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, 2007

Commission file number 1-1398

UGI UTILITIES, INC.

Pennsylvania		23-1174060
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o     Accelerated filer o     Non-accelerated filer þ

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, 2007, 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.

 

 

TABLE OF CONTENTS

				Page
PART I:					2
Items 1. and 2.		Business and Properties			2
Item 1A.		Risk Factors			9
Item 1B.		Unresolved Staff Comments			11
Item 3.		Legal Proceedings			11
PART II:					14
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			14
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			15
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			33
Item 8.		Financial Statements and Supplementary Data			33
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			33
Item 9A.		Controls and Procedures			33
Item 9B.		Other Information			34
PART III:					35
Item 14.		Principal Accounting Fees and Services			35
PART IV:					35
Item 15.		Exhibits and Financial Statement Schedules			35
		Signatures			44
Index to Financial Statements and Financial Statement Schedule					F-2
Exhibit 10.5
Exhibit 12.1
Exhibit 23
Exhibit 31.1
Exhibit 31.2
Exhibit 32

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 two 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 acquired a Pennsylvania natural gas utility business from Southern Union Company which significantly increased our natural gas distribution business. The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of UGI Utilities (“UGI Gas”) and UGI Utilities’ subsidiary, UGI Penn Natural Gas, Inc. (“UGIPNG”). Gas Utility serves approximately 478,000 customers in eastern and northeastern Pennsylvania. 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. We are subject to regulation by the Pennsylvania Public Utility Commission (“PUC”). 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.

GAS UTILITY

Service Area; Revenue Analysis

Gas Utility is authorized to distribute natural gas to approximately 478,000 customers in portions of 28 eastern and northeastern Pennsylvania counties through its distribution system of approximately 7,800 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 the 2007 fiscal year was approximately 131.8 billion cubic feet (“bcf”). System sales of gas accounted for approximately 43% of system throughput, while gas transported for residential, commercial and industrial customers (who bought their gas from others) accounted for approximately 57% 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 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 year 2007, Gas Utility purchased approximately 79 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. 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 (“Gas 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, 2007, three marketers provide gas supplies to approximately 4,100 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 recent years, Gas Utility’s margin for interruptible service has been higher than in past years due to the higher cost of oil compared to natural gas. In accordance with the PUC’s June 29, 2000 Gas Restructuring Order applicable to UGI Gas, 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 29% 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 Fiscal 2008. 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 2008. 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 year 2007, 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 9,800 residential heating customers during fiscal year 2007. Despite the nationwide slowdown in the real estate market, of those new customers, new home construction accounted for over 6,200 heating customers. If the slowdown in new home construction continues in fiscal year 2008 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 1,700.

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 year 2007, about 53% of sales volume came from residential customers, 35% from commercial customers and 12% from industrial customers.

Sources of Supply

Electric Utility has third-party generation supply contracts in place for substantially all of its expected energy requirements for fiscal years 2008 and 2009. Electric Utility distributes electricity that it purchases from others and electricity that customers purchase from other suppliers, if any. As of September 30, 2007, 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.

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. 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 (collectively, the “POLR Settlement”). Consistent with the terms of the POLR Settlement, Electric Utility’s POLR rates were increased in January 2007. Electric Utility has announced its intent to increase POLR rates in January 2008 and is permitted, but not required, to further increase its POLR rates in

January 2009. Electric Utility is the only regulated electric utility having the right, granted by the PUC or by law, to distribute electricity in its service territory. Sales of electricity for residential heating purposes accounted for approximately 19% of total sales of electricity during fiscal year 2007. Electricity competes with natural gas, oil, propane and other heating fuels for this use. For current POLR 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”) 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 distribution base rates by $12.5 million of additional revenue annually, 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 (Provider-Of-Last-Resort or “POLR” or “default service”) components in 1998. 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 annually from 2004 through 2007. Effective January 1, 2007, Electric Utility’s increase in POLR rates increased the average cost to residential customers by approximately 35% over such costs in effect during calendar year 2006. Effective January 1, 2008, total average residential rates will increase by approximately 5.5%. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its customers. New PUC default service regulations became effective on September 15, 2007, but do not disturb Electric Utility’s POLR Settlement through 2009. Under the default service regulations, Electric Utility will be required to file a default service plan with the PUC in 2008 that will establish the terms and conditions under which it will offer POLR service commencing 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 ITEM 3. “LEGAL PROCEEDINGS — Environmental Matters -Manufactured Gas Plants.”

Employees

At September 30, 2007, UGI Utilities had 1,238 employees, of which 1,149 employees are dedicated to Gas Utility and 89 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 2007, 2006 and 2005 fiscal years appears in Note 11 to the 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.

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, 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 cost increases in our current 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, a change 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.

In our Gas Utility and Electric Utility segments, our operations are subject to regulation by the PUC. The PUC, among other things, approves the rates that UGI Utilities and UGIPNG may charge to its utility customers, thus impacting the returns that UGI Utilities and UGIPNG may earn on the assets that are dedicated to those operations. If UGI Utilities or UGIPNG are required in a rate proceeding to reduce the rates they charge their utility customers, or if UGI Utilities or UGIPNG are unable to obtain approval for rate increases from the PUC, particularly when necessary to cover increased costs, UGI Utilities’ and UGIPNG’s revenue growth will be limited and their earnings may decrease.

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

Our business operations are subject to all of the operating hazards and risks normally incidental to the handling, storage and distribution of combustible products, such as natural gas. These risks could result in substantial losses due to personal injury and/or loss of life, 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 are investigating and remediating contamination at a number of present and former operating sites in the U.S., including former sites where we or our former subsidiaries operated manufactured gas plants. We have also 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 to remediate 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 to clean up these sites may exceed our current estimates due to factors beyond our control, such as:

	•		the discovery of presently unknown conditions;
	•		changes in environmental laws and regulations;
	•		judicial rejection of our legal defenses to the third-party claims; or
	•		the insolvency of other responsible parties at the sites at which we are involved.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

With the exception of the matters set forth below, no material legal proceedings are pending involving UGI Utilities, or any of its properties, and no such proceedings are known to be contemplated by governmental authorities other than claims arising in the ordinary course of the Company’s business.

Environmental Matters — 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, UGI Utilities divested all of its utility operations other than those which now constitute UGI Gas and Electric Utility by the early 1950s.

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 Utilities (excluding UGIPNG) is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. In accordance with the terms of the UGIPNG base rate case order which became effective December 2, 2006, site-specified environmental investigation and remediation costs associated with UGIPNG incurred prior to December 2, 2006 are amortized as removal costs over five-year periods. Such costs incurred after December 2, 2006 are expensed as incurred.

As a result of the acquisition of PG Energy by UGI Utilities’ wholly owned subsidiary, UGIPNG, UGIPNG became 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 $1.1 million in any calendar year. Costs related to investigation and remediation of one property formerly owned by UGIPNG are also included in this cap. The Multi-Site Agreement terminates in 2019 but may be terminated by either party at the end of any two-year period beginning with the effective date.

UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating four claims against it relating to out-of-state sites.

City of Bangor, Maine v. Citizens Communications Co. 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 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. Citizens’ third-party claims have been stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March of 2005 that it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of Maine related to gas plant contaminants at this site. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. Citizens and the City subsequently 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. UGI Utilities is evaluating what effect the settlement agreement would have on any claims against it. UGI Utilities believes that it has good defenses to any claim that the DEP may bring to recover its costs, and is defending the Citizens’ suit.

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 former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites.

The trial court granted UGI Utilities’ motion for summary judgment and dismissed ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court’s decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. ConEd claims that the cost of remediation of the three sites would be approximately $14 million. On October 7, 2005, UGI Utilities filed for reconsideration of the panel’s order, which was denied by the Second Circuit Court of Appeals on January 17, 2006. On April 14, 2006, UGI Utilities filed a petition requesting that the United States Supreme Court review the decision of the Second Circuit Court of Appeals. On June 18, 2007, the United States Supreme Court denied UGI Utilities’ petition. This case has been remanded back to the trial court. UGI Utilities is defending the suit.

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. The Northeast Companies estimate that remediation costs for all of the sites would total approximately $215 million and assert 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.

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 United States District Court for the District 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 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.

PART II:

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

Market Information

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

Dividends

Cash dividends declared on the Company’s Common Stock totaled $40.0 million in fiscal year 2007, $37.6 million in fiscal year 2006 and $38.5 million in fiscal year 2005.

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 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”). UGI Gas’ rate of customer growth exceeds the national averages for local gas distribution companies (“LDCs”) and its proximity to major population centers and its extensive transportation infrastructure makes its service area a desired location for homes and businesses. 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 August 24, 2006, UGI Utilities, through its subsidiary UGIPNG, acquired the natural gas distribution business of Southern Union Company’s (“SU’s”) PG Energy Division (the “PG Energy Acquisition”), a natural gas LDC located in northeastern Pennsylvania now referred to as PNG Gas. The results of PNG Gas are included in our consolidated results beginning August 24, 2006 and Fiscal 2007 represented the first full year of PNG Gas’ results. Management devoted considerable effort during Fiscal 2007 toward the successful integration of the PNG Gas operations. We expect to continue to obtain operating and financial synergies as we further integrate PNG Gas with our existing operations over time.

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. 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. 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. Because of this ratemaking process, there is limited commodity price risk associated with Gas Utility. 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 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.

The comparison of our performance for the year ended September 30, 2007 (“Fiscal 2007”) with the year ended September 30, 2006 (“Fiscal 2006”) is significantly affected by the full-year impact of PNG Gas. Our financial results in Fiscal 2007 also reflect weather that, although warmer than normal, was colder than in Fiscal 2006. The warmer than normal weather reduced the full earnings benefits we expected from PNG Gas. Our Electric Utility Fiscal 2007 results improved in large part from the implementation of new POLR rates which became effective January 1, 2007. Our interest expense was significantly higher in Fiscal 2007 due to interest on acquisition-related debt associated with the PG Energy Acquisition and higher bank loans outstanding to fund the working capital requirements of 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, 2007. 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 11.

Fiscal 2007 Compared with Fiscal 2006

Year Ended September 30,		2007				2006				Increase
(Millions of dollars)
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. Increases or decreases in retail core-market customer 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 amount included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $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 as a result of the PG Energy Acquisition.

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.

Fiscal 2006 Compared with Fiscal 2005

										Increase
Year Ended September 30,		2006				2005				(Decrease)
(Millions of dollars)
Gas Utility:
Revenues		$	724.0			$	585.1			$	138.9				23.7	%
Total margin (a)		$	201.2			$	195.0			$	6.2				3.2	%
Operating income		$	84.2			$	81.6			$	2.6				3.2	%
Income before income taxes		$	62.4			$	65.0			$	(2.6	)			(4.0	)%
System throughput — bcf			82.6				84.7				(2.1	)			(2.5	)%
Degree days — % warmer than normal (b)			8.7	%			2.0	%			—				—
Electric Utility:
Revenues		$	98.0			$	96.1			$	1.9				2.0	%
Total margin (a)		$	41.7			$	43.1			$	(1.4	)			(3.2	)%
Operating income		$	20.7			$	21.6			$	(0.9	)			(4.2	)%
Income before income taxes		$	18.2			$	19.9			$	(1.7	)			(8.5	)%
Distribution sales — gwh			1,005.0				1,021.8				(16.8	)			(1.6	)%

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 total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes of $5.3 million in Fiscal 2006 and $5.2 million in Fiscal 2005.
(b)		Deviation from average heating degree days for the 30-year period 1975-2004 based upon weather statistics provided by 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 8.7% warmer than normal in Fiscal 2006 compared with temperatures that were 2.0% warmer than normal in Fiscal 2005. Total distribution system throughput declined 2.1 bcf in Fiscal 2006 despite 2.7 bcf of incremental throughput contributed by PNG Gas’ operations during the period from August 24, 2006, the date of the PG Energy Acquisition, through September 30, 2006. Notwithstanding year-over-year growth in the number of UGI Gas’ retail core-market customers, its Fiscal 2006 system throughput was approximately 6% lower than in Fiscal 2005 primarily due to a reduction in retail core-market customer usage largely resulting from the warmer weather and customer conservation in response to the pass through of higher natural gas costs.

The increase in Gas Utility revenues during Fiscal 2006 is principally the result of (1) an $86.6 million increase in UGI Gas’ retail core-market revenues reflecting higher average PGC rates, (2) a $43.0 million increase in revenues from UGI Gas’ low-margin off-system sales and, to a much lesser extent, (3) revenues from PNG Gas subsequent to the PG Energy Acquisition. Gas Utility’s cost of gas was $522.9 million in Fiscal 2006 compared to $390.1 million in Fiscal 2005 largely reflecting the effects of the higher PGC rates, the higher low-margin off-system sales and, to a much lesser extent, cost of gas associated with PNG Gas’ operations subsequent to the PG Energy Acquisition.

The $6.2 million increase in Gas Utility total margin in Fiscal 2006 principally reflects greater margin generated from higher average interruptible delivery service unit margins and margin from PNG Gas partially offset by lower UGI Gas retail core-market margin. The increase in average interruptible delivery service unit margins reflects an increase in the spread between delivered prices for natural gas and alternative fuels, principally oil. The lower gross margin from UGI Gas retail core-market customers largely reflects the previously mentioned lower retail core-market customer usage.

Gas Utility operating income increased $2.6 million in Fiscal 2006 as the $6.2 million increase in total margin was partially offset by a $2.6 million increase in depreciation and amortization expense, including depreciation expense associated with PNG Gas, and slightly higher operating and administrative expenses. Fiscal 2006 operating and administrative expenses were slightly higher than in Fiscal 2005 reflecting operating and administrative expenses from PNG Gas and higher UGI Gas uncollectible accounts and customer assistance expenses, partially offset by lower distribution system expenses resulting in large part from the mild heating-season weather and lower stock-based compensation expense.

The decrease in Gas Utility income before income taxes in Fiscal 2006 reflects the increase in operating income which was more than offset by higher interest expense. The higher interest expense resulted from higher average short-term debt outstanding, higher short-term interest rates and interest on long-term debt associated with the PG Energy Acquisition.

Electric Utility. Electric Utility’s Fiscal 2006 kilowatt-hour sales decreased 1.6% principally reflecting the effects of warmer heating-season weather. Electric Utility revenues increased 2.0% principally reflecting the effects of a 3.0% increase in its POLR electric generation rates effective January 1, 2006 partially offset by the lower kilowatt-hour sales. Electric Utility’s cost of sales increased to $51.0 million in Fiscal 2006 from $47.8 million in Fiscal 2005 as a result of higher per-unit purchased power costs partially offset by the lower kilowatt-hour sales. Electric Utility total margin in Fiscal 2006 decreased $1.4 million principally as a result of the lower kilowatt-hour sales and the increase in per-unit purchased power costs.

Electric Utility operating income decreased $0.9 million reflecting the decrease in total margin and slightly higher depreciation and amortization expense slightly offset by lower operating and administrative expenses. The decrease in Electric Utility income before income taxes in Fiscal 2006 reflects the decrease in operating income and higher interest expense resulting from higher average short-term debt outstanding and higher short-term interest rates.

PG Energy Acquisition

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 million in cash, subject to adjustment as further described below. The closing date cash payment of $580 million was funded with net proceeds from the issuance of $275 million 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 million 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 million of 5.753% Senior Notes due 2016 and $100 million of 6.206% 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 $68.1 million 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 $23.7 million in cash.

FINANCIAL CONDITION AND LIQUIDITY

Capitalization and Liquidity

UGI Utilities’ total debt outstanding was $702.0 million at September 30, 2007. Included in this amount is $190.0 million of bank loans outstanding. In June 2007, UGI Utilities refinanced $20 million of its maturing 7.17% Medium-Term Notes with proceeds from the issuance of $20 million of 6.17% Medium-Term Notes due June 2017.

UGI Utilities has a $350 million Revolving Credit Agreement which expires in August 2011. At September 30, 2007, there was $190.0 million outstanding under this Revolving Credit Agreement. From time to time, UGI Utilities has entered into short-term borrowings under uncommitted arrangements with major banks in order to meet liquidity needs. There were no such amounts outstanding under uncommitted arrangements at September 30, 2007 and 2006. Amounts outstanding under the Revolving Credit Agreement at September 30, 2007 and 2006 are classified as bank loans on the Consolidated Balance Sheets. 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 2007 and 2006, peak bank loan borrowings totaled $259.0 million and $219.0 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 is generally greatest. Average daily bank loan borrowings were $163.7 million in Fiscal 2007 and $118.4 million in Fiscal 2006. The increase in average and peak bank loan borrowings during Fiscal 2007 reflects borrowings to fund the working capital of PNG Gas.

UGI Utilities has a shelf registration statement with the U.S. Securities and Exchange Commission under which it may issue up to an additional $55 million of Medium-Term Notes or other debt securities subject to the financial ratio covenant in its Revolving Credit Agreement.

Based upon cash expected to be generated from our operations, borrowings under our Revolving Credit Agreement and our ability to issue debt under our Medium-Term Note program, management believes the Company will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2008. For additional discussion of UGI Utilities’ long-term debt and Revolving Credit Agreement, see Note 4 to Consolidated Financial Statements.

Cash Flows

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

Cash flow provided by operating activities was $133.5 million in Fiscal 2007, $10.7 million in Fiscal 2006 and $68.3 million in Fiscal 2005. Cash flow from operating activities before changes in operating working capital was $150.6 million in Fiscal 2007, $93.8 million in Fiscal 2006 and $86.3 million in Fiscal 2005. Changes in operating working capital used $17.1 million in Fiscal 2007, $83.1 million in Fiscal 2006, and $18.0 million in Fiscal 2005. The significant increase in Fiscal 2007 operating cash flow before changes in working capital reflects the full-year effects of PNG Gas. The significant increase in Fiscal 2006 cash used by changes in working capital principally reflects greater cash required to fund natural gas storage inventories and changes in accounts payable, lower cash flow from changes in deferred fuel costs, and $13.5 million of refunds of collateral deposits principally received in Fiscal 2005.

Investing activities. Cash used by investing activities was $55.2 million in Fiscal 2007, $647.8 million in Fiscal 2006, and $47.5 million in Fiscal 2005. Expenditures for property, plant and equipment increased $15.2 million in Fiscal 2007 reflecting higher Gas Utility capital expenditures from the full-year effects of PNG Gas partially offset by lower information system and Electric Utility capital expenditures. 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 the PG Energy Acquisition working capital adjustment.

Financing activities. Cash used by financing activities was $65.1 million in Fiscal 2007 compared with cash provided of $637.4 million in Fiscal 2006 and cash used of $18.2 million in Fiscal 2007. Financing activities cash flows are primarily the result of issuances and repayments of long-term debt, net short-term borrowings including borrowings under revolving credit agreements and other uncommitted arrangements, cash dividends to UGI, and capital contributions from UGI. 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 on June 1, 2006 which was repaid in September 2006. Repayments of debt in Fiscal 2006 also includes two $35 million borrowings with maturities greater than three months entered into during Fiscal 2005. Net bank loan (repayments) borrowings totaled $(26.0) million in Fiscal 2007, $204.8 million in Fiscal 2006, and $(49.7) million in Fiscal 2005. The significantly higher borrowings in Fiscal 2006 reflect borrowings needed to finance higher working capital including working capital related to PNG Gas.

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 the Pension Plans’ assets totaled $290.1 million and $274.6 million at September 30, 2007 and 2006, respectively. At September 30, 2007 and 2006, the Pension Plans’ projected benefit obligations (“PBOs”) exceeded the Pension Plans’ assets by $9.3 million and $31.7 million, respectively.

We believe we are in compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations, and we do not anticipate we will be required to make contributions to the Pension Plans in Fiscal 2008. Pre-tax pension expense reflected in our Fiscal 2007, 2006 and 2005 results was $2.3 million, $2.2 million and $2.5 million, respectively. Pension expense in Fiscal 2008 is not expected to be material.

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”), 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 as well as 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. In conjunction with our adoption of SFAS 158, we adjusted certain amounts on our September 30, 2007 Consolidated Balance Sheet relating to the Pension Plans as well as amounts associated with our other postretirement benefit plans and recorded an after-tax reduction to Common Stockholder’s Equity of $10.0 million. For a more detailed discussion of the effects of the adoption of SFAS 158, and details regarding 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 2007, Fiscal 2006 and Fiscal 2005. We also provide amounts we expect to spend in Fiscal 2008. We expect to finance a substantial portion of Fiscal 2008 capital expenditures from cash generated by operations and the remainder from borrowings under our Revolving Credit Agreement.

Year Ended September 30,		2008				2007				2006				2005
(Millions of dollars)		(estimate)
Gas Utility		$	60.6			$	66.2			$	49.2			$	38.8
Electric Utility			5.8				7.2				9.0				7.5
		$	66.4			$	73.4			$	58.2			$	46.3

Contractual Cash Obligations and Commitments

UGI Utilities has contractual cash obligations that extend beyond Fiscal 2007 including scheduled repayments of long-term debt and interest, operating lease obligations, unconditional purchase obligations for pipeline transportation and natural gas storage services, and commitments to purchase natural gas and electricity. The following table presents significant contractual cash obligations under agreements existing as of September 30, 2007 (in millions of dollars).

		Payments Due by Period
						Fiscal				Fiscal				Fiscal
		Total				2008				2009-2010				2011-2012				Thereafter
Long-term debt and associated interest		$	952.0			$	38.5			$	61.0			$	93.7			$	758.8
Operating leases			19.1				4.9				6.6				4.2				3.4
Gas Utility and Electric Utility supply, storage and transportation contracts			1,019.4				478.9				293.5				125.4				121.6
Total		$	1,990.5			$	522.3			$	361.1			$	223.3			$	883.8

RELATED PARTY TRANSACTIONS

UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct corporate expenses and for an allocated share of indirect corporate expenses incurred or paid on behalf of UGI Utilities. These billed expenses totaled $11.6 million in Fiscal 2007, $10.7 million in Fiscal 2006 and $12.9 million in Fiscal 2005 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, and subject to recall for operational purposes, 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 $92.7 million in Fiscal 2007, $85.8 million in Fiscal 2006 and $80.7 million in Fiscal 2005.

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, 2007, comprising approximately 8.2 billion cubic feet of natural gas, was $66.1 million. The carrying value of these gas storage inventories at September 30, 2006, comprising approximately 8.4 billion cubic feet of natural gas, was $71.3 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 2007, 2006 and 2005 (exclusive of Storage Agreement transactions described above) totaled $34.3 million, $15.1 million and $8.5 million, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During Fiscal 2007, 2006 and 2005, revenues associated with sales to Energy Services totaled $33.4 million, $14.1 million, and $4.2 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

As a result of Pennsylvania’s Natural Gas Choice and Competition Act (the “Gas Competition Act”), since July 1, 1999, all natural gas consumers in Pennsylvania, including residential and smaller commercial and industrial customers (“core-market customers”), have been able to purchase gas supplies from entities other than natural gas distribution companies (“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, 2007, fewer than 2% of Gas Utility’s 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 base rates $12.5 million annually, 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, 2007, 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, have been established in a series of PUC approved settlements, the latest of which became effective in June 2006 (collectively, the “POLR Settlement”).

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 4.5% on January 1, 2005 and 3% on January 1, 2006. Electric Utility also increased its POLR rates effective January 1, 2007, which increased the average cost to residential customers by approximately 35% over such costs in effect during calendar year 2006. Effective January 1, 2008, total average residential rates will increase approximately 5.5%. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its customers. New PUC default service regulations became effective on September 15, 2007, but do not disturb Electric Utility’s POLR Settlement through 2009. Under the default service regulations, Electric Utility will be required to file a default service plan with the PUC in 2008 that will establish the terms and conditions under which it will offer POLR service commencing 2010.

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, UGI Utilities divested all of its utility operations other than those which now constitute UGI Gas and Electric Utility by the early 1950s.

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 on December 2 , 2006, site-specified 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 2, 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. Costs related to investigation and remediation of one property formerly owned by UGIPNG are also included in this cap. 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 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 four 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 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 Co. 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 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. Citizens’ third-party claims have been stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March 2005 that it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of Maine related to gas plant contaminants at this site. 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 liabilities. UGI Utilities is evaluating what effect, if any, the settlement agreement would have on claims against it. UGI Utilities believes that it has good defenses to any claim that the DEP may bring to recover its costs, and is defending the Citizens’ suit.

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 former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites.

The trial court granted UGI Utilities’ motion for summary judgment and dismissed ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court’s decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. ConEd claims that the cost of remediation for the three sites would be approximately $14 million. On October 7, 2005, UGI Utilities filed for reconsideration of the panel’s order which was denied by the Second Circuit Court of Appeals on January 17, 2006. On April 14, 2006, UGI Utilities filed a petition requesting that the United States Supreme Court review the decision of the Second Circuit Court of Appeals. On June 18, 2007, the United States Supreme Court denied UGI Utilities’ petition. The case has now been remanded back to the trial court. UGI Utilities is defending the suit.

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. 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.

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 cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism.

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. 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.

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 2007 and Fiscal 2006, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $1.6 million and $1.2 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 $40.3 million and $43.8 million at September 30, 2007 and 2006, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $46.1 million and $50.6 million at September 30, 2007 and 2006, 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 appropriate accounting principles 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. Estimating fair values can be a complex and judgmental area 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 allocations.

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 must perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In performing such 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, 2007, our goodwill totaled $162.3 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 UGIPNG 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, 2007, UGI Utilities net property, plant and equipment totaled $1,083.9 million and we recorded depreciation expense of $39.2 million during Fiscal 2007.

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, 2007, our regulatory assets totaled $103.8 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. Pension Plan assets 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. An unfavorable change 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 expense of approximately $1.8 million in Fiscal 2008. An unfavorable change in the discount rate of 50 basis points to a rate of 5.9% would result in an increase in pre-tax pension expense of approximately $1.7 million in Fiscal 2008.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

Below is a listing of recently issued accounting pronouncement by the Financial Accounting Standards Board. See Note 1 to the Consolidated Financial Statements for additional discussion of these pronouncements.

Title of Pronouncement		Month of Issue		Effective Date
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115”		February 2007		Fiscal 2009
SFAS No. 157, “Fair Value Measures”		September 2006		Fiscal 2009
FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”		June 2006		Fiscal 2008

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) the impact of pending and future legal proceedings; (5) competitive pressures from the same and alternative energy sources; (6) liability for environmental claims; (7) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (8) adverse labor relations; (9) large customer, counterparty or supplier defaults; (10) increased uncollectible accounts expense; (11) 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; (12) political, regulatory and economic conditions in the United States; and (13) reduced access to capital markets and interest rate fluctuations.

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 September 30, 2007 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 by, and under the supervision of, 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, 2007, based on the COSO Framework. In our 2006 Management’s Report on Internal Control over Financial Reporting, we excluded the PG Energy business from our assessment of internal control over financial reporting as of September 30, 2006 because it was acquired by UGI Penn Natural Gas, Inc. (“UGIPNG”), a wholly owned subsidiary of the Company, on August 24, 2006. The PG Energy business total assets represented 42% of total consolidated assets and its total revenues represented less than 2% of total consolidated revenues as of and for the year ended September 30, 2006. Such exclusion is permitted based upon guidance of the U.S. Securities and Exchange Commission.
	(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 years 2007 and 2006 were as follows:

		2007				2006
Audit Fees		$	978,351			$	1,086,178
Audit-Related Fees			- 0 -				- 0 -
Tax Fees			- 0 -				- 0 -
All Other Fees			- 0 -				- 0 -
Total Fees for Services Provided		$	978,351			$	1,086,178

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, 2007 and 2006

Consolidated Statements of Income for the fiscal years ended September 30, 2007, 2006 and 2005

Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2007, 2006 and 2005

Consolidated Statements of Stockholder’s Equity for the fiscal years ended September 30, 2007, 2006 and 2005

Notes to Consolidated Financial Statements

	(2)		Financial Statement Schedule:
			For the years ended September 30, 2007, 2006 and 2005

II — Valuation and Qualifying Accounts

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

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

Incorporation by Reference
Exhibit No.		Exhibit		Registrant		Filing		Exhibit
3.1		UGI Utilities’ Amended and Restated Articles of Incorporation		Utilities		Registration Statement No. 333-72540 (10/31/01)			3
3.2		Bylaws of UGI Utilities as amended through September 30, 2003		Utilities		Form 10-K (9/30/03)			3.2
4		Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of its long-term debt not required to be filed pursuant to the description of Exhibit 4 contained in Item 601 of Regulation S-K)
4.1		UGI Utilities’ Articles of Incorporation and Bylaws referred to in Exhibit Nos. 3.1 and 3.2
4.2		Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994		Utilities		Registration Statement No. 33-77514 (4/8/94)			4	(c)
4.3		Form of Fixed Rate Medium-Term Note		Utilities		Form 8-K (8/26/94)			(4)i
4.4		Form of Fixed Rate Series B Medium-Term Note		Utilities		Form 8-K (8/1/96)			4	(i)
4.5		Form of Floating Rate Series B Medium-Term Note		Utilities		Form 8-K (8/1/96)		4(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)		4(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)		4(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

Incorporation by Reference
Exhibit No.		Exhibit		Registrant		Filing		Exhibit
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
*10.5**		UGI Utilities, Inc. Executive Annual Bonus Plan effective as of October 1, 2006
10.6		[Intentionally Omitted]
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		[Intentionally Omitted]
10.10		[Intentionally Omitted]

Incorporation by Reference
Exhibit No.		Exhibit		Registrant		Filing		Exhibit
10.11**		UGI Corporation Senior Executive Employee Severance Pay Plan as amended December 7, 2004		UGI		Form 10-K (9/30/04)			10.12
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 for Messrs. Greenberg, Walsh and Knauss		UGI		Form 8-K (12/6/05)			10.1
10.21**		UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Stock Unit Grant Letter		UGI		Form 8-K (12/6/05)			10.9
10.22**		Form of Change in Control Agreement for Messrs. Trego and Barney		Utilities		Form 8-K (12/6/05)			10.2
10.23**		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

Incorporation by Reference
Exhibit No.		Exhibit		Registrant		Filing		Exhibit
10.24**		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
10.25		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

Incorporation by Reference
Exhibit No.		Exhibit		Registrant		Filing		Exhibit
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
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 Corporation		Form 10-K (9/30/05)			10.30

Incorporation by Reference
Exhibit No.		Exhibit		Registrant		Filing		Exhibit
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
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

Incorporation by Reference
Exhibit No.		Exhibit		Registrant		Filing		Exhibit
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
*12.1		Computation of Ratio of Earnings to Fixed Charges
14		Code of Ethics for principal executive, financial and accounting officers		Utilities		Form 10-K (9/30/03)			14
*23		Consent of PricewaterhouseCoopers LLP
*31.1		Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the year ended September 30, 2007 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, 2007 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, 2007

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.

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 27, 2007 by the following persons on behalf of the Registrant in the capacities indicated.

Signature		Title
/s/ David W. Trego   David W. Trego		President and Chief Executive Officer (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   John C. Barney		Sr. Vice President – Finance and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
/s/ Stephen D. Ban   Stephen D. Ban		Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 27, 2007 by the following persons on behalf of the Registrant in the capacities indicated.

Signature		Title
/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 year 2007.

UGI UTILITIES, INC.

FINANCIAL INFORMATION

FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K

YEAR ENDED SEPTEMBER 30, 2007

UGI UTILITIES, INC.

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE

		Pages
Financial Statements:
Report of Independent Registered Public Accounting Firm		F-3 to F-4
Consolidated Balance Sheets as of September 30, 2007 and 2006		F-5 to F-6
Consolidated Statements of Income for the years ended September 30, 2007, 2006 and 2005		F-7
Consolidated Statements of Cash Flows for the years ended September 30, 2007, 2006 and 2005		F-8
Consolidated Statements of Stockholder’s Equity for the years ended September 30, 2007, 2006 and 2005		F-9
Notes to Consolidated Financial Statements		F-10 to F-34
Financial Statement Schedule:
For the years ended September 30, 2007, 2006 and 2005:
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.

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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2007 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, 2007, 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 6 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 and, as discussed in Note 1, the Company changed the manner in which it accounts for share-based compensation as of October 1, 2005.

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.

In the 2006 Management’s Report on Internal Control over Financial Reporting, management excluded the PG Energy business from its assessment of internal control over financial reporting as of September 30, 2006 because it was acquired by a wholly owned subsidiary of the Company in a purchase business combination on August 24, 2006. We had also excluded the PG Energy business from our audit of internal control over financial reporting as of September 30, 2006. The PG Energy business total assets represented approximately 42% of total consolidated assets and its total revenues represented less than 2% of total consolidated revenues as of and for the year ended September 30, 2006.

/s/ PricewaterhouseCoopers LLP

November 29, 2007
Philadelphia, Pennsylvania

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

		September 30,
		2007				2006
ASSETS
Current assets:
Cash and cash equivalents		$	16,207			$	2,942
Restricted cash			6,642				2,697
Accounts receivable (less allowances for doubtful accounts of $10,824 and $12,389, respectively)			74,696				61,917
Accounts receivable — related parties			1,450				1,888
Accrued utility revenues			17,889				16,649
Inventories			162,259				162,610
Deferred income taxes			6,673				12,869
Regulatory assets			14,782				—
Income taxes recoverable			—				2,776
Prepaid expenses and other current assets			5,532				11,013
Total current assets			306,130				275,361
Property, plant and equipment
Gas Utility			1,467,454				1,410,264
Electric Utility			126,451				120,049
General			26,124				23,557
			1,620,029				1,553,870
Less accumulated depreciation and amortization			(536,132	)			(503,046	)
Net property, plant and equipment			1,083,897				1,050,824
Goodwill			162,309				182,851
Regulatory assets			88,990				72,919
Other assets			7,712				27,788
Total assets		$	1,649,038			$	1,609,743

See accompanying notes to consolidated financial statements.

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

		September 30,
		2007				2006
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt		$	—			$	20,000
Bank loans			190,000				216,000
Accounts payable			60,012				46,916
Accounts payable — related parties			15,871				14,768
Employee compensation and benefits accrued			10,619				8,961
Dividends and interest accrued			15,870				8,399
Customer deposits and refunds			35,144				29,126
Accrued income taxes			1,017				—
Deferred fuel costs			—				12,171
Other current liabilities			14,902				12,757
Total current liabilities			343,435				369,098
Long-term debt			512,000				492,000
Deferred income taxes			175,012				162,871
Deferred investment tax credits			6,417				6,803
Other noncurrent liabilities			41,460				31,872
Commitments and contingencies (note 9)
Total liabilities			1,078,324				1,062,644
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			346,758				345,801
Retained earnings			179,014				144,833
Accumulated other comprehensive loss			(15,317	)			(3,794	)
Total common stockholder’s equity			570,714				547,099
Total liabilities and stockholder’s equity		$	1,649,038			$	1,609,743

See accompanying notes to consolidated financial statements.

UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)

		Year Ended
		September 30,
		2007				2006				2005
Revenues		$	1,183,247			$	822,069			$	681,152
Costs and expenses:
Cost of sales — gas, fuel and purchased power			816,451				573,867				437,930
Operating and administrative expenses			140,013				96,149				94,370
Operating and administrative expenses — related parties			11,584				10,675				12,900
Taxes other than income taxes			17,736				14,334				13,379
Depreciation and amortization			40,934				26,617				23,827
Other income, net			(8,564	)			(4,462	)			(4,533	)
			1,018,154				717,180				577,873
Operating income			165,093				104,889				103,279
Interest expense			42,327				24,345				18,326
Income before income taxes			122,766				80,544				84,953
Income taxes			48,579				31,903				34,132
Net income		$	74,187			$	48,641			$	50,821

See accompanying notes to consolidated financial statements.

UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)

		Year Ended
		September 30,
		2007				2006				2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	74,187			$	48,641			$	50,821
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			40,934				26,617				23,827
Deferred income taxes, net			16,281				9,240				(631	)
Provision for uncollectible accounts			14,353				10,382				8,210
Other, net			4,833				(1,098	)			4,064
Net change in:
Accounts receivable and accrued utility revenues			(27,934	)			(10,091	)			(19,591	)
Inventories			351				(21,409	)			(6,407	)
Deferred fuel costs			(26,953	)			(17,850	)			9,508
Accounts payable			14,386				(22,393	)			(9,906	)
Electric supplier collateral deposits			—				(13,500	)			11,000
Other current assets and liabilities			23,054				2,187				(2,581	)
Net cash provided by operating activities			133,492				10,726				68,314
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment			(73,411	)			(58,220	)			(46,305	)
Net costs of property, plant and equipment disposals			(1,492	)			(1,744	)			(1,176	)
PG Energy Acquisition			23,670				(585,170	)			—
Increase in restricted cash			(3,945	)			(2,697	)			—
Net cash used by investing activities			(55,178	)			(647,831	)			(47,481	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends			(40,006	)			(37,615	)			(38,468	)
(Decrease) increase in bank loans with maturities of three months or less			(26,000	)			204,800				(49,700	)
Issuances of debt including bank loans with maturities greater than three months			20,000				345,000				130,000
Repayments of debt including bank loans with maturities greater than three months			(20,000	)			(140,000	)			(40,000	)
Redemption of preferred shares subject to mandatory redemption			—				—				(20,000	)
Capital contribution from UGI Corporation			—				265,000				—
Excess tax benefits from equity-based payment arrangements			957				176				—
Net cash (used) provided by financing activities			(65,049	)			637,361				(18,168	)
Cash and cash equivalents increase		$	13,265			$	256			$	2,665
CASH AND CASH EQUIVALENTS:
End of year		$	16,207			$	2,942			$	2,686
Beginning of year			2,942				2,686				21
Increase		$	13,265			$	256			$	2,665

See accompanying notes to consolidated financial statements.

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, 2004		$	60,259			$	79,773			$	121,454			$	(1,455	)		$	260,031
Net income											50,821								50,821
Net change in fair value of derivative instruments (net of tax of $1,027)															1,448				1,448
Reclassifications of net losses on interest rate protection agreements (net of tax of $177)															250				250
Comprehensive income											50,821				1,698				52,519
Cash dividends — Common Stock											(38,468	)							(38,468	)
Other							849												849
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