================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------- FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2004 Commission file number 1-1398 UGI UTILITIES, INC. (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) Pennsylvania 23-1174060 (STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.) INCORPORATION OR ORGANIZATION) 100 Kachel Boulevard, Suite 400, Green Hills Corporate Center Reading, PA 19607 (ADDRESS OF PRINCIPAL 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 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 X NO . ----- ----- 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. [X] At November 30, 2004, 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. Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [X] No [ ] 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: ...................................................................1 Items 1. and 2. Business and Properties..........................1 Item 3. Legal Proceedings................................7 PART II: ..................................................................10 Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities..................10 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...................................11 Item 7A. Quantitative and Qualitative Disclosures About Market Risk...............................26 Item 8. Financial Statements and Supplementary Data............................................26 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................26 Item 9A. Controls and Procedures.........................26 Item 9B. Other Information...............................27 PART III: INTENTIONALLY OMITTED.............................................28 PART IV: ..................................................................29 Item 15. Exhibits and Financial Statement Schedules.......................................29 Signatures........................................................36 Index to Financial Statements and Financial Statement Schedule.............................F-2 (i) PART I: ITEMS 1. AND 2. BUSINESS AND PROPERTIES GENERAL UGI Utilities, Inc. ("Utilities," "UGI Utilities" or the "Company") is a public utility company that owns and operates (i) a natural gas distribution utility serving customers in 14 counties in eastern and southeastern Pennsylvania ("Gas Utility"), and (ii) an electric utility serving parts of Luzerne and Wyoming counties in northeastern Pennsylvania ("Electric Utility"). We are a wholly owned subsidiary of UGI Corporation ("UGI"). In response to state deregulation legislation, effective October 1, 1999 we transferred our electric generation assets to our non-utility subsidiary, UGI Development Company ("UGID"). UGID contributed certain of its generation assets to a joint venture with a subsidiary of Allegheny Energy, Inc. in December 2000. In June 2003, we dividended the stock of UGID to UGI. UGID's results of operations did not have a material effect on our results of operations for fiscal year 2003 or 2002. 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 "Utilities," as well as the terms, "our," "we," and "its," are sometimes used to refer to UGI Utilities, Inc. or, collectively (for periods prior to July 2003), UGI Utilities, Inc. and its consolidated subsidiaries. GAS UTILITY OPERATIONS SERVICE AREA; REVENUE ANALYSIS Gas Utility distributes natural gas to approximately 300,000 customers in portions of 14 eastern and southeastern Pennsylvania counties through its distribution system of approximately 4,900 miles of gas mains. The service area consists of approximately 3,000 square miles and includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon and Reading, Pennsylvania. Located in Gas Utility's service area are major production centers for basic industries such as specialty metals, aluminum and glass. System throughput (the total volume of gas sold to or transported for customers within Gas Utility's distribution system) for the 2004 fiscal year was approximately 82.2 billion cubic feet ("bcf"). System sales of gas to firm-residential, commercial and industrial ("retail core-market") customers accounted for approximately 42% of system throughput, while gas delivery service (gas transported for residential, commercial and industrial customers who bought their gas from others) accounted for approximately 58% of system throughput. Based on the most recent available industry data (2002), residential customers account for approximately 35% of total system throughput by natural gas distribution companies in the United States. By contrast, -1- for the 2004 fiscal year, Gas Utility's residential customers represented 26% of its total 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 producers and marketers, and 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 and Transcontinental Gas Pipeline Corporation. GAS SUPPLY CONTRACTS During fiscal year 2004, Gas Utility purchased approximately 50 bcf of natural gas for sale to retail core-market and off-system sales customers. Approximately 77% of the volumes purchased were supplied under agreements with ten major suppliers. The remaining 23% of gas purchased was supplied by approximately 20 different producers and marketers. Gas supply contracts are generally no longer than one year. SEASONAL VARIATION Because many of its customers use gas for heating purposes, Gas Utility sales are seasonal. Approximately 59% of fiscal year 2004 throughput occurred during the winter 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 perceived reliability, 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. 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 territory, Utilities 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 Gas Utility. As a result of Pennsylvania's Natural Gas Choice and Competition Act ("Gas Competition Act"), which became effective July 1, 1999, all of Gas Utility's customers, including residential and smaller commercial and industrial customers have been afforded this opportunity. -2- 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 their alternate fuel. Profitability from these customers, therefore, is affected by the difference, or "spread," between the customers' delivered cost of gas and the customers' delivered alternate fuel cost, and the frequency and duration of interruptions. See "Gas Utility and Electric Utility Regulation and Rates - Gas Utility Rates." Commercial and industrial customers representing 22% of total system throughput have locations which afford them the opportunity, although none have exercised it, of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. The majority of customers in this group are served under transportation contracts having three- to twenty-year terms. Included in these two groups are Gas Utility's ten largest customers in terms of annual volume. All of these customers have contracts, eight of which extend beyond fiscal year 2005. No single customer represents, or is anticipated to represent, more than 5% of the total revenues of Gas Utility. 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 2005. Supply mix is diversified, market priced, and delivered pursuant to a number of long- and short-term firm transportation and storage arrangements, including transportation contracts held by some of Gas Utility's larger customers. During fiscal year 2004, Gas Utility supplied transportation service to two major cogeneration installations and three electric generation facilities. Gas Utility continues to pursue opportunities to supply natural gas to electric generation projects located in its service territory. 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 10,600 new residential heating customers during fiscal year 2004, which represented a record annual increase. Of those new customers, new home construction accounted for over 8,000 heating customers. 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 customers was approximately 1,200. Gas Utility continues to monitor and participate extensively in rulemaking and individual rate and tariff proceedings before the Federal Energy Regulatory Commission ("FERC") affecting the rates and the terms and conditions under which Gas Utility transports and stores natural gas. Among these proceedings are those arising out of certain FERC orders and/or pipeline filings 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. -3- Gas Utility's 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 achievable for reliable and secure supplies. Consistent with that objective, Gas Utility negotiates the terms of firm transportation capacity on all pipelines serving it, arranges for appropriate storage and peak-shaving resources, negotiates with producers for competitively priced gas purchases and aggressively participates in regulatory proceedings related to transportation rights and costs of service. ELECTRIC UTILITY SERVICE AREA; SALES ANALYSIS Electric Utility supplies electric service to approximately 62,000 customers in portions of Luzerne and Wyoming Counties in northeastern Pennsylvania through a system consisting of approximately 2,100 miles of transmission and distribution lines and 14 transmission substations. For fiscal year 2004, about 53% of sales volume came from residential customers, 35% from commercial customers and 12% from industrial customers. Electricity transported for customers who purchased their power from other suppliers represented less than 1% of fiscal year 2004 sales volume. SOURCES OF SUPPLY Electric Utility has third-party generation supply contracts in place for substantially all of its expected energy requirements for fiscal year 2005. Electric Utility distributes both electricity that it purchases from others and electricity that customers purchase from other suppliers. At September 30, 2004, alternate suppliers served customers representing less than 1% of system load. Electric Utility expects to continue to provide energy to the great majority of its distribution customers for the foreseeable future. COMPETITION As a result of the Electricity Generation Customer Choice and Competition Act ("ECC Act") that became effective in 1997, all Pennsylvania retail electric customers have the ability to choose their electric generation supplier. Under the ECC Act, 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, the most recent of which became effective in June 2004 (collectively, the "POLR Settlement.") Consistent with the terms of the POLR Settlement, Electric Utility's POLR rates will increase beginning January 2005 and Electric Utility is permitted, but not required, to further increase its POLR rates in January 2006. 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 -4- accounted for approximately 20% of total sales of electricity during the 2004 fiscal year. Electricity competes with natural gas, oil, propane and other heating fuels for this use. GAS UTILITY AND ELECTRIC UTILITY REGULATION AND RATES PENNSYLVANIA PUBLIC UTILITY COMMISSION JURISDICTION 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. FERC ORDERS 888 AND 889 In April 1996, FERC issued Orders No. 888 and 889, which established rules for the use of electric transmission facilities for wholesale transactions. FERC has also asserted jurisdiction over the transmission component of electric retail choice transactions. In compliance with these orders, the PJM Interconnection, LLC ("PJM"), of which Utilities is a member, has filed an open access transmission tariff with FERC establishing transmission rates and procedures for transmission within the PJM control area. Under the PJM tariff and associated agreements, Electric Utility is entitled to receive certain revenues when its transmission facilities are used by third parties. GAS UTILITY RATES Effective October 1, 2000, Gas Utility increased its base rates for retail core-market customers and implemented a credit to its purchased gas cost rates (described below). Since December 1, 2001, Gas Utility has reduced its purchased gas cost rates to retail core-market customers by an amount equal to the margin it receives from customers served under interruptible rates to the extent they use capacity contracted for by Gas Utility for retail core-market customers. As a result of these changes in its regulated rates, since December 1, 2001, Gas Utility's operating results have been more sensitive to heating season weather and less sensitive to competition from alternative fuels in commercial and industrial markets. Gas Utility's gas service tariff contains purchased gas cost ("PGC") rates that provide for annual increases or decreases in the rate per thousand cubic feet ("mcf") that Gas Utility charges for natural gas sold by it, to reflect Gas Utility's projected cost of purchased gas. PGC rates may also be adjusted quarterly, or, under certain conditions monthly, to reflect the actual cost of gas. Each proposed annual PGC rate is required to be filed with the PUC six months prior to its effective date. During this period the PUC holds hearings to determine whether the proposed rate reflects a least-cost fuel procurement policy consistent with the obligation to provide safe, adequate and reliable service. After completion of these hearings, the PUC issues an order permitting the collection of gas costs at levels which meet that standard. The PGC mechanism also provides for an annual reconciliation. Gas Utility has two PGC rates. PGC (1) is applicable to small, firm, retail core-market customers consisting of the residential and small commercial -5- 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, Gas Utility's PGC rates are adjusted to reflect margins, if any, from interruptible rate customers who do not obtain their own pipeline capacity. ELECTRIC UTILITY RATES Electric Utility's POLR rates will increase beginning January 2005 and Electric Utility is permitted, but not required, to further increase its POLR rates in January 2006. Pursuant to the requirements of the ECC Act, the PUC is currently developing POLR regulations that are expected to further define POLR service obligations and pricing. As of September 30, 2004, fewer than 1% of Electric Utility's customers have chosen an alternative electricity generation supplier. STATE TAX SURCHARGE CLAUSES 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 Utilities from the effects of increases in most of the Pennsylvania taxes to which it is subject. UTILITY FRANCHISES Utilities holds 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 it believes are adequate to authorize it to carry on its business in substantially all the territory to which it now renders gas and electric service. Under applicable Pennsylvania law, Utilities also has certain rights of eminent domain as well as the right to maintain its facilities in streets and highways in its territories. OTHER GOVERNMENT REGULATION In addition to regulation by the PUC, the gas and electric utility operations of Utilities are subject to various federal, state and local laws governing environmental matters, occupational health and safety, pipeline safety and other matters. Certain of Utilities' activities involving the interstate movement of natural gas, the transmission of electricity, transactions with non-utility generators of electricity, and other matters, are also subject to the jurisdiction of FERC. 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 Utilities. See ITEM 3. "LEGAL PROCEEDINGS - Environmental Matters-Manufactured Gas Plants." -6- EMPLOYEES At September 30, 2004, Utilities had approximately 1,000 employees. BUSINESS SEGMENT INFORMATION The table stating the amounts of revenues, operating income and identifiable assets attributable to Utilities' operating segments for the 2004, 2003 and 2002 fiscal years appears in Note 10 "Segment Information" of Notes to Consolidated Financial Statements included in this Report and is incorporated herein by reference. ITEM 3. LEGAL PROCEEDINGS With the exception of the matters set forth below, no material legal proceedings are pending involving 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, 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, Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the business of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, Utilities divested all of its utility operations other than those which now constitute Gas Utility and Electric Utility. 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 Utilities is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by Utilities or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. Utilities is currently litigating three claims against it relating to out-of-state sites. Consolidated Edison Company of New York v. UGI Utilities, Inc. On September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed suit against Utilities in the United States District Court for the Southern District of New York, seeking contribution from 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 -7- complaint alleges that Utilities "owned and operated" the MGPs prior to 1904. The complaint also seeks a declaration that Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70 million. By orders issued in November 2003 and March 2004, the court granted Utilities' motion for summary judgment and dismissed ConEd's complaint. ConEd has appealed. City of Bangor, Maine v. Citizens Communications Co. In April 2003, Citizens Communications Company ("Citizens") served a complaint naming Utilities as a third-party defendant in a civil action pending in 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 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 Utilities and its predecessors owned and operated the plant from 1901 to 1928. The City believes it could cost as much as $50 million to clean up the river. Utilities believes that it has good defenses to the claim and is defending the suit. Atlanta Gas Light Company v. UGI Utilities, Inc. By letter dated July 29, 2003, Atlanta Gas Light Company ("AGL") served Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that Utilities is responsible for 20% of approximately $8 million incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. Utilities believes that it has good defenses to the claim and is defending the suit. Savannah, Georgia Matter. AGL previously informed Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of Utilities operated the MGP in the early 1900s. AGL has recently informed Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55 million. AGL has not filed suit against Utilities for a share of these costs. Utilities believes that it will have good defenses to any action that may arise out of this site. Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy ("KeySpan") informed 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 Utilities is responsible for approximately 50% of these costs as a result of Utilities' alleged direct ownership and operation of the plant from 1885 to 1902. Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim. Connecticut Gas Plants Matter. By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together the "Northeast Companies"), demanded contribution from Utilities for past and future -8- 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 Utilities controlled operations of the plants from 1883 to 1941. According to the letter, investigation and remedial costs at the sites to date total approximately $10 million and complete remediation costs for all sites could total $182 million. The Northeast Companies seek an unspecified fair and equitable allocation of these costs to Utilities. Utilities is in the process of reviewing the information provided by Northeast Companies and is investigating this claim. RELATED MATTER UGI Utilities, Inc. v. Insurance Co. of North America, et al. On February 11, 1999, Utilities filed suit in the Court of Common Pleas of Montgomery County, Pennsylvania against more than fifty insurance companies, including Insurance Services, Ltd. (AEGIS). The complaint alleges that the defendants breached contracts of insurance by failing to indemnify Utilities for certain environmental costs. Utilities has now settled with all known solvent defendants and the suit has been dismissed. -9- 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 $45 million in fiscal year 2004, $33.9 million in fiscal year 2003 and $37.9 million in fiscal year 2002. -10- ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS In the following Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A"), Electric Utility and the electric generation business of UGI Development Company ("UGID") prior to its distribution to UGI in June 2003 are collectively referred to as "Electric Operations." The MD&A should be read in conjunction with our Consolidated Financial Statements and Notes to Consolidated Financial Statements including the business segment information in Note 10. FISCAL 2004 COMPARED WITH FISCAL 2003 Increase Year Ended September 30, 2004 2003 (Decrease) - ------------------------ ------ ------ -------------- (Millions of dollars) GAS UTILITY: Revenues $560.4 $539.9 $ 20.5 3.8 % Total margin (a) $191.5 $196.9 $ (5.4) (2.7)% Operating income $ 80.1 $ 96.1 $(16.0) (16.6)% Income before income taxes $ 64.2 $ 80.7 $(16.5) (20.4)% System throughput - bcf 82.2 83.8 (1.6) (1.9)% Degree days - % (warmer) colder than normal (2.9)% 7.0% -- -- ELECTRIC OPERATIONS: Revenues $ 89.7 $ 96.9 $ (7.2) (7.4)% Total margin (a) $ 41.5 $ 42.2 $ (0.7) (1.7)% Operating income $ 20.9 $ 21.8 $ (0.9) (4.1)% Income before income taxes $ 18.9 $ 19.5 $ (0.6) (3.1)% Distribution sales - gwh 983.9 980.0 3.9 0.4 % bcf - billions of cubic feet. gwh - millions of kilowatt hours. (a) Gas Utility's total margin represents total revenues less cost of sales. Electric Operation's total margin represents total revenues less cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes of $4.8 million in both Fiscal 2004 and Fiscal 2003. For financial statement purposes, Gas Utility's and Electric Operations' cost of sales is included in "gas, fuel and purchased power" and revenue-related taxes are included in "taxes other than income taxes" on the Consolidated Statements of Income. GAS UTILITY. Weather in Gas Utility's service territory based upon heating degree days was 2.9% warmer than normal in Fiscal 2004 compared with weather that was 7.0% colder than normal in Fiscal 2003. Total distribution system throughput decreased 1.6 bcf or 1.9% as the adverse effects of the warmer weather on heating-related sales to firm- residential, commercial and industrial ("retail core-market") customers were partially offset by greater volumes transported for delivery service customers and the volume effects of year-over-year retail core-market customer growth. The increase in Gas Utility revenues during Fiscal 2004 includes a $20.1 million increase in revenues from off-system sales partially offset by lower retail core-market -11- and delivery service revenues. The decline in retail core-market revenues reflects the effects of the reduced retail core-market volumes partially offset by higher average purchased gas costs ("PGC") rates reflecting higher natural gas costs. Gas Utility's cost of gas was $368.9 million in Fiscal 2004 compared to $343.0 million in Fiscal 2003 reflecting greater cost of gas associated with the higher off-system sales and the higher average retail core-market PGC rates partially offset by the effects of the lower retail core-market volumes sold. Increases or decreases in Gas Utility's cost of gas associated with retail core-market customers result from changes in retail core-market volumes, the price of the gas purchased and the level of gas costs collected through the PGC recovery mechanism. Under this recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers equal to the amount included in rates and defers the difference on the balance sheet as a regulatory asset or liability representing an amount to be collected from or refunded to customers in a future period. As a result, 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 total margin declined $5.4 million principally reflecting a $4.0 million decline in retail core-market margin and the effects of lower margins on delivery-service. Gas Utility operating income declined $16.0 million in Fiscal 2004 principally reflecting the previously mentioned decline in total margin, lower other income and higher operating and administrative expenses. Other income declined $5.4 million due in large part to a decline in non-tariff service income, costs related to settling a regulatory claim and the absence of pension income in Fiscal 2004. Operating and administrative expenses increased $3.8 million due primarily to higher compensation and benefits expense, including the effects of a lump-sum payment made to a participant of UGI Utilities' unfunded executive retirement plan, partially offset by the absence of costs related to settling an environmental claim recorded in the prior year and lower Fiscal 2004 distribution system maintenance expenses. The decrease in Gas Utility income before income taxes reflects the decline in operating income and slightly higher interest expense in Fiscal 2004 resulting from classifying dividends paid on preferred shares subject to mandatory redemption as interest expense, beginning July 1, 2003, in accordance with Statement of Financial Accounting Standards ("SFAS") No. 150 ("SFAS 150"). ELECTRIC OPERATIONS. Electric Utility's Fiscal 2004 kilowatt-hour sales were slightly higher than in Fiscal 2003 due in large part to greater air conditioning sales partially offset by the adverse effects of slightly warmer winter weather on heating-related sales. The decline in Electric Operations revenues in Fiscal 2004 principally reflects the absence of $8.0 million of revenues from UGID's electricity generation business recorded in the prior year. Electric Operations' cost of sales declined $6.6 million in Fiscal 2004 reflecting the absence of $6.2 million of costs related to UGID's operations and approximately $0.4 million of lower Electric Utility purchased power costs. Electric Operations total margin in Fiscal 2004 declined $0.7 million principally reflecting the absence of $1.8 million of total margin related to UGID's operations partially offset by a $1.1 million increase in Electric Utility total margin. Operating income and income before income -12- taxes were lower in Fiscal 2004 principally reflecting the decline in total margin. FISCAL 2003 COMPARED WITH FISCAL 2002 Year Ended September 30, 2003 2002 Increase - ------------------------ ------ ------ -------------- (Millions of dollars) GAS UTILITY: Revenues $539.9 $404.5 $135.4 33.5% Total margin $196.9 $162.9 $ 34.0 20.9% Operating income $ 96.1 $ 77.1 $ 19.0 24.6% Income before income taxes $ 80.7 $ 62.9 $ 17.8 28.3% System throughput - bcf 83.8 70.5 13.3 18.9% Degree days - % colder (warmer) than normal 7.0% (17.4)% -- -- ELECTRIC OPERATIONS: Revenues $ 96.9 $ 86.0 $ 10.9 12.7% Total margin (a) $ 42.2 $ 32.8 $ 9.4 28.7% Operating income $ 21.8 $ 13.2 $ 8.6 65.2% Income before income taxes $ 19.5 $ 10.7 $ 8.8 82.2% Distribution sales - gwh 980.0 933.6 46.4 5.0% (a) Electric Operation's total margin represents total revenues less cost of sales and Electric Utility gross receipts taxes of $4.8 million and $4.6 million in Fiscal 2003 and Fiscal 2002, respectively. GAS UTILITY. Weather in Gas Utility's service territory based upon heating degree days was 7.0% colder than normal during Fiscal 2003 compared to weather that was 17.4% warmer than normal during Fiscal 2002. The significantly colder weather resulted in higher heating-related sales to retail core-market customers and, to a lesser extent, greater volumes transported for residential, commercial and industrial delivery service customers. System throughput in Fiscal 2003 also benefited from a year-over-year increase in the number of customers. Gas Utility revenues in Fiscal 2003 increased principally as a result of the previously mentioned greater retail core-market and delivery service volumes and higher average retail core-market PGC rates resulting from higher natural gas costs. Gas Utility's cost of gas was $343.0 million in Fiscal 2003, an increase of $101.3 million from Fiscal 2002, reflecting the higher retail core-market volumes sold and the higher retail core-market PGC rates. The increase in Gas Utility total margin in Fiscal 2003 compared to Fiscal 2002 principally reflects a $27.1 million increase in retail core-market total margin due to the higher retail core-market sales and increased margin from greater delivery service volumes. -13- The increase in Gas Utility operating income principally reflects the increase in total margin partially offset by a $12.7 million increase in operating and administrative expenses and lower other income. Fiscal 2003 operating and administrative expenses include higher costs associated with litigation-related costs and expenses, greater distribution system maintenance expenses, higher uncollectible accounts expenses and increased incentive compensation costs. Other income declined $3.2 million principally reflecting a $2.2 million decrease in pension income and lower interest income on PGC undercollections. The increase in Gas Utility income before income taxes reflects the increase in operating income offset by higher interest expense on PGC overcollections and, beginning July 1, 2003, the classification of dividends on preferred shares as interest expense. ELECTRIC OPERATIONS. Electric Utility's Fiscal 2003 kilowatt-hour sales increased principally as a result of weather based upon heating degree days that was 8.4% colder than normal compared to weather that was 14.5% warmer than normal in the prior year. The higher Electric Operations revenues reflect greater Electric Utility sales and greater sales of electricity produced by UGID's electricity generation assets to third parties prior to its distribution to UGI in June 2003. Prior to September 2002, UGID sold substantially all of the electricity it produced to Electric Utility with the associated revenue and margin eliminated in our consolidated results. Beginning September 2002, Electric Utility began purchasing its power needs exclusively from third-party electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market, and UGID began selling electric power produced from its interests in electricity generating facilities to third parties on the spot market. Notwithstanding the significant increase in Electric Operations' revenues, cost of sales increased only $1.3 million in Fiscal 2003 as the impact on cost of sales resulting from the greater Electric Utility and electric generation third-party sales was partially offset by lower Electric Utility per-unit purchased power costs. The increase in Electric Operations' total margin principally reflects lower Electric Utility per-unit purchased power costs, the increase in Electric Utility sales, and margin from the greater sales of electricity produced by UGID's electricity generation assets to third parties. The higher Fiscal 2003 operating income reflects the greater total margin and higher other income partially offset by slightly higher operating and administrative expenses. The increase in Electric Operations income before income taxes reflects the increase in operating income and slightly lower interest expense. FINANCIAL CONDITION AND LIQUIDITY CAPITALIZATION AND LIQUIDITY Utilities total debt outstanding was $278.1 million at September 30, 2004. Included in this amount is $60.9 million of borrowings outstanding under revolving credit agreements. -14- Utilities has revolving credit commitments under which it may borrow up to a total of $110 million. These agreements are currently scheduled to expire in June 2007. In addition, UGI Utilities has an uncommitted arrangement with a major bank under which it may borrow up to $20 million. At September 30, 2004, there were no borrowings outstanding under this arrangement. Amounts outstanding under the revolving credit agreements and the uncommitted arrangement are classified as bank loans on the Consolidated Balance Sheets. The revolving credit agreements have restrictions on such items as total debt, debt service and payments for investments. On July 27, 2004, UGI Utilities' Board of Directors approved the redemption on October 1, 2004 of all 200,000 shares of the $7.75 Series Preferred Stock at a price of $100 per share together with full cumulative dividends. The redemption on October 1, 2004 of all 200,000 shares of the $7.75 Series Preferred Stock was funded with proceeds from the issuance of $20 million of 6.13% Medium-Term Notes due October 2034. Utilities has a shelf registration statement with the U.S. Securities and Exchange Commission under which it may issue up to an additional $20 million of Medium-Term Notes or other debt securities. In order to provide additional short-term liquidity during the peak-heating season, on November 1, 2004, Utilities borrowed $20 million under the uncommitted arrangement with a major bank, which is scheduled to mature on March 1, 2005. Based upon cash expected to be generated from Gas Utility and Electric Utility operations, short-term borrowings, including borrowings available under revolving credit agreements and the availability of its Medium-Term Notes, management believes that Utilities will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2005. For a more detailed discussion of Utilities' long-term debt and credit facilities, see Note 3 to Consolidated Financial Statements. CASH FLOWS OPERATING ACTIVITIES. Due to the seasonal nature of Utilities' businesses, cash flows from 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 usually at their lowest levels during the first and fourth quarters when the Company's investment in working capital, principally accounts receivable and inventories, is generally greatest. Utilities uses its revolving credit agreements and the uncommitted arrangement with a major bank to satisfy its seasonal operating cash flow needs. Cash flow from operating activities was $67.0 million in Fiscal 2004, $97.8 million in Fiscal 2003, and $55.1 million in Fiscal 2002. Cash flow from operating activities before changes in operating working capital was $92.9 million in Fiscal 2004, $91.8 million in Fiscal 2003 and $78.4 million in Fiscal 2002. Changes in operating working capital used $26.0 million of operating cash flow in Fiscal 2004, provided $6.0 million of operating cash flow in Fiscal 2003 and used $23.3 million of operating cash flow in Fiscal 2002. The decrease in Fiscal 2004 cash flow from operating activities compared to Fiscal 2003 principally reflects, among other things, a decline in cash flow from changes in Gas Utility deferred fuel costs and an increase in accounts receivable partially offset by greater noncash deferred income taxes. -15- INVESTING ACTIVITIES. Cash flow used in investing activities was $42.4 million in Fiscal 2004, $43.1 million in Fiscal 2003 and $36.6 million in Fiscal 2002. Expenditures for property, plant and equipment were $40.7 million in Fiscal 2004, $41.3 million in Fiscal 2003 and $35.9 million in Fiscal 2002. Net costs of property, plant and equipment disposals which principally represent net costs associated with retirements of distribution system assets were $1.7 million in Fiscal 2004, $1.8 million in Fiscal 2003 and $0.7 million in Fiscal 2002. FINANCING ACTIVITIES. Cash flow used by financing activities was $24.8 million in Fiscal 2004, $60.5 million in Fiscal 2003 and $20.1 million in Fiscal 2002. Financing activity cash flow changes are primarily due to issuances and repayments of long-term debt, net short-term borrowings including borrowings under revolving credit facilities, dividends on common stock and, prior to the adoption of SFAS 150, effective July 1, 2003, dividends on preferred shares subject to mandatory redemption and capital contributions from UGI. During Fiscal 2004, 2003 and 2002, we paid cash dividends to UGI of $45.0 million, $33.9 million and $37.9 million, respectively. Although we paid dividends on our preferred shares subject to mandatory redemption of $1.6 million in all three periods, dividends paid on the preferred shares subject to mandatory redemption for all periods beginning July 1, 2003 are reflected in cash flow from operations as a result of the application of SFAS 150 (see "Preferred Shares Subject to Mandatory Redemption" below). PREFERRED SHARES SUBJECT TO MANDATORY REDEMPTION Beginning July 1, 2003 through the date of their redemption on October 1, 2004, the Company accounted for its preferred shares subject to mandatory redemption in accordance with SFAS 150. SFAS 150 establishes guidelines on how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The adoption of SFAS 150, effective July 1, 2003, resulted in the Company presenting its preferred shares subject to mandatory redemption in the liabilities section of the balance sheet and reflecting dividends paid on these shares as a component of interest expense for periods presented after June 30, 2003. Prior to July 1, 2003, these dividends were reflected as a deduction from net income. Because SFAS 150 specifically prohibits the restatement of financial statements prior to its adoption, prior period amounts have not been reclassified. The amount of such dividends reflected in interest expense was $1.6 million in Fiscal 2004 and $0.4 million in Fiscal 2003. DIVIDEND OF UGID In June 2003, the Company dividended all of the common stock of UGID and UGID's subsidiaries to UGI. The net book value of the assets and liabilities of UGID and its subsidiaries on the date of distribution totaling $15.4 million (including $2.6 million of cash) was eliminated from the consolidated balance sheet and reflected as a dividend from retained earnings. The results of operations of UGID and its subsidiaries through the date of distribution did not have a material effect on the Company's net income in Fiscal 2003 or 2002. -16- UTILITIES PENSION PLAN UGI Utilities sponsors a defined benefit pension plan ("Pension Plan") for employees of UGI Utilities, UGI, and certain of UGI's other subsidiaries. The fair value of Pension Plan assets was $196.4 million and $183.8 million at September 30, 2004 and 2003, respectively. At September 30, 2004 and 2003, the Pension Plan's assets exceeded its accumulated benefit obligations by $9.2 million and $7.3 million, respectively. The Company is in full compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 ("ERISA") rules and regulations, and does not anticipate it will be required to make a contribution to the Pension Plan in Fiscal 2005. Pre-tax pension expense (income) reflected in Fiscal 2004, 2003 and 2002 results was $1.0 million, $(1.2) million and $(3.9) million, respectively. The decrease in pension income during this period principally reflects the changes in the market value of Plan assets and decreases in the discount rate assumption. Pension expense in Fiscal 2005 is expected to be approximately $2.5 million due in large part to the expiration of the Pension Plan's transition asset amortization. CAPITAL EXPENDITURES In the following table, we present capital expenditures by business segment for Fiscal 2004, Fiscal 2003 and Fiscal 2002. We also provide amounts we expect to spend in Fiscal 2005. We expect to finance a substantial portion of Fiscal 2005 capital expenditures from cash generated by operations and the remainder from borrowings under our credit facilities. Year Ended September 30, 2005 2004 2003(a) 2002(a) - ------------------------ ---------- ----- ------- ------- (Millions of dollars) (estimate) Gas Utility $41.4 $35.5 $37.2 $31.0 Electric Operations 9.6 5.2 4.1 4.9 ----- ----- ----- ----- $51.0 $40.7 $41.3 $35.9 ===== ===== ===== ===== (a) Includes capital expenditures for both the Electric Utility and UGID businesses. -17- CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS Utilities has certain contractual cash obligations that extend beyond Fiscal 2004 including scheduled repayments of long-term debt and, prior to their redemption on October 1, 2004, preferred shares subject to mandatory redemption, operating lease obligations and unconditional purchase obligations for pipeline transportation and natural gas storage services, and commitments to purchase natural gas and electricity. The following table presents contractual cash obligations under agreements existing as of September 30, 2004 (in millions). Payments Due by Period -------------------------------------------- 1 year 2 - 3 4 - 5 After Total or less years years 5 years ------ ------- ------ ------ ------- Long-term debt $217.0 $ 20.0 $ 70.0 $ -- $127.0 UGI Utilities preferred shares subject to mandatory redemption 20.0 20.0 -- -- -- Operating leases 14.8 3.5 5.7 2.7 2.9 Gas Utility and Electric Utility supply, storage and transportation contracts 598.3 188.5 181.3 112.2 116.3 ------ ------- ------ ------ ------ Total $850.1 $232.0 $257.0 $114.9 $246.2 ====== ====== ====== ====== ====== RELATED PARTY TRANSACTIONS UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct and for an allocated share of indirect corporate expenses incurred or paid on behalf of UGI Utilities. These billed expenses totaled $11.2 million in Fiscal 2004, $9.4 million in Fiscal 2003 and $6.7 million in Fiscal 2002 and are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI's subsidiaries, largely payroll related services. Amounts billed to these entities by UGI Utilities is not material. Gas Utility enters into wholesale natural gas transactions with UGI Energy Services, Inc. ("Energy Services"), a wholly owned second-tier subsidiary of UGI, for winter peaking service and, from time to time, purchases of natural gas or pipeline capacity. In addition, from time to time, the Company sells natural gas to Energy Services. These transactions did not have a material effect on the Company's net income during 2004, 2003 and 2002. For additional information on these transactions, see Note 12 to Consolidated Financial Statements included elsewhere in this Form 10-K. 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. -18- REGULATORY MATTERS Since the 1980s, larger commercial and industrial customers have been able to purchase gas supplies from entities other than Gas Utility. As a result of Pennsylvania's Natural Gas Choice and Competition Act (the "Gas Competition Act") that became effective July 1, 1999, all natural gas consumers in Pennsylvania, including residential and smaller commercial and industrial customers ("core-market customers"), have been afforded this opportunity. Under the Gas Competition Act, natural gas distribution companies ("NGDCs"), like Gas Utility, continue to serve as the supplier 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, 2004, less than two percent of Gas Utility's core-market customers purchase their gas from alternative suppliers. As a result of the Electricity Generation Customer Choice and Competition Act ("Electric 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. Electric Utility remains the provider of last resort ("POLR") for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service, have been established in a series of PUC-approved settlements, the last of which became effective on June 7, 2004 (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. Customers who do not select an alternate supplier will be obligated to remain on POLR service until the next shopping period. Residential customers who return to POLR service at a time other than during the annual shopping period 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 at a time other than during the annual shopping period must remain on POLR service until the next open shopping period, and may, in certain circumstances, be subject to generation rate surcharges. Consistent with the terms of the POLR Settlement, Electric Utility's POLR rates will increase beginning January 2005, and Electric Utility is permitted, but not required, to further increase its POLR rates beginning January 2006. Electric Utility is also permitted to, and has, entered into multiple-year fixed-rate POLR contracts with certain of its customers. Pursuant to the requirements of the Electric Competition Act, the PUC is currently developing post-rate-cap POLR regulations that are expected to further define POLR service obligations and pricing. As of September 30, 2004, fewer than 1% of Electric Utility's customers have chosen an alternative electricity generation supplier. 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 -19- 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, 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, Utilities divested all of its utility operations other than those which now constitute Gas Utility and Electric Utility. 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 Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. 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. Utilities is currently litigating three claims against it relating to out-of-state sites. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Management believes that under applicable law 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 Utilities directly owned or operated, or that were owned or operated by former subsidiaries of Utilities, if a court were to conclude that (1) the subsidiary's separate corporate form should be disregarded or (2) Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary's MGP. In April 2003, Citizens Communications Company ("Citizens") served a complaint naming UGI Utilities as a third party defendant in a civil action pending in United States District Court for the District of Maine. In that action, the plaintiff, City of Bangor, Maine ("City") sued Citizens to -20- 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 MGP from 1901 to 1928. The City believes that it could cost as much as $50 million to clean up the river. UGI Utilities believes that it has good defenses to the claim and is defending the suit. By letter dated July 29, 2003, Atlanta Gas Light Company ("AGL") served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8 million incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. UGI Utilities believes that it has good defenses to the claim and is defending the suit. AGL previously informed UGI Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL has recently informed UGI Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55 million. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site. 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. ConEd believes that the cost of remediation for all of the sites could exceed $70 million. By orders issued in November 2003 and March 2004, the court granted UGI Utilities' motion for summary judgment and dismissed ConEd's complaint. ConEd has appealed. 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. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim. -21- By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together, the "Northeast Companies"), demanded 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. According to the letter, investigation and remedial costs at the sites to date total approximately $10 million and complete remediation costs for all sites could total $182 million. The Northeast Companies seek an unspecified fair and equitable allocation of these costs to UGI Utilities. UGI Utilities is in the process of reviewing the information provided by Northeast Companies and is investigating this claim. MARKET RISK DISCLOSURES 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 a periodic adjustment 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 exchange-traded natural gas call option contracts to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these call option contracts, net of any associated gains, is included in Gas Utility's PGC recovery mechanism. Electric Utility purchases its power needs from electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market. Prices for electricity can be volatile especially during periods of high demand or tight supply. In accordance with POLR settlements approved by the PUC, Electric Utility may increase its POLR rates up to certain limits through December 31, 2006. In accordance with these settlements, effective January 1, 2005 and January 1, 2006, POLR generation rates for all metered customers may increase up to 4.5% and 7.5%, respectively, of total rates in effect on December 31, 2004. Currently, Electric Utility's fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 31, 2006. However, should any of the suppliers under these contracts fail to provide electric power under the terms of the power and capacity contracts, any increases in the cost of replacement power or capacity could negatively impact Electric Utility results. In order to reduce this non-performance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. At September 30, 2004, the fair value of our electricity price swap was a gain of $2.0 million. Fair value reflects the estimated amount that we would expect to receive or pay to terminate the contract based upon quoted market prices of comparable contracts at September 30, 2004. An adverse change in electricity prices of ten percent would result in a $1.0 million decrease in the fair value of the swap. -22- 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 borrowings under our revolving credit agreements. These 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 2004 and Fiscal 2003, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.4 million and $0.3 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 $13.8 million and $14.0 million at September 30, 2004 and 2003, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $15.5 million and $15.7 million at September 30, 2004 and 2003, respectively. In order to reduce interest rate risk associated with near-term issuances of fixed-rate debt, we may enter into interest rate protection agreements. The fair value of our unsettled interest rate protection agreements, which have been designated and qualify as cash flow hedges, was a loss of $1.0 million at September 30, 2004. An adverse change in interest rates of ten percent on ten-year U.S. treasury notes would result in a $2.3 million decrease in the fair value of these 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 that are most important to the portrayal of the Company's financial condition and results of operations. Changes in these policies could have a material effect on the financial statements. The application of these accounting policies 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 its Audit Committee. In addition, management has reviewed the following disclosures regarding the application of these critical accounting policies with the Audit Committee. 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, Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere at which hazardous substances may be present. In accordance with -23- 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 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. REGULATORY ASSETS AND LIABILITIES. Gas Utility and Electric Utility's distribution businesses are subject to regulation by the Pennsylvania Public Utility Commission ("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, 2004, our regulatory assets totaled $65.1 million. DEFINED BENEFIT PENSION PLAN. The costs of providing benefits under our Pension Plan are 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 utilized including, the discount rate applied to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase. 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 the expected rate of return on plan assets and the discount rate. An unfavorable change in the expected rate of return on plan assets of 50 basis points would result in higher pre-tax pension expense of approximately $1.0 million in Fiscal 2005. An unfavorable change in the discount rate of 50 basis points would result in higher pre-tax pension expense of approximately $1.5 million in Fiscal 2005. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In December 2003, the Financial Accounting Standards Board ("FASB") revised Financial Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"), which was originally issued in January 2003 and clarifies Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FIN 46 was effective immediately for variable interest entities created or obtained after January 31, 2003. For variable interests created or acquired before February 1, 2003, FIN 46 was effective beginning with our interim period ended March -24- 31, 2004. The Company has not created or obtained any variable interest entities after January 31, 2003. If certain conditions are met, FIN 46 requires the primary beneficiary to consolidate certain variable interest entities. The adoption of FIN 46 did not have any impact on the Company's financial position or results of operations. On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act") was signed into law. Among other things, the Act provides for a prescription drug benefit to Medicare beneficiaries on a voluntary basis beginning in 2006. To encourage employers to continue to offer retiree prescription drug benefits, the Act provides for a tax-free subsidy to employers who offer a prescription drug benefit that is at least actuarially equivalent to the standard benefit offered under the Act. In May 2004, the FASB issued Staff Position No. FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" ("FSP 106-2"). FSP 106-2 is effective for periods beginning after June 15, 2004. The Company provides postretirement health care benefits to certain of its retirees and a limited number of active employees meeting certain age and service requirements. See Note 5 to the Consolidated Financial Statements for information on our Employee Retirement Plans. These postretirement benefits include certain retiree prescription drug benefits. The Company has determined that, as currently designed, its prescription drug benefit for eligible retirees is not actuarially equivalent to the standard benefit offered under the Act and, as a result, does not qualify for the tax-free subsidy. 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 -25- matters; (4) competitive pressures from the same and alternative energy sources; (5) liability for environmental claims; (6) customer conservation measures and improvements in energy efficiency and technology resulting in reduced demand; (7) adverse labor relations; (8) large customer, counterparty or supplier defaults; (9) 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; (10) political, regulatory and economic conditions in the United States; and (11) interest rate fluctuations and other capital market conditions. 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 set forth on pages F-2 to F-27 and page S-1 of this Report are incorporated herein by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES (a) Evaluation of Disclosure Controls and Procedures 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 -26- and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures as of the end of the period covered by this report were designed and functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The Company believes that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. (b) Change in Internal Control over Financial Reporting 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 Not applicable. -27- PART III: INTENTIONALLY OMITTED -28- 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, 2004 and 2003 Consolidated Statements of Income for the fiscal years ended September 30, 2004, 2003 and 2002 Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2004, 2003 and 2002 Consolidated Statements of Stockholder's Equity for the fiscal years ended September 30, 2004, 2003 and 2002 Notes to Consolidated Financial Statements (2) FINANCIAL STATEMENT SCHEDULE: For the years ended September 30, 2004, 2003 and 2002 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): -29- INCORPORATION BY REFERENCE EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - ----------- -------------------------------------------------------- ---------- ------------- -------- 3.1 Utilities' Articles of Incorporation Utilities Registration 3 Statement No. 333-72540 3.2 Bylaws of UGI Utilities as amended through September 30, Utilities Form 10-K 3.2 2003 (9/30/03) 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 Utilities' Articles of Incorporation and Bylaws referred to in Exhibit Nos. 3.1 and 3.2 4.2 [Intentionally omitted] 4.3 Form of Fixed Rate Medium-Term Note Utilities Form 8-K (4)i (8/26/94) 4.4 Form of Fixed Rate Series B Medium-Term Note Utilities Form 8-K 4(i) (8/1/96) 4.5 Form of Floating Rate Series B Medium-Term Note Utilities Form 8-K 4(ii) (8/1/96) 4.6 [Intentionally omitted] 4.7 Officer's Certificate establishing Medium-Term Notes Utilities Form 8-K 4(iv) series (8/26/94) 4.8 [Intentionally omitted] 4.9 Form of Officer's Certificate establishing Series B Utilities Form 8-K 4(iv) Medium-Term Notes under the Indenture (8/1/96) 4.10 Forms of Floating Rate and Fixed Rate Series C Utilities Form 8-K 4.1 Medium-Term Notes (5/21/02) 4.11 Form of Officers' Certificate establishing Series C Utilities Form 8-K 4.2 Medium-Term Notes under the Indenture (5/21/02) -30- INCORPORATION BY REFERENCE EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - ----------- -------------------------------------------------------- ---------- --------- ------- 10.1 Service Agreement (Rate FSS) dated as of November 1, UGI Form 10-K 10.5 1989 between Utilities and Columbia, as modified (9/30/95) 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) 10.2** UGI Corporation 2004 Omnibus Equity Compensation Plan, UGI Form 10-K 10.17 as amended December 7, 2004 (9/30/04) 10.3** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.2 Directors Stock Unit Grant Letter dated as of January 8, (9/30/04) 2004 10.4** UGI Corporation 1992 Directors' Stock Plan Amended and UGI Form 10-Q 10.2 Restated as of April 29, 2003 (3/31/03) 10.5** UGI Corporation Directors' Deferred Compensation Plan UGI Form 10-K 10.6 Amended and Restated as of January 1, 2000 (9/30/00) 10.6** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.3 Directors Nonqualified Stock Option Grant Letter dated (9/30/04) as of January 8, 2004 10.7** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.36 UGI Employees Nonqualified Stock Option Grant Letter (9/30/04) dated as of January 1, 2004 10.8** UGI Corporation Annual Bonus Plan dated March 8, 1996 UGI Form 10-Q 10.4 (6/30/96) 10.9** UGI Utilities, Inc. Annual Bonus Plan dated March 8, Utilities Form 10-Q 10.4 1996 (6/30/96) 10.10** 1997 Stock Purchase Loan Plan UGI Form 10-K 10.16 (9/30/97) 10.11** UGI Corporation Senior Executive Employee Severance Pay UGI Form 10-K 10.12 Plan as amended December 7, 2004 (9/30/04) -31- INCORPORATION BY REFERENCE EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - ----------- -------------------------------------------------------- ---------- --------- ------- 10.12** UGI Corporation 1992 Non-Qualified Stock Option Plan, as UGI Form 10-K 10.39 amended (9/30/00) 10.13** UGI Corporation 2000 Directors' Stock Option Plan UGI Form 10-Q 10.1 Amended and Restated as of April 29, 2003 (3/31/03) 10.14** UGI Corporation 2000 Stock Incentive Plan Amended and UGI Form 10-Q 10.5 Restated as of April 29, 2003 (3/31/03) 10.15 Service Agreement for comprehensive delivery service UGI Form 10-K 10.41 (Rate CDS) dated February 23, 1999 between UGI (9/30/00) Utilities, Inc. and Texas Eastern Transmission Corporation 10.16** UGI Corporation 1997 Stock Option and Dividend UGI Form 10-Q 10.4 Equivalent Plan Amended and Restated as of April 29, (3/31/03) 2003 10.17** UGI Corporation Supplemental Executive Retirement Plan UGI Form 10-Q 10 Amended and Restated effective October 1, 1996 (6/30/98) 10.18 ** UGI Corporation 1992 Non-Qualified Stock Option Plan UGI Form 10-Q 10.3 Amended and Restated as of April 29, 2003 (3/31/03) 10.19 [Intentionally omitted] 10.20** Description of Change of Control arrangement for Mr. UGI Form 10-K 10.33 Greenberg (9/30/99) 10.21** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.5 UGI Employees Stock Unit Grant Letter dated as of (9/30/04) January 1, 2004 10.22** Form of Change of Control Agreement for executive Utilities Form 10-K 10.22 officers other than Mr. Greenberg (9/30/03) 10.23** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.7 UGI Employees Performance Unit Grant Letter dated as of (9/30/04) January 1, 2004 -32- INCORPORATION BY REFERENCE EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - ----------- -------------------------------------------------------- ---------- --------- ------- 10.24** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.4 Utilities Employees Performance Unit Grant Letter dated (9/30/04) as of January 1, 2004 10.25 Storage Transportation Service Agreement (Rate Schedule Utilities Form 10-K 10.25 SST) between Utilities and Columbia dated November 1, (9/30/02) 1993, as modified pursuant to orders of the Federal Energy Regulatory Commission *10.26 Amendment No. 1 dated November 1, 2004, to the Service Agreement (Rate FSS) dated as of November 1, 1989 between 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) 10.27 No-Notice Transportation Service Agreement (Rate Utilities Form 10-K 10.27 Schedule CDS) between Utilities and Texas Eastern (9/30/02) Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission 10.28 No-Notice Transportation Service Agreement (Rate Utilities Form 10-K 10.28 Schedule CDS) between Utilities and Texas Eastern (9/30/02) Transmission dated October 31, 2000, as modified pursuant to various orders of the Federal Energy Regulatory Commission 10.29 Firm Transportation Service Agreement (Rate Schedule Utilities Form 10-K 10.29 FT-1) between Utilities and Texas Eastern Transmission (9/30/02) dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission *10.30 Amendment No. 1 dated November 1, 2004, to the No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission -33- INCORPORATION BY REFERENCE EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - ----------- -------------------------------------------------------- ---------- --------- -------- 10.31 Firm Transportation Service Agreement (Rate Schedule FT) Utilities Form 10-K 10.31 between Utilities and Transcontinental Gas Pipe Line (9/30/02) dated October 1, 1996, as modified pursuant to various orders of the Federal Energy Regulatory Commission *10.32 Gas Service Delivery and Supply Agreement between Utilities and UGI Energy Services, Inc. dated August 26, 2004 *10.33 Amendment No. 1 dated November 1, 2004, to the Firm Transportation Service Agreement (Rate Schedule FT-1) between Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission *10.34 Firm Transportation Service Agreement (Rate Schedule FTS) between Utilities and Columbia Gas Transmission dated November 1, 2004 10.35** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.36(a) UGI Utilities Employees Nonqualified Stock Option Grant (9/30/04) Letter dated as of January 1, 2004 *12.1 Computation of Ratio of Earnings to Fixed Charges *12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends 14 Code of Ethics for principal executive, financial and Utilities Form 10-K 14 accounting officers (9/30/03) *23 Consent of PricewaterhouseCoopers LLP *31.1 Certification by the Chief Executive Officer relating to the Registrant's Report on Form 10-K for the year ended September 30, 2004 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 -34- INCORPORATION BY REFERENCE EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - ----------- -------------------------------------------------------- ---------- --------- ------- *31.2 Certification by the Chief Financial Officer relating to the Registrant's Report on Form 10-K for the year ended September 30, 2004 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, 2004 * Filed herewith. ** As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement. -35- SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized. UGI UTILITIES, INC. Date: December 7, 2004 By: John C. Barney ------------------------------------ John C. Barney Senior Vice President - Finance Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 7, 2004 by the following persons on behalf of the Registrant in the capacities indicated. SIGNATURE TITLE --------- ----- David W. Trego President and Chief - ----------------------- Executive Officer David W. Trego (Principal Executive Officer) and Director Lon R. Greenberg Chairman and Director - ----------------------- Lon R. Greenberg John C. Barney Senior Vice President - - ----------------------- Finance John C. Barney (Principal Financial Officer and Principal Accounting Officer) Stephen D. Ban Director - ----------------------- Stephen D. Ban Thomas F. Donovan Director - ----------------------- Thomas F. Donovan -36- Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 7, 2004 by the following persons on behalf of the Registrant in the capacities indicated. SIGNATURE TITLE --------- ----- Ernest E. Jones Director - ----------------------- Ernest E. Jones Richard C. Gozon Director - ----------------------- Richard C. Gozon Anne Pol Director - ----------------------- Anne Pol Marvin O. Schlanger Director - ----------------------- Marvin O. Schlanger James W. Stratton Director - ----------------------- James W. Stratton -37- 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 2004. UGI UTILITIES, INC. FINANCIAL INFORMATION FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K YEAR ENDED SEPTEMBER 30, 2004 F-1 UGI UTILITIES, INC. INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE Pages ----- Financial Statements: Report of Independent Registered Public Accounting Firm F-3 Consolidated Balance Sheets as of September 30, 2004 and 2003 F-4 to F-5 Consolidated Statements of Income for the years ended September 30, 2004, 2003 and 2002 F-6 Consolidated Statements of Cash Flows for the years ended September 30, 2004, 2003 and 2002 F-7 Consolidated Statements of Stockholder's Equity for the years ended September 30, 2004, 2003 and 2002 F-8 Notes to Consolidated Financial Statements F-9 to F-27 Financial Statement Schedule: For the years ended September 30, 2004, 2003 and 2002: II - Valuation and Qualifying Accounts S-1 We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes. F-2 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholder of UGI Utilities, Inc.: In our opinion, the consolidated financial statements listed in the index appearing under Item 15a (1) present fairly, in all material respects, the financial position of UGI Utilities, Inc. and its subsidiaries at September 30, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2004 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 15a (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion. /s/ PricewaterhouseCoopers LLP Philadelphia, Pennsylvania December 6, 2004 F-3 UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of dollars) September 30, --------------------- 2004 2003 --------- --------- ASSETS Current assets: Cash and cash equivalents $ 21 $ 304 Accounts receivable (less allowances for doubtful accounts of $3,374 and $3,275, respectively) 38,897 30,101 Accrued utility revenues 9,742 7,431 Inventories 65,177 54,017 Deferred income taxes 7,230 10,375 Prepaid expenses and other current assets 8,723 5,552 --------- --------- Total current assets 129,790 107,780 Property, plant and equipment Gas utility 820,275 791,164 Electric operations 108,231 103,917 General 15,788 12,777 --------- --------- 944,294 907,858 Less accumulated depreciation and amortization (313,030) (296,871) --------- --------- Net property, plant and equipment 631,264 610,987 Regulatory assets 65,060 60,253 Other assets 29,664 30,028 --------- --------- Total assets $ 855,778 $ 809,048 ========= ========= See accompanying notes to consolidated financial statements. F-4 UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of dollars, except per share) September 30, ------------------- 2004 2003 -------- -------- LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities: Current maturities of long-term debt $ 20,000 $ -- Bank loans 60,900 40,700 Preferred shares subject to mandatory redemption, without par value 20,000 -- Accounts payable 62,707 55,298 Employee compensation and benefits accrued 12,639 8,457 Dividends and interest accrued 6,254 6,466 Income taxes accrued 2,111 479 Customer deposits and refunds 17,024 15,074 Deferred fuel costs 7,862 14,734 Other current liabilities 13,450 11,703 -------- -------- Total current liabilities 222,947 152,911 Long-term debt 197,151 217,271 Deferred income taxes 158,136 144,176 Deferred investment tax credits 7,589 7,987 Other noncurrent liabilities 9,924 11,951 Preferred shares subject to mandatory redemption, without par value -- 20,000 Commitments and contingencies (note 8) -------- -------- Total liabilities 595,747 554,296 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 79,773 79,046 Retained earnings 121,454 117,496 Accumulated other comprehensive loss (1,455) (2,049) -------- -------- Total common stockholder's equity 260,031 254,752 -------- -------- Total liabilities and stockholder's equity $855,778 $809,048 ======== ======== See accompanying notes to consolidated financial statements. F-5 UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Thousands of dollars) Year Ended September 30, ------------------------------ 2004 2003 2002 -------- -------- -------- Revenues $650,088 $636,758 $490,552 -------- -------- -------- Costs and expenses: Gas, fuel and purchased power 412,240 392,901 290,282 Operating and administrative expenses 93,244 91,947 80,910 Operating and administrative expenses - related parties 11,223 9,352 6,664 Taxes other than income taxes 12,501 12,195 11,930 Depreciation and amortization 22,520 21,240 22,172 Other income, net (2,669) (8,745) (11,723) -------- -------- -------- 549,059 518,890 400,235 -------- -------- -------- Operating income 101,029 117,868 90,317 Interest expense 17,931 17,656 16,652 -------- -------- -------- Income before income taxes 83,098 100,212 73,665 Income taxes 34,140 39,540 29,570 -------- -------- -------- Net income 48,958 60,672 44,095 Dividends on preferred shares subject to mandatory redemption -- 1,163 1,550 -------- -------- -------- Net income after dividends on preferred shares subject to mandatory redemption $ 48,958 $ 59,509 $ 42,545 ======== ======== ======== See accompanying notes to consolidated financial statements. F-6 UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Thousands of dollars) Year Ended September 30, ------------------------------ 2004 2003 2002 -------- -------- -------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 48,958 $ 60,672 $ 44,095 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 22,520 21,240 22,172 Deferred income taxes, net 11,873 2,097 11,114 Provision for uncollectible accounts 6,971 7,778 5,270 Pension expense (income) 1,022 (1,242) (3,857) Other 1,591 1,284 (391) Net change in: Accounts receivable and accrued utility revenues (18,078) (610) (1,631) Inventories (11,160) (15,601) 9,420 Deferred fuel costs (6,872) 19,038 (7,056) Accounts payable 7,409 (454) (9,957) Other current assets and liabilities 2,732 3,599 (14,123) -------- -------- -------- Net cash provided by operating activities 66,966 97,801 55,056 -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for property, plant and equipment (40,737) (41,297) (35,884) Net costs of property, plant and equipment disposals (1,712) (1,831) (704) -------- -------- -------- Net cash used by investing activities (42,449) (43,128) (36,588) -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Payment of dividends (45,000) (35,081) (39,489) Cash portion of UGID dividend -- (2,572) -- Issuance of long-term debt -- 44,694 40,000 Repayment of long-term debt -- (76,000) -- Bank loans increase (decrease) 20,200 3,500 (20,600) Capital contribution from UGI Corporation -- 5,000 -- -------- -------- -------- Net cash used by financing activities (24,800) (60,459) (20,089) -------- -------- -------- Cash and cash equivalents decrease $ (283) $ (5,786) $ (1,621) ======== ======== ======== CASH AND CASH EQUIVALENTS: End of year $ 21 $ 304 $ 6,090 Beginning of year 304 6,090 7,711 -------- -------- -------- Decrease $ (283) $ (5,786) $ (1,621) ======== ======== ======== See accompanying notes to consolidated financial statements. F-7 UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (Thousands of dollars) Accumulated Total Additional Other Common Common Paid-in Retained Comprehensive Stockholder's Stock Capital Earnings Loss Equity ------- ---------- -------- ------------- ------------- Balance September 30, 2001 $60,259 $72,792 $102,706 $ -- $235,757 Net income 44,095 44,095 Net change in fair value of interest rate protection agreements (net of tax of $1,968) (2,774) (2,774) -------- ------- -------- Comprehensive income 44,095 (2,774) 41,321 Cash dividends - common stock (37,939) (37,939) Cash dividends - preferred stock (1,550) (1,550) Other 265 265 ------- ------- -------- ------- -------- Balance September 30, 2002 60,259 73,057 107,312 (2,774) 237,854 Net income 60,672 60,672 Net change in fair value of interest rate protection agreements (net of tax of $365) 515 515 Reclassifications of net loss on interest rate protection agreements (net of tax of $149) 210 210 -------- ------- -------- Comprehensive income 60,672 725 61,397 Capital contribution by UGI Corporation 5,000 5,000 Cash dividends - common stock (33,918) (33,918) Cash dividends - preferred stock (1,163) (1,163) Dividend of UGID common stock (15,407) (15,407) Other 989 989 ------- ------- -------- ------- -------- Balance September 30, 2003 60,259 79,046 117,496 (2,049) 254,752 Net income 48,958 48,958 Net change in fair value of derivative instruments (net of tax of $246) 347 347 Reclassifications of net losses on interest rate protection agreements (net of tax of $176) 247 247 -------- ------- -------- Comprehensive income 48,958 594 49,552 Cash dividends - common stock (45,000) (45,000) Other 727 727 ------- ------- -------- ------- -------- Balance September 30, 2004 $60,259 $79,773 $121,454 $(1,455) $260,031 ======= ======= ======== ======= ======== See accompanying notes to consolidated financial statements. F-8 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS) 1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES CONSOLIDATION PRINCIPLES UGI Utilities, Inc. ("UGI Utilities"), a wholly owned subsidiary of UGI Corporation ("UGI"), owns and operates a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania; owns and operates an electricity distribution utility ("Electric Utility") in northeastern Pennsylvania; and prior to the June 2003 distribution to UGI of UGI Development Company ("UGID") and UGID's subsidiaries and 50%-owned joint-venture affiliate Hunlock Creek Energy Ventures ("Energy Ventures"), owned interests in Pennsylvania-based electricity generation assets through UGID. We refer to Gas Utility, Electric Utility and UGID (prior to its distribution to UGI) collectively as "the Company" or "we," and Electric Utility and UGID collectively as "Electric Operations." Our consolidated financial statements include the accounts of UGI Utilities and its consolidated subsidiaries for the periods prior to June 2003 and those of UGI Utilities subsequent to May 2003. We eliminate all significant intercompany accounts and transactions when we consolidate. Our investment in Energy Ventures, prior to its distribution in June 2003, was accounted for under the equity method. Gas Utility and Electric Utility (collectively, "Utilities") are subject to regulation by the Pennsylvania Public Utility Commission ("PUC"). UGID was granted "Exempt Wholesale Generator" status by the Federal Energy Regulatory Commission. As previously mentioned, in June 2003 the Company dividended all of the common stock of UGID and its subsidiaries to UGI. The net book value of the assets and liabilities of UGID and its subsidiaries totaling $15,407 (including $2,572 of cash) was eliminated from the consolidated balance sheet and reflected as a dividend from retained earnings. UGID and its subsidiaries' results of operations, prior to their distribution, did not have a material effect on the Company's results of operations in 2003 and 2002. USE OF ESTIMATES We make estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States of America. These estimates and assumptions affect the reported amounts of assets and liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. REGULATED UTILITY OPERATIONS We account for the operations of Gas Utility and Electric Utility in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71"). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and F-9 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated operations and that the recovery of our regulatory assets is probable. See Note 2. CONSOLIDATED STATEMENTS OF CASH FLOWS We define cash equivalents as all highly liquid investments with maturities of three months or less when purchased. We record cash equivalents at cost plus accrued interest, which approximates market value. We paid interest totaling $18,143 in 2004, $16,046 in 2003 and $16,348 in 2002. We paid income taxes totaling $19,910 in 2004, $29,372 in 2003 and $36,282 in 2002. REVENUE RECOGNITION Gas Utility and Electric Utility record regulated revenues for service provided to the end of each month which includes an accrual for certain unbilled amounts based upon estimated usage. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered. INVENTORIES Our inventories are stated at the lower of cost or market. We determine cost principally on an average cost method except for appliances for which we use the specific identification method. INCOME TAXES Gas Utility and Electric Utility record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. They also record a deferred tax liability for tax benefits that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse. We are amortizing deferred investment tax credits related to Utilities' plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in F-10 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is generally consistent with income taxes calculated on a separate return basis. PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION We record property, plant and equipment at cost. When Gas Utility and Electric Utility retire depreciable utility plant and equipment, we charge the original cost, net of removal costs and salvage value, to accumulated depreciation for financial accounting purposes. We record depreciation expense for UGI Utilities' plant and equipment on a straight-line method over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.3% in both 2004 and 2003 and 2.5% in 2002. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.8% in 2004 and 3.0% in both 2003 and 2002. Depreciation expense was $21,860 in 2004, $20,754 in 2003 and $21,649 in 2002. We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. COMPUTER SOFTWARE COSTS We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding ten years once the installed software is ready for its intended use. DEFERRED FUEL COSTS Gas Utility's tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost ("PGC") rates. The clauses provide for periodic adjustments to PGC rates for the difference between the total amount of purchased gas costs collected from customers and the recoverable costs incurred. In accordance with SFAS 71, we defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers. The balance sheet caption "deferred fuel costs" reflects amounts related to this PGC recovery mechanism. PREFERRED SHARES SUBJECT TO MANDATORY REDEMPTION Beginning July 1, 2003 through the date of their redemption on October 1, 2004 (see Note 7), the Company accounted for its preferred shares subject to mandatory redemption in accordance with SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" ("SFAS 150"). SFAS 150 establishes guidelines on how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The adoption of SFAS 150, effective July 1, 2003, resulted in the Company presenting its preferred shares subject to mandatory redemption in the liabilities section of the balance sheet, and reflecting F-11 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) dividends paid on these shares as a component of interest expense, for periods presented after June 30, 2003. Prior to July 1, 2003, these dividends were reflected as a deduction from net income. Because SFAS 150 specifically prohibits the restatement of financial statements prior to its adoption, prior period amounts have not been reclassified. STOCK-BASED COMPENSATION Certain members of Utilities' management may be granted stock options and other equity-based awards of UGI Common Stock under UGI's current equity compensation plans. As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), we apply the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"), in recording compensation expense for grants of equity instruments to employees. We use the intrinsic value method prescribed by APB 25 for UGI's equity-based employee compensation plans. We recorded equity-based compensation expense of $2,652 in 2004, $1,372 in 2003 and $1,168 in 2002, respectively. If we had determined stock-based compensation expense under the fair value method prescribed by the provisions of SFAS 123, net income after dividends on preferred shares subject to mandatory redemption would have been as follows at September 30: 2004 2003 2002 ------- ------- ------- Net income after dividends on preferred shares subject to mandatory redemption, as reported $48,958 $59,509 $42,545 Add: Stock-based employee compensation expense included in reported net income, net of related tax effects 1,551 803 684 Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of related tax effects (1,715) (927) (812) ------- ------- ------- Pro forma net income after dividends on preferred shares subject to mandatory redemption $48,794 $59,385 $42,417 ======= ======= ======= ENVIRONMENTAL AND OTHER LEGAL MATTERS We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Amounts accrued generally reflect our best estimate of costs expected to be incurred or the minimum liability associated with a range of expected environmental response costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of any incurred costs through all appropriate means, including regulatory relief. Gas Utility is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. Gas Utility is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred removal costs. At September 30, 2004, the Company's accrued F-12 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) liability for environmental investigation and cleanup costs was not material. Similar to environmental matters, we accrue investigation and other legal costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated (see Note 8). DERIVATIVE INSTRUMENTS SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. For a detailed description of the derivative instruments we use, our objectives for using them, and related supplemental information required by SFAS 133, see Note 9. COMPREHENSIVE INCOME Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) of $594, $725 and $(2,774) for the years ended September 30, 2004, 2003 and 2002, respectively, is the result of gains or losses on interest rate protection agreements ("IRPAs") and in 2004, changes in the fair value of an electric price swap agreement qualifying as cash flow hedges, net of reclassifications to net income. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In December 2003, the Financial Accounting Standards Board ("FASB") revised Financial Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"), which was originally issued in January 2003 and clarifies Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FIN 46 was effective immediately for variable interest entities created or obtained after January 31, 2003. For variable interests created or acquired before February 1, 2003, FIN 46 was effective beginning with our interim period ended March 31, 2004. The Company has not created or obtained any variable interest entities after January 31, 2003. If certain conditions are met, FIN 46 requires the primary beneficiary to consolidate certain variable interest entities. The adoption of FIN 46 did not have any impact on the Company's financial position, results of operations or cash flows. On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act") was signed into law. Among other things, the Act provides for a prescription drug benefit to Medicare beneficiaries on a voluntary basis beginning in 2006. To encourage employers to continue to offer retiree prescription drug benefits, the Act provides for a tax-free subsidy to employers who offer a prescription drug benefit that is at least actuarially equivalent to the standard benefit offered under the Act. In May 2004, the FASB issued Staff Position No. FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" ("FSP 106-2"). FSP 106-2 is effective for periods beginning after June 15, 2004. The Company provides postretirement health care benefits principally to certain of its retirees and a limited number of active employees meeting certain age and service requirements. See F-13 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note 6 for information on our employee retirement plans. These postretirement benefits include certain retiree prescription drug benefits. The Company has determined that, as currently designed, its prescription drug benefit for retirees is not actuarially equivalent to the standard benefit offered under the Act and, as a result, does not qualify for the tax-free subsidy. 2. UTILITY REGULATORY ASSETS AND LIABILITIES The following regulatory assets and liabilities are included in our accompanying balance sheets at September 30: 2004 2003 ------- ------- Regulatory assets: Income taxes recoverable $62,039 $57,625 Other postretirement benefits 1,926 2,162 Other 1,095 466 ------- ------- Total regulatory assets $65,060 $60,253 ------- ------- Regulatory liabilities: Other postretirement benefits $ 2,976 $ 3,746 Deferred fuel costs 7,862 14,734 ------- ------- Total regulatory liabilities $10,838 $18,480 ------- ------- The Company's regulatory liabilities relating to other postretirement benefits are included in "other noncurrent liabilities" on the Consolidated Balance Sheets. The Company does not recover a rate of return on its regulatory assets. 3. DEBT Long-term debt comprises the following at September 30: 2004 2003 -------- -------- Medium-Term Notes: 7.25% Notes, due November 2017 $ 20,000 $ 20,000 7.17% Notes, due June 2007 20,000 20,000 7.37% Notes, due October 2015 22,000 22,000 6.62% Notes, due May 2005 20,000 20,000 7.14% Notes, due December 2005 (including unamortized premium of $151 and $271, respectively, effective rate - 6.64%) 30,151 30,271 7.14% Notes, due December 2005 20,000 20,000 5.53% Notes due September 2012 40,000 40,000 5.37% Notes due August 2013 25,000 25,000 6.50% Notes due August 2033 20,000 20,000 -------- -------- Total long-term debt 217,151 217,271 Less current maturities (20,000) -- -------- -------- Long-term debt due after one year $197,151 $217,271 -------- -------- Scheduled principal repayments of long-term debt for each of the next five fiscal years ending September 30 are as follows: 2005 - $20,000; 2006 - $50,000; 2007 - $20,000; 2008 - $0; 2009 - $0. F-14 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) At September 30, 2004, UGI Utilities had revolving credit agreements with five banks providing for borrowings of up to $110,000. These agreements are currently scheduled to expire in June 2007. UGI Utilities may borrow at various prevailing interest rates, including LIBOR and the banks' prime rate. UGI Utilities pays quarterly commitment fees on these credit lines. UGI Utilities had revolving credit agreement borrowings totaling $60,900 at September 30, 2004 and $40,700 at September 30, 2003 which we classify as bank loans. The weighted-average interest rates on bank loans were 2.35% at September 30, 2004 and 1.63% at September 30, 2003. UGI Utilities' credit agreements have restrictions on such items as total debt, debt service, and payments for investments. They also require consolidated tangible net worth of at least $125,000. At September 30, 2004, UGI Utilities was in compliance with these financial covenants. 4. INCOME TAXES The provisions for income taxes consist of the following: 2004 2003 2002 ------- ------- ------- Current expense: Federal $15,413 $27,027 $13,341 State 6,854 10,416 5,115 ------- ------- ------- Total current expense 22,267 37,443 18,456 Deferred expense 12,271 2,495 11,512 Investment tax credit amortization (398) (398) (398) ------- ------- ------- Total income tax expense $34,140 $39,540 $29,570 ======= ======= ======= A reconciliation from the statutory federal tax rate to our effective tax rate is as follows: 2004 2003 2002 ---- ---- ---- Statutory federal tax rate 35.0% 35.0% 35.0% Difference in tax rate due to: State income taxes, net of federal benefit 5.7 5.6 6.3 Deferred investment tax credit amortization (0.4) (0.4) (0.5) Other, net 0.8 (0.7) (0.7) ---- ---- ---- Effective tax rate 41.1% 39.5% 40.1% ==== ==== ==== Deferred tax liabilities (assets) comprise the following at September 30: F-15 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 2004 2003 -------- -------- Excess book basis over tax basis of property, plant and equipment $130,297 $117,891 Regulatory assets 27,589 25,001 Pension plan asset 10,541 11,019 Other 1,550 2,170 -------- -------- Gross deferred tax liabilities 169,977 156,081 -------- -------- Deferred investment tax credits (3,149) (3,314) Employee-related expenses (6,973) (7,072) Regulatory liabilities (3,967) (7,667) Accumulated other comprehensive loss (1,032) (1,454) Other (3,950) (2,773) -------- -------- Gross deferred tax assets (19,071) (22,280) -------- -------- Net deferred tax liabilities $150,906 $133,801 -------- -------- UGI Utilities had recorded deferred tax liabilities of approximately $39,445 as of September 30, 2004 and $37,029 as of September 30, 2003 pertaining to utility temporary differences, principally a result of accelerated tax depreciation for state income tax purposes, the tax benefits of which previously were or will be flowed through to ratepayers. These deferred tax liabilities have been reduced by deferred tax assets of $3,149 at September 30, 2004 and $3,314 at September 30, 2003, pertaining to utility deferred investment tax credits. UGI Utilities had recorded regulatory income tax assets related to these net deferred taxes of $62,039 at September 30, 2004 and $57,625 as of September 30, 2003. These regulatory income tax assets represent future revenues expected to be recovered through the ratemaking process. We will recognize this regulatory income tax asset in deferred tax expense as the corresponding temporary differences reverse and additional income taxes are incurred. 5. EMPLOYEE RETIREMENT PLANS DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS We sponsor a defined benefit pension plan ("UGI Utilities Pension Plan") for employees of UGI, UGI Utilities, and certain of UGI's other wholly owned subsidiaries. In addition, we provide postretirement health care benefits to certain of our retirees and a limited number of active employees meeting certain age and service requirements, and postretirement life insurance benefits to nearly all domestic active and retired employees. F-16 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following provides a reconciliation of projected benefit obligations, plan assets, and funded status of the plans as of September 30: Pension Other Postretirement Benefits Benefits ------------------- -------------------- 2004 2003 2004 2003 -------- -------- -------- -------- Change in benefit obligations: Benefit obligations - beginning of year $209,459 $190,873 $ 24,567 $ 23,397 Service cost 4,953 4,544 120 117 Interest cost 12,996 12,976 1,514 1,518 Actuarial loss 2,608 10,472 1,208 863 Plan amendments -- -- -- -- Benefits paid (9,530) (9,406) (2,261) (1,328) -------- -------- -------- -------- Benefit obligations - end of year $220,486 $209,459 $ 25,148 $ 24,567 -------- -------- -------- -------- Change in plan assets: Fair value of plan assets - beginning of year $183,840 $166,064 $ 9,000 $ 7,846 Actual return on plan assets 22,045 27,182 826 172 Employer contributions -- -- 2,461 2,310 Benefits paid (9,530) (9,406) (2,115) (1,328) -------- -------- -------- -------- Fair value of plan assets - end of year $196,355 $183,840 $ 10,172 $ 9,000 -------- -------- -------- -------- Funded status of the plans $(24,131) $(25,619) $(14,976) $(15,567) Unrecognized net actuarial loss 47,884 51,205 6,932 6,870 Unrecognized prior service cost 1,651 2,345 -- -- Unrecognized net transition (asset) obligation -- (1,374) 5,690 6,375 -------- -------- -------- -------- Prepaid (accrued) benefit cost - end of year $ 25,404 $ 26,557 $ (2,354) $ (2,322) -------- -------- -------- -------- Assumptions as of September 30: Discount rate 6.1% 6.2% 6.1% 6.2% Expected return on plan assets 9.0% 9.0% 5.8% 6.0% Rate of increase in salary levels 4.0% 4.0% 4.0% 4.0% Net pension expense (income) is determined using assumptions as of the beginning of each fiscal year. Funded status is determined using assumptions as of the end of each fiscal year. The expected rate of return on assets assumption is based on the rates of return for certain asset classes and the allocation of plan assets among those asset classes as well as actual historic long-term rates of return on our plan assets. Included in the end of year pension benefit obligations above are $23,581 at September 30, 2004 and $15,528 at September 30, 2003 relating to employees of UGI and certain of its other subsidiaries. Included in the end of year postretirement obligations above are $735 at September 30, 2004 and $658 at September 30, 2003 relating to employees of UGI and certain of its other subsidiaries. F-17 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Net periodic pension expense (income) and other postretirement benefit costs relating to UGI Utilities employees include the following components: Pension Other Postretirement Benefits Benefits ------------------------------ ------------------------ 2004 2003 2002 2004 2003 2002 -------- -------- -------- ------ ------ ------ Service cost $ 4,318 $ 4,051 $ 3,193 $ 110 $ 109 $ 84 Interest cost 11,642 12,004 11,600 1,487 1,497 1,453 Expected return on assets (15,412) (16,646) (17,778) (459) (414) (366) Amortization of: Transition (asset) obligation (1,233) (1,510) (1,518) 680 680 680 Prior service cost 622 643 646 -- -- -- Actuarial (gain) loss 1,085 216 -- 316 203 20 -------- -------- -------- ------ ------ ------ Net benefit cost (income) 1,022 (1,242) (3,857) 2,134 2,075 1,871 Change in regulatory assets and liabilities -- -- -- 965 1,024 1,228 -------- -------- -------- ------ ------ ------ Net expense (income) $ 1,022 $ (1,242) $ (3,857) $3,099 $3,099 $3,099 ======== ======== ======== ====== ====== ====== UGI Utilities Pension Plan assets are held in trust. Although the UGI Utilities Pension Plan projected benefit obligations exceeded plan assets at September 30, 2004 and 2003, plan assets exceeded accumulated benefit obligations by $9,160 and $7,346, respectively. The Company did not make any contributions in 2004 nor does it believe it will be required to make any contributions to the UGI Utilities Pension Plan during the year ending September 30, 2005. Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary Employees' Beneficiary Association ("VEBA") trust to fund the UGI Utilities' postretirement obligations and to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under SFAS No. 106, "Employers Accounting for Postretirement Benefits Other than Pensions" ("SFAS 106"). The difference between such amounts calculated under SFAS 106 and the amounts included in Utilities' rates is deferred for future recovery from, or refund to, ratepayers. The Company expects to contribute approximately $2,500 to the VEBA during the year ending September 30, 2005. Expected payments for pension benefits and for other postretirement welfare benefits are as follows: Other Pension Postretirement Benefits Benefits -------- -------------- Fiscal 2005 $ 9,881 $ 2,045 Fiscal 2006 9,876 2,121 Fiscal 2007 10,121 2,184 Fiscal 2008 10,276 2,236 Fiscal 2009 10,801 2,270 Fiscal 2010-2014 64,300 10,988 F-18 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) In accordance with our investment strategy to obtain long-term growth, our target allocations are to maintain a mix of 60% equities and the remainder in fixed income funds or cash equivalents. The targets and actual allocations for the UGI Utilities Pension Plan assets and VEBA trust assets at September 30 are as follows: Target Pension Plan VEBA -------------- ------------ ----------- Pension Plan VEBA 2004 2003 2004 2003 ------- ---- ---- ---- ---- ---- Equities 60% 60% 63% 60% 58% 57% Fixed income funds 40% 30% 37% 40% 27% 29% Cash equivalents N/A 10% N/A N/A 15% 14% UGI Common Stock comprised approximately 8% and 7% of pension plan assets at September 30, 2004 and 2003, respectively. The assumed health care cost trend rates are 10.0% for fiscal 2005, decreasing to 5.5% in fiscal 2010. A one percentage point change in the assumed health care cost trend rate would change the 2004 postretirement benefit cost and obligation as follows: 1% 1% Increase Decrease -------- -------- Effect on total service and interest costs $ 93 $ (82) Effect on postretirement benefit obligation 1,468 (1,300) We also sponsor an unfunded and non-qualified supplemental executive retirement income plan. At September 30, 2004 and 2003, the projected benefit obligations of this plan were $1,600 and $3,469, respectively. We recorded expense for this plan of $460 in 2004, $353 in 2003 and $269 in 2002. We also recorded a settlement loss of $1,537 in 2004 associated with this plan. DEFINED CONTRIBUTION PLANS We sponsor a 401(k) savings plan for eligible employees ("Utilities Savings Plan"). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. We may, at our discretion, match a portion of participants' contributions. The cost of benefits under the savings plan totaled $915 in 2004, $968 in 2003 and $932 in 2002. F-19 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 6. INVENTORIES Inventories comprise the following at September 30: 2004 2003 ------- ------- Utility fuel and gases $62,673 $51,505 Appliances for sale 537 548 Materials, supplies and other 1,967 1,964 ------- ------- Total inventories $65,177 $54,017 ======= ======= 7. SERIES PREFERRED STOCK The Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, has 2,000,000 shares authorized for issuance. The holders of shares of Series Preferred Stock have the right to elect a majority of the Board of Directors (without cumulative voting) if dividend payments on any series are in arrears in an amount equal to four quarterly dividends. This election right continues until the arrearage has been cured. We have paid cash dividends at the specified annual rates on all outstanding Series Preferred Stock. At September 30, 2004 and 2003, we had outstanding 200,000 shares of $7.75 Series cumulative preferred stock. On July 27, 2004, UGI Utilities' Board of Directors approved the redemption on October 1, 2004 of all 200,000 shares of the $7.75 Series Preferred Stock at a price of $100 per share together with full cumulative dividends. The redemption on October 1, 2004 of all 200,000 shares of the $7.75 Series Preferred Stock was funded with proceeds from the October 2004 issuance of $20,000 of 6.13% Medium-Term Notes due October 2034. 8. COMMITMENTS AND CONTINGENCIES We lease various buildings and transportation, computer and office equipment and other facilities under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $4,431 in 2004, $4,303 in 2003 and $4,690 in 2002. Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year for the fiscal years ending September 30 are as follows: 2005 - $3,510; 2006 - $3,079; 2007 - $2,633; 2008 - $1,798; 2009 - $922; after 2009 - $2,931. Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation and natural gas storage service which Gas Utility may terminate at various dates through 2016. Gas Utility's costs associated with transportation and storage service agreements are included in its annual PGC filing with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices. F-20 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Electric Utility purchases its capacity requirements and electric energy needs under contracts with various suppliers and on the spot market. Contracts with producers for capacity and energy needs expire at various dates through fiscal 2008. Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2004 are as follows: 2005 - $188,484; 2006 - $100,630; 2007 - $80,680; 2008 - $60,552; 2009 - - $51,650; after 2009 - $116,288. 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 Gas Utility and Electric Utility. UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating three claims against it relating to out-of-state sites. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly owned or 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. In April 2003, Citizens Communications Company ("Citizens") served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in 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 MGP from 1901 to 1928. The City believes that it could cost as much as $50,000 to clean up the river. UGI Utilities believes that it has good defenses to the claim and is defending the suit. F-21 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) By letter dated July 29, 2003, Atlanta Gas Light Company ("AGL") served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8,000 incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. UGI Utilities believes that it has good defenses to the claim and is defending the suit. AGL previously informed UGI Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL has recently informed UGI Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55,000. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site. 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. ConEd believes that the cost of remediation for all of the sites could exceed $70,000. By orders issued in November 2003 and March 2004, the court granted UGI Utilities' motion for summary judgment and dismissed ConEd's complaint. ConEd has appealed. By letter dated June 24, 2004, KeySpan Energy ("KeySpan") informed UGI Utilities that KeySpan has spent $2,300 and expects to spend another $11,000 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities' alleged direct ownership and operation of the plant from 1885 to 1902. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim. By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together, the "Northeast Companies"), demanded 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. According to the letter, investigation and remedial costs at the sites to date total approximately $10,000 and complete remediation costs for all sites could total $182,000. The Northeast Companies seek an unspecified fair and equitable allocation of these costs to UGI Utilities. UGI Utilities is in the process of reviewing the information provided by Northeast Companies and is investigating this claim. In addition to these environmental matters, there are other pending claims and legal actions arising in the normal course of our businesses. We cannot predict with certainty the final results of F-22 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) environmental and other matters. However, it is reasonably possible that some of them could be resolved unfavorably to us. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. 9. FINANCIAL INSTRUMENTS In accordance with its commodity hedging policy, the Company may enter into (1) natural gas call option contracts to reduce volatility in the cost of gas it purchases for its firm- residential, commercial and industrial ("retail core-market") customers and (2) electric swap agreements in order to reduce the volatility in the cost of anticipated electricity requirements. We designate these contracts as cash flow or fair value hedges under SFAS 133. Because the cost of the natural gas call option contracts and any associated gains will be included in our PGC recovery mechanism, as these contracts are recorded at fair value in accordance with SFAS 133, any gains are deferred for future recovery from or refund to Gas Utility's ratepayers in deferred fuel costs. We are a party to a number of contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts are not subject to the accounting requirements of SFAS 133, as amended, because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business or the value of the contract is directly associated with the price or value of a service. We enter into IRPAs in order to manage interest rate risk associated with planned issuances of fixed-rate long-term debt. We designate these IRPAs as cash flow hedges. Gains or losses on IRPAs are included in other comprehensive income and are reclassified to interest expense as the interest on the associated debt affects earnings. During 2004, 2003 and 2002, there were no gains or losses recognized in earnings as a result of hedge ineffectiveness or from excluding a portion of a derivative instrument's gain or loss from the assessment of hedge effectiveness, and there were no gains or losses recognized in earnings as a result of a hedged firm commitment no longer qualifying as a fair value hedge. At September 30, 2004, our unsettled derivative contracts included in accumulated other comprehensive loss included an electric price swap agreement and two IRPAs. Gains and losses included in accumulated other comprehensive loss at September 30, 2004 relating to cash flow hedges will be reclassified into (1) interest expense when interest on anticipated issuances of fixed-rate long-term debt is reflected in net income and (2) cost of sales when the forecasted purchase of electricity subject to the hedge impact net income. Included in accumulated other comprehensive loss at September 30, 2004 are net after-tax losses of approximately $2,599 associated with settled IRPAs and two unsettled IRPAs associated with forecasted issuances of long-term debt anticipated to occur during the next two years. The F-23 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) amount of net loss on IRPAs expected to be reclassified into net income during the next twelve months is not material. Also included in accumulated other comprehensive loss at September 30, 2004 is an after-tax gain of $1,143 associated with our electric price swap agreement for purchases of electricity anticipated to occur during fiscal 2007. The actual amount of gains or losses on unsettled derivative instruments that ultimately is reclassified into net income will depend upon the value of such derivative contracts when settled. The fair value of derivative instruments is included in prepaid expenses and other current assets, other assets, other current liabilities and other noncurrent liabilities in the Consolidated Balance Sheets. The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivatives and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amounts and estimated fair values of our remaining financial instruments (including unsettled derivative instruments) at September 30 are: Carrying Estimated Amount Fair Value -------- ---------- 2004: Electric swap agreement $ 1,954 $ 1,954 Interest rate protection agreements (993) (993) Long-tem debt 217,151 231,000 Preferred shares subject to mandatory redemption (a) 20,000 20,000 2003: Interest rate protection agreement $ 1,953 $ 1,953 Long-tem debt 217,271 233,000 Preferred shares subject to mandatory redemption (a) 20,000 20,900 (a) On October 1, 2004, we redeemed all preferred shares subject to mandatory redemption. We estimate the fair value of long-term debt by using current market prices and by discounting future cash flows using rates available for similar type debt. We estimated the fair value of our Preferred shares subject to mandatory redemption based on the fair value of redeemable preferred stock with similar credit ratings and redemption features. We have financial instruments such as trade accounts receivable which could expose us to concentrations of credit risk. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different markets. At September 30, 2004 and 2003, we had no significant concentrations of credit risk. F-24 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 10. SEGMENT INFORMATION We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Operations. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern and southeastern Pennsylvania. Electric Operations derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The accounting policies of our reportable segments are the same as those described in Note 1. We evaluate the performance of our Gas Utility and Electric Operations segments principally based upon their income before income taxes. No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments' revenues are derived from sources within the United States, and all of our reportable segments' long-lived assets are located in the United States. F-25 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Financial information by business segment follows: Gas Electric Total Utility Operations -------- -------- ---------- 2004 Revenues $650,088 $560,400 $ 89,688 Cost of sales 412,240 368,906 43,334 Depreciation and amortization 22,520 19,516 3,004 Operating income 101,029 80,097 20,932 Interest expense 17,931 15,944 1,987 Income before income taxes 83,098 64,153 18,945 Total assets 855,778 765,954 89,824 Capital expenditures 40,737 35,470 5,267 2003 Revenues $636,758 $539,862 $ 96,896 Cost of sales 392,901 342,987 49,914 Depreciation and amortization 21,240 18,147 3,093 Operating income 117,868 96,086 21,782 Interest expense 17,656 15,409 2,247 Income before income taxes 100,212 80,677 19,535 Total assets 809,048 725,085 83,963 Capital expenditures 41,297 37,204 4,093 2002 Revenues $490,552 $404,519 $ 86,033 Cost of sales 290,282 241,669 48,613 Depreciation and amortization 22,172 18,983 3,189 Operating income 90,317 77,148 13,169 Interest expense 16,652 14,224 2,428 Income before income taxes 73,665 62,924 10,741 Total assets 798,123 689,080 109,043 Capital expenditures 35,884 31,034 4,850 F-26 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 11. OTHER INCOME, NET Other income, net, comprises the following: 2004 2003 2002 ------ ------ ------- Non-tariff service income $2,048 $5,693 $ 5,701 Pension income -- 1,242 3,858 Interest income 183 128 1,110 Other, net 438 1,682 1,054 ------ ------ ------- $2,669 $8,745 $11,723 ====== ====== ======= 12. RELATED PARTY TRANSACTIONS UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct and for an allocated share of indirect corporate expenses incurred or paid on behalf of UGI Utilities. These billed expenses are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI's subsidiaries, largely payroll related services. Amounts billed to these entities by UGI Utilities is not material. Gas Utility enters into wholesale natural gas transactions with UGI Energy Services, Inc. ("Energy Services"), a wholly owned second-tier subsidiary of UGI, for winter peaking service and, from time to time, purchases of natural gas or pipeline capacity. During 2004, 2003 and 2002, the aggregate amount of these transactions totaled $6,257, $4,709 and $2,614, respectively. In addition, from time to time, the Company sells natural gas or pipeline capacity to Energy Services. During 2004, 2003 and 2002, revenues associated with these sales to Energy Services totaled $1,698, $4,234 and $17,379, respectively. These transactions did not have a material effect on the Company's net income during 2004, 2003 and 2002. 13. QUARTERLY DATA (UNAUDITED) The following quarterly information includes all adjustments (consisting only of normal recurring adjustments), which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of UGI Utilities' businesses. December 31, March 31, June 30, September 30, ------------------- ------------------- ------------------- ----------------- 2003 2002 2004 2003 2004 2003 2004 2003 -------- -------- -------- -------- -------- -------- ------- ------- Revenues $170,684 $168,351 $268,217 $269,296 $118,717 $121,546 $92,470 $77,565 Operating income 33,950 38,830 53,277 63,449 12,282 10,005 1,520 5,584 Net income (loss) 17,508 20,714 29,149 35,399 4,495 3,640 (2,194) 919 F-27 UGI UTILITIES, INC. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Thousands of dollars) Balance at Charged to Balance at beginning costs and end of of year expenses Other year ------------- ------------- ------------ ------------- YEAR ENDED SEPTEMBER 30, 2004 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 3,275 $ 6,971 $ (6,872) (1) $ 3,374 ============= ============= Other reserves (3) $ 3,616 $ 3,552 $ (1,314) (2) $ 5,854 ============= ============= YEAR ENDED SEPTEMBER 30, 2003 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 1,972 $ 7,778 $ (6,475) (1) $ 3,275 ============= ============= Other reserves (3) $ 3,363 $ 3,164 $ (3,294) (2) $ 3,616 ============= ============= 383 (4) YEAR ENDED SEPTEMBER 30, 2002 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 3,151 $ 5,270 $ (6,449) (1) $ 1,972 ============= ============= Other reserves (3) $ 3,467 $ 748 $ (2,352) (2) $ 3,363 ============= ============= 1,500 (4) (1) Uncollectible accounts written off, net of recoveries. (2) Payments, net (3) Includes reserves for self-insured property and casualty liability, insured property and casualty liability, environmental, litigation and other. (4) Other adjustments S-1 EXHIBIT INDEX EXHIBIT NO. DESCRIPTION - ----------- ----------- 10.26 Amendment No. 1 dated November 1, 2004, to the Service Agreement (Rate FSS) dated as of November 1, 1989 between 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) 10.30 Amendment No. 1 dated November 1, 2004, to the No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission 10.32 Gas Service Delivery and Supply Agreement between Utilities and UGI Energy Services, Inc. dated August 26, 2004 10.33 Amendment No. 1 dated November 1, 2004, to the Firm Transportation Service Agreement (Rate Schedule FT-1) between Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission 10.34 Firm Transportation Service Agreement (Rate Schedule FTS) between Utilities and Columbia Gas Transmission dated November 1, 2004 12.1 Computation of Ratio of Earnings to Fixed Charges 12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends 23 Consent of PricewaterhouseCoopers LLP 31.1 Certification by the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act 31.2 Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act *32 Certification by Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act * The Exhibit attached to this Form 10-K shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to liability under that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as expressly set forth by specific reference in such filing.