-BALANCE SHEET ARRANGEMENTS

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

REGULATORY MATTERS

Since 1999, all natural gas consumers in Pennsylvania, including core market customers, have been able to purchase gas supplies from entities other than NGDCs. Under the Gas Competition Act, NGDCs, like UGI Gas and PNG Gas, continue to serve as the suppliers of last resort for all core market customers, and such sales of gas, as well as the distribution service provided by NGDCs, continue to be subject to rate regulation by the PUC. As of September 30, 2008, fewer than 1% of Gas Utility’s core market customers purchase their gas from alternate suppliers.

In an order entered on November 30, 2006, the PUC approved a settlement of a PNG Gas base rate proceeding. The settlement authorized PNG Gas to increase annual base rates $12.5 million, or approximately 4%, effective December 2, 2006.

As a result of the Electricity Generation Customer Choice and Competition Act that became effective January 1, 1997, all of Electric Utility’s customers have the ability to acquire their electricity from entities other than Electric Utility. As of September 30, 2008, none of Electric Utility’s customers have chosen an alternative electricity generation supplier and no alternate suppliers of electricity are currently offering such service in Electric Utility’s service territory. Electric Utility remains the provider of last resort, or default service provider, for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides 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 in June 23, 2006.

Electric Utility’s POLR service rules provide for annual shopping periods during which customers may elect to remain on POLR service or choose an alternate supplier, if available. Customers who do not select an alternate supplier are obligated to remain on POLR service until the next shopping period. Residential customers who return to POLR service must remain on POLR service until the date of the second open shopping period after returning. Commercial and industrial customers who return to POLR service must remain on POLR service until the next open shopping period, and may, in certain circumstances, be subject to generation rate surcharges.

In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement, Electric Utility’s POLR rates increased 3% on January 1, 2006. Electric Utility also increased its POLR rates effective January 1, 2007, which increased the average cost to a residential heating customer by approximately 35% over such costs in effect during calendar year 2006, and increased its POLR rates effective January 1, 2008, which increased the average cost to a residential heating customer by approximately 5.5% over such costs in effect during calendar year 2007. Effective January 1, 2009, average residential heating customer rates will increase by approximately 1.5%. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its customers.

On July 17, 2008, the PUC approved Electric Utility’s default service procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s default service regulations. These plans do not affect Electric Utility’s existing POLR Settlement effective through December 31, 2009. The approved plans specify how Electric Utility will solicit and acquire default service supplies for residential customers for the period January 1, 2010 through May 31, 2014, and for commercial and industrial customers for the period January 1, 2010 through May 31, 2011 (collectively the “Settlement Term”). UGI Utilities filed a rate plan on August 29, 2008 for the Settlement Term. Under applicable statutory standards, Electric Utility is entitled to fully recover its default service costs.

Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010 Electric Utility will no longer be subject to the risks that actual costs for purchased power will exceed POLR revenues. However, beginning January 1, 2010, Electric Utility will forego the opportunity to recover revenues in excess of actual costs as currently permitted under the POLR Settlement. During Fiscal 2008, such excess of revenues over actual costs was material to UGI Utilities’ results of operations. Although we believe the impact of the approved default service plans will be material to the Electric Utility’s results of operations beginning in Fiscal 2010, we believe such impact will not be material to UGI Utilities because it will be offset by expected increases in operating income from our Gas Utility.

We account for the operations of Gas Utility and Electric Utility in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated operations and that the recovery of our regulatory assets is probable.

MANUFACTURED GAS PLANTS

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 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 those which now constitute UGI Gas and Electric Utility. At September 30, 2008, neither the Company’s undiscounted amount nor its accrued liability for environmental investigation and cleanup costs was material.

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. In accordance with the terms of the PNG Gas base rate case order which became effective December 2, 2006, site-specific environmental investigation and remediation costs associated with PNG Gas incurred prior to December 2, 2006 are amortized as removal costs over five-year periods. Such costs incurred after December 1, 2006 are expensed as incurred.

As a result of the PG Energy Acquisition, UGIPNG became a party to a Multi-Site Remediation Consent Order and Agreement between PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform a specified level of activities associated with environmental investigation and remediation work at 11 currently owned properties on which MGP-related facilities were operated (“Properties”). Under the Multi-Site Agreement, environmental expenditures, including costs to perform work on the Properties, are capped at $1.1 million in any calendar year. The Multi-Site Agreement 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.

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. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.

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 47% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 million in remediation costs and $26 million in third-party claims relating to the site and estimates that future remediation costs could be as high as $2.5 million. SCE&G further asserts that it has received a demand from the United States Justice Department for natural resource damages. UGI Utilities is defending the suit.

City of Bangor, Maine v. Citizens Communications Company. In April 2003, Citizens Communications Company (“Citizens”) 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 plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that through ownership and control of a subsidiary, Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18 million to clean up the river. Citizen’s third-party claims were stayed pending trial of the City’s suit against Citizens, which took place in September 2005. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. On February 14, 2007, Citizens and the City entered into a settlement agreement pursuant to which Citizens agreed to pay $7.6 million in exchange for a release of its and all predecessors’ liabilities. Separately, the Maine Department of Environmental Protection has disclaimed its previously announced intention to pursue third-party defendants, including UGI Utilities, for costs incurred by the State of Maine related to contaminants at this site. UGI Utilities believes that it has good defenses to all Citizens’ claims.

Consolidated Edison Company of New York v. UGI Utilities, Inc. On September 20, 2001, Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at twelve former MGP sites in Westchester County, New York. The complaint alleged that UGI Utilities “owned and operated” the MGPs prior to 1904 as a result of control of subsidiaries that owned the MGPs and at three sites where UGI Utilities allegedly operated the MGPs under lease with the owner.

UGI Utilities successfully moved for summary judgment on all but the three sites where UGI Utilities allegedly operated the MGP sites under lease. On June 17, 2008, UGI Utilities and ConEd agreed to a settlement with respect to the three remaining sites. UGI Utilities’ obligations under the settlement agreement will not have a material effect on the Company’s operating results or financial condition.

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend another $11 million 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 million. KeySpan believes that the cost could be as high as $20 million. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.

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 seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of its subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215 million and asserted that UGI Utilities is responsible for approximately $103 million of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23 million. UGI Utilities is defending the suit. Trial is scheduled for April 2009.

MARKET RISK DISCLOSURES

As previously mentioned, Gas Utility’s tariffs contain clauses that permit recovery of substantially 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 contracts to reduce volatility in the cost of gas it purchases for its retail core-market customers. The fair value of these contracts at September 30, 2008 and 2007 were losses of $23.3 million and $0.6 million, respectively. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. At September 30, 2008 and 2007, Gas Utility had approximately $34.0 million and $6.6 million, respectively, of restricted cash associated with natural gas futures accounts with brokers.

Electric Utility purchases its electric power needs from electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market. Wholesale prices for electricity can be volatile especially during periods of high demand or tight supply. As previously mentioned and in accordance with POLR settlements approved by the PUC, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. Electric Utility’s fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 31, 2009. With respect to its existing fixed-price power contracts, should any of the counterparties fail to provide electric power under the terms of such contracts, any increases in the cost of replacement power could negatively impact Electric Utility results. In order to reduce this nonperformance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. From time to time, Electric Utility enters into electric price swap agreements to reduce the volatility in the cost of a portion of its anticipated electricity requirements. There were no price swaps outstanding at September 30, 2008. At September 30, 2007, Electric Utility had an electric price swap agreement associated with purchases of a portion of electricity anticipated to occur through December 2007.

As previously mentioned, on July 17, 2008, the PUC approved the Electric Utility’s default service plans filed in accordance with the PUC’s default service regulations. Under applicable statutory standards, Electric Utility is entitled to fully recover its default service costs. Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010, Electric Utility will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues.

Electric Utility obtains financial transmission rights (“FTRs”) through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, from purchases through monthly PJM auctions. FTRs are 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 electricity 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. Although FTRs are economically effective as hedges of congestion charges, they do not currently qualify for hedge accounting treatment. At September 30, 2008, the fair value of Electric Utility’s FTRs was $0.5 million. A 10% adverse change in the market value of FTRs would not have a material impact on the Company’s operating income.

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

Our variable-rate debt includes our bank loan borrowings. These debt agreements provide 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 2008 and Fiscal 2007, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $1.2 million and $1.6 million, respectively.

The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of $34.4 million and $40.3 million at September 30, 2008 and 2007, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $38.8 million and $46.1 million at September 30, 2008 and 2007, respectively.

In order to reduce interest rate risk associated with near or medium term issuances of fixed-rate debt, we may enter into interest rate protection agreements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements and related disclosures in compliance with accounting principles generally accepted in the United States of America 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 SFAS No. 141, “Business Combinations” (“SFAS 141”), the purchase price is allocated to the various assets and liabilities acquired at their estimated fair value. Fair values of assets are based upon available information and we may involve an independent third-party to perform appraisals. Estimating fair values can be a 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 the PG Energy Acquisition resulted in the Company recording goodwill. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), 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, 2008, our goodwill totaled $161.7 million.

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 owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with accounting principles generally accepted in the United States of America, 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, 2008, UGI Utilities net property, plant and equipment totaled $1,106.9 million and we recorded depreciation expense of $39.5 million during Fiscal 2008.

Regulatory Assets and Liabilities. Gas Utility and Electric Utility’s distribution businesses are subject to regulation by the PUC. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” 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, 2008, our regulatory assets totaled $107.4 million. See Note 3 to the Consolidated Financial Statements.

Pension Plan Assumptions. The costs of providing benefits under our 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 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 bond 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 plan assets of 50 basis points to a rate of 8.0% would result in an increase in pre-tax pension cost of approximately $1.3 million in Fiscal 2009. A decrease in the discount rate of 50 basis points to a rate of 6.3% would result in an increase in pre-tax pension cost of approximately $1.4 million in Fiscal 2009.

SUBSEQUENT EVENT – ACQUISITION OF PPL GAS UTILITIES CORPORATION AND PENN FUEL PROPANE, LLC

On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas Utilities Corporation, the natural gas distribution utility of PPL Corporation, for cash consideration of $267.6 million plus estimated working capital of $35.4 million. Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central Penn, LLC, “CPP”), its retail propane distributor, sold the assets of CPP to AmeriGas Propane, L.P. (“AmeriGas OLP”), an affiliate of UGI, for cash consideration of $32 million plus estimated working capital of $1.6 million. 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 sells propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition with a combination of $120 million cash contributed by UGI on September 25, 2008, proceeds from the issuance of $108 million principal amount of 6.375% Senior Notes due 2013 and approximately $75.0 million of borrowings under UGI Utilities Revolving Credit Agreement. The cash proceeds of $33.6 million from the sale of the assets of CPP to AmeriGas OLP were used to reduce borrowings under UGI Utilities’ Revolving Credit Agreement. The acquisition of CPG will be reflected in our financial statements beginning October 1, 2008. See Note 14 to Consolidated Financial Statements.

NEWLY ADOPTED AND RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

Effective October 1, 2007, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). The impact of the adoption of FIN 48 and related disclosures are included in Notes 1 and 5 to Consolidated Financial Statements. As previously mentioned, effective September 30, 2007, we adopted SFAS No. 158. The impact of SFAS 158 and related disclosures are included in Notes 1 and 6 to Consolidated Financial Statements.

Below is a listing of recently issued accounting pronouncement by the FASB which have not yet been adopted as of September 30, 2008. See Note 1 to the Consolidated Financial Statements for additional discussion of these pronouncements.


Title of Pronouncement	Month of Issue		Effective Date
FASB Staff Position No. SFAS 142-3, “Determination of the Useful Life of Intangible Assets”		April 2008		Fiscal 2010

SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities”		March 2008		Fiscal 2009 (Second Quarter)

SFAS 141R, “Business Combinations”		December 2007		Fiscal 2010

SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51”		December 2007		Fiscal 2010

FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39”		April 2007		Fiscal 2009

SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities”		February 2007		Fiscal 2009

SFAS 157, “Fair Value Measurements”		September 2006		Fiscal 2009

FORWARD-LOOKING STATEMENTS

Information contained above in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this 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 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.


ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

“Quantitative and Qualitative Disclosures about Market Risk” are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Market Risk Disclosures” and are incorporated here 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-2 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 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 designed and functioning effectively 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 disclosure.

	(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 maintained effective internal control over financial reporting as of September 30, 2008, based on the COSO Framework.

	(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 ACCOUNTANT FEES AND SERVICES

The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent registered public accountants, in Fiscal 2008 and Fiscal 2007 were as follows:


	2008		2007
Audit Fees	$	848,898	$	978,351
Audit-Related Fees		- 0 -		- 0 -
Tax Fees		- 0 -		- 0 -
All Other Fees		- 0 -		- 0 -

Total Fees for Services Provided	$	848,898	$	978,351

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, 2008 and 2007

			Consolidated Statements of Income for the fiscal years ended September 30, 2008, 2007 and 2006

			Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2008, 2007 and 2006

			Consolidated Statements of Stockholder’s Equity for the fiscal years ended September 30, 2008, 2007 and 2006

			Notes to Consolidated Financial Statements

(2)

Financial Statement Schedule:

For the years ended September 30, 2008, 2007 and 2006

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)

3.2

Bylaws of UGI Utilities as amended through September 30, 2003

Utilities

Form 10-K (9/30/03)

3.2

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)

Incorporation by Reference

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

4.1

UGI Utilities’ Articles of Incorporation and Bylaws referred to in Exhibit Nos. 3.1 and 3.2

4.2

Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994

Utilities

Registration Statement No. 33-77514 (4/8/94)

(c)

4.3

Form of Fixed Rate Medium-Term Note

Utilities

Form 8-K (8/26/94)

4.4

Form of Fixed Rate Series B Medium-Term Note

Utilities

Form 8-K (8/1/96)

(i)

4.5

Form of Floating Rate Series B Medium-Term Note

Utilities

Form 8-K (8/1/96)

(ii)

4.6

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

4.7

Officer’s Certificate establishing Medium-Term Notes series

Utilities

Form 8-K (8/26/94)

(iv)

4.8

[Intentionally Omitted]

4.9

Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture

Utilities

Form 8-K (8/1/96)

(iv)

4.10

Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes

Utilities

Form 8-K (5/21/02)

4.1

4.11

Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture

Utilities

Form 8-K (5/21/02)

4.2

10.1

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 (9/30/95)

10.5

10.2

UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006

UGI

Form 8-K (3/27/07)

10.1

10.3

UGI Corporation 2004 Omnibus Equity Compensation Plan, as amended December 7, 2004 — Terms and Conditions as amended December 6, 2005

UGI

Form 8-K (12/6/05)

10.10

10.4

Credit Agreement, dated as of August 11, 2006, among UGI Utilities, Inc., as borrower, and Citibank, N.A., as agent, Wachovia Bank, National Association, as syndication agent, and Citizens Bank of Pennsylvania, Credit Suisse, Cayman Islands Branch, Deutsche Bank AG New York Branch, JPMorgan Chase Bank, N.A., Mellon Bank, N.A., PNC Bank, National Association, and the other financial institutions from time to time parties thereto

Utilities

Form 8-K (8/11/06)

10.1

Incorporation by Reference

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

10.5

Stock Purchase Agreement by and between PPL Corporation, as Seller, and UGI Utilities, Inc., as Buyer, dated as of March 5, 2008

Utilities

Form 8-K (3/5/08)

10.1

10.6

Amendment dated May 2, 2008 to the Stock Purchase Agreement by and between PPL Corporation, as Seller, and UGI Utilities, Inc., as Buyer, dated as of March 5, 2008

Utilities

Form 10-Q (3/31/08)

10.2

10.7

UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Nonqualified Stock Option Grant Letter dated as of January 1, 2006

UGI

Form 8-K (12/6/05)

10.4

10.8

UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006

UGI

Form 10-K (9/30/07)

10.8

10.9

UGI Corporation 2004 Omnibus Equity Compensation Plan Utilities Employees Performance Unit Grant Letter dated as of January 1, 2006

UGI

Form 10-K (9/30/06)

10.4

10.10

UGI Utilities, Inc. Executive Annual Bonus Plan effective as of October 1, 2006

Utilities

Form 10-K (9/30/07)

10.5

10.11

UGI Corporation Senior Executive Employee Severance Plan as in effect as of January 1, 2008

UGI

Form 10-Q (3/31/08)

10.1

10.12

Description of UGI Corporation Senior Executive Employee Severance Pay Plan, as amended July 25, 2006

UGI

Form 10-Q (6/30/06)

10.1

10.13

[Intentionally Omitted]

10.14

UGI Corporation 2000 Stock Incentive Plan Amended and Restated as of May 24, 2005

UGI

Form 10-K (9/30/06)

10.14

10.15

Service Agreement for comprehensive delivery service (Rate CDS) dated February 23, 1999 between UGI Utilities, Inc. and Texas Eastern Transmission Corporation

UGI

Form 10-K (9/30/00)

10.41

10.16

UGI Corporation 1997 Stock Option and Dividend Equivalent Plan Amended and Restated as of May 24, 2005

UGI

Form 10-K (9/30/06)

10.10

10.17

UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, As Amended and Restated on July 31, 2007

UGI

Form 10-K (9/30/07)

10.16

10.18

[Intentionally Omitted]

10.19

UGI Corporation 1992 Non-Qualified Stock Option Plan Amended and Restated as of May 24, 2005

UGI

Form 10-K (9/30/06)

10.39

10.20

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

Incorporation by Reference

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

10.21

UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Stock Unit Grant Letter dated as of January 1, 2008

UGI

Form 10-K (9/30/08)

10.5

10.22

Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Messrs. Trego and Terranova

Utilities

Form 10-Q (6/30/08)

10.1

10.23

Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Mr. Barney

Utilities

Form 10-Q (6/30/08)

10.2

10.24

UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Performance Unit Grant Letter dated as of January 1, 2006

UGI

Form 10-K (9/30/06)

10.7

10.25

Storage Transportation Service Agreement (Rate Schedule SST) between UGI Utilities and Columbia dated November 1, 1993, as modified pursuant to orders of the Federal Energy Regulatory Commission

Utilities

Form 10-K (9/30/02)

10.25

10.26

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)

Utilities

Form 10-K (9/30/04)

10.26

10.27

No-Notice Transportation Service Agreement (Rate Schedule CDS) between UGI Utilities and Texas Eastern Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission

Utilities

Form 10-K (9/30/02)

10.27

10.28

No-Notice Transportation Service Agreement (Rate Schedule CDS) between UGI Utilities and Texas Eastern Transmission dated October 31, 2000, as modified pursuant to various orders of the Federal Energy Regulatory Commission

Utilities

Form 10-K (9/30/02)

10.28

10.29

Firm Transportation Service Agreement (Rate Schedule FT-1) between UGI Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission

Utilities

Form 10-K (9/30/02)

10.29

10.30

Amendment No. 1 dated November 1, 2004, to the No-Notice Transportation Service Agreement (Rate Schedule CDS) between UGI Utilities and Texas Eastern Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission

Utilities

Form 10-K (9/30/04)

10.30

10.31

Firm Transportation Service Agreement (Rate Schedule FT) between UGI Utilities and Transcontinental Gas Pipe Line dated October 1, 1996, as modified pursuant to various orders of the Federal Energy Regulatory Commission

Utilities

Form 10-K (9/30/02)

10.31

Incorporation by Reference

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

10.31

(a)

Amendment dated March 20, 2007 to the Firm Transportation Service Agreement (Rate Schedule FT) dated October 1, 1996 between UGI Utilities and Transcontinental Gas Pipe Line Corporation, as modified pursuant to various orders of the Federal Energy Regulatory Commission

Utilities

Form 8-K (3/20/07)

10.1

10.32

Gas Service Delivery and Supply Agreement between UGI Utilities and UGI Energy Services, Inc. dated August 1, 2004

Utilities

Form 10-K (9/30/04)

10.32

10.33

Amendment No. 1 dated November 1, 2004, to the Firm Transportation Service Agreement (Rate Schedule FT-1) between UGI Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission

Utilities

Form 10-K (9/30/04)

10.33

10.34

Firm Transportation Service Agreement (Rate Schedule FTS) between UGI Utilities and Columbia Gas Transmission dated November 1, 2004

Utilities

Form 10-K (9/30/04)

10.34

10.35

UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Utilities Employees Nonqualified Stock Option Grant Letter dated as of January 1, 2006

UGI

Form 8-K (12/6/05)

10.5

10.36

2002 Non-Qualified Stock Option Plan Amended and Restated as of May 24, 2005

UGI

Form 10-K (9/30/06)

10.38

10.37

Description of oral employment at-will arrangements for Messrs. Trego, Barney and Knauss

Utilities

Form 10-K (9/30/05)

10.37

10.38

Description of oral employment at-will arrangements for Messrs. Greenberg and Walsh

UGI

Form 10-K (9/30/05)

10.30

10.39

Purchase and Sale Agreement by and between Southern Union Company, as Seller, and UGI Corporation, as Buyer, dated as of January 26, 2006 (See Exhibit No. 10.43)

UGI

Form 8-K (1/26/06)

10.1

10.40

Employee Agreement by and between Southern Union Company and UGI Corporation dated as of January 26, 2006 (See Exhibit No. 10.43)

UGI

Form 8-K (1/26/06)

10.2

10.41

[Intentionally Omitted]

10.42

Assignment and Assumption Agreement, dated August 24, 2006, by and between UGI Corporation, as Assignor, and UGI Penn Natural Gas, Inc., as Assignee

Utilities

Form 8-K (8/24/06)

10.1

10.43

First Amendment Agreement, dated August 24, 2006, by and between Southern Union Company, as Seller, and UGI Corporation, as Buyer

Utilities

Form 8-K (8/24/06)

10.2

Incorporation by Reference

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

10.44

Assignment and Assumption Agreement, dated August 24, 2006, by and between UGI Corporation, as Assignor, and UGI Utilities, Inc., as Assignee with respect to the Southern Union Company Pension

Utilities

Form 8-K (8/24/06)

10.3

10.45

Service Agreement (Rate FSS) dated August 16, 2004 between Columbia Gas Transmission Corporation and PG Energy

Utilities

Form 8-K (8/24/06)

10.4

10.46

Service Agreement (Rate SST) dated August 16, 2004 between Columbia Gas Transmission Corporation and PG Energy

Utilities

Form 8-K (8/24/06)

10.5

10.47

Firm Transportation Service Agreement (Rate FT) dated February 1, 1992 between Transcontinental Gas Pipe Line Corporation and PG Energy (as successor to Pennsylvania Gas and Water Company)

Utilities

Form 8-K (8/24/06)

10.6

10.48

Firm Transportation Service Agreement (Rate FT) dated July 10, 1997 between Transcontinental Gas Pipe Line Corporation and PG Energy

Utilities

Form 8-K (8/24/06)

10.7

10.49

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

10.50

Transition Services Agreement, dated October 1, 2008, by and between UGI Utilities, Inc. and PPL Corporation

Utilities

Form 8-K (10/1/08)

10.1

10.51

FSS Service Agreement No. 49789, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.)

Utilities

Form 8-K (10/1/08)

10.2

10.52

FSS Service Agreement No. 49791, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.)

Utilities

Form 8-K (10/1/08)

10.3

10.53

FSS Service Agreement No. 80935, dated October 29, 2004, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to PPL Gas Utilities Corporation)

Utilities

Form 8-K (10/1/08)

10.4

10.54

SST Service Agreement No. 49788, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.)

Utilities

Form 8-K (10/1/08)

10.5

Incorporation by Reference

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

10.55

SST Service Agreement No. 49790, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.)

Utilities

Form 8-K (10/1/08)

10.6

10.56

SST Service Agreement No. 80934, dated October 29, 2004, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to PPL Gas Utilities Corporation)

Utilities

Form 8-K (10/1/08)

10.7

*12.1

Computation of Ratio of Earnings to Fixed Charges

Code of Ethics for principal executive, financial and accounting officers

Utilities

Form 10-K (9/30/03)

*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 year ended September 30, 2008 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 year ended September 30, 2008 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, 2008


*		Filed herewith.

**		As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement.

SIGNATURES

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


	UGI UTILITIES, INC.
Date: November 21, 2008	By:	/s/ John C. Barney
		John C. Barney
		Senior 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, 2008 by the following persons on behalf of the Registrant in the capacities indicated.


Signature		Title

/s/ David W. Trego		President and Chief Executive Officer
David W. Trego		(Principal Executive Officer) and Director

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

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

/s/ John C. Barney		Sr. Vice President — Finance and Chief Financial Officer
John C. Barney		(Principal Financial Officer and Principal Accounting Officer)

/s/ Stephen D. Ban Stephen D. Ban		Director

/s/ Richard C. Gozon Richard C. Gozon		Director

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

/s/ Anne Pol Anne Pol		Director

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

/s/ James W. Stratton James W. Stratton		Director

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

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 2008.

UGI UTILITIES, INC.

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE


	Pages
Financial Statements:

Report of Independent Registered Public Accounting Firm	F-3

Consolidated Balance Sheets as of September 30, 2008 and 2007	F-4 to F-5

Consolidated Statements of Income for the years ended September 30, 2008, 2007 and 2006		F-6

Consolidated Statements of Cash Flows for the years ended September 30, 2008, 2007 and 2006		F-7

Consolidated Statements of Stockholder’s Equity for the years ended September 30, 2008, 2007 and 2006		F-8

Notes to Consolidated Financial Statements	F-9 to F-34

Financial Statement Schedule:

For the years ended September 30, 2008, 2007 and 2006:

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-2

Report of Independent Registered Public Accounting Firm

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

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1), present fairly, in all material respects, the financial position of UGI Utilities, Inc. and its subsidiaries at September 30, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2008, 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.

As discussed in Notes 1 and 4 to the consolidated financial statements, effective October 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” Additionally, as discussed in Notes 1 and 5 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement plans as of September 30, 2007.

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, 2008

F-3

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)


	September 30,
	2008			2007
ASSETS

Current assets:
Cash and cash equivalents	$	3,483		$	16,207
Restricted cash		34,037			6,642
Accounts receivable (less allowances for doubtful accounts of $10,369 and $10,824, respectively)		70,259			74,696
Accounts receivable — related parties		1,946			1,450
Accrued utility revenues		20,823			17,889
Inventories		161,272			162,259
Deferred income taxes		13,712			6,673
Regulatory assets		15,987			14,782
Derivative financial instruments		506			1,201
Prepaid expenses & other current assets		3,380			4,331

Total current assets		325,405			306,130

Property, plant and equipment
Gas Utility		1,506,195			1,467,454
Electric Utility		130,904			126,451
General		31,957			26,124

		1,669,056			1,620,029
Less accumulated depreciation and amortization		(562,135	)		(536,132	)

Net property, plant and equipment		1,106,921			1,083,897

Goodwill		161,726			162,309
Regulatory assets		91,396			88,990
Other assets		9,018			7,712


Total assets	$	1,694,466		$	1,649,038

See accompanying notes to consolidated financial statements.

F-4

UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)


	September 30,
	2008			2007
LIABILITIES AND STOCKHOLDER’S EQUITY

Current liabilities:
Bank loans	$	57,000		$	190,000
Accounts payable		57,384			60,012
Accounts payable — related parties		14,680			15,871
Employee compensation and benefits accrued		9,105			10,619
Dividends and interest accrued		8,797			15,870
Customer deposits and refunds		40,422			35,144
Accrued income taxes		3,170			1,017
Derivative financial instruments		23,488			992
Other current liabilities		10,117			13,910

Total current liabilities		224,163			343,435

Long-term debt		532,000			512,000
Deferred income taxes		171,623			175,012
Deferred investment tax credits		6,039			6,417
Other noncurrent liabilities		93,071			41,460

Total liabilities		1,026,896			1,078,324

Commitments and contingencies (Note 8)

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		466,888			346,758
Retained earnings		184,201			179,014
Accumulated other comprehensive loss		(43,778	)		(15,317	)

Total common stockholder’s equity		667,570			570,714


Total liabilities and stockholder’s equity	$	1,694,466		$	1,649,038

See accompanying notes to consolidated financial statements.

F-5

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)


	Year Ended
	September 30,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	74,027		$	74,187		$	48,641
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		41,325			40,934			26,617
Deferred income taxes, net		7,516			16,281			9,240
Provision for uncollectible accounts		18,210			14,353			10,382
Other, net		2,249			4,833			(1,098	)
Net change in:
Accounts receivable and accrued utility revenues		(19,293	)		(27,934	)		(10,091	)
Inventories		491			351			(21,409	)
Deferred fuel costs, net of changes in unsettled derivatives		21,521			(26,953	)		(17,850	)
Accounts payable		(3,311	)		14,386			(22,393	)
Electric supplier collateral deposits		—			—			(13,500	)
Other current assets		696			2,033			(3,055	)
Other current liabilities		(875	)		21,021			5,242

Net cash provided by operating activities		142,556			133,492			10,726


CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(64,351	)		(73,411	)		(58,220	)
Net costs of property, plant and equipment disposals		(521	)		(1,492	)		(1,744	)
PG Energy Acquisition		—			23,670			(585,170	)
Increase in restricted cash		(27,395	)		(3,945	)		(2,697	)

Net cash used by investing activities		(92,267	)		(55,178	)		(647,831	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends		(68,762	)		(40,006	)		(37,615	)
(Decrease) increase in bank loans with maturities of three months or less		(133,000	)		(26,000	)		204,800
Issuances of debt including bank loans with maturities greater than three months		20,000			20,000			345,000
Repayments of debt including bank loans with maturities greater than three months		—			(20,000	)		(140,000	)
Capital contribution from UGI Corporation		120,000			—			265,000
Cash portion of UGI HVAC dividend		(1,381	)		—			—
Excess tax benefits from equity-based payment arrangements		130			957			176

Net cash (used) provided by financing activities		(63,013	)		(65,049	)		637,361


Cash and cash equivalents (decrease) increase	$	(12,724	)	$	13,265		$	256


CASH AND CASH EQUIVALENTS:
End of year	$	3,483		$	16,207		$	2,942
Beginning of year		16,207			2,942			2,686

(Decrease) Increase	$	(12,724	)	$	13,265		$	256

See accompanying notes to consolidated financial statements.

F-7

UGI UTILITIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(Thousands of dollars)


								Accumulated			Total
			Additional					Other			Common
	Common		Paid-in		Retained			Comprehensive			Stockholder’s
	Stock		Capital		Earnings			Income (Loss)			Equity

Balance September 30, 2005	$	60,259	$	80,622	$	133,807		$	243		$	274,931
Net income						48,641						48,641
Net change in fair value of derivative instruments (net of tax of $3,130)									(4,413	)		(4,413	)
Reclassifications of net losses on interest rate protection agreements (net of tax of $267)									376			376

Comprehensive income						48,641			(4,037	)		44,604
Cash dividends — Common Stock						(37,615	)					(37,615	)
Capital contribution from UGI				265,000								265,000
Other				179								179

Balance September 30, 2006		60,259		345,801		144,833			(3,794	)		547,099
Net income						74,187						74,187
Net change in fair value of derivative instruments (net of tax of $21)									(30	)		(30	)
Reclassifications of net gains on derivative instruments (net of tax of $1,068)									(1,506	)		(1,506	)

Comprehensive income						74,187			(1,536	)		72,651
Adjustment to initially apply SFAS 158 (net of tax of $7,082)									(9,987	)		(9,987	)
Cash dividends — Common Stock						(40,006	)					(40,006	)
Other				957								957

Balance September 30, 2007		60,259		346,758		179,014			(15,317	)		570,714
Net income						74,027						74,027
Cumulative effect from adoption of FIN 48						(230	)					(230	)
Net change in fair value of derivative instruments (net of tax of $695)									979			979
Reclassifications of net gains on derivative instruments (net of tax of $176)									(248	)		(248	)
Benefit plans, principally actuarial losses (net of tax of $20,718)									(29,211	)		(29,211	)
Reclassifications of benefit plans actuarial losses and prior service costs (net of tax of $13)									19			19

Comprehensive income						73,797			(28,461	)		45,336
Cash dividends — Common Stock						(68,762	)					(68,762	)
Capital contribution from UGI				120,000								120,000
Dividend of UGI HVAC						152						152
Other				130								130

Balance September 30, 2008	$	60,259	$	466,888	$	184,201		$	(43,778	)	$	667,570

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. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Organization and Consolidation Principles

UGI Utilities, Inc., a wholly owned subsidiary of UGI Corporation (“UGI”), and its wholly owned subsidiary UGI Penn Natural Gas, Inc. (“UGIPNG”), own and operate (1) natural gas distribution utilities in eastern and northeastern Pennsylvania (“UGI Gas” and “PNG Gas,” respectively, and collectively, “Gas Utility”) and (2) an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). On August 24, 2006, UGIPNG acquired certain assets and assumed certain liabilities of Southern Union Company’s (“SU’s”) PG Energy Division and all of the issued and outstanding stock of SU’s wholly owned subsidiary PG Energy Services, Inc. (collectively, the “PG Energy Acquisition”). On October 1, 2008, UGI Utilities, Inc. acquired the stock of PPL Gas Utilities Corporation, a Pennsylvania natural gas distribution utility (see Note 14).

Effective January 1, 2007, as previously approved by the Pennsylvania Public Utility Commission (“PUC”), UGI Gas contributed its heating, ventilation and air conditioning services business to its wholly owned second-tier subsidiary, UGI HVAC Services, Inc. (“UGI HVAC”). Effective April 1, 2008, UGI Utilities transferred by dividend its ownership interest in UGI HVAC to UGI. UGI HVAC and PG Energy Services, Inc., (now known as UGI Penn Natural Gas Services, Inc.), operate principally within the Gas Utility service territory. These businesses are hereafter referred to as the “HVAC Business.”

Gas Utility and Electric Utility are subject to regulation by the PUC. The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including UGIPNG. Our financial statements are prepared in conformity with U.S. generally accepted accounting principles (“GAAP”). 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.

Use of Estimates

We make estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

Regulated Utility Operations

We account for the operations of Gas Utility and Electric Utility (collectively, “Utilities”) in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated operations and that the recovery of our regulatory assets is probable. See Note 3.

F-9

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

Deferred Fuel Costs.

Gas Utility’s tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost (“PGC”) rates. The clauses provide for periodic adjustments to PGC rates for the difference between the total amount of purchased gas costs collected from customers and the recoverable costs incurred. In accordance with SFAS 71, we defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers.

Consolidated Statements of Cash Flows

We define cash equivalents as all highly liquid investments with maturities of three months or less when purchased. We record cash equivalents at cost plus accrued interest, which approximates market value. Restricted cash represents those cash balances in our commodity futures brokerage accounts which are restricted from withdrawal.

We paid interest totaling $44,273 in Fiscal 2008, $32,944 in Fiscal 2007 and $22,131 in Fiscal 2006. We paid income taxes totaling $40,625 in Fiscal 2008, $27,547 in Fiscal 2007 and $24,939 in Fiscal 2006.

Revenue Recognition

We record regulated revenues for distribution service and commodity charges provided to the end of each month which includes an accrual for certain unbilled amounts based upon estimated usage. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered.

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

Inventories

Our inventories are stated at the lower of cost or market. Substantially all of our inventory is determined on an average cost method.

Inventories comprise the following at September 30:


	2008		2007
Utility fuel and gases	$	155,843	$	156,921
Appliances for sale		—		543
Materials, supplies and other		5,429		4,795


Total inventories	$	161,272	$	162,259

UGI Utilities has storage contract administrative agreements pursuant to which UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the storage agreements. UGI Utilities also transferred certain associated storage inventories upon commencement of the storage agreements, will receive a transfer of storage inventories at the end of the storage agreements, and makes payments associated with refilling storage inventories during the term of such agreements. Included among these contract administrative agreements is an agreement with UGI Energy Services, Inc., a second-tier, wholly owned subsidiary of UGI (see Note 12). The historical cost of natural gas storage inventories released under these agreements, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreements but not yet replenished), are included in the caption “Utility fuel and gases” in the table above. The carrying value of gas storage inventories released under these agreements at September 30, 2008 and 2007 comprising 9.8 billion cubic feet (“bcf”) and 8.2 bcf of natural gas was $81,182 and $66,113, respectively.

F-10

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

Income Taxes

We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits 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 the Company’s plant additions over the service lives of the related property. The Company 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.

Effective October 1, 2007, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). For a more detailed discussion of the effects of FIN 48 and related disclosures, see “Newly Adopted Accounting Standards” below and Note 5.

Property, Plant and Equipment and Related Depreciation

We record property, plant and equipment at cost. When Gas Utility and Electric Utility retire depreciable utility plant and equipment, we charge the original cost, net of removal costs and salvage value, to accumulated depreciation for financial accounting purposes.

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


	2008		2007
Utilites:
Distribution	$	1,520,346	$	1,465,911
Transmission		28,547		27,593
General and other		120,163		126,300
Non-utility		—		225

Total property, plant and equipment	$	1,669,056	$	1,620,029

We record depreciation expense for plant and equipment on a straight-line method over the estimated average remaining lives of the various classes of depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.4% in Fiscal 2008, 2.7% in Fiscal 2007 and 2.5% in Fiscal 2006. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.6% in Fiscal 2008, 2.7% in Fiscal 2007 and 2.8% in Fiscal 2006. Depreciation expense was $39,464 in Fiscal 2008, $39,176 in Fiscal 2007 and $25,501 in Fiscal 2006.

F-11

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

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.

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 2008, Fiscal 2007 or Fiscal 2006.

Goodwill

The goodwill reflected on our Consolidated Balance Sheet at September 30, 2008 and 2007 reflects the final purchase price allocation of the PG Energy Acquisition. In accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), our goodwill is not amortized but is subject to tests for impairment at least annually. SFAS 142 requires that we perform impairment tests more frequently than annually if events or circumstances indicate that the value of goodwill might be impaired. We use discounted estimates of forecasted future cash flows to perform our impairment tests. No provisions for goodwill impairments were recorded during Fiscal 2008, Fiscal 2007 or Fiscal 2006.

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 our pension and other postretirement plans’ assets. The market-related value of plan assets, other than equity investments, is based upon market prices. 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 6).

Stock-Based Compensation

Under UGI Corporation’s 2004 Omnibus Equity Compensation Plan, as Amended and Restated on 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.

F-12

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

Effective October 1, 2005, the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”). Among other things, SFAS 123R requires expensing the fair value of stock options, a previously optional accounting method. We chose the modified prospective approach which requires that the new guidance be applied to the unvested portion of all outstanding option grants as of October 1, 2005 and to new grants after that date. In accordance with SFAS 123R, all of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock, and grants of UGI Stock Units or Performance Units are measured at fair value on the grant date, date of modification, or end of the period, as applicable, and recognized in earnings over the requisite service period. 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. Equity-based compensation costs associated with the portion of UGI Unit awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with the portion of UGI Unit awards classified as liabilities are measured based upon their estimated fair value at the grant date and remeasured as of the end of each period. We recorded total net pre-tax equity-based compensation expense associated with both UGI Units and UGI stock options of $842 ($492 after-tax) during Fiscal 2008; $1,006 ($588 after-tax) during Fiscal 2007; and $367 ($215 after-tax) during Fiscal 2006.

During Fiscal 2006, the Company modified the settlement terms of UGI Unit awards previously granted to key employees on January 1, 2006. The modification did not affect the number of UGI Units awarded to employees. We did not record any incremental equity-based compensation expense as a result of this modification.

As of September 30, 2008, there was $604 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 1.9 years. As of September 30, 2008, there was a total of $711 of unrecognized compensation expense associated with 63,300 UGI Unit awards that is expected to be recognized over a weighted average period of 1.9 years. At September 30, 2008 and 2007, total liabilities of $357 and $512, 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 2008:


	Total					Vested					Non-Vested
				Weighted					Weighted					Weighted
				Average					Average					Average
	Number of			Grant Date		Number of			Grant Date		Number of			Grant Date
	UGI			Fair Value		UGI			Fair Value		UGI			Fair Value
	Units			(per Unit)		Units			(per Unit)		Units			(per Unit)
September 30, 2007		65,400		$	22.90		8,867		$	21.49		56,533		$	23.12
Granted		23,100		$	30.34		—		$	—		23,100		$	30.34
Vested		—		$	—		32,866		$	22.37		(32,866	)	$	22.37
Transferred		(1,800	)	$	23.30		—		$	—		(1,800	)	$	23.30
Performance criteria not met		(23,400	)	$	19.99		(23,400	)	$	19.99		—		$	—

September 30, 2008		63,300		$	26.68		18,333		$	24.98		44,967		$	27.37

F-13

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

Environmental and Other Legal Matters

We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Amounts accrued generally reflect 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 response 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 any 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 removal costs. In accordance with the terms of the PNG Gas base rate order which became effective December 2, 2006, site-specific environmental investigation and remediation costs associated with PNG Gas incurred prior to December 2, 2006 are amortized as removal costs over five-year periods. Such costs incurred after December 1, 2006 are expensed as incurred.

Similar to environmental issues, we also accrue for other pending claims and legal actions or matters when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated (see Note 8).

Derivative Instruments

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It 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.

All of Gas Utility’s natural gas derivative financial instruments, which hedge variability in the cost of natural gas, are includable in deferred fuel costs in accordance with SFAS 71 and reflected in cost of sales through the application of the PGC mechanism. Substantially all of our other derivative financial instruments qualify and are designated as cash flow hedges. Our derivative financial instruments that qualify as cash flow hedges relate principally to the variability in cash flows associated with purchases of electricity and the variability of interest rates associated with anticipated issuances of long-term debt. At September 30, 2008, there were no unsettled derivative financial instruments that qualify as cash flow hedges outstanding.

For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income, 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.

We also use Financial Transmission Rights (“FTRs”) to hedge a portion of electricity transmission costs associated with Electric Utility’s service obligations. Although FTRs are economically effective as hedges of certain electricity transmission costs, they do not currently qualify for hedge accounting treatment. Accordingly, FTRs are recorded at fair value with changes in fair value reflected in cost of sales.

Gains and losses on derivative financial instruments qualifying as cash flow hedges of variability in purchase prices of electricity are recorded in cost of sales on the Consolidated Statements of Income. Gains and losses on derivative financial instruments qualifying as cash flow hedges of variability in interest rates, when recognized, are recorded in interest expense. The portion of any gains or losses on cash flow hedges determined to be ineffective, or any portion of gains or losses excluded from the measurement of the hedging relationship’s effectiveness, are recorded in other income, net. Cash flows from derivative financial instruments are included in cash flows from operating activities.

For a detailed description of the derivative instruments we use, our objectives for using them, and related supplemental information required by SFAS 133, see Note 9.

F-14

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

Comprehensive Income

Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive loss of $28,461, $1,536 and $4,037 for Fiscal 2008, Fiscal 2007 and Fiscal 2006, respectively, reflects actuarial gains and losses on postretirement benefit plans subsequent to the adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (“SFAS 158”), gains or losses on interest rate protection agreements (“IRPAs”) and, through the date of its expiration in December 2007, changes in the fair value of an electric price swap agreement, net of reclassifications to net income. Fiscal 2007 accumulated other comprehensive loss also includes an after-tax charge of $9,987 associated with the initial adoption of SFAS 158 (see “Newly Adopted Accounting Standards” below).

Newly Adopted Accounting Standards

Effective October 1, 2007, we adopted FIN 48, “Accounting for Uncertainty in Income Taxes,” which provides a comprehensive model for the recognition, measurement and disclosure in financial statements of uncertain income tax positions that a company has taken or expects to take on a tax return. Under FIN 48, a company can recognize the benefit of an income tax position only if it is more likely than not (likelihood greater than 50%) that the tax position will be sustained upon tax examination, based solely on the technical merits of the tax position. Otherwise, no benefit can be recognized. Additionally, companies are required to accrue interest and related penalties, if applicable, on all tax exposures for which reserves have been established consistent with jurisdictional tax laws. Any cumulative effect from the adoption of FIN 48 is recorded as an adjustment to opening retained earnings. As a result of the adoption of FIN 48, effective October 1, 2007 we recorded a non-cash reduction to retained earnings of $230.

SFAS 158 became effective for us as of September 30, 2007 and requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and postretirement benefit plans such as retiree health and life, with current year changes recognized in shareholders’ equity. SFAS 158 did not change the existing criteria for measurement of periodic benefit costs, plan assets or benefit obligations. The incremental effect of the initial adoption of SFAS 158 reduced our stockholder’s equity at September 30, 2007 by $9,987.

Recently Issued Accounting Standards Not Yet Adopted

In April 2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP SFAS 142-3”). FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”), and other applicable accounting literature. FSP SFAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 (Fiscal 2010) and must be applied prospectively to intangible assets acquired after the effective date. We are currently evaluating the provisions of FSP SFAS 142-3.

F-15

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 requires enhanced disclosures in the following areas: (1) qualitative disclosures about the overall objectives and strategies for using derivatives; (2) quantitative disclosures on the fair value of the derivative instruments and related gains and losses in a tabular format; and (3) credit-risk-related contingent features in derivative instruments. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008 (second quarter of Fiscal 2009). We are currently evaluating the impact of the provisions of SFAS 161 on our future disclosures.

In December 2007, the FASB issued SFAS 141R (“Business Combinations”). SFAS 141R applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS 141R 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. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008 (Fiscal 2010). Among the more significant changes in accounting for acquisitions are (1) transaction costs will generally be expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, will generally be 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 will be recognized in operations (rather than decreases in goodwill). Generally, the effects of SFAS 141R will depend on future acquisitions.

Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 establishes accounting and reporting standards that require, among other things, (1) ownership interests in subsidiaries held by parties other than the parent be presented within stockholder’s equity, but separate from the parent’s equity; (2) earnings attributable to minority interests will be included in net earnings, although such earnings will continue to be deducted to measure earnings per share; (3) changes in a parent’s ownership interest while retaining control be accounted for as equity transactions; and (4) any retained noncontrolling equity investments in a former subsidiary be initially measured at fair value. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (Fiscal 2010). We do not currently have any noncontrolling interests in consolidated subsidiaries.

In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP 39-1”). FSP 39-1 permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. In addition, upon the adoption, companies are permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements. FSP 39-1 requires retrospective application for all periods presented. FSP 39-1 was effective for us on October 1, 2008 (Fiscal 2009). The adoption of FSP 39-1 did not have a material effect on our earnings or financial position and will have no effect on our future cash flows.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). Under SFAS 159, we may elect to report individual financial instruments and certain items at fair value with changes in fair value reported in earnings. Once made, this election is irrevocable for those items. SFAS 159 was effective for us on October 1, 2008 (Fiscal 2009). The adoption of SFAS 159 did not impact our financial statements.

F-16

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. In February 2008, the FASB issued two final staff positions (“FSPs”) amending SFAS 157. FSP SFAS 157-1 amends SFAS 157 to exclude SFAS No. 13, “Accounting for Leases,” and its related interpretive accounting pronouncements that address leasing transactions. FSP SFAS 157-2 delays the effective date of SFAS 157 until fiscal years beginning after November 15, 2008 for non-financial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a non-recurring basis. The standard, as amended, applies prospectively to new fair value measurements for the Company as follows: on October 1, 2008 (Fiscal 2009) the standard applies to our measurements of fair values of financial instruments and recurring fair value measurements of non-financial assets and liabilities; on October 1, 2009 (Fiscal 2010), the standard will apply to all remaining fair value measurements including nonrecurring measurements of non-financial assets and liabilities such as measurement of potential impairments of goodwill, other intangible assets and other long-lived assets. It will also apply to non-financial assets acquired and liabilities assumed that are initially measured at fair value in a business combination but that are not subject to remeasurement at fair value in subsequent periods. SFAS 157 is not expected to have a material effect on our earnings or financial position and will have no effect on our future cash flows.

2. ACQUISITION OF PG ENERGY

On August 24, 2006, UGI Utilities acquired certain assets and assumed certain liabilities of SU’s PG Energy Division, a natural gas distribution utility located in northeastern Pennsylvania, and all of the issued and outstanding stock of SU’s wholly-owned subsidiary, PG Energy Services, Inc., pursuant to a Purchase and Sale Agreement, as amended, between SU and UGI dated January 26, 2006 (the “Agreement”). UGI subsequently assigned its rights under the Agreement to UGI Utilities. The PG Energy Acquisition increased UGI Utilities’ presence in northeastern Pennsylvania by adding approximately 158,000 natural gas customers. On August 24, 2006 and in accordance with the terms of the Agreement, UGI Utilities paid SU $580,000 in cash. The cash payment of $580,000 was funded with net proceeds from the issuance of $275,000 of UGI Utilities’ bank loans under a Credit Agreement dated as of August 18, 2006 (the “Bridge Loan”), cash capital contributions from UGI of $265,000 and borrowings under UGI Utilities’ Revolving Credit Agreement for working capital. In September 2006, UGI Utilities repaid the Bridge Loan with proceeds from the issuance of $175,000 of 5.75% Senior Notes due 2016 and $100,000 of 6.21% Senior Notes due 2036. Pursuant to the terms of the Agreement, the initial purchase price was subject to a working capital adjustment equal to the difference between $68,100 and the actual working capital as of the closing date agreed to by both UGI Utilities and SU. In March 2007, UGI Utilities and SU reached an agreement on the working capital adjustment pursuant to which SU paid UGI Utilities approximately $23,700 in cash.

During Fiscal 2007, UGI Utilities completed its review and determination of the fair value of the assets acquired and liabilities assumed. The purchase price of the PG Energy Acquisition, including transaction fees and expenses of approximately $11,000, has been allocated to the assets acquired and liabilities assumed as follows:


Working capital	$	47,345
Property, plant and equipment		362,304
Goodwill		162,309
Regulatory assets		14,957
Other assets		4,033
Noncurrent liabilities		(23,619	)

Total	$	567,329

F-17

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

Substantially all of the goodwill is deductible for income tax purposes over a fifteen-year period.

The operating results of PNG Gas are included in our consolidated results beginning August 24, 2006. The following table presents unaudited pro forma income statement data for Fiscal 2006 as if the PG Energy Acquisition had occurred as of the beginning of those periods:


	2006
	(pro forma)
Revenues	$	1,146,700
Net loss	$	(38,200	)

The pro forma results of operations reflect PNG Gas’ historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The pro forma amounts are not necessarily indicative of the operating results that would have occurred had the PG Energy Acquisition been completed as of the date indicated, nor are they necessarily indicative of future operating results. The unaudited pro forma net loss for Fiscal 2006 includes the effects of a writedown of goodwill of $98,000 recorded by SU during the three months ended December 31, 2005.

3. 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:


	2008		2007
Regulatory assets:
Income taxes recoverable	$	73,695	$	72,040
Postretirement benefits		4,321		4,868
Environmental costs		9,009		8,255
Deferred fuel costs		15,987		14,782
Other		4,371		3,827

Total regulatory assets	$	107,383	$	103,772

Regulatory liabilities:
Postretirement benefits	$	8,886	$	7,502

Total regulatory liabilities	$	8,886	$	7,502

Income taxes recoverable. This regulatory asset is the result of recording, as required by SFAS No. 109, “Accounting for Income Taxes,” 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 expected to be recovered through the ratemaking process. Based upon current regulatory ratemaking and income tax laws, at September 30, 2008, UGI Utilities expects to recover deferred income taxes associated with these temporary differences over the average remaining lives of the associated property ranging from 1 to approximately 50 years.

F-18

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

Postretirement benefits. The PUC has authorized UGI Utilities to recover certain early retirement benefit costs as well as other postretirement benefit costs incurred subsequent to the adoption of SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“SFAS 106”), but prior to such amounts being reflected in tariff rates. These costs are reflected as regulatory assets in the table above. At September 30, 2008, UGI Utilities expects to recover these costs over periods ranging from 1 to 11 years.

Gas Utility and Electric Utility are also recovering ongoing SFAS 106 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 SFAS 106 are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above. In addition, as a result of the adoption of SFAS 158, Utilities’ postretirement regulatory liability is adjusted annually to reflect changes in the funded status of UGI Gas’ and Electric Utility’s postretirement benefit plan.

Environmental costs. Environmental costs represent the portion of estimated probable environmental remediation and investigation costs that PNG Gas expects to incur in conjunction with the UGIPNG Multi-State Remediation Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 8). PNG Gas is currently recovering and expects to continue to recover these costs in rates. At September 30, 2008, PNG Gas expects to recover these costs over a period of 11 years.

Deferred fuel costs and refunds. Gas Utility’s tariffs contain clauses which permit recovery of certain purchased gas costs through the application of PGC rates. The clauses provide for periodic adjustments to PGC rates for differences between the total amount of purchased gas costs collected from customers and recoverable costs incurred. Net undercollected gas 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 refunds or costs. Unrealized losses on such contracts at September 30, 2008, and September 30, 2007 were $23,321 and $596, respectively. UGI Utilities expects to recover or refund deferred fuel costs generally over a period of 1 to 2 years.

Other. Other regulatory assets comprise a number of items including, among others, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2008, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.

UGI Utilities regulatory liabilities relating to postretirement benefits are included in “Other noncurrent liabilities” on the Consolidated Balance Sheets. Utilities does not recover a rate of return on its regulatory assets.

Other Regulatory Matters

In an order entered on November 30, 2006, the PUC approved a settlement of a PNG Gas base rate proceeding. The settlement authorized PNG Gas to increase annual base rates $12,500, or approximately 4%, effective December 2, 2006.

As a result of Pennsylvania’s Electricity Generation Customer Choice and Competition Act that became effective January 1, 1997, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. Electric Utility remains the provider of last resort (“POLR”) for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides 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 may increase its POLR rates up to certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement, Electric Utility increased its POLR rates effective January 1, 2008, which increased the average cost to a residential heating customer by approximately 5.5% over such cost in effect during calendar year 2007. Electric Utility also increased its POLR rates effective January 1, 2007, which increased the average cost to a residential heating customer by approximately 35% over such costs in effect during calendar year 2006, and increased its POLR rates approximately 3% on January 1, 2006.

F-19

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

On July 17, 2008, the PUC approved Electric Utility’s default service procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s default service regulations. These plans do not affect Electric Utility’s existing POLR settlement effective through December 31, 2009. The approved plans specify how Electric Utility will solicit and acquire default service supplies for residential customers for the period January 1, 2010 through May 31, 2014, and for commercial and industrial customers for the period January 1, 2010 through May 31, 2011 (collectively the “Settlement Term”). UGI Utilities filed a rate plan on August 29, 2008. Under applicable statutory standards, Electric Utility is entitled to fully recover its default service costs

4. DEBT

Long-term debt comprises the following at September 30:


	2008		2007
Senior Notes:
5.75% Notes, due October 2016	$	175,000	$	175,000
6.21% Notes, due October 2036		100,000		100,000
Medium-Term Notes:
5.53% Notes, due September 2012		40,000		40,000
5.37% Notes, due August 2013		25,000		25,000
5.16% Notes, due May 2015		20,000		20,000
7.37% Notes, due October 2015		22,000		22,000
5.64% Notes, due December 2015		50,000		50,000
6.17% Notes, due June 2017		20,000		20,000
7.25% Notes, due November 2017		20,000		20,000
5.67% Notes, due January 2018		20,000		—
6.50% Notes, due August 2033		20,000		20,000
6.13% Notes, due October 2034		20,000		20,000

Total long-term debt	$	532,000	$	512,000

There are no principal payments of long-term debt due through Fiscal 2011 and $40,000 is due in September 2012.

UGI Utilities has a revolving credit agreement (“Revolving Credit Agreement”) with banks providing for borrowings of up to $350,000 which expires in August 2011. Under The Revolving Credit Agreement, UGI Utilities may borrow at various prevailing interest rates, including LIBOR and the banks’ prime rate. UGI Utilities had borrowings outstanding under the Revolving Credit Agreement, which we classify as bank loans, totaling $57,000 at September 30, 2008 and $190,000 at September 30, 2007. In February and March 2006, we repaid two $35,000 short-term borrowings outstanding under uncommitted arrangements with major banks. There were no amounts borrowed under uncommitted arrangements during Fiscal 2008 or Fiscal 2007. The weighted-average interest rates on Revolving Credit Agreement borrowings at September 30, 2008 and 2007 were 4.36% and 5.24%, respectively. In conjunction with the October 1, 2008 acquisition of PPL Gas Utilities Corporation, UGI made a $120,000 cash contribution to UGI Utilities on September 25, 2008. This cash contribution was used by UGI Utilities to reduce borrowings under the Utilities Revolving Credit Agreement. On October 1, 2008 UGI Utilities borrowed under the Revolving Credit Agreement to fund a portion of the PPL Gas Utilities Corporation acquisition (see Note 14).

The Revolving Credit Agreement requires UGI Utilities to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

F-20

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

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


	2008			2007
Excess book basis over tax basis of property, plant and equipment	$	164,870		$	153,060
Goodwill		9,006			4,849
Regulatory assets		34,030			43,223
Derivative financial instruments		209			334
Other		1,745			2,187

Gross deferred tax liabilities		209,860			203,653


Pension plan liabilities		(21,713	)		(2,477	)
Allowance for doubtful accounts		(4,340	)		(4,388	)
Deferred investment tax credits		(2,505	)		(2,663	)
Employee-related expenses		(5,224	)		(6,446	)
Regulatory liabilities		(3,687	)		(3,113	)
Derivative financial instruments		(3,280	)		(4,114	)
Other		(11,200	)		(12,113	)

Gross deferred tax assets		(51,949	)		(35,314	)


Net deferred tax liabilities	$	157,911		$	168,339

The Company had recorded deferred tax liabilities of approximately $45,620 as of September 30, 2008 and $42,141 as of September 30, 2007 pertaining to utility temporary differences, principally a result of accelerated tax depreciation for state income tax purposes, the tax benefits of which previously were or will be flowed through to ratepayers. These deferred tax liabilities have been reduced by deferred tax assets of $2,505 at September 30, 2008 and $2,663 at September 30, 2007, pertaining to utility deferred investment tax credits. We had recorded regulatory income tax assets related to these net deferred taxes of $73,695 at September 30, 2008 and $72,040 at September 30, 2007. These regulatory income tax assets represent future revenues expected to be recovered through the ratemaking process. We will recognize this regulatory income tax asset in deferred tax expense as the corresponding temporary differences reverse and additional income taxes are incurred.

As discussed in Note 1, on October 1, 2007, we adopted FIN 48, “Accounting for Uncertainty in Income Taxes.” The adoption of FIN 48 resulted in a non-cash reduction to retained earnings of $230.

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 2004. UGI’s federal income tax returns for Fiscal 2005 and Fiscal 2006 are currently under audit. Although it is not possible to predict with certainty the timing of the conclusion of UGI’s pending federal tax audits, we anticipate that the aforementioned federal tax audits will likely be completed during Fiscal 2009. Although we cannot predict with certainty, we do not anticipate that our unrecognized federal income tax benefits will significantly increase or decrease during the next twelve months.

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. We do not expect that any unrecognized state income tax benefits will significantly increase or decrease during the next twelve months.

F-22

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

During Fiscal 2008, $57 related to interest was recognized in income taxes in the Consolidated Statement of Income. As of September 30, 2008, we have unrecognized income tax benefits totaling $945 including related accrued interest of $126. If these unrecognized tax benefits were subsequently recognized, $870 would be recorded as a benefit to income taxes on the consolidated statement of income and, therefore, would impact the effective tax rate. The amount of reasonably possible changes in unrecognized tax benefits and related interest and penalties in the next twelve months is a net reduction of approximately $532 as a result of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities.

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


	2008
Balance at October 1, 2007	$	694
Additions for tax positions of the current year		66
Additions for tax positions of prior years		185

Balance at September 30, 2008	$	945

6. EMPLOYEE RETIREMENT PLANS

Defined Benefit Pension and Other Postretirement Plans

The Company sponsors two defined benefit pension plans (“Pension Plans”) for employees of UGI Utilities, UGIPNG, UGI, and certain of UGI’s other wholly owned subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all active and retired employees.

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets and the funded status of the pension and other postretirement plans as of September 30, 2008 and 2007. 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.

F-23

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)


	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007
Change in benefit obligations:
Benefit obligations — beginning of year	$	299,441		$	306,312		$	13,822		$	17,000
Service cost		5,660			6,119			277			291
Interest cost		19,064			18,353			802			865
Actuarial gain		(9,261	)		(17,848	)		(1,794	)		(1,057	)
Plan amendments		—			352			(357	)		(2,323	)
Plan curtailment		—			—			(2,202	)		—
Benefits paid		(14,326	)		(13,847	)		(835	)		(954	)

Benefit obligations — end of year	$	300,578		$	299,441		$	9,713		$	13,822


Change in plan assets:
Fair value of plan assets — beginning of year	$	290,112		$	274,565		$	12,173		$	11,353
Actual (loss) gain on assets		(34,789	)		29,394			(1,773	)		1,150
Employer contributions		—			—			438			624
Benefits paid		(14,326	)		(13,847	)		(836	)		(954	)

Fair value of plan assets — end of year	$	240,997		$	290,112		$	10,002		$	12,173


Funded status of the plans — end of year	$	(59,581	)	$	(9,329	)	$	289		$	(1,649	)


Assets (liabilities) recorded in the balance sheet:
Prepaid assets (included in other assets)	$	—		$	—		$	701		$	760
Unfunded liabilities (included in other noncurrent liabilities)		(59,581	)		(9,329	)		(412	)		(2,409	)

Net amount recognized	$	(59,581	)	$	(9,329	)	$	289		$	(1,649	)


Amounts recorded in stockholder’s equity:
Prior service cost	$	321		$	352		$	—		$	—
Net actuarial loss (gain)		66,645			16,959			(142	)		(242	)

Total	$	66,966		$	17,311		$	(142	)	$	(242	)

In Fiscal 2009, we estimate that we will amortize $740 of net actuarial losses and $32 of prior service cost from stockholder’s equity into retiree benefit cost. In Fiscal 2008, we amortized $362 of prior service credits and no actuarial gains or losses from stockholder’s equity.

Actuarial assumptions are described below. The discount rates at September 30 are used to measure the year-end benefit obligations and the earnings effects for the subsequent year. The discount rate is based upon market-observed yields for high quality fixed income securities with maturities that correspond to the payment of benefits. 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.


	Pension Plans												Other Postretirement Plans
Weighted-average assumptions:	2008			2007			2006			2005			2008			2007			2006			2005
Discount rate		6.8	%		6.4	%		6.0	%		5.7	%		6.8	%		6.4	%		6.0	%		5.7	%
Expected return on plan assets		8.5	%		8.5	%		8.5	%		9.0	%		5.5	%		5.5	%		5.6	%		5.8	%
Rate of increase in salary levels		3.8	%		3.8	%		3.8	%		4.0	%		3.8	%		3.8	%		3.8	%		4.0	%

The ABO for the Pension Plans was $267,798 and $264,502 as of September 30, 2008 and 2007, respectively. Included in the end of year Pension Plans PBO above are $27,882 at September 30, 2008 and $25,830 at September 30, 2007 relating to employees of UGI and certain of its other subsidiaries. Included in the end of year other postretirement plans ABO above are $562 at September 30, 2008 and $694 at September 30, 2007 relating to employees of UGI and certain of its other subsidiaries.

F-24

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

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


	Pension Benefits									Other Postretirement Benefits
	2008			2007			2006			2008			2007			2006
Service cost	$	5,053		$	5,457		$	5,023		$	261		$	273		$	139
Interest cost		17,757			17,144			12,795			775			842			850
Expected return on assets		(22,702	)		(21,838	)		(17,614	)		(640	)		(596	)		(609	)
Curtailment gain		—			—			—			(2,202	)		—			—
Amortization of:
Prior service cost (benefit)		26			242			757			(388	)		(350	)		(220	)
Actuarial loss		—			866			1,650			—			115			220

Net benefit cost (income)		134			1,871			2,611			(2,194	)		284			380
Change in associated regulatory liabilities		—			—			—			3,435			3,123			2,744


Benefit cost after change in regulatory liabilities	$	134		$	1,871		$	2,611		$	1,241		$	3,407		$	3,124

Pension Plans assets are held in trust. The Company did not make any contributions to the Pension Plans in Fiscal 2008, Fiscal 2007 or Fiscal 2006 and does not believe that it will be required to make any contributions during Fiscal 2009 for ERISA funding purposes.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to fund the UGI Utilities’ postretirement benefit obligations and to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under SFAS 106. The difference between such amounts calculated under SFAS 106 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 2009 is not expected to be material.

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


			Other
	Pension		Postretirement
	Benefits		Benefits
Fiscal 2009	$	15,181	$	939
Fiscal 2010		15,788		962
Fiscal 2011		16,588		981
Fiscal 2012		17,455		973
Fiscal 2013		18,336		977
Fiscal 2014 - 2018		105,585		4,687

F-25

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

In accordance with our investment strategy to obtain long-term growth, our target asset allocations are to maintain a mix of 65% equities and the remainder in fixed income funds or cash equivalents in the Pension Plans. The targets and actual allocations for the Pension Plans’ and the VEBA trust assets at September 30 are as follows:


	Target						Pension Plan						VEBA
	Pension Plan			VEBA			2008			2007			2008			2007
Equities		65	%		60	%		63	%		63	%		57	%		66	%
Fixed income funds		35	%		30	%		37	%		37	%		34	%		29	%
Cash equivalents		N/A			10	%		N/A			N/A			9	%		5	%

UGI Common Stock comprised approximately 9% and 7% of Pension Plans’ assets at September 30, 2008 and 2007, respectively.

The assumed health care cost trend rates are 9.0% for Fiscal 2009, decreasing to 5.5% in Fiscal 2014. A one percentage point change in the assumed health care cost trend rate would increase (decrease) the Fiscal 2008 postretirement benefit cost and obligation as follows:


	1% Increase		1% Decrease
Service and interest costs in Fiscal 2008	$	14	$	(13	)
ABO at September 30, 2008	$	221	$	(199	)

We also sponsor an unfunded and non-qualified supplemental executive retirement income plan. At September 30, 2008 and 2007, the projected benefit obligations of this plan were $3,161 and $2,509, respectively. We recorded expense for this plan of $362 in Fiscal 2008, $355 in Fiscal 2007 and $522 in Fiscal 2006.

Defined Contribution Plans

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 UGI Utilities Savings Plan provides for employer matching contributions. The cost of benefits under the savings plan totaled $1,256 in Fiscal 2008, $1,069 in Fiscal 2007 and $918 in Fiscal 2006.

7. SERIES PREFERRED STOCK

We have 2,000,000 shares of Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, authorized for issuance. We had no shares of Series Preferred Stock outstanding at September 30, 2008 or 2007.

8. COMMITMENTS AND CONTINGENCIES

We lease various buildings and transportation, 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 $4,858 in Fiscal 2008, $4,519 in Fiscal 2007 and $5,025 in Fiscal 2006.

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: 2009 — $5,236; 2010 — $4,115; 2011 — $3,225; 2012 — $2,868; 2013 — $2,515; after 2013 — $6,482.

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 2029. Gas Utility’s costs associated with transportation and storage service agreements are included in its annual PGC filing 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.

F-26

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

Electric Utility purchases its electric energy needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2012.

Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2008 for fiscal years ending September 30 are as follows: 2009 — $441,178; 2010 — $168,438; 2011 — $100,430; 2012 — $89,232; 2013 — $47,530; after 2013 — $151,840.

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 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.

As a result of the PG Energy Acquisition, UGIPNG became a party to a Multi-Site Remediation Consent Order and Agreement between PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform annually a specified level of activities associated with environmental investigation and remediation work at 11 currently owned properties on which MGP-related facilities were operated (“Properties”). Under the Multi-Site Agreement, environmental expenditures, including costs to perform work on the Properties, are capped at $1,100 in any calendar year. The Multi-Site Agreement 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. At September 30, 2008, our accrued liability for environmental investigation and remediation costs related to the Multi-Site Agreement was $9,009.

F-27

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

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 47% of the costs associated with the site. SCE&G asserts that it has spent approximately $22,000 in remediation costs and $26,000 in third-party claims relating to the site and estimates that future remediation costs could be as high as $2,500. SCE&G further asserts that it has received a demand from the United States Justice Department for natural resource damages. UGI Utilities is defending the suit.

City of Bangor, Maine v. Citizens Communications Company. In April 2003, Citizens Communications Company (“Citizens”) 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 plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that through ownership and control of a subsidiary, Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18,000 to clean up the river. Citizen’s third-party claims were stayed pending trial of the City’s suit against Citizens, which took place in September 2005. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. On February 14, 2007, Citizens and the City entered into a settlement agreement pursuant to which Citizens agreed to pay $7,625 in exchange for a release of its and all predecessors’ liabilities. Separately, the Maine Department of Environmental Protection has disclaimed its previously announced intention to pursue third-party defendants, including UGI Utilities, for costs incurred by the State of Maine related to contaminants at this site. UGI Utilities believes that it has good defenses to all Citizens’ claims.

F-28

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

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. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.

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 seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of its subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215,000 and asserted that UGI Utilities is responsible for approximately $103,000 of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23,000. UGI Utilities is defending the suit. Trial is scheduled for April 2009.

In addition to these environmental matters, there are other pending claims and legal actions arising in the normal course of our businesses. We cannot predict with certainty the final results of environmental and other matters. 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.

9. FINANCIAL INSTRUMENTS

In accordance with its commodity hedging policy, the Company has entered into (1) natural gas futures and call option contracts to reduce volatility in the cost of gas it purchases for its retail core-market customers and (2) prior to its expiration in December 2007, an electric price swap agreement to reduce the volatility in the cost of anticipated electricity requirements. Because the cost of natural gas futures and option contracts and any associated gains or losses are included in our PGC recovery mechanism, as these contracts are recorded at fair value in accordance with SFAS 133, any gains or losses are deferred for future refund to or recovery from Gas Utility’s ratepayers. Prior to its expiration, the electric price swap was designated and qualified as a cash flow hedge under SFAS 133.

We are 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 electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts are not subject to the accounting requirements of SFAS 133, as amended, 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 or the value of the contract is directly associated with the price or value of a service.

F-29

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

From time to time we enter into interest rate protection agreements (“IRPAs”) in order to manage interest rate risk associated with planned issuances of fixed-rate long-term debt. We designate these IRPAs as cash flow hedges. Gains or losses on IRPAs are included in other comprehensive income and are reclassified to interest expense as the interest expense on the associated debt affects earnings. There were no unsettled IRPAs at September 30, 2008 or 2007.

Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, from purchases through monthly PJM auctions. FTRs are 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 electricity 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. Although FTRs are economically effective as hedges of congestion charges, they do not currently qualify for hedge accounting treatment. Accordingly, FTRs are recorded at fair value with changes in fair value reflected in cost of sales.

During Fiscal 2008, Fiscal 2007 and Fiscal 2006, gains or losses recognized in earnings as a result of hedge ineffectiveness or as a result of excluding a portion of a derivative instrument’s gain or loss from the assessment of hedge effectiveness were not material. There were no gains or losses recognized in earnings as a result of a hedged firm commitment no longer qualifying as a fair value hedge.

Gains and losses on IRPAs included in accumulated other comprehensive loss at September 30, 2008 will be reclassified into interest expense when interest on hedged issuances of fixed-rate long-term debt is reflected in net income. Included in accumulated other comprehensive income at September 30, 2008 are net after-tax losses of approximately $4,599 associated with settled IRPAs. The amount of net after-tax losses on IRPAs expected to be reclassified into net income during the next twelve months is approximately $680.

The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivatives and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amounts and estimated fair values of our remaining financial instruments assets and (liabilities) at September 30 (including unsettled derivative instruments) are as follows:


	Asset (Liability)
	Carrying			Estimated
	Amount			Fair Value

2008:
Natural gas futures contracts	$	(23,321	)	$	(23,321	)
FTRs		506			506
Long-term debt		(532,000	)		(483,853	)

2007:
Natural gas futures and option contracts	$	(596	)	$	(596	)
Electric price swap agreement		805			805
Long-term debt		(512,000	)		(506,500	)

F-30

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

We estimate the fair value of long-term debt by using current market prices and by discounting future cash flows using rates available for similar type debt.

We have financial instruments such as trade accounts receivable which could expose us to concentrations of credit risk. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different markets. At September 30, 2008 and 2007, we had no significant concentrations of credit risk.

10. 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 and northeastern 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 the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” and has been included in “Other” for periods after January 1, 2007. Prior periods have not been restated.

The accounting policies of our reportable segments are the same as those described in Note 1. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.

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

F-31

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

Financial information by business segment follows:


			Gas		Electric
	Total		Utility		Utility		Other
2008
Revenues	$	1,289,053	$	1,138,346	$	139,232	$	11,475
Cost of sales		920,413		831,066		84,312		5,035
Depreciation and amortization		41,325		37,679		3,638		8
Operating income		163,042		137,556		24,449		1,037
Interest expense		39,065		37,068		1,997		—
Income before income taxes		123,977		100,489		22,451		1,037
Total assets		1,694,466		1,582,371		112,095		—
Goodwill		161,726		161,726		—		—
Capital expenditures		64,351		58,243		6,048		60

2007
Revenues	$	1,183,247	$	1,044,946	$	121,935	$	16,366
Cost of sales		816,451		741,468		67,770		7,213
Depreciation and amortization		40,934		37,396		3,532		6
Operating income		165,093		136,586		25,995		2,512
Interest expense		42,327		39,891		2,436		—
Income before income taxes		122,766		96,695		23,559		2,512
Total assets		1,649,038		1,530,399		110,076		8,563
Goodwill		162,309		162,309		—		—
Capital expenditures		73,411		66,164		7,212		35

2006
Revenues	$	822,069	$	724,040	$	98,029	$	—
Cost of sales		573,867		522,863		51,004		—
Depreciation and amortization		26,617		23,303		3,314		—
Operating income		104,889		84,218		20,671		—
Interest expense		24,345		21,836		2,509		—
Income before income taxes		80,544		62,382		18,162		—
Total assets		1,609,743		1,504,476		105,267		—
Goodwill		182,851		182,851		—		—
Capital expenditures		58,220		49,239		8,981		—

11. OTHER INCOME, NET

Other income, net, comprises the following:


	2008			2007		2006
Non-tariff service income	$	6,191		$	5,068	$	1,023
Interest income		1,444			2,480		1,121
Postretirement benefit plan curtailment gain		2,202			—		—
Non-utility sales and installation (loss) income		(41	)		838		2,584
Other		3,128			178		(266	)

Total other income, net	$	12,924		$	8,564	$	4,462

F-32

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

12. 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 UGI’s other 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.

UGI Utilities has entered into a Storage Contract Administration Agreement (“Storage Agreement”) extending through October 31, 2008 with Energy Services. Under the Storage Agreement UGI Utilities has, among other things, released certain storage and transportation contracts to Energy Services for the term of the Storage Agreement. UGI Utilities also transferred certain associated storage inventories upon the commencement of the Storage Agreement, will receive a transfer of storage inventories at the end of the Storage Agreement, and makes payments associated with refilling storage inventories during the term of the Storage Agreement. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the Storage Agreement. UGI Utilities incurred costs associated with the Storage Agreement totaling $111,764 in Fiscal 2008, $92,683 in Fiscal 2007 and $85,839 in Fiscal 2006.

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, 2008, comprising approximately 8.3 billion cubic feet of natural gas, was $70,833. The carrying value of these gas storage inventories at September 30, 2007, comprising approximately 8.2 billion cubic feet of natural gas, was $66,113.

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 UGI Utilities during the peak heating-season months of November to March. In addition, from time to time, UGI Utilities purchases natural gas or pipeline capacity from Energy Services. The aggregate amount of these transactions (exclusive of Storage Agreement transactions) during Fiscal 2008, Fiscal 2007 and Fiscal 2006 totaled $52,603, $36,286 and $15,114, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2008, Fiscal 2007 and Fiscal 2006, revenues associated with sales to Energy Services totaled $66,126, $39,564 and $14,080, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

F-33

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)

13. 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,
	2007		2006		2008		2007		2008		2007		2008			2007
Revenues	$	364,388	$	299,324	$	519,998	$	498,816	$	235,544	$	221,687	$	169,123		$	163,420
Operating income	$	58,609	$	44,441	$	81,669	$	85,001	$	20,058	$	24,732	$	2,706		$	10,919
Net income (loss)	$	28,633	$	19,759	$	43,086	$	44,708	$	6,248	$	9,085	$	(3,940	)	$	635

14. SUBSEQUENT EVENT — ACQUISITION OF PPL GAS UTILITIES CORPORATION AND PENN FUEL PROPANE, LLC

On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas Utilities Corporation (now named UGI Central Penn Gas, Inc., “CPG”), the natural gas distribution utility of PPL Corporation (the “CPG Acquisition”), for cash consideration of $267,600 plus estimated working capital of $35,370. 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 sells propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition with a combination of $120,000 cash contributed by UGI on September 25, 2008, proceeds from the issuance of $108,000 principal amount of 6.375% Senior Notes due 2013 and approximately $75,000 of borrowings under UGI Utilities’ Revolving Credit Agreement. The cash proceeds of $33,621 from the sale of the assets of CPP to AmeriGas OLP were used to reduce borrowings under UGI Utilities’ Revolving Credit Agreement. The acquisition of CPG will be reflected in our financial statements beginning October 1, 2008.

F-34

UGI UTILITIES, INC. AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Thousands of dollars)


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

Year Ended September 30, 2008
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	10,824	$	18,210	$	(18,533	)(1)	$	10,369

					$	(132	)(4)

Other reserves:
Other, principally environmental	$	18,562	$	795	$	(4,101	)(3)	$	16,011

					$	755	(5)

Year Ended September 30, 2007
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	12,389	$	14,353	$	(16,341	)(1)	$	10,824

					$	423	(2)

Other reserves:
Other, principally environmental	$	8,868	$	2,363	$	(923	)(3)	$	18,562

					$	8,254	(2)

Year Ended September 30, 2006
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	4,562	$	10,382	$	(8,714	)(1)	$	12,389

					$	6,159	(2)

Other reserves:
Other, principally environmental	$	6,168	$	2,720	$	924	(2)	$	8,868

					$	(944	)(3)


(1)		Uncollectible accounts written off, net of recoveries

(2)		Acquisition adjustments

(3)		Payments, net

(4)		Dividend of UGI HVAC

(5)		Other adjustments

S-1


	Page
PART I:		3

Items 1. and 2. Business and Properties		3

Item 1A. Risk Factors		10

Item 1B. Unresolved Staff Comments		12

Item 3. Legal Proceedings		13

PART II:		13

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

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		14

Item 7A. Quantitative and Qualitative Disclosures About Market Risk		32

Item 8. Financial Statements and Supplementary Data		32

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		32

Item 9A. Controls and Procedures		32

Item 9B. Other Information		33

PART III:		33

Item 14. Principal Accountant Fees and Services		33

PART IV:		34

Item 15. Exhibits and Financial Statement Schedules		34

Signatures		41

F-Index to Financial Statements and Financial Statement Schedule		F-2

Exhibit 12.1
Exhibit 23
Exhibit 31.1
Exhibit 31.2
Exhibit 32


	2008			2007			2006
Current expense:
Federal	$	31,974		$	24,727		$	17,613
State		10,460			7,571			5,050

Total current expense		42,434			32,298			22,663
Deferred expense		7,894			16,667			9,647
Investment tax credit amortization		(378	)		(386	)		(407	)


Total income tax expense	$	49,950		$	48,579		$	31,903


	Year Ended September 30,
	2008		2007		2006		2005		2004
Earnings:
Earnings before income taxes	$	123,977	$	122,766	$	80,544	$	84,953	$	83,098
Interest expense		39,065		42,327		24,102		18,079		17,698
Amortization of debt discount and expense		467		462		243		247		233
Estimated interest component of rental expense		1,619		1,506		1,675		1,568		1,477

	$	165,128	$	167,061	$	106,564	$	104,847	$	102,506


Fixed Charges:
Interest expense	$	39,065	$	42,327	$	24,102	$	18,079	$	17,698
Amortization of debt discount and expense		467		462		243		247		233
Allowance for funds used during construction (capitalized interest)		139		179		85		22		11
Estimated interest component of rental expense		1,619		1,506		1,675		1,568		1,477

	$	41,290	$	44,474	$	26,105	$	19,916	$	19,419


Ratio of earnings to fixed charges		4.00		3.76		4.08		5.26		5.28


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


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


CHIEF EXECUTIVE OFFICER		CHIEF FINANCIAL OFFICER
/s/ David W. Trego		/s/ John C. Barney

David W. Trego		John C. Barney

Date: November 21, 2008		Date: November 21, 2008