-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, SNp0gLPSx0Z8DilXWkHhq8HmqTkeDnwEK5rMr3igqn4RFXYibFie3RYk3H10zO2w kbT38IMYQAE+awbUVHpUhQ== 0000893220-02-001515.txt : 20021223 0000893220-02-001515.hdr.sgml : 20021223 20021223171533 ACCESSION NUMBER: 0000893220-02-001515 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 20020930 FILED AS OF DATE: 20021223 FILER: COMPANY DATA: COMPANY CONFORMED NAME: UGI UTILITIES INC CENTRAL INDEX KEY: 0000100548 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 231174060 STATE OF INCORPORATION: PA FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-01398 FILM NUMBER: 02867570 BUSINESS ADDRESS: STREET 1: 100 KACHEL BOULEVARD SUITE 400 STREET 2: GREEN HILLS CORPORATE CENTER CITY: VALLEY FORGE STATE: PA ZIP: 19607 BUSINESS PHONE: 6107963400 MAIL ADDRESS: STREET 1: P O BOX 858 CITY: VALLEY FORGE STATE: PA ZIP: 19482 FORMER COMPANY: FORMER CONFORMED NAME: CONSUMERS GAS CO DATE OF NAME CHANGE: 19660830 FORMER COMPANY: FORMER CONFORMED NAME: UNITED GAS IMPROVEMENT CO DATE OF NAME CHANGE: 19680911 FORMER COMPANY: FORMER CONFORMED NAME: UGI CORP DATE OF NAME CHANGE: 19920429 10-K 1 w66595e10vk.txt FORM 10-K FOR FISCAL YEAR ENDED SEPTEMBER 30, 2002 ================================================================================ 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, 2002 Commission file number 1-1398 UGI UTILITIES, INC. (Exact name of registrant as specified in its charter) Pennsylvania (State or other jurisdiction of 23-1174060 incorporation or organization) (I.R.S. Employer Identification No.) 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 29, 2002, 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 | | ================================================================================ TABLE OF CONTENTS
Page ---- PART I: BUSINESS 1 Items 1 And 2. Business and Properties................................................. 1 General............................................................... 1 Gas Utility Operations................................................ 1 Item 3. Legal Proceedings....................................................... 9 Item 4. Submission of Matters to a Vote of Security Holders..................... 11 PART II: SECURITIES AND FINANCIAL INFORMATION 12 Item 5. Market for Registrant's Common Equity and Related Stockholder Matters... 12 Item 6. Selected Financial Data................................................. 13 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................... 14 Item 7a. Quantitative and Qualitative Disclosures About Market Risk.............. 25 Item 8. Financial Statements and Supplementary Data............................. 25 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................................... 25 PART III: UGI UTILITIES MANAGEMENT AND SECURITY HOLDERS 26 Item 10. Directors and Executive Officers of the Registrant...................... 26 Item 11. Executive Compensation.................................................. 31 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters............................................. 38
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Page ---- Item 13. Certain Relationships and Related Transactions.......................... 40 Item 14. Controls and Procedures................................................. 40 PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS 41 Item 15. Exhibits, Financial Statement Schedule, and Reports on Form 8-K......... 41 Signatures............................................................ 47 Certifications........................................................ 50 Index to Financial Statements and Financial Statement Schedule........ F-2
(ii) PART I: BUSINESS 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 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"). 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. We are a wholly owned subsidiary of UGI Corporation ("UGI"). Utilities was incorporated in Pennsylvania in 1925 as the successor to a business founded in 1882. 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, UGI Utilities, Inc. and its consolidated subsidiaries. GAS UTILITY OPERATIONS NATURAL GAS CHOICE AND COMPETITION ACT On June 22, 1999, Pennsylvania's Natural Gas Choice and Competition Act ("Gas Competition Act") was signed into law. The purpose of the Gas Competition Act was to provide all natural gas consumers in Pennsylvania with the ability to purchase their gas supplies from the supplier of their choice. Under the Gas Competition Act, local distribution companies ("LDCs") like Gas Utility may continue to sell gas to customers, and such sales of gas, as well as distribution services provided by LDCs, continue to be subject to price regulation by the PUC. Generally, Pennsylvania LDCs will serve as the supplier of last resort for all residential and small commercial and industrial customers unless the PUC approves another supplier of last resort. The Gas Competition Act requires energy marketers seeking to serve customers of LDCs to accept assignment of a portion of the LDC's interstate pipeline capacity and storage contracts at contract rates, thus avoiding the creation of stranded costs. On October 1, 1999, Gas Utility filed its restructuring plan with the PUC pursuant to the Gas Competition Act. On June 29, 2000, the PUC entered its order ("Gas Restructuring Order") approving Gas Utility's restructuring plan substantially as filed. Gas Utility designed its restructuring plan to ensure reliability of gas supply deliveries to Gas Utility on behalf of -1- residential and small commercial and industrial customers. In addition, the plan changed Gas Utility's base rates for firm customers. It also changed the calculation of purchased gas cost rates. See "Utility Regulation and Rates." Since October 1, 2000, all of Gas Utility's customers have had the option to purchase their gas supplies from an alternative gas supplier. Large commercial and industrial customers of Gas Utility have been able to purchase their gas from other suppliers since 1982. During fiscal year 2002, two third-party suppliers qualified to serve residential or small commercial and industrial customers in Gas Utility's service territory. Together, they are serving approximately 2,400 customers. Management believes none of the Gas Competition Act, the Gas Restructuring Order, or commodity sales to core-market customers by third party suppliers will have a material adverse impact on the Company's financial condition or results of operations. SERVICE AREA; REVENUE ANALYSIS Gas Utility distributes natural gas to approximately 286,000 customers in portions of 14 eastern and southeastern Pennsylvania counties through its distribution system of approximately 4,700 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 2002 fiscal year was approximately 70.5 billion cubic feet ("bcf"). System sales of gas accounted for approximately 41% of system throughput, while gas transported for residential, commercial and industrial customers (who bought their gas from others) accounted for approximately 59% of system throughput. Based on industry data for 2000, residential customers account for approximately 31% of total system throughput by LDCs in the United States. By contrast, for the 2002 fiscal year, Gas Utility's residential customers represented 24% 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, Utilities 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 2002, Gas Utility purchased approximately 28 bcf of natural gas for sale to customers. Approximately 90% of the volumes purchased were supplied under -2- agreements with six major suppliers. The remaining 10% of gas purchased was supplied by over 30 producers and marketers. Gas supply contracts are generally no longer than one year. In fiscal year 2002, as a result of changing market conditions following the bankruptcy of Enron Corp., a number of suppliers that Utilities formerly did business with exited the wholesale trading market. This development did not significantly impact Utilities' ability to secure gas supplies. SEASONAL VARIATION Because many of its customers use gas for heating purposes, Gas Utility's sales are seasonal. Approximately 57% of fiscal year 2002 throughput and approximately 68% of earnings before interest expense, income taxes, depreciation and amortization 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 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, Gas Utility is the only regulated gas distribution utility having the right, granted by the PUC or by law, to provide gas distribution services. Under the Gas Competition Act, retail customers may purchase their natural gas from a supplier other than Gas Utility. Commercial and industrial customers in Gas Utility's service territory have been able to do this since 1982. As of October 2002, two marketers have qualified to serve residential and small commercial and industrial customers. Together they serve approximately 2,400 customers. Gas Utility provides transportation services for residential and small commercial and industrial customers who purchase natural gas from others. Many 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. Gas Utility's 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. See "Utility Regulation and Rates - Gas Utility Rates." Commercial and industrial customers representing 17% of total system throughput have locations which afford them the option, although none has 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 Utilities' ten largest customers in terms of annual volume. All of these customers have contracts with Utilities, eight of which extend into -3- fiscal year 2004. 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 2003. 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 Utilities' larger customers. During fiscal year 2002, 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 9,200 residential heating customers during fiscal year 2002, which represented a record annual increase. Of those new customers, new home construction accounted for over 7,100 heating customers. Customers converting from other energy sources, primarily oil and electric, 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 over 1,100. Utilities 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. Gas Utility's objective in negotiations with interstate pipeline and natural gas suppliers, and in litigation before regulatory agencies, is to assure availability of supply, transportation and storage alternatives to serve market requirements at the lowest cost possible, taking into account the need for security of supply. Consistent with that objective, Gas Utility negotiates the terms of firm transportation capacity on all pipelines serving Gas Utility, 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. -4- ELECTRIC OPERATIONS ELECTRICITY GENERATION CUSTOMER CHOICE AND COMPETITION ACT On January 1, 1997, Pennsylvania's Electricity Generation Customer Choice and Competition Act ("ECC Act") became effective. The ECC Act permits all Pennsylvania retail electric customers to choose their electric generation supplier. Pursuant to the Act, all electric utilities were required to file restructuring plans with the PUC which, among other things, included unbundled prices for electric generation, transmission and distribution and a competitive transition charge (CTC) for the recovery of "stranded costs" which would be paid by all customers receiving distribution service. Stranded costs generally are electric generation-related costs that traditionally would be recoverable in a regulated environment but may not be recoverable in a competitive electric generation market. Under the ECC Act, Electric Utility generally may not increase prices for electric generation as long as stranded costs are being recovered through the CTC. In accordance with the restructuring proceedings discussed below, Utilities collected a CTC from commercial and industrial customers until September 2002 and expects to collect from all other distribution customers until May 2003. Under the ECC Act, Electric Utility is obligated to provide energy at the capped rates to customers who do not choose alternate suppliers. Electric Utility will continue to be the only regulated electric utility having the right, granted by the PUC or by law, to distribute electric energy in its service territory. On June 19, 1998, the PUC entered its Opinion and Order (the "Restructuring Order") in Electric Utility's restructuring proceeding under the ECC Act. The Electric Restructuring Order authorized Electric Utility to recover from its customers approximately $32.5 million in stranded costs (on a full revenue requirements basis, which includes all income and gross receipts taxes) over a four-year period which commenced January 1, 1999 through a CTC, together with carrying charges on unrecovered balances of 7.94%. The PUC approved a settlement establishing rules for Electric Utility Provider of Last Resort ("POLR") service on March 28, 2002, and a separate settlement that modified these rules on June 13, 2002 (collectively, the "POLR Settlement") under which Electric Utility terminated stranded cost recovery through its CTC from commercial and industrial ("C&I") customers on July 31, 2002, and from residential customers on October 31, 2002, and is no longer subject to the statutory rate caps as of August 1, 2002 for C&I customers and as of November 1, 2002 for residential customers. Charges for generation service will (1) initially be set at a level equal to the rates paid by Electric Utility customers for POLR service under the statutory rate caps; (2) may be raised at certain designated times up to certain specified caps through December 2004; and (3) may be set at market rates thereafter. Electric Utility may also offer multiple year POLR contracts to its customers. The POLR Settlement provides 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. C&I customers who return to POLR service at a time other than during the annual shopping period must remain on POLR service until the next -5- open shopping period, and may, in certain circumstances, be subject to generation rate surcharges. SERVICE AREA; SALES ANALYSIS Electric Utility supplies electric service to approximately 61,500 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 2002, about 52% of sales volume came from residential customers, 36% from commercial customers and 12% from industrial customers. Electricity transported for customers who purchased their power from others pursuant to the ECC Act represented approximately 1% of fiscal year 2002 sales volume. SOURCES OF SUPPLY Effective October 1, 1999, Utilities transferred its electric generation assets to its non-utility subsidiary, UGI Development Company ("UGID"). These generation assets consisted principally of Utilities' Hunlock generating station ("Hunlock Station"), located near Kingston, Pennsylvania and its 1.11% interest in the Conemaugh generating station ("Conemaugh Station"), located near Johnstown, Pennsylvania. Effective December 8, 2000, UGID entered into a partnership ("Energy Ventures") with a subsidiary of Allegheny Energy, Inc. for the purpose of owning and operating electric generation facilities. UGID contributed Hunlock Station, coal inventory and $6 million to the partnership and Allegheny contributed a 44 megawatt gas combustion electric generator. UGID has the right to purchase half the output of Energy Ventures' generation at cost. During fiscal year 2002, Electric Utility purchased approximately 28% of its energy requirements from UGID. Effective October 1, 2002, Electric Utility has generation supply contracts in place for substantially all of its expected on-peak energy requirements through fiscal year 2004. UGID plans to market the electric generation it controls to third parties. Electric Utility distributes both electricity that it purchases from others (including UGID) and electricity that customers purchase from other suppliers. At September 30, 2002, 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. ENVIRONMENTAL FACTORS Energy Ventures' operation of Hunlock Station complies with the air quality standards of the Pennsylvania Department of Environmental Resources ("DER") with respect to stack emissions. Under the Federal Water Pollution Control Act, UGID has a permit from the DER to discharge water from Hunlock Station into the North Branch of the Susquehanna River. The Federal Clean Air Act Amendments of 1990 (the "Clean Air Act Amendments") impose emissions limitations for certain compounds, including sulfur dioxide and nitrous oxides. Both -6- the Conemaugh Station and the Hunlock Station are in material compliance with these emission standards. SEASONALITY Sales and distribution of electricity for residential heating purposes accounted for approximately 19% of the total sales of Electric Utility during fiscal year 2002. Electricity competes with natural gas, oil, propane and other heating fuels in this use. Approximately 51% of volume occurred during the six coldest months of fiscal year 2002 (November through April), demonstrating modest seasonality favoring winter due to the use of electricity for residential heating purposes. UTILITY REGULATION AND RATES PENNSYLVANIA PUBLIC UTILITY COMMISSION JURISDICTION Utilities' gas and electric utility operations, which exclude electric generation, 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. As noted earlier, effective October 1, 1999, Utilities contributed its electric generation assets to UGID. UGID has FERC authority to sell power at market-based rates. Generally, UGID is not subject to regulation by the PUC. 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 the 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 The Gas Restructuring Order included an increase in firm, core-market base rates, effective October 1, 2000. The increase, calculated in accordance with the Gas Competition Act, was designed to generate approximately $16.7 million in additional annual revenues. The Order also provided that Gas Utility reduce its purchased gas cost rates by an annualized amount of $16.7 million for the first 14 months following the base rate increase. Effective December 1, 2001, Gas Utility was required to reduce its purchased gas cost rates to core market customers by an amount equal to the margin it receives from customers -7- served under interruptible rates to the extent they use capacity contracted for by Gas Utility for 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 the market prices of alternative fuel than in the past. BASE RATES As stated above, Gas Utility's current base rates went into effect October 1, 2000 pursuant to The Gas Restructuring Order. See Note 4 to the Company's Consolidated Financial Statements. PURCHASED GAS COST RATES Gas Utility's gas service tariff contains Purchased Gas Cost ("PGC") rates which provide for annual increases or decreases in the rate per thousand cubic feet ("mcf") which Gas Utility charges for natural gas sold by it, to reflect Utilities' projected cost of purchased gas. PGC rates may also be adjusted quarterly, or monthly, to reflect purchased gas costs. 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. Utilities has two PGC rates. PGC (1) is applicable to small, firm, core-market customers consisting of the residential and small commercial and industrial classes; PGC (2) is applicable to firm, contractual, high-load factor customers served on three separate rates. In addition, residential customers maintaining a high load factor may qualify for the PGC (2) rate. As described above, the Gas Restructuring Order provided for ongoing adjustments to Gas Utilities' PGC rates, commencing December 1, 2001, to reflect margins, if any, from interruptible rate customers who do not obtain their own pipeline capacity. ELECTRIC UTILITY RATES Electric Utility's rates for electric generation are frozen through approximately July 2003 for commercial and industrial customers and approximately May 2004 for residential customers. After these dates and through December 2004, Electric Utility can increase generation rates by up to 5% of the total rate for distribution, transmission and generation. See "Electricity Generation Customer Choice and Competition Act." The ECC Act obligates Electric Utility to act as "provider of last resort" to customers who do not choose alternate generation suppliers. 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 effect of increases in most of the Pennsylvania taxes to which it is subject. -8- 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, like UGID, 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." The electric generation activities of Utilities are also subject to the Clean Air Act Amendments, the Federal Water Pollution Control Act and comparable state statutes and regulations. See "UTILITY OPERATIONS - Electric Operations - Environmental Factors." EMPLOYEES At September 30, 2002, Utilities and its subsidiaries had approximately 1,100 employees. BUSINESS SEGMENT INFORMATION The table stating the amounts of revenues, operating income (loss) and identifiable assets attributable to Utilities' operating segments for the 2002, 2001 and 2000 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, any of its subsidiaries or any of their properties, and no such proceedings are known to be contemplated by governmental authorities. -9- ENVIRONMENTAL MATTERS - MANUFACTURED GAS PLANTS In 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 business of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by 1953, UGI Utilities had 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 UGI Utilities 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 (1) MGPs were formerly operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or private parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating two claims against it relating to out-of-state sites. Fishbein Family Partnership v. PPG Industries, Inc., et al. In July 1993, Public Service Electric and Gas Company ("PSE&G") joined Utilities as a third-party defendant in a civil action in the United States District Court for the District of New Jersey, seeking damages as a result of contamination relating to the former manufactured gas plant operations at Halladay Street in Jersey City, New Jersey. The case principally involved claims by the Fishbein Family Partnership against PPG Industries, Inc. for damages associated with chemical contamination unrelated to gas plant operations. In November 2001, the parties agreed voluntarily to dismiss all claims by and against PSE&G without prejudice. All claims against Utilities have been dismissed, although they could be re-instituted in the future. Consolidated Edison Company of New York v. UGI Utilities, Inc. On September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed suit against UGI Utilities, Inc. 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 manufactured gas plant sites in eleven communities in Westchester County, New York. The complaint alleges that Utilities "owned and operated" the plants 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 has stated that the cost of remediation at two of the sites, Tarrytown and White Plains, could exceed $20 million and $10 million respectively. ConEd has not provided specific estimates of costs at the remainder of the sites and Utilities has no other information on which to base estimates. Utilities continues to investigate its involvement at these sites and is defending the claim. -10- EnergyNorth Natural Gas, Inc. v. UGI Utilities, Inc. By letter dated October 26, 2000, EnergyNorth Natural Gas, Inc. ("EnergyNorth") notified Utilities that it has filed suit in the United States District Court for the District of New Hampshire, seeking contribution from Utilities for response and remediation costs associated with contamination on the site of a former manufactured gas plant allegedly operated by former subsidiaries of Utilities. EnergyNorth has not stated the amount of the costs and has provided no information on which Utilities could make an estimate. Utilities is actively defending the suit. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that the subsidiary's separate corporate form should be disregarded. RELATED MATTER UGI Utilities, Inc. v. Insurance Co. of North America, et. al. On February 11, 1999, UGI Utilities, Inc. filed suit in the Court of Common Pleas of Montgomery County, Pennsylvania against more than fifty insurance companies, including Associated Electric and Gas Insurance Services, Ltd. (AEGIS). The complaint alleges that the defendants breached contracts of insurance by failing to indemnify Utilities for certain environmental costs. To date, Utilities has recovered a significant portion of its claims through settlements with most of the defendants, including AEGIS. The court has not yet set a date for trial of the claims against the remaining defendants. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of security holders during the last fiscal quarter of fiscal year 2002. -11- PART II: SECURITIES AND FINANCIAL INFORMATION ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 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 $37.9 million in fiscal year 2002, $35.3 million in fiscal year 2001 and $44.0 million in fiscal year 2000. -12- ITEM 6. SELECTED FINANCIAL DATA (a)
Year Ended September 30, ------------------------------------------------------------------------ 2002 2001 2000 1999 1998 --------- --------- --------- --------- --------- (Thousands of dollars) FOR THE PERIOD: INCOME STATEMENT DATA: Revenues $ 490,552 $ 584,762 $ 436,942 $ 420,647 $ 422,283 ========= ========= ========= ========= ========= Net income $ 44,095 $ 48,137 $ 50,476 $ 38,868 $ 35,551 Dividends on preferred stock 1,550 1,550 1,550 1,550 2,160 --------- --------- --------- --------- --------- Net income after dividends on preferred stock $ 42,545 $ 46,587 $ 48,926 $ 37,318 $ 33,391 ========= ========= ========= ========= ========= AT PERIOD END: BALANCE SHEET DATA: Total assets $ 798,123 $ 784,409 $ 751,137 $ 717,169 $ 690,317 ========= ========= ========= ========= ========= Capitalization: Debt: Bank loans $ 37,200 $ 57,800 $ 100,400 $ 87,400 $ 68,400 Long-term debt including current maturities 248,369 208,477 172,924 180,047 187,170 --------- --------- --------- --------- --------- Total debt 285,569 266,277 273,324 267,447 255,570 Preferred stock subject to mandatory redemption 20,000 20,000 20,000 20,000 20,000 Common equity 237,854 235,757 224,473 219,560 211,242 --------- --------- --------- --------- --------- Total capitalization $ 543,423 $ 522,034 $ 517,797 $ 507,007 $ 486,812 ========= ========= ========= ========= ========= RATIO OF CAPITALIZATION: Total debt 52.6% 51.0% 52.8% 52.8% 52.5% UGI Utilities preferred stock 3.7% 3.8% 3.9% 3.9% 4.1% Common equity 43.7% 45.2% 43.3% 43.3% 43.4% --------- --------- --------- --------- --------- 100.0% 100.0% 100.0% 100.0% 100.0% ========= ========= ========= ========= =========
(a) Arthur Andersen LLP audited our consolidated financial statements for 2001, 2000, 1999 and 1998. See Item 15 - Notice Regarding Arthur Andersen LLP. -13- ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS In the following Management's Discussion and Analysis ("MD&A") of Financial Condition and Results of Operations, Electric Utility and UGID's electric generation business 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 2002 COMPARED WITH FISCAL 2001
Increase Year Ended September 30, 2002 2001 (Decrease) - ------------------------ ---- ---- ---------- (Millions of dollars) GAS UTILITY: Revenues $404.5 $ 500.8 $ (96.3) (19.2)% Total margin (a) $162.9 $ 177.9 $ (15.0) (8.4)% Operating income $ 77.1 $ 87.8 $ (10.7) (12.2)% System throughput - bcf 70.5 77.3 (6.8) (8.8)% Degree days - % colder (warmer) than normal (17.4)% 2.0% -- -- ELECTRIC OPERATIONS: Revenues $ 86.0 $ 83.9 $ 2.1 2.5% Total margin (a) $ 32.8 $ 28.6 $ 4.2 14.7% Operating income $ 13.2 $ 10.7 $ 2.5 23.4% Distribution sales - gwh 933.6 945.5 (11.9) (1.3)%
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. For financial statement purposes, 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 during Fiscal 2002 based upon heating degree days was 17.4% warmer than normal compared to weather that was 2.0% colder than normal in Fiscal 2001. As a result of the significantly warmer weather and the effects of a weak economy on commercial and industrial natural gas usage, distribution system throughput declined 8.8%. The $96.3 million decrease in Fiscal 2002 Gas Utility revenues reflects the impact of lower PGC rates, resulting from the pass through of lower natural gas costs to firm- residential, commercial and industrial (collectively, "core-market") customers, and the lower distribution system throughput. Gas Utility cost of gas was $241.7 million in Fiscal 2002 compared to $322.9 -14- million in Fiscal 2001 reflecting lower natural gas costs and the decline in core-market throughput in Fiscal 2002. The decline in Gas Utility margin principally reflects a $6.0 million decline in core-market margin due to the lower sales; a $6.6 million decline in interruptible margin due principally to the flowback of certain interruptible customer margin to core-market customers beginning December 1, 2001 pursuant to the Gas Restructuring Order; and lower firm delivery service total margin due to lower sales. Interruptible customers are those who have the ability to switch to alternate fuels. Gas Utility operating income declined $10.7 million in Fiscal 2002 reflecting the previously mentioned decline in total margin and a decrease in pension income partially offset by lower operating expenses. Operating expenses declined $4.1 million primarily as a result of lower charges for uncollectible accounts and lower distribution system expenses. Depreciation expense declined $1.2 million due to a change effective April 1, 2002 in the estimated useful lives of Gas Utility's natural gas distribution assets resulting from an asset life study required by the PUC. ELECTRIC OPERATIONS. The decline in kilowatt-hour sales in Fiscal 2002 reflects the effects on heating-related sales of significantly warmer winter weather partially offset by the effects on air conditioning sales of warmer summer weather. Notwithstanding the decrease in total kilowatt-hour sales, revenues increased $2.1 million principally due to an increase in state tax surcharge revenue and greater third-party sales of electricity produced by our Pennsylvania-based electric generation facilities. Electric Operations cost of sales was $48.6 million in Fiscal 2002 compared to $51.9 million in Fiscal 2001 principally reflecting the impact of the lower sales and lower purchased power unit costs partially offset by the full-period increase to cost of sales resulting from the transfer of our Hunlock Creek electricity generation assets to Hunlock Creek Energy Ventures ("Energy Ventures") in December 2000. Energy Ventures is an electricity generation joint-venture with a subsidiary of Allegheny Energy, Inc. Subsequent to the formation of Energy Ventures, our electric generating business purchases its share of the power produced by Energy Ventures rather than producing this electricity itself. As a result, the cost of this power is reflected in cost of sales whereas prior to the formation of Energy Ventures such costs were reflected as operating and administrative expenses. Electric Operations total margin increased $4.2 million in Fiscal 2002 as a result of lower purchased power unit costs partially offset by the weather-driven decline in sales. Operating income increased $2.5 million reflecting the greater total margin and lower operating costs subsequent to the formation of Energy Ventures partially offset by a decline in other income. INTEREST EXPENSE. The lower interest expense in Fiscal 2002 resulted primarily from lower levels of long-term debt and lower bank loans outstanding. -15- FISCAL 2001 COMPARED WITH FISCAL 2000
Increase Year Ended September 30, 2001 2000 (Decrease) - ------------------------ ---- ---- ---------- (Millions of dollars) GAS UTILITY: Revenues $ 500.8 $ 359.0 $ 141.8 39.5 % Total margin $ 177.9 $ 170.8 $ 7.1 4.2 % Operating income $ 87.8 $ 86.2 $ 1.6 1.9 % System throughput - bcf 77.3 79.7 (2.4) (3.0)% Degree days - % colder (warmer) than normal 2.0% (9.9)% -- -- ELECTRIC OPERATIONS: Revenues $ 83.9 $ 77.9 $ 6.0 7.7 % Total margin $ 28.6 $ 40.8 $ (12.2) (29.9)% Operating income $ 10.7 $ 15.1 $ (4.4) (29.1)% Distribution sales - gwh 945.5 907.2 38.3 4.2 %
GAS UTILITY. Although temperatures based upon heating degree days were colder in Fiscal 2001, total system throughput declined 3.0% as the impact of the colder weather was more than offset by lower interruptible and firm delivery service volumes, the impact of price-induced customer conservation, and the effects of a slowing economy. Natural gas prices were significantly higher in Fiscal 2001 than in the prior year. The higher prices resulted in fuel switching by many of our interruptible customers, who have the ability to switch to alternate fuels, and encouraged price-induced conservation by many of our firm customers. Throughput to our core-market customers increased 3.3 bcf (10.6%) reflecting the impact of the colder Fiscal 2001 weather. The significant increase in Gas Utility revenues is primarily a result of higher core-market revenues reflecting greater PGC rates and higher revenues from sales to customers not on our distribution system ("off-system sales"). Gas Utility's tariffs permit it to pass through prudently incurred gas costs to its core-market customers through higher PGC rates. Gas Utility cost of gas totaled $322.9 million in Fiscal 2001 compared with $184.2 million in Fiscal 2000 principally reflecting the higher average PGC rates and, to a lesser extent, higher core-market and off-system sales. Gas Utility total margin increased $7.1 million reflecting a $12.1 million increase in core-market margin partially offset by lower total margin from interruptible customers. The decline in interruptible margin reflects lower average interruptible unit margins due to a decline in the spread between oil and natural gas prices and the lower interruptible throughput. Gas Utility operating income increased $1.6 million as the previously mentioned increase in total margin and an increase in pension income was partially offset by higher operating and administrative expenses. The increase in operating and administrative expenses includes, among -16- other things, greater allowances for uncollectible accounts, reflecting significantly higher Fiscal 2001 customer bills, and lower income from environmental insurance litigation settlements. Such settlements totaled $0.9 million in Fiscal 2001 compared with $4.5 million in Fiscal 2000. Depreciation expense increased $1.1 million reflecting greater depreciation associated with distribution system capital expenditures. ELECTRIC OPERATIONS. Electric Utility distribution system sales in Fiscal 2001 increased 4.2% on favorable weather. Revenues increased as a result of the higher distribution system sales as well as off-system sales of electricity generated by Energy Ventures. Cost of sales totaled $51.9 million in Fiscal 2001 compared to $34.2 million in the prior year. The increase reflects higher per-unit purchased power costs, the impact on cost of sales resulting from the formation of Energy Ventures, and the higher Fiscal 2001 sales. Electric Operations total margin decreased $12.2 million as a result of the higher purchased power costs. Operating income declined less than the decline in total margin reflecting lower power production and depreciation expenses subsequent to the formation of Energy Ventures and lower utility realty taxes. INTEREST EXPENSE. The greater interest expense in Fiscal 2001 resulted primarily from greater long-term debt outstanding. FINANCIAL CONDITION AND LIQUIDITY CAPITALIZATION AND LIQUIDITY Utilities debt outstanding totaled $285.6 million at September 30, 2002. Included in this amount is $37.2 million under revolving credit agreements. Utilities may borrow up to a total of $97 million under its revolving credit agreements. The revolving credit agreements contain financial covenants including interest coverage ratios, debt service, and minimum tangible net worth. In September 2002, Utilities issued $40 million face value of its Series C Medium-Term Notes under a shelf registration statement with the U.S. Securities and Exchange Commission ("SEC"). The proceeds of the issuance were used after the end of Fiscal 2002 principally to repay debt maturing in October 2002. Utilities may issue up to an additional $85 million of debt securities under the shelf registration statement. Based upon cash expected to be generated from operations, the expected ability to refinance all or a portion of long-term debt maturing in Fiscal 2003, and borrowings available under revolving credit agreements, management believes that Utilities will be able to meet its anticipated contractual and projected cash commitments in Fiscal 2003. For a more detailed discussion of Utilities' debt and credit facilities, see Note 3 to Consolidated Financial Statements. -17- CASH FLOWS OPERATING ACTIVITIES. Cash provided by operating activities was $55.1 million in Fiscal 2002 compared to $76.1 million in Fiscal 2001. Changes in working capital required $23.3 million of operating cash flow in Fiscal 2002 compared to $3.8 million of operating cash flow provided in Fiscal 2001. Cash flow before working capital changes increased to $78.4 million in Fiscal 2002 compared to $72.3 million in Fiscal 2001, notwithstanding the decrease in Fiscal 2002 net income, reflecting in large part higher noncash charges for deferred income taxes. INVESTING ACTIVITIES. Expenditures for property, plant and equipment totaled $35.9 million during Fiscal 2002 compared to $36.8 million during Fiscal 2001. Cash used for investing activities in Fiscal 2001 included a $6 million cash contribution relating to the formation of Energy Ventures in December 2000. FINANCING ACTIVITIES. We paid cash dividends to UGI totaling $37.9 million in Fiscal 2002 compared to $35.3 million in Fiscal 2001. We also paid dividends of $1.6 million on our preferred stock. In September 2002, we issued $40 million face amount of Medium-Term Notes and used the proceeds after the end of Fiscal 2002 principally to repay debt maturing in October 2002. During Fiscal 2001, we issued $50 million face amount of Medium-Term Notes and used the proceeds for working capital purposes, to repay $15 million of maturing Medium-Term Notes, and to reduce borrowings under our revolving credit agreements. UTILITIES PENSION PLAN Utilities sponsors a defined benefit pension plan ("Pension Plan") for employees of UGI, Utilities, and certain of UGI's other subsidiaries. During Fiscal 2002 and 2001, the market value of plan assets was negatively affected by persistent declines in the equity markets. Notwithstanding the significant decline in the market value of plan assets during these years, at September 30, 2002 the Pension Plan's assets exceeded its accumulated benefit obligations by approximately $7.2 million. Utilities is in full compliance with regulations governing defined benefit pension plans, including ERISA rules and regulations, and does not anticipate it will be required to make a contribution to the Pension Plan in Fiscal 2003. Pretax pension income reflected in Fiscal 2002, 2001 and 2000 results was $3.9 million, $5.7 million, and $2.9 million, respectively. Pension income in Fiscal 2003 is expected to decline to approximately $1.0 million principally as a result of the impact of recent declines in the market value of Pension Plan assets. CAPITAL EXPENDITURES In the following table, we present capital expenditures by business segment for Fiscal 2002, 2001 and 2000. We also provide amounts we expect to spend in Fiscal 2003. We expect to finance a substantial portion of Fiscal 2003 capital expenditures from cash generated by operations and the remainder from borrowings under our credit facilities. -18-
Year Ended September 30, 2003 2002 2001 2000 - ------------------------ ---- ---- ---- ---- (Millions of dollars) (estimate) Gas Utility $ 39.6 $ 31.0 $ 31.8 $ 31.7 Electric Utility 5.3 4.9 5.0 4.7 ------ ------ ------ ------ $ 44.9 $ 35.9 $ 36.8 $ 36.4 ====== ====== ====== ======
CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS The following table presents significant contractual cash obligations under agreements existing as of September 30, 2002 (in millions).
Fiscal Fiscal 2003 - 2004 2005 - 2006 Thereafter Total ----------- ----------- ---------- ----- Long-term debt $ 76.0 $ 70.0 $ 102.0 $ 248.0 UGI Utilities redeemable preferred stock -- 2.0 18.0 20.0 Operating leases 5.4 3.9 5.6 14.9 Gas and Electric utility supply agreements 202.9 80.2 107.3 390.4 ------- ------- ------- ------- Total $ 284.3 $ 156.1 $ 232.9 $ 673.3 ======= ======= ======= =======
REGULATORY MATTERS The PUC approved a settlement establishing rules for Electric Utility Provider of Last Resort ("POLR") service on March 28, 2002, and a separate settlement that modified these rules on June 13, 2002 (collectively the "POLR Settlement"). Under the terms of the POLR Settlement, Electric Utility terminated stranded cost recovery through its CTC from commercial and industrial ("C&I") customers on July 31, 2002, and from residential customers on October 31, 2002, and is no longer subject to the statutory rate caps as of August 1, 2002 for C&I customers and as of November 1, 2002 for residential customers. Stranded costs are electric generation-related costs that traditionally would be recoverable in a regulated environment but may not be recoverable in a competitive electric generation market. Charges for generation service will (1) initially be set at a level equal to the rates paid by Electric Utility customers for POLR service under the statutory rate caps; (2) may be raised at certain designated times up to certain specified caps through December 2004; and (3) may be set at market rates thereafter. Electric Utility may also offer multiple year POLR contracts to its customers. The POLR Settlement provides 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. -19- C&I 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. On June 29, 2000, the PUC issued its order ("Gas Restructuring Order") approving Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's Natural Gas Choice and Competition Act. Among other things, the implementation of the Gas Restructuring Order resulted in an increase in Gas Utility's core-market base rates effective October 1, 2000. This base rate increase was designed to generate approximately $16.7 million in additional net annual revenues. In accordance with the Gas Restructuring Order, Gas Utility reduced its core-market PGC rates by an annualized amount of $16.7 million in the first 14 months following the October 1, 2000 base rate increase. Effective December 1, 2001, Gas Utility was required to reduce its PGC rates by amounts equal to the margin it receives from interruptible customers using pipeline capacity contracted by Gas Utility for core-market customers. As a result, Gas Utility operating results are more sensitive to the effects of heating-season weather and less sensitive to the market prices of alternative fuels. 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 (1) MGPs were formerly operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or private parties are investigating the extent of environmental contamination or performing environmental remediation. Utilities is currently litigating two claims against it relating to out-of-state sites. Management believes that under applicable law Utilities should not be liable in those instances in which a former subsidiary 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 operated, or that were owned or operated by former -20- subsidiaries of Utilities, if a court were to conclude that the subsidiary's separate corporate form should be disregarded. Utilities has filed suit against more than fifty insurance companies alleging that the defendants breached contracts of insurance by failing to indemnify Utilities for certain environmental costs. The suit seeks to recover more than $11 million in such costs. During 2002, 2001 and 2000, Utilities entered into settlement agreements with several of the insurers and recorded pre-tax income of $0.4 million, $0.9 million and $4.5 million, respectively, which amounts are included in operating and administrative expenses in the Consolidated Statements of Income. CRITICAL ACCOUNTING POLICIES AND ESTIMATES In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," 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. The following accounting policies require management's most subjective or complex judgments, as a result of the need to make estimates regarding matters that are inherently uncertain. 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 accounting principles generally accepted in the United States, 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 business, are subject to regulation by the Pennsylvania Public Utility Commission. 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 -21- 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. As of September 30, 2002, our regulatory assets totaled $62.0 million. MARKET RISK DISCLOSURES Gas Utility's tariffs contain clauses that permit recovery of substantially all of the prudently incurred cost of natural gas it sells to its customers. The recovery clauses provide for a periodic adjustment for the difference between the total amount actually collected from customers and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. During Fiscal 2002, 2001 and 2000, Electric Utility purchased all of its electric power needs, in excess of the electric power it obtained from its interests in electric generating facilities, under power supply arrangements of various lengths and on the spot market. Beginning September 2002, Electric Utility began purchasing its power needs from electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market, and our electricity generation businesses began selling on the spot market electric power produced from its interests in electricity generating facilities to third parties. Prices for electricity can be volatile especially during periods of high demand or tight supply. Although the generation component of Electric Utility's rates is subject to various rate cap provisions as a result of the Electricity Restructuring Order and the POLR Settlement, Electric Utility's fixed-price contracts with electricity suppliers mitigate most risks associated with offering customers a fixed price during the contract periods. However, should any of the suppliers under these contracts fail to provide electric power under the terms of the power and capacity contracts, increases, if any, in the cost of replacement power or capacity would 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. 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 2002 and Fiscal 2001, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.5 million and $0.7 million, respectively. -22- 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 $11.0 million and $8.5 million at September 30, 2002 and 2001, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $12.0 million and $9.2 million at September 30, 2002 and 2001, 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 interest rate protection agreements, which have been designated and qualify as cash flow hedges, was $(1.2) million at September 30, 2002. An adverse change in interest rates on ten-year U.S. treasury notes of 100 basis points would result in a $2.2 million decrease in the fair value of these interest rate protection agreements. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS The Financial Accounting Standards Board ("FASB") recently issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"); SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"); SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" ("SFAS 145"); and SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 143 addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with a corresponding increase in the carrying value of the related asset. Entities shall subsequently charge the retirement cost to expense using a systematic and rational method over the related asset's useful life and adjust the fair value of the liability resulting from the passage of time through charges to operating expense. We adopted SFAS 143 effective October 1, 2002. The adoption of SFAS 143 did not have a material effect on our financial position or results of operations. SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121") and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" as it relates to the disposal of a segment of a business. SFAS 144 establishes a single accounting model for long-lived assets to be disposed of based upon the framework of SFAS 121, and resolves significant implementation issues of SFAS 121. We adopted SFAS 144 effective October 1, 2002. The adoption of SFAS 144 did not affect our financial position or results of operations. -23- SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"), effective May 15, 2002. SFAS 4 had required that material gains and losses on extinguishment of debt be classified as an extraordinary item. Under SFAS 145, it is less likely that a gain or loss on extinguishment of debt would be classified as an extraordinary item in our Consolidated Statement of Income. Among other things, SFAS 145 also amends SFAS No. 13, "Accounting for Leases," to require that certain lease modifications that have economic effects similar to sale-leaseback transactions be accounted for in the same manner as sale-leaseback transactions. The provisions of SFAS 145 relating to leases became effective for transactions occurring after May 15, 2002. The adoption of SFAS 145 did not affect our financial position or results of operations. SFAS 146 addresses accounting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force ("EITF") No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." Generally, SFAS 146 requires that a liability for costs associated with an exit or disposal activity, including contract termination costs, employee termination benefits and other associated costs, be recognized when the liability is incurred. Under EITF No. 94-3, a liability was recognized at the date of an entity's commitment to an exit plan. SFAS 146 will be effective for disposal activities initiated after December 31, 2002. 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 to market areas; (3) changes in laws and regulations, including safety, tax and accounting 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) -24- 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. 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-1 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 During fiscal year 2002, the Company engaged a new independent auditor, PricewaterhouseCoopers LLP. The information required by Item 9 is incorporated in this Report by reference to the Company's Current Report on Form 8-K dated May 21, 2002. -25- PART III: UGI UTILITIES MANAGEMENT AND SECURITY HOLDERS ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT DIRECTORS
Utilities Director Principal Occupation Name Age Since and Other Directorships (1) - ---- --- ----- --------------------------- Lon R. Greenberg 52 1994 Mr. Greenberg has been Chairman of the Board of Directors of UGI Utilities, Inc. since August 1996. He was formerly Vice Chairman of the Board from 1995 to 1996, and Senior Vice President - Legal and Corporate Development from 1989 to 1994. James W. Stratton 66 1979 Mr. Stratton is the Chairman, Chief Executive Officer, and a director of Stratton Management Company (an investment advisory and financial consulting firm) (since 1972). Mr. Stratton also serves as a director of AmeriGas Propane, Inc.; Stratton Growth Fund, Inc.; Stratton Monthly Dividend REIT Shares, Inc.; Stratton Small-Cap Value Fund; Teleflex, Inc.; and BE&K, Inc. Richard C. Gozon 64 1989 Mr. Gozon retired as Executive Vice President of Weyerhaeuser Company in April of 2002 (an integrated forest products company) and Chairman of Norpac (North Pacific Paper Company, a joint venture with Nippon Paper Industries headquartered in Tokyo, Japan) positions he has held since 1994. Mr. Gozon was formerly a director (1984 to 1993), President and Chief Operating Officer of Alco Standard Corporation (a provider of paper and office products) (1988 to 1993); Executive Vice President and Chief Operating Officer (1988), President (1985 to 1987) of Paper Corporation of America. He also serves as a director of AmeriSource Bergen Corp.; and Triumph Group, Inc.
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Utilities Director Principal Occupation Name Age Since and Other Directorships (1) - ---- --- ----- --------------------------- Stephen D. Ban 62 1991 Dr. Ban is currently serving as the Director of the Technology Transfer Division of the Argonne National Laboratory (science-based Department of Energy laboratory dedicated to advancing the frontiers of science in energy, environment, biosciences and materials. He previously served as President and Chief Executive Officer of the Gas Research Institute (GRI), a gas industry research and development organization funded by distributors, transporters, and producers of natural gas (1987 through 1999). He also served as Executive Vice President. Prior to coming to GRI in 1981, he was Vice President, Research and Development and Quality Control of Bituminous Materials, Inc. Dr. Ban also serves as a director of Energen Corporation. Robert J. Chaney 60 1999 Mr. Chaney has been President and Chief Executive Officer of UGI Utilities, Inc. (since March 1999). He previously served as Executive Vice President - Utilities (1998 to 1999) and Vice President and General Manager-Gas Utility Division of the Company (1991 to 1998). Marvin O. Schlanger 54 1998 Mr. Schlanger is a Principal in the firm of Cherry Hill Chemical Investments, L.L.C. (management services and capital for chemical and allied industries) (October 1998 to present) and Chairman and Chief Executive Officer of Resolution Performance Products, Inc. (a producer and marketer of specialty and intermediate chemicals) (November 2000 to present). Mr. Schlanger was previously President and Chief Executive Officer (May 1998 to October 1998), Executive Vice President and Chief Operating Officer (1994 to May 1998) and a director (1994 to 1998) of ARCO Chemical Company. Mr. Schlanger also serves as a director of Wellman, Inc.
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Utilities Director Principal Occupation Name Age Since and Other Directorships (1) - ---- --- ----- --------------------------- Thomas F. Donovan 69 1998 Mr. Donovan retired as Vice Chairman of Mellon Bank on January 31, 1997, a position he had held since 1988. He continues to serve as a director of AmeriGas Propane, Inc. and Nuclear Electric Insurance Ltd. Anne Pol 55 1999 (and Mrs. Pol is President and Chief Operating Officer of Trex 1993-1997) Enterprises Corporation (a high technology research and development company), a position she has held since October 15, 2001. She previously served as Senior Vice President, Thermo Electron Corporation (environmental monitoring, analytical instruments and a major producer of recycling equipment, biomedical products and alternative energy systems) (1998 to 2001); and Vice President (1996 to 1998). Mrs. Pol also served as President, Pitney Bowes Shipping and Weighing Systems Division, a business unit of Pitney Bowes Inc. (mailing and related business equipment) (1993 to 1996); Vice President, New Product Programs in the Mailing Systems Division of Pitney Bowes Inc. (1991 to 1993); and Vice President, Manufacturing Operations in the Mailing Systems Division of Pitney (1990 to 1991).
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Utilities Director Principal Occupation Name Age Since and Other Directorships (1) - ---- --- ----- --------------------------- Ernest E. Jones 58 2002 Mr. Jones is President and Chief Executive Officer of Philadelphia Workforce Development Corporation (an agency which funds, coordinates and implements employment and training activities in Philadelphia), a position he has held since 1998. He formerly served as President and Executive Director of the Greater Philadelphia Urban Affairs Coalition (1983 to 1998). Mr. Jones also served as Executive Director of Community Legal Services, Inc. (1977 to 1983). Mr. Jones also serves as a director of the African American Museum in Philadelphia; First Union Regional Foundation; Thomas Jefferson University; United Way of Southeastern Pennsylvania; and the William Penn Foundation.
(1) All of the directors except Mr. Chaney also serve as directors of UGI Corporation. In addition, Messrs. Greenberg, Donovan, Gozon, and Stratton serve as directors of AmeriGas Propane, Inc., the General Partner of AmeriGas Partners, L.P. EXECUTIVE OFFICERS
Name Age Position - ---- --- -------- Lon R. Greenberg 52 Chairman of the Board of Directors Robert J. Chaney 60 President and Chief Executive Officer Peter G. Terranova 50 Vice President -Operations John C. Barney 54 Senior Vice President-Finance Brendan P. Bovaird 54 Vice President and General Counsel Vicki O. Ebner 43 Vice President -Marketing and Gas Supply
Directors are elected annually. All officers are elected for a one-year term at the organizational meeting of the Board of Directors held each year. -29- There are no family relationships between any of the directors or any of the officers or between any of the officers and any of the directors. The following is a summary of the business experience of the executive officers listed above during at least the last five years: Lon R. Greenberg Mr. Greenberg is Chairman of the Board of the Company (since August 1996), having served as a Director since 1994; he is also Chairman (since 1996), Chief Executive Officer (since August 1995) and President (since 1994) of UGI. In addition, he is Chairman of AmeriGas Propane, Inc. (since August 1996). Mr. Greenberg previously served as President and Chief Executive Officer of AmeriGas Propane, Inc. (1996 to 2000). Robert J. Chaney Mr. Chaney is President and Chief Executive Officer of the Company (since March 1999). He previously served as Executive Vice President - Utilities (1998 to 1999) and Vice President and General Manager-Gas Utility Division of the Company (1991 to 1998). John C. Barney Mr. Barney is Senior Vice President-Finance of Utilities (since March 1999). Previously, Mr. Barney served as Vice President-Finance and Accounting (1992 to 1999). Brendan P. Bovaird Mr. Bovaird is Vice President and General Counsel of the Company (since April 1995). He is also Vice President and General Counsel of UGI Corporation and AmeriGas Propane, Inc. (since April 1995). Mr. Bovaird previously served as Division Counsel and Member of the Executive and Operations Committees of Wyeth-Ayerst International Inc. (1992 to 1995). Peter G. Terranova Mr. Terranova is Vice President - Operations (since 1999). He previously served as Vice President - Marketing and Rates (1994-2000). Vicki O. Ebner Mrs. Ebner is Vice President - Marketing, Rates and Gas Supply (since 1999). She previously served as Vice President - Gas Supply (1998-1999), Customer Relations Manager - Harrisburg (1996-1998) and Manager - Gas Supply Services and Regulatory Affairs (1991-1995). -30- ITEM 11. EXECUTIVE COMPENSATION The following table shows cash and other compensation paid or accrued to the Company's Chief Executive Officer and each of its four other most highly compensated executive officers, (collectively, the "Named Executives") for the last three fiscal years. Summary Compensation Table
Annual Compensation Long Term Compensation ------------------------------- ------------------------------------ Awards Payouts --------------------------- ------- Other Annual Restricted Securities All Other Name and Principal Fiscal Compen- Stock underlying LTIP Compensation Position Year Salary Bonus (1) sation(2) Awards (3) Options / SARs Payouts (4) -------- ---- ------ --------- --------- ---------- -------------- ------- --- Robert J. Chaney 2002 $294,415 $105,754 $6,814 $120,800 18,000 $0 $9,867 President and Chief $120,800 Executive Officer(6) $120,800 2001 $285,500 $144,144 $7,511 $64,688 0 $0 $9,609 $133,450 2000 $264,307 $141,570 $7,679 $0 45,000 $0 $7,569 Lon R. Greenberg, 2002 $705,015 $521,092 $15,342 $785,200 120,000 $0 $28,033 Chairman(5)(6) $785,200 $785,200 2001 $667,799 $595,010 $14,849 $323,438 0 $0 $20,939 $1,000,875 2000 $640,662 $262,836 $13,092 $0 225,000 $0 $20,417 Brendan P. Bovaird, 2002 $232,683 $95,459 $5,449 $90,600 14,500 $0 $7,411 Vice President and General Counsel $90,600 (5)(6) $90,600 2001 $222,283 $96,708 $5,012 $38,813 0 $0 $6,112 $120,105 2000 $210,392 $49,349 $7,264 $0 28,000 $0 $5,927 John C. Barney 2002 $176,033 $64,262 $6,340 $60,400 8,000 $0 $5,124 Senior Vice President $60,400 - -Finance $60,400 2001 $170,826 $51,710 $3,827 $31,050 0 $0 $5,167 $68,059 2000 $164,848 $58,806 $2,145 $0 15,000 $0 $4,453 Mark R. Dingman, 2002 $156,003 $35,161 $7,335 $60,400 8,000 $0 $3,510 Vice President and $60,400 General Manager - $60,400 Electric Utility 2001 $152,882 $0 $6,862 $38,813 0 $0 $4,258 $88,077 2000 $149,583 $36,383 $6,907 $0 28,000 $0 $4,385
(1) Bonuses earned under the Annual Bonus Plan are for the year reported, regardless of the year paid. The Company's Annual Bonus Plan is based on the achievement of business and/or financial performance objectives, which support business plans and goals. Bonus opportunities vary by position and for Fiscal 2002 ranged from 0% to 86% of base salary for Mr. Chaney, 0% to 184% of base salary for Mr. Greenberg, 0% to 104% of base salary for Mr. Bovaird, 0% to 60% of base salary for Mr. Barney and 0% to 52% of base salary for Mr. Dingman. (2) Amounts represent tax payment reimbursements for certain benefits and, for Messrs. Barney and Bovaird, above-market interest on deferred compensation. (3) Effective January 1, 2002, the Board of Directors of UGI Corporation, approved three phantom performance-contingent -31- restricted stock awards ("Restricted Shares") to the Named Executives under the UGI Corporation 2000 Stock Incentive Plan. The restriction period for all three awards will end on December 31, 2004 provided that certain performance criteria are met for each performance period. Each award has a separate performance period as follows: January 1, 2002 through December 31, 2002, January 1, 2002 through December 31, 2003, and January 1, 2002 through December 31, 2004. The performance requirement is that UGI's Total Shareholder Return (TSR) during the relevant performance period equals the median of a peer group. The peer group is the group of companies that comprises the S&P Utilities Index. The actual amount of the award may be higher or lower than the original grant, or even zero, based on UGI's TSR percentile rank relative to the companies in the S&P Utilities Index. The maximum payout potential is 200% of the original award. The share price used for determining the TSR at the beginning and the end of each performance period will be the average price for the 90-day period preceding each December 31st. The dollar values shown in the restricted stock awards column of the table above represent the aggregate value of each award on the date of grant, determined by multiplying the number of shares awarded by the closing price of UGI Common Stock on the New York Stock Exchange on the effective dates of the respective grants. Based on the closing stock price of UGI Common Stock on the New York Stock Exchange on September 30, 2002, Mr. Greenberg's 128,000 Restricted Shares had a market value of $4,652,800; Mr. Chaney's 19,500 Restricted Shares had a market value of $708,825; Mr. Bovaird's 15,000 Restricted Shares had a market value of $545,250; Mr. Barney's 9,750 Restricted Shares had a market value of $354,413 and Mr. Dingman's 10,800 Restricted Shares had a market value of $392,580. (4) Amounts represent matching contributions by the Company or UGI in accordance with the provisions of the UGI Utilities, Inc. Employee Savings Plan and/or allocations under the Executive Retirement Plan. During 2002, 2001 and 2000, the following contributions were made to the Named Executives: (i) under the Employee Savings Plan: for each of Messrs. Greenberg, Chaney, Bovaird and Barney $3,825, $3,825, and $3,825; and Mr. Dingman $3,510, $3,825, and $3,825; (ii) under the Supplemental Executive Retirement Plan: Mr. Greenberg, $24,208, $17,114, and $16,592; Mr. Chaney, $6,042, $5,784, and, $3,744; Mr. Bovaird, $3,586, $2,287, and $2,102; Mr. Barney, $1,299, $1,342, and $628; and Mr. Dingman, $0, $433, and $560. (5) Compensation for Mr. Greenberg is attributable to his employment as Chairman, President and Chief Executive Officer of UGI Corporation. Compensation for Mr. Bovaird is attributable to his employment as Vice President and General Counsel of UGI Corporation. Mr. Greenberg and Mr. Bovaird receive no compensation from UGI Utilities, Inc. (6) Compensation reported for Messrs. Greenberg, Bovaird and Chaney is also reported in the Proxy Statement for UGI's 2002 Annual Meeting of Shareholders and is not additive. -32- Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values The following table shows information for fiscal year 2002 concerning exercised and unexercised stock options for shares of UGI Common Stock for each of the Named Executives.
Option Exercises in Fiscal 2002 And Fiscal Year-End Option Values Value of Number of Securities Unexercised Underlying Unexercised In-The-Money Number of Options at Options at Shares Fiscal Year End Fiscal Year End (2) Acquired on Value -------------------------- ------------------------------ Name Exercise Realized (1) Exercisable Unexercisable Exercisable Unexercisable ---- -------- ------------ ----------- ------------- ----------- ------------- Robert J. Chaney 13,639 $135,697 78,889 33,000 $1,152,475 $339,375 Lon R. Greenberg 123,959 $1,661,893 468,750 251,250 $7,113,281 $2,767,969 Brendan P. Bovaird 0 $0 48,667 14,500 $705,289 $83,375 John C. Barney 0 $0 20,000 13,000 $294,500 $124,625 Mark R. Dingman 18,666 $220,176 0 17,334 $0 $192,777
(1) Value realized is calculated on the difference between the option exercise price and the closing market price of UGI's Common Stock on the date of exercise multiplied by the number of shares to which the exercise relates. (2) The closing price of UGI's Common Stock as reported on the New York Stock Exchange Composite tape on September 30, 2002 was $36.35 and is used in calculating the value of unexercised options. -33- Option Grants in Last Fiscal Year The following table shows information on grants of stock options for UGI Corporation Common Stock during fiscal year 2002 to each of the Named Executives. OPTION GRANTS IN LAST FISCAL YEAR
Grant Date Individual Grants Value ----------------- ----- Number of Securities % of Total Underlying Options Granted Grant Date Options to Employees in Exercise Present Name Granted Fiscal Year (1) or Base Price Expiration Date Value (2) ---- ------- --------------- ------------- --------------- --------- Robert J. Chaney 18,000 4.02% $30.600 12/31/2011 $92,093 Lon R. Greenberg 120,000 26.77% $30.600 12/31/2011 $613,953 Brendan P. Bovaird 14,500 3.23% $30.600 12/31/2011 $74,186 John C. Barney 8,000 1.78% $30.600 12/31/2011 $40,930 Mark R. Dingman 8,000 1.78% $30.600 12/31/2011 $40,930
(1) A total of 448,250 options were granted to employees and executive officers of the Company during fiscal year 2002 under the 1992 Non-Qualified Stock Option Plan, the 2000 Stock Incentive Plan and the 2002 Non-Qualified Stock Option Plan. Under each Plan, the option exercise price is not less than 100% of the fair market value of UGI's Common Stock on the date of grant. All options will vest at the rate of 33% per year on the anniversary of the grant date. Options are nontransferable and generally exercisable only while the optionee is employed by the Company or an affiliate. Options are subject to adjustment in the event of recapitalizations, stock splits, mergers, and other similar corporate transactions affecting UGI's Common Stock. (2) Based on the Black-Scholes options pricing model. The assumptions used in calculating the grant date present value are as follows: - Three years of closing monthly stock price and dividend observations were used to calculate the stock volatility and dividend yield assumptions. - Stock volatility 29.10% - Stock's dividend yield 6.70% - Length of option term 10 years - Annualized risk-free interest rate 5.54% - Discount of risk of forfeiture 0% per year
All options were granted at fair market value. The actual value, if any, the executive may realize will depend on the excess of the stock price on the date the option is exercised over the exercise price. There is no assurance that the value realized by the executive will be at or near the value estimated by the Black-Scholes model. -34- RETIREMENT BENEFITS The following table shows the annual benefits payable upon retirement to the Named Executive Officers under the Retirement Income Plan for Employees of UGI Utilities, Inc. and participating employers (the "Retirement Plan") and the UGI Supplemental Executive Retirement Plan. The amounts shown assume the executive retires in 2002 at age 65, and that the aggregate benefits are not subject to statutory maximums. PENSION PLAN BENEFITS TABLE ANNUAL PLAN BENEFIT FOR YEARS CREDITED SERVICE SHOWN (1)
FINAL 5-YEAR AVERAGE ANNUAL 5 10 15 20 25 30 35 40 EARNINGS (2) YEARS YEARS YEARS YEARS YEARS YEARS YEARS YEARS ------------ ----- ----- ----- ----- ----- ----- ----- ----- $ 200,000 $ 19,000 $ 38,000 $ 57,000 $ 76,000 $ 95,000 $ 114,000 $ 133,000 $ 136,800 (3) $ 400,000 $ 38,000 $ 76,000 $114,000 $152,000 $190,000 $ 228,000 $ 266,000 $ 273,600 (3) $ 600,000 $ 57,000 $114,000 $171,000 $228,000 $285,000 $ 342,000 $ 399,000 $ 410,400 (3) $ 800,000 $ 76,000 $152,000 $228,000 $304,000 $380,000 $ 456,000 $ 532,000 $ 547,200 (3) $1,000,000 $ 95,000 $190,000 $285,000 $380,000 $475,000 $ 570,000 $ 665,000 $ 684,000 (3) $1,200,000 $114,000 $228,000 $342,000 $456,000 $570,000 $ 684,000 $ 798,000 $ 820,800 (3) $1,400,000 $133,000 $266,000 $399,000 $532,000 $665,000 $ 798,000 $ 931,000 $ 957,600 (3) $1,600,000 $152,000 $304,000 $456,000 $608,000 $760,000 $ 912,000 $1,064,000 $1,094,400 (3) $1,800,000 $171,000 $342,000 $513,000 $684,000 $855,000 $1,026,000 $1,197,000 $1,231,200 (3) $2,000,000 $190,000 $380,000 $570,000 $760,000 $950,000 $1,140,000 $1,330,000 $1,368,000 (3)
(1) Annual benefits are computed on the basis of straight life annuity amounts. These amounts include pension benefits, if any, to which a participant may be entitled as a result of participation in a pension plan of a subsidiary during previous periods of employment. The amounts shown do not take into account exclusion of up to 35% of the estimated primary Social Security benefit. The Retirement Plan provides a minimum benefit equal to 25% of a participant's final 12 months' earnings, reduced proportionately for less than 15 years of credited service at retirement. The minimum Retirement Plan Benefit is not subject to Social Security offset. Messrs. Greenberg, Barney, Chaney, Dingman and Bovaird had, respectively, 22 years, 30 years, 38 years, 29 years and 7 years of estimated credited service at September 30, 2002. (2) Consists of (i) base salary, commissions and cash payments under the UGI and Utilities Annual Bonus Plans, and (ii) deferrals thereof permitted under the Internal Revenue Code. (3) The maximum benefit under the Retirement Plan and the Supplemental Executive Retirement Plan is equal to 60% of a participant's highest consecutive 12 months' earnings during the last 120 months. -35- SEVERANCE PAY PLAN FOR SENIOR EXECUTIVE EMPLOYEES The UGI Corporation Senior Executive Employee Severance Pay Plan (the "UGI Severance Plan") assists certain senior level employees of Utilities, including Messrs. Greenberg, Bovaird, Chaney, Barney and Dingman in the event their employment is terminated without fault on their part. Specified benefits are payable to a senior executive covered by the UGI Severance Plan if the senior executive's employment is involuntarily terminated for any reason other than for cause or as a result of the senior executive's death or disability. The UGI Severance Plan provides for cash payments equal to a participant's compensation for a period of time ranging from 3 months to 15 months (30 months in the case of Mr. Greenberg), depending on length of service. In addition, a participant receives the cash equivalent of his or her target bonus under the Annual Bonus Plan, pro-rated for the number of months served in the fiscal year. However, if the termination occurs in the last two months of the fiscal year, the Chief Executive Officer has the discretion to determine whether the participant will receive a pro-rated target bonus, or the actual annual bonus which would have been paid after the end of the fiscal year, assuming that the participant's entire bonus was contingent on meeting the applicable financial performance goal. Certain employee benefits are continued under the Plan for a period of up to 15 months (30 months in the case of Mr. Greenberg). Utilities has the option to pay a participant the cash equivalent of those employee benefits. In order to receive benefits under the UGI Severance Plan, a senior executive is required to execute a release which discharges Utilities and its affiliates from liability for any claims the senior executive may have against any of them, other than claims for amounts or benefits due to the executive under any plan, program or contract provided by or entered into with Utilities or its affiliates. The senior executive is also required to cooperate in attending to matters pending at the time of his or her termination of employment. CHANGE OF CONTROL ARRANGEMENTS Named Executives Employed by UGI Corporation. Messrs. Greenberg and Bovaird each have an agreement with UGI Corporation (the "Agreement") which provides certain benefits in the event of a change of control of UGI. The Agreements operate independently of the UGI Severance Plan, continue through July 2004, and are automatically extended in one-year increments thereafter unless, prior to a change of control, UGI terminates an Agreement. In the absence of a change of control, each Agreement will terminate when, for any reason, the executive terminates his employment with UGI or its subsidiaries. A change of control is generally deemed to occur if: (i) any person (other than the executive, his affiliates and associates, UGI or any of its subsidiaries, any employee benefit plan of UGI or any of its subsidiaries, or any person or entity organized, appointed, or established by UGI or its subsidiaries for or pursuant to the terms of any such employee benefit plan), together with all affiliates and associates of such person, acquires securities representing 20% or more of either (x) the then outstanding shares of common stock of UGI or (y) the combined voting power -36- of UGI's then outstanding voting securities; (ii) individuals who at the beginning of any 24-month period constitute the Board of Directors (the "Incumbent Board") and any new director whose election by the Board, or nomination for election by UGI's shareholders, was approved by a vote of at least a majority of the Incumbent Board, cease for any reason to constitute a majority thereof; (iii) UGI is reorganized, merged or consolidated with or into, or sells all or substantially all of its assets to, another corporation in a transaction in which former shareholders of UGI do not own more than 50% of the outstanding common stock and the combined voting power, respectively, of the then outstanding voting securities of the surviving or acquiring corporation after the transaction; or (iv) UGI is liquidated or dissolved. Upon a change of control, the Agreement provides for an immediate cash payment equal to the market value of any pending target award under UGI's long-term compensation plan. Severance benefits are payable under the Agreements if there is a termination of the executive's employment without cause at any time within three years after a change of control. In addition, following a change of control, the executive may elect to terminate his or her employment without loss of severance benefits in certain specified contingencies, including termination of officer status; a significant adverse change in authority, duties, responsibilities or compensation; the failure of UGI to comply with and satisfy any of the terms of the Agreement; or a substantial relocation or excessive travel requirements. An executive who is terminated with rights to severance compensation under an Agreement will be entitled to receive an amount equal to 1.0 or 1.5 (2.5 in the case of Mr. Greenberg) times his average total cash remuneration for the preceding five calendar years. If the severance compensation payable under the Agreement, either alone or together with other payments to an executive, would constitute "excess parachute payments," as defined in Section 280G of the Internal Revenue Code of 1986, as amended (the "Code"), the executive will also receive an amount to satisfy the executive's additional tax burden. Named Executives Employed by UGI Utilities, Inc. Messrs. Chaney, Barney and Dingman each have an agreement with UGI Utilities (the "Agreement") which provides certain benefits in the event of a change of control of Utilities or of UGI. The Agreements operate independently of the UGI Severance Plan, continue through July 2004, and are automatically extended in one-year increments thereafter unless, prior to a change of control, the Company terminates an Agreement. In the absence of a change of control, each Agreement will terminate when, for any reason, the executive terminates his employment with Utilities or its subsidiaries. A change of control is generally deemed to occur if a change of control of UGI, as defined above, occurs or if: (i) UGI and its subsidiaries fail to own more than fifty percent of the combined voting power of the Company's then outstanding voting securities, (ii) the Company is reorganized, merged or consolidated with or into, or sells all or substantially all of its assets to, another corporation in a transaction in which former shareholders of the Company do not own more than 50% of the outstanding common stock and the combined voting power, respectively, of the then outstanding voting securities of the surviving or acquiring corporation after the transaction, or (iii) the Company is liquidated or dissolved. -37- Upon a change of control, the Agreement provides for an immediate cash payment equal to the market value of any pending target award under Utilities' long-term compensation plan. Severance benefits are payable under the Agreements if there is a termination of the executive's employment without cause at any time within three years after a change of control. In addition, following a change of control, the executive may elect to terminate his or her employment without loss of severance benefits in certain specified contingencies, including termination of officer status; a significant adverse change in authority, duties, responsibilities or compensation; the failure of the Company to comply with and satisfy any of the terms of the Agreement; or a substantial relocation or excessive travel requirements. An executive who is terminated with rights to severance compensation under an Agreement will be entitled to receive an amount equal to 1.0 or 1.5 times his average total cash remuneration for the preceding five calendar years. If the severance compensation payable under the Agreement, either alone or together with other payments to an executive, would constitute "excess parachute payments," as defined in Section 280G of the Internal Revenue Code of 1986, as amended (the "Code"), the executive will also receive an amount to satisfy the executive's additional tax burden. COMPENSATION OF DIRECTORS Messrs. Chaney and Greenberg are not compensated for service on the Board of Directors or on any Committee of the Board. The other members of the Company's Board of Directors also serve on the UGI Board and receive no additional compensation for service on the Company's Board. The Company reimburses UGI for 50% of the attendance fees and expenses incurred by the non-employee directors of UGI. COMPENSATION COMMITTEE The members of the UGI Utilities, Inc. Compensation and Management Development Committee are Richard C. Gozon (Chairman), Thomas F. Donovan and Anne Pol. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS At December 2, 2002, UGI Corporation held 100% of the Company's Common Stock. UGI is located at 460 North Gulph Road, King of Prussia, PA 19406. The following table sets forth, as of October 31, 2002, the number of shares of Common Stock of UGI beneficially owned by each director of the Company and each of the Named Executives, as well as all directors and executive officers as a group. Mr. Greenberg is the beneficial owner of approximately 2% of UGI's Common Stock. All other directors, Named Executives and executive officers own less than 1% of UGI's outstanding shares. The total -38- number of shares beneficially owned by all directors and executive officers as a group (including 726,739 shares subject to exercisable options) represents approximately 4% of UGI's outstanding shares. SECURITY OWNERSHIP OF MANAGEMENT
NUMBER OF SHARES AND NATURE OF BENEFICIAL OWNERSHIP NUMBER OF EXCLUDING OPTIONS EXERCISABLE STOCK NAME OF BENEFICIAL OWNER (1) OPTIONS TOTAL ------------------------ --- ------- ----- Stephen D. Ban 15,470 (2) 14,100 29,570 John C. Barney (3) 8,343 20,000 28,343 Brendan P. Bovaird (4) 22,965 48,667 71,632 Robert J. Chaney 38,450 (5) 78,889 117,339 Thomas F. Donovan 5,629 (2) 12,800 18,429 Richard C. Gozon 25,964 (2) 16,800 42,764 Lon R. Greenberg (6) 112,040 468,750 580,790 Anne Pol 11,752 (2) 12,800 24,552 Marvin O. Schlanger 9,433 (2) 12,800 22,233 James W. Stratton (7) 16,427 (2) 16,800 33,227 Peter G. Terranova (8) 4,871 20,333 25,204 Mark R. Dingman 17,000 0 17,000 Ernest E. Jones 1,084 (2) 4,000 5,084 All directors and executive officers as a group (13 total) 314,761 726,739 1,041,500
(1) The director or officer has sole voting and investment power unless otherwise specified. (2) The number of Shares shown includes Deferred Units ("Units") acquired through the 1997 Amended and Restated Directors' Equity Compensation Plan. Units are neither actual shares nor other securities, but each Unit will be converted to one share of Common Stock and paid out to directors upon their retirement or termination of service. The number of Units included for each director is as follows: Messrs. Donovan (3,546), Stratton (13,316), Schlanger (6,950), Gozon (18,853), Ban (9,653), Mrs. Pol (9,879) and Mr. Jones (970). (3) Mr. Barney holds 236 shares represented by units held in the UGI Stock Fund of the 401(k) Employee Savings Plan, based on September 30, 2002 Savings Plan statements. Mr. Barney disclaims beneficial ownership of 200 Shares owned by an adult son. -39- (4) Mr. Bovaird holds 19,993 shares jointly with his spouse and 2,972 Shares represented by units held in the UGI Stock Fund of the 401(k) Employee Savings Plan, based on September 30, 2002 Saving Plan statements. (5) Mr. Chaney is trustee of a trust that holds 13,650 shares. (6) Mr. Greenberg holds 88,220 shares jointly with his spouse and 6,105 Shares represented by units held in the UGI Stock Fund of the 401(k) Employee Savings Plan, based on September 30, 2002 Saving Plan statements. (7) Mr. Stratton holds 3,111 shares jointly with his spouse. (8) Mr. Terranova holds 820 shares represented by units held in the UGI Stock Fund of the 401(k) Employee Savings Plan, based on September 30, 2002 Savings Plan statements. (9) The total number of shares beneficially owned by the directors and officers as a group represents approximately 4% of UGI's outstanding Shares. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS In fiscal year 2002 UGI allocated 49%, or approximately $6.7 million, of its general corporate expenses to Utilities. ITEM 14. CONTROLS AND PROCEDURES An evaluation of the effectiveness of the design and operation of the Company's disclosure controls and procedures as of December 20, 2002 was carried out by the Company under the supervision and with the participation of the Company's management, including the Chief Executive Officer and Chief Financial Officer. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures have been designed and are being operated in a manner that provides reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. 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. Subsequent to the date of the most recent evaluation of the Company's internal controls, there were no significant changes in the Company's internal controls or in other factors that could significantly affect the internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses. -40- PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K (a) DOCUMENTS FILED AS PART OF THIS REPORT: (1) FINANCIAL STATEMENTS: Included under Item 8 are the following financial statements and supplementary data: Reports of Independent Public Accountants Consolidated Balance Sheets as of September 30, 2002 and 2001 Consolidated Statements of Income for the fiscal years ended September 30, 2002, 2001 and 2000 Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2002, 2001 and 2000 Consolidated Statements of Stockholders' Equity for the fiscal years ended September 30, 2002, 2001 and 2000 Notes to Consolidated Financial Statements (2) FINANCIAL STATEMENT SCHEDULE: For the years ended September 30, 2002, 2001 and 2000 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. NOTICE REGARDING ARTHUR ANDERSEN LLP Arthur Anderson LLP audited our consolidated financial statements for the three years in the period ended September 30, 2001 and issued a report thereon dated November 16, 2001. Arthur Anderson LLP has not reissued its report or consented to the incorporation by reference of such report into the Company's prospectuses relating to offering and sale of our debt -41- securities. On June 15, 2002, Arthur Andersen LLP was convicted of obstruction of justice by a federal jury in Houston, Texas in connection with Arthur Andersen LLP's work for Enron Corp. On September 15, 2002, a federal judge upheld this conviction. Arthur Andersen LLP ceased its audit practice before the SEC on August 31, 2002. Effective May 21, 2002, we terminated the engagement of Arthur Andersen LLP as our independent accountants and engaged PricewaterhouseCoopers LLP to serve as our independent accountants for the fiscal year ending September 30, 2002. Because of the circumstances currently affecting Arthur Andersen LLP, as a practical matter it may not be able to satisfy any claims arising from the provision of auditing services to us, including claims available to security holders under federal and state securities laws. (3) LIST OF EXHIBITS: The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing): INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT ----------- ------- ---------- ------ ------- 3.1 Utilities' Articles of Incorporation Utilities Registration 3 Statement No. 333-72540 *3.2 Bylaws of UGI Utilities as in effect since September 24, 2002 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 Indenture between Utilities and First Union National UGI Form 10-K (4)e Bank (formerly, First Fidelity Bank, N.A. (9/30/93) Pennsylvania,) Trustee, dated as of August 1, 1993 and related 6.5% Note due 2003
-42- INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT ----------- ------- ---------- ------ ------- 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 Service Agreement for comprehensive delivery service UGI Form 10-K 10.40 (Rate CDS) dated February 23, 1998 between UGI (9/30/00) Utilities, Inc. and Texas Eastern Transmission Corporation 4.7 Officer's Certificate establishing Medium-Term Notes Utilities Form 8-K 4(iv) series (8/26/94) 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) 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 Paragraph 61,060 (1993), order on rehearing, 64 FERC Paragraph 61,365 (1993) 10.2 Service Agreement (Rate FTS) dated June 1, 1987 Utilities Form 10-K (10)o. between Utilities and Columbia, as modified by (12/31/90) Supplement No. 1 dated October 1, 1988; Supplement No. 2 dated November 1, 1989; Supplement No. 3 dated November 1, 1990; Supplement No. 4 dated November 1, 1990; and Supplement No. 5 dated January 1, 1991, as further 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 Paragraph 61,060 (1993), order on rehearing, 64 FERC Paragraph 61,365 (1993) 10.3 Transportation Service Agreement (Rate FTS-1) dated Utilities Form 10-K (10)p. November 1, 1989 between Utilities and Columbia Gulf (12/31/90) Transmission Company, as modified pursuant to the orders of the Federal Energy Regulatory Commission in Docket No. RP93-6-000 reported at Columbia Gulf Transmission Co., 64 FERC Paragraph 61,060 (1993), order on rehearing, 64 FERC Paragraph 61,365 (1993)
-43- INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT ----------- ------- ---------- ------ ------- 10.4** UGI Corporation 1992 Directors' Stock Plan UGI Form 10-Q (10)ff (6/30/92) 10.5** UGI Corporation Directors' Deferred Compensation Plan Form 10-K 10.6 Amended and Restated as of January 1, 2000 UGI (9/30/00) 10.6** UGI Corporation Directors' Equity Compensation Plan Form 10-K 10.9 Amended and Restated as of January 1, 2000 UGI (9/30/00) 10.7** UGI Corporation 1992 Stock Option and Dividend Form 10-Q (10)ee Equivalent Plan, as amended May 19, 1992 UGI (6/30/92) 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, Form 10-Q 10.4 1996` Utilities (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 Form 10-K 10.12 Pay Plan effective January 1, 1997 UGI (9/30/97) 10.12** UGI Corporation 1992 Non-Qualified Stock Option Plan, Form 10-K 10.39 as amended UGI (9/30/00) 10.13** UGI Corporation 2000 Directors' Stock Option Plan UGI Form 10-K 10.13 (9/30/99) 10.14** UGI Corporation 2000 Stock Incentive Plan UGI Form 10-Q 10.1 (6/30/00) 10.15** Service Agreement for comprehensive delivery service (Rate CDS) dated February 23, 1999 between UGI Utilities, Inc. and Texas Eastern Transmission Form 10-K 10.41 Corporation UGI (9/30/00) 10.16** UGI Corporation 1997 Stock Option and Dividend Form 10-Q 10.2 Equivalent Plan UGI (3/31/97) 10.17** UGI Corporation Supplemental Executive Retirement Plan Form 10-Q 10 Amended and Restated effective October 1, 1996 UGI (6/30/98) 10.18 ** Summary of Terms of UGI Corporation 1999 Restricted Form 10-Q 10 Stock Awards UGI (6/30/99) 10.20** Description of Change of Control arrangements for UGI Form 10-K 10.33 Messrs. Greenberg and Bovaird (9/30/99) 10.21** Description of Change of Control arrangements for UGI Form 10-K 10.34 Messrs. Chaney, Barney and Dingman (9/30/99) 10.22** Consulting Services Agreement dated as of August 1, UGI Form 10-K 10.38 2000 between Stephen D. Ban and UGI Corporation (9/30/00)
-44- INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT ----------- ------- ---------- ------ ------- 10.23 Power Sales Agreement between UGI Utilities, Inc. and Utilities Form 10-K 10.23 UGI Development Company dated as of November 30, 2001 (9/30/01) 10.24 Partnership Agreement of Hunlock Creek Energy Ventures Utilities Form 10-K 10.24 dated December 8, 2001 by and between UGI Hunlock (9/30/01) Development Company and Allegheny Energy Supply Hunlock Creek LLC *10.25 Storage Transportation Service Agreement (Rate Schedule SST) between Utilities and Columbia dated November 1, 1993, as modified pursuant to orders of the Federal Energy Regulatory Commission *10.26 No-Notice Transportation Service Agreement (Rate Schedule NTS) between Utilities and Columbia dated November 1, 1993, as modified pursuant to orders of the Federal Energy Regulatory Commission *10.27 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 *10.28 No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern 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 FT-1) between Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission *10.30 Firm Transportation Service Agreement (Rate Schedule FT-1) between Utilities and Texas Eastern Transmission dated October 31, 2000, as modified pursuant to various orders of the Federal Energy Regulatory Commission *10.31 Firm Transportation Service Agreement (Rate Schedule FT) between Utilities and Transcontinental Gas Pipe Line dated October 1, 1996, as modified pursuant to various orders of the Federal Energy Regulatory Commission 10.32** 2002 UGI Corporation Non-Qualified Stock Option Plan UGI Form 10-K 10.38 (9/30/02) *12.1 Computation of Ratio of Earnings to Fixed Charges Computation of Ratio of Earnings to Combined Fixed *12.2 Charges and Preferred Stock Dividends
-45- INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT ----------- ------- ---------- ------ ------- 21 Subsidiaries of the Registrant Utilities Form 10-K 21 (9/30/00) *23 Consent of PricewaterhouseCoopers LLP *99 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, 2002
* Filed herewith. ** As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement. (b) REPORTS ON FORM 8-K: The Company filed the following Current Reports on Form 8-K during the fourth quarter of fiscal year 2002:
Date Item Number(s) Content ---- -------------- ------- 09/16/02 5 Other Events - Standard & Poor's Ratings Services Press Release dated September 11, 2002 re: Corporate Credit and Unsecured Debt Ratings
-46- 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 17, 2002 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 17, 2002 by the following persons on behalf of the Registrant in the capacities indicated. SIGNATURE TITLE --------- ----- Robert J. Chaney President and Chief - --------------------------- Executive Officer Robert J. Chaney (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 -47- Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 17, 2002 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 -48- 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 2002. -49- CERTIFICATIONS I, Robert J. Chaney, certify that: 1. I have reviewed this annual report on Form 10-K of UGI Utilities, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: (a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and (c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors: (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: December 20, 2002 Robert J. Chaney ------------------------------------- Robert J. Chaney President and Chief Executive Officer -50- I, John C. Barney, certify that: 1. I have reviewed this annual report on Form 10-K of UGI Utilities, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: (a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and (c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors: (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: December 20, 2002 John C. Barney -------------------------------------------- John C. Barney Senior Vice President - Finance and Chief Financial Officer -51- UGI UTILITIES, INC. AND SUBSIDIARIES FINANCIAL INFORMATION FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K YEAR ENDED SEPTEMBER 30, 2002 F-1 UGI UTILITIES, INC. AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
Pages ----- Financial Statements: Reports of Independent Accountants F-3 to F-4 Consolidated Balance Sheets as of September 30, 2002 and 2001 F-5 to F-6 Consolidated Statements of Income for the years ended September 30, 2002, 2001 and 2000 F-7 Consolidated Statements of Cash Flows for the years ended September 30, 2002, 2001 and 2000 F-8 Consolidated Statements of Stockholder's Equity for the years ended September 30, 2002, 2001 and 2000 F-9 Notes to Consolidated Financial Statements F-10 to F-27 Financial Statement Schedule: For the years ended September 30, 2002, 2001 and 2000: 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 ACCOUNTANTS To the Board of Directors and Stockholder of UGI Utilities, Inc.: In our opinion, the consolidated financial statements as of and for the year ended September 30, 2002 listed in the index appearing under Item 15a(1) and (2) present fairly, in all material respects, the financial position of UGI Utilities, Inc. and its subsidiaries at September 30, 2002 and the results of their operations and their cash flows for the year ended September 30, 2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule as of and for the year ended September 30, 2002 listed in the Index to Financial Statements and Financial Statement Schedule present 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 audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which 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 audit provides a reasonable basis for our opinion. The financial statements of UGI Utilities, Inc. and its subsidiaries as of September 30, 2001, and for each of the two years in the period ended September 30, 2001 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statements in their report dated November 16, 2001. PricewaterhouseCoopers LLP Philadelphia, Pennsylvania November 15, 2002 F-3 THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED ACCOUNTANT'S REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholder of UGI Utilities, Inc.: We have audited the accompanying consolidated balance sheets of UGI Utilities, Inc. and subsidiaries as of September 30, 2001 and 2000, and the related consolidated statements of income, cash flows and stockholder's equity for each of the three years in the period ended September 30, 2001. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of UGI Utilities, Inc. and subsidiaries as of September 30, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2001 in conformity with accounting principles generally accepted in the United States. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the Index to Financial Statements and Financial Statement Schedule is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Philadelphia, Pennsylvania November 16, 2001 F-4 UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of dollars)
September 30, 2002 2001 --------- --------- ASSETS Current assets: Cash and cash equivalents $ 6,090 $ 7,711 Accounts receivable (less allowances for doubtful accounts of $1,972 and $3,151, respectively) 38,554 39,152 Accrued utility revenues 8,069 11,110 Inventories 38,654 48,074 Deferred income taxes 2,610 5,527 Income taxes recoverable 6,892 - Deferred fuel costs 4,304 - Prepaid expenses and other current assets 3,151 2,178 --------- --------- Total current assets 108,324 113,752 Property, plant and equipment Gas utility 760,161 734,661 Electric operations 111,265 108,423 General 11,909 12,113 --------- --------- 883,335 855,197 Less accumulated depreciation and amortization (290,194) (276,429) --------- --------- Net property, plant and equipment 593,141 578,768 Regulatory assets 57,685 56,155 Other assets 38,973 35,734 --------- --------- Total assets $ 798,123 $ 784,409 ========= =========
See accompanying notes to consolidated financial statements. F-5 UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of dollars, except per share)
September 30, 2002 2001 ---------- ---------- LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Current maturities of long-term debt $ 76,000 $ - Bank loans 37,200 57,800 Accounts payable 57,499 67,456 Employee compensation and benefits accrued 8,984 8,356 Dividends and interest accrued 5,443 5,392 Income taxes accrued - 11,138 Customer deposits and refunds 8,745 6,032 Other current liabilities 22,346 21,264 --------- --------- Total current liabilities 216,217 177,438 Long-term debt 172,369 208,477 Deferred income taxes 131,483 121,890 Deferred investment tax credits 8,385 8,783 Other noncurrent liabilities 11,815 12,064 Commitments and contingencies (note 8) Preferred stock subject to mandatory redemption, without par value 20,000 20,000 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 73,057 72,792 Retained earnings 107,312 102,706 Accumulated other comprehensive loss (2,774) - --------- --------- Total common stockholder's equity 237,854 235,757 --------- --------- Total liabilities and stockholders' equity $ 798,123 $ 784,409 ========= =========
See accompanying notes to consolidated financial statements. F-6 UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Thousands of dollars)
Year Ended September 30, ----------------------------------------------- 2002 2001 2000 --------- --------- --------- Revenues $ 490,552 $ 584,762 $ 436,942 --------- --------- --------- Costs and expenses: Gas, fuel and purchased power 290,282 374,781 218,119 Operating and administrative expenses 80,910 88,310 85,425 Operating and administrative expenses - related parties 6,664 5,277 4,159 Taxes other than income taxes 11,930 9,182 17,052 Depreciation and amortization 22,172 23,767 23,612 Other income, net (11,723) (15,111) (12,660) --------- --------- --------- 400,235 486,206 335,707 --------- --------- --------- Operating income 90,317 98,556 101,235 Interest expense 16,652 18,988 18,353 --------- --------- --------- Income before income taxes 73,665 79,568 82,882 Income taxes 29,570 31,431 32,406 --------- --------- --------- Net income 44,095 48,137 50,476 Dividends on preferred stock 1,550 1,550 1,550 --------- --------- --------- Net income after dividends on preferred stock $ 42,545 $ 46,587 $ 48,926 ========= ========= =========
See accompanying notes to consolidated financial statements. F-7 UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Thousands of dollars)
Year Ended September 30, ----------------------------------------------- 2002 2001 2000 --------- --------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 44,095 $ 48,137 $ 50,476 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 22,172 23,767 23,612 Deferred income taxes, net 11,114 (2,016) 2,866 Provision for uncollectible accounts 5,270 8,269 4,386 Pension income (3,857) (5,671) (2,930) Other (391) (177) 4,892 Net change in: Accounts receivable and accrued utility revenues (1,631) (14,704) (14,823) Inventories 9,420 (14,508) (8,831) Deferred fuel costs (7,056) 9,948 (3,751) Accounts payable (9,957) 13,318 16,257 Other current assets and liabilities (14,123) 9,769 9,293 --------- --------- --------- Net cash provided by operating activities 55,056 76,132 81,447 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for property, plant and equipment (35,884) (36,783) (36,391) Net costs of property, plant and equipment disposals (704) (1,407) (838) Cash contribution to partnership - (6,000) - --------- --------- --------- Net cash used by investing activities (36,588) (44,190) (37,229) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Payment of dividends (39,489) (36,809) (45,563) Issuance of long-term debt 40,000 50,603 - Repayment of long-term debt - (15,000) (7,143) Bank loans increase (decrease) (20,600) (42,600) 13,000 Capital contribution from UGI Corporation - 4,000 - --------- --------- --------- Net cash used by financing activities (20,089) (39,806) (39,706) --------- --------- --------- Cash and cash equivalents increase (decrease) $ (1,621) $ (7,864) $ 4,512 ========= ========= ========= CASH AND CASH EQUIVALENTS: End of year $ 6,090 $ 7,711 $ 15,575 Beginning of year 7,711 15,575 11,063 --------- --------- --------- Increase (decrease) $ (1,621) $ (7,864) $ 4,512 ========= ========= =========
See accompanying notes to consolidated financial statements. F-8 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, 1999 $ 60,259 $ 68,559 $ 90,742 $ - $ 219,560 Net income 50,476 50,476 Cash dividends - common stock (44,013) (44,013) Cash dividends - preferred stock (1,550) (1,550) ---------- ---------- --------- -------- ---------- Balance September 30, 2000 60,259 68,559 95,655 - 224,473 Net income 48,137 48,137 Capital contribution by UGI Corporation 4,000 4,000 Cash dividends - common stock (35,259) (35,259) Cash dividends - preferred stock (1,550) (1,550) Dividends of net assets (4,277) (4,277) Other 233 233 ---------- ---------- --------- -------- ---------- 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 ========== ========== ========= ======== ==========
See accompanying notes to consolidated financial statements. F-9 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 (1) a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and (2) an electricity distribution utility ("Electric Utility") and electricity generation business (which together with Electric Utility are referred to herein as "Electric Operations") in northeastern Pennsylvania. The Company's interests in electric generation assets are owned by our non-utility subsidiary, UGI Development Company ("UGID") and its 50%-owned joint-venture partnership Hunlock Creek Energy Ventures ("Energy Ventures") which is accounted for under the equity method. We refer to UGI Utilities and its subsidiaries collectively as "the Company" or "we." Our consolidated financial statements include the accounts of UGI Utilities and its majority-owned subsidiaries. We eliminate all significant intercompany accounts and transactions when we consolidate. UGID has been granted "Exempt Wholesale Generator" status by the Federal Energy Regulatory Commission. USE OF ESTIMATES We make estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States. 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 Gas Utility and Electric Utility (collectively, "Utilities") are subject to regulation by the Pennsylvania Public Utility Commission ("PUC"). We account for 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. If a separable portion of Gas Utility or Electric Utility no longer meets the provisions of SFAS 71, we are required to eliminate the financial statement effects of regulation for that portion of our operations. On June 29, 2000, the PUC entered its order ("Gas Restructuring Order") in Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's Natural Gas Choice and Competition Act ("Gas Competition Act"). Based upon the provisions of the Gas Restructuring Order and the Gas Competition Act, we believe Gas Utility's regulatory assets continue to satisfy the criteria of SFAS 71. For further information on the impact of the Gas Competition Act and Pennsylvania's Electricity Customer Choice Act ("Electricity Choice Act"), see Note 2. F-10 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 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 $16,348 in 2002, $17,543 in 2001 and $17,941 in 2000. We paid income taxes totaling $36,282 in 2002, $29,000 in 2001 and $23,108 in 2000. 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. 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. Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is generally consistent with income taxes calculated on a separate return basis. F-11 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION We record property, plant and equipment at cost. We charge to accumulated depreciation the original cost of UGI Utilities' retired plant and equipment, together with the net cost of removal, for financial accounting purposes. We record depreciation expense for 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 2.5% in 2002 and 2.6% in each of 2001 and 2000. Depreciation expense as a percentage of the related average depreciable base for Electric Operations was 3.0% in each of 2002 and 2001, and 3.5% in 2000. Depreciation expense was $21,649 in 2002, $22,701 in 2001 and $23,000 in 2000. 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. ENVIRONMENTAL LIABILITIES 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. 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. We do not discount to present value the costs of future expenditures for environmental liabilities. 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. F-12 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DERIVATIVE INSTRUMENTS Effective October 1, 2000, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). 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. To the extent a derivative instrument qualifies and is designated as a hedge of the variability of cash flows associated with a forecasted transaction ("cash flow hedge"), the effective portion of the gain or loss on such derivative instrument is generally reported in other comprehensive income and the ineffective portion, if any, is reported in net income. Such amounts reported in other comprehensive income are reclassified into net income when the forecasted transaction affects earnings. If a cash flow hedge is discontinued because it is probable that the forecasted transaction will not occur, the net gain or loss is immediately reclassified into net income. To the extent derivative instruments qualify and are designated as hedges of changes in the fair value of an existing asset, liability or firm commitment ("fair value hedge"), the gain or loss on the hedging instrument is recognized in earnings along with changes in the fair value of the hedged asset, liability or firm commitment attributable to the hedged risk. On occasion, we have used a managed program of natural gas and oil futures contracts to preserve gross margin associated with certain of our natural gas customers. These contracts were designated as cash flow hedges. The Company did not enter into these types of contracts in 2002. During 2001, the amount of cash flow hedge gains associated with these contracts that were reclassified to earnings because it became probable that the original forecasted transactions would not occur was $1,034 which amount is included in other income. During 2002, in order to reduce our interest rate risk associated with forecasted issuances of fixed-rate debt, we entered into interest rate protection agreements ("IRPAs") which have been designated and qualify as cash flow hedges. Included in accumulated other comprehensive loss at September 30, 2002 are net after-tax losses of $2,774 from settled and unsettled IRPAs associated with forecasted issuances of debt. The amount of this net loss expected to be reclassified into net income during the next twelve months is not material. The fair value of our unsettled IRPAs was a loss of $1,205 at September 30, 2002 which is included in other current liabilities on the Consolidated Balance Sheet. These IRPAs hedge interest rate risk associated with forecasted issuances of debt to occur during Fiscal 2003. We did not have any derivative instruments outstanding at September 30, 2001. During 2002 and 2001, there were no gains or losses from 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. 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 delivery of natural gas, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although F-13 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) many of these contracts have the requisite elements of a derivative instrument, these contracts are not subject to the accounting requirements of SFAS 133 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. COMPREHENSIVE INCOME Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive loss of $(2,774) for the year ended September 30, 2002 is the result of losses on IRPAs qualifying as hedges. The Company's comprehensive income was the same as net income for the years ended September 30, 2001 and 2000. ADOPTION OF SFAS 142 Effective October 1, 2001, we early adopted the provisions of SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 142 addresses the financial accounting and reporting for acquired goodwill and other intangible assets and supersedes Accounting Principles Board ("APB") Opinion No. 17, "Intangible Assets." SFAS 142 addresses the financial accounting and reporting for intangible assets acquired individually or with a group of other assets (excluding those acquired in a business combination) at acquisition and also addresses the financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under SFAS 142, an intangible asset is amortized over its useful life unless that life is determined to be indefinite. Goodwill and other intangible assets with indefinite lives are not amortized but are subject to tests for impairment at least annually. Because we do not have significant intangible assets or goodwill resulting from prior business combinations, the adoption of SFAS 142 did not impact our results of operations or financial position. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS The Financial Accounting Standards Board ("FASB") recently issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"); SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"); SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" ("SFAS 145"); and SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 143 addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with a corresponding increase in the carrying value of the related asset. Entities shall subsequently charge the retirement cost to expense using a systematic and rational method over the related asset's useful life and adjust the fair value of the liability resulting from the passage of time through charges to operating expense. We adopted SFAS 143 effective October 1, 2002. The adoption of SFAS 143 did not have a material effect on our financial position or results of operations. F-14 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," as it relates to the disposal of a segment of a business. SFAS 144 establishes a single accounting model for long-lived assets to be disposed of based upon the framework of SFAS 121, and resolves significant implementation issues of SFAS 121. We adopted SFAS 144 effective October 1, 2002. The adoption of SFAS 144 did not affect our financial position or results of operations. SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"), effective for fiscal years beginning after May 15, 2002. SFAS 4 had required that material gains and losses on extinguishment of debt be classified as an extraordinary item. Under SFAS 145, it is less likely that a gain or loss on extinguishment of debt would be classified as an extraordinary item in the Consolidated Statement of Income. Among other things, SFAS 145 also amends SFAS No. 13, "Accounting for Leases," to require that certain lease modifications that have economic effects similar to sale-leaseback transactions be accounted for in the same manner as sale-leaseback transactions. The provisions of SFAS 145 relating to leases were effective for transactions occurring after May 15, 2002. The application of SFAS 145 did not affect our financial position or results of operations during 2002. SFAS 146 addresses accounting for costs associated with exit or disposal activities and replaces the guidance in Emerging Issues Task Force ("EITF") No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." Generally, SFAS 146 requires that a liability for costs associated with an exit or disposal activity, including contract termination costs, employee termination benefits and other associated costs, be recognized when the liability is incurred. Under EITF No. 94-3, a liability was recognized at the date an entity committed to an exit plan. SFAS 146 will be effective for disposal activities initiated after December 31, 2002. 2. UTILITY REGULATORY MATTERS Gas Utility Gas Competition Act. On June 22, 1999, the Gas Competition Act was signed into law. The purpose of the Gas Competition Act is to provide all natural gas consumers in Pennsylvania with the ability to purchase their gas supplies from the supplier of their choice. Under the Gas Competition Act, local gas distribution companies ("LDCs") like Gas Utility may continue to sell gas to customers, and such sales of gas, as well as distribution services provided by LDCs, continue to be subject to price regulation by the PUC. LDCs serve as the supplier of last resort for all residential and small commercial and industrial ("core-market") customers unless the PUC approves another supplier of last resort. The Gas Competition Act requires energy marketers seeking to serve customers of LDCs to accept assignment of a portion of the LDC's pipeline capacity and storage contracts at contract rates, thus avoiding the creation of stranded costs. After July 1, 2002, a natural gas supplier may petition the PUC to avoid such contract release or F-15 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) assignment. However, such petition may be granted only if the LDC fully recovers the cost of contracts. The Gas Competition Act, in conjunction with a companion bill, eliminated the gross receipts tax on sales of gas effective January 1, 2000. On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas Utility's restructuring plan filed by Gas Utility pursuant to the Gas Competition Act. Among other things, the implementation of the Gas Restructuring Order resulted in an increase in Gas Utility's core-market base rates effective October 1, 2000. This base rate increase was designed to generate approximately $16,700 in additional net annual revenues. In accordance with the Gas Restructuring Order, Gas Utility reduced its core-market PGC rates by an annualized amount of $16,700 in the first 14 months following the October 1, 2000 base rate increase. Effective December 1, 2001, Gas Utility was required to reduce its core-market PGC rates by amounts equal to the margin it receives from interruptible customers using pipeline capacity contracted by Gas Utility for core-market customers. As a result, beginning December 31, 2001, Gas Utility operating results are more sensitive to the effects of heating-season weather and less sensitive to the market prices of alternative fuels. Transfer of Assets. On May 24, 2001, the PUC approved Gas Utility's application for approval to transfer its liquefied natural gas ("LNG") and propane air ("LP") facilities, along with related assets, to an unregulated affiliate, Energy Services, Inc. ("Energy Services"), a second-tier wholly owned subsidiary of UGI. The associated reduction in Gas Utility's base rates, adjusted for the impact of the transfer on net operating expenses, is not expected to have a material effect on our results of operations. Gas Utility transferred the LNG and LP assets, which had a net book value of $4,277, on September 30, 2001. The transfer is reflected as a dividend of net assets in the 2001 Consolidated Statement of Stockholder's Equity. Electric Utility Electric Utility Restructuring Order. On June 19, 1998, the PUC entered its Opinion and Order ("Electricity Restructuring Order") in Electric Utility's restructuring proceeding pursuant to the Electricity Choice Act. Under the terms of the Electricity Restructuring Order, Electric Utility was authorized to recover $32,500 in stranded costs (on a full revenue requirements basis which includes all income and gross receipts taxes) over a four-year period beginning January 1, 1999 through a Competitive Transition Charge ("CTC") (together with carrying charges on unrecovered balances of 7.94%) and to charge unbundled rates for generation, transmission and distribution services. Stranded costs are electric generation-related costs that traditionally would be recoverable in a regulated environment but may not be recoverable in a competitive electric generation market. Electric Utility's recoverable stranded costs included $8,692 for the buy-out of a 1993 power purchase agreement with an independent power producer. Under the terms of the Electricity Restructuring Order and in accordance with the Electricity Choice Act, Electric Utility generally could not increase the generation component of prices during the period that stranded costs were being recovered through the CTC. Since January 1, 1999, all of Electric Utility's customers have been permitted to choose an alternative generation supplier. Customers choosing an alternative supplier during the stranded cost recovery period received a "shopping credit." F-16 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The PUC approved a settlement establishing rules for Electric Utility Provider of Last Resort ("POLR") service on March 28, 2002 and a separate settlement that modified these rules on June 13, 2002 (collectively the "POLR Settlement") under which Electric Utility terminated stranded cost recovery through its CTC from commercial and industrial ("C&I") customers on July 31, 2002, and from residential customers on October 31, 2002, and is no longer subject to the statutory rate caps as of August 1, 2002 for C&I customers and as of November 1, 2002 for residential customers. Charges for generation service will (1) initially be set at a level equal to the rates paid by Electric Utility customers for POLR service under the statutory rate caps; (2) may be raised at certain designated times up to certain specified caps through December 2004; and (3) may be set at market rates thereafter. Electric Utility may also offer multiple-year POLR contracts to its customers. The POLR Settlement provides 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. C&I 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. Formation of Hunlock Creek Energy Ventures. On December 8, 2000, UGID contributed its coal-fired Hunlock Creek generating station ("Hunlock") and certain related assets having a net book value of $4,214, and $6,000 in cash, to Energy Ventures, a general partnership jointly owned by the Company and a subsidiary of Allegheny Energy, Inc. ("Allegheny"). The contribution was recorded at its carrying value and no gain was recognized by the Company. Also on December 8, 2000, Allegheny contributed a newly constructed, gas-fired combustion turbine generator to be operated at the Hunlock site. Under the terms of our arrangement with Allegheny, each partner is entitled to purchase 50% of the output of the joint venture at cost. Total purchases from Energy Ventures in 2002 and 2001 were $9,751 and $7,966, respectively. At September 30, 2002 and 2001, the carrying amounts of our investment in Energy Ventures were $10,017 and $10,832, respectively, which amounts are included in other assets in the Consolidated Balance Sheets. Regulatory Assets and Liabilities The following regulatory assets and liabilities are included in our accompanying balance sheets at September 30:
- ----------------------------------------------------------- 2002 2001 - ----------------------------------------------------------- Regulatory assets: Income taxes recoverable $ 54,727 $ 51,761 Power agreement buy-out - 1,338 Other postretirement benefits 2,397 2,633 Deferred fuel costs 4,304 - Other 561 423 - ----------------------------------------------------------- Total regulatory assets $ 61,989 $ 56,155 - ----------------------------------------------------------- Regulatory liabilities: Other postretirement benefits $ 4,332 $ 4,339 Deferred fuel costs - 2,752 - ----------------------------------------------------------- Total regulatory liabilities $ 4,332 $ 7,091 - -----------------------------------------------------------
F-17 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The Company's regulatory liabilities are included in "other current liabilities" and "other noncurrent liabilities" on the Consolidated Balance Sheets. The Company's regulatory assets do not earn a return. 3. DEBT Long-term debt comprises the following at September 30:
- ----------------------------------------------------------------------------------------------------- 2002 2001 - ----------------------------------------------------------------------------------------------------- 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 6.73% Notes, due October 2002 26,000 26,000 6.62% Notes, due May 2005 20,000 20,000 7.14% Notes, due December 2005 (including unamortized premium of $392 and $533, respectively, effective rate - 6.64%) 30,392 30,533 7.14% Notes, due December 2005 20,000 20,000 5.53% Notes due September 2012 40,000 - 6.50% Senior Notes, due August 2003 (less unamortized discount of $23 and $56, respectively) 49,977 49,944 - ----------------------------------------------------------------------------------------------------- Total long-term debt 248,369 208,477 Less current maturities (76,000) - - ----------------------------------------------------------------------------------------------------- Long-term debt due after one year $172,369 $208,477 - -----------------------------------------------------------------------------------------------------
Scheduled principal repayments of long-term debt for each of the next five fiscal years ending September 30 are as follows: 2003 - $76,000; 2004 - $0; 2005 - $20,000; 2006 - $50,000; 2007 - $20,000. At September 30, 2002, UGI Utilities had revolving credit agreements with four banks providing for borrowings of up to $97,000. These agreements expire at various dates through September 2005. UGI Utilities may borrow at various prevailing interest rates, including LIBOR. UGI Utilities pays quarterly commitment fees on these credit lines. UGI Utilities had borrowings under these agreements totaling $37,200 at September 30, 2002 and $57,800 at September 30, 2001, which we classify as bank loans. The weighted-average interest rates on bank loans were 2.35% at September 30, 2002 and 3.75% at September 30, 2001. 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, 2002, UGI Utilities was in compliance with its financial covenants. F-18 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 4. INCOME TAXES The provisions for income taxes consist of the following:
- ------------------------------------------------------------------------------------------- 2002 2001 2000 - ------------------------------------------------------------------------------------------- Current expense: Federal $ 13,341 $ 25,344 $ 22,721 State 5,115 8,103 6,819 - ------------------------------------------------------------------------------------------- Total current expense 18,456 33,447 29,540 Deferred (benefit) expense 11,512 (1,618) 3,264 Investment tax credit amortization (398) (398) (398) - ------------------------------------------------------------------------------------------- Total income tax expense $ 29,570 $ 31,431 $ 32,406 - -------------------------------------------------------------------------------------------
A reconciliation from the statutory federal tax rate to our effective tax rate is as follows:
- ------------------------------------------------------------------------------------------- 2002 2001 2000 - ------------------------------------------------------------------------------------------- Statutory federal tax rate 35.0% 35.0% 35.0% Difference in tax rate due to: State income taxes, net of federal benefit 6.3 6.5 6.1 Deferred investment tax credit amortization (0.5) (0.5) (0.5) Other, net (0.7) (1.5) (1.5) - ------------------------------------------------------------------------------------------- Effective tax rate 40.1% 39.5% 39.1% - -------------------------------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September 30:
- ------------------------------------------------------------------------------------------- 2002 2001 - ------------------------------------------------------------------------------------------- Excess book basis over tax basis of property, plant and equipment $ 107,627 $ 99,928 Regulatory assets 25,108 23,301 Employee-related expenses 10,546 8,901 Other 777 804 - ------------------------------------------------------------------------------------------- Gross deferred tax liabilities 144,058 132,934 - ------------------------------------------------------------------------------------------- Deferred investment tax credits (3,479) (3,644) Employee-related expenses (6,371) (6,067) Power purchase agreement liability (515) (1,487) Accumulated other comprehensive loss (1,968) - Other (2,852) (5,373) - ------------------------------------------------------------------------------------------- Gross deferred tax assets (15,185) (16,571) - ------------------------------------------------------------------------------------------- Net deferred tax liabilities $ 128,873 $116,363 - -------------------------------------------------------------------------------------------
UGI Utilities had recorded deferred tax liabilities of approximately $35,498 as of September 30, 2002 and $33,928 as of September 30, 2001 pertaining to utility temporary differences, principally F-19 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) a result of accelerated tax depreciation, 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 $3,479 at September 30, 2002 and $3,644 at September 30, 2001, pertaining to utility deferred investment tax credits. UGI Utilities had recorded regulatory income tax assets related to these net deferred taxes of $54,727 as of September 30, 2002 and $51,761 as of September 30, 2001. 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 retirees and a limited number of active employees meeting certain age and service requirements, and postretirement life insurance benefits to nearly all active and retired employees. F-20 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following provides a reconciliation of benefit obligations, plan assets, and funded status of the plans as of September 30:
- ------------------------------------------------------------------------------------------------- Pension Other Postretirement Benefits Benefits ----------------------- --------------------- 2002 2001 2002 2001 - ------------------------------------------------------------------------------------------------- CHANGE IN BENEFIT OBLIGATIONS: Benefit obligations - beginning of year $ 165,154 $ 150,952 $ 18,179 $ 16,939 Service cost 3,582 3,085 90 75 Interest cost 12,480 12,076 1,474 1,390 Actuarial loss 18,589 7,901 5,051 1,404 Plan amendments 395 - - - Benefits paid (9,327) (8,860) (1,397) (1,629) - ------------------------------------------------------------------------------------------------- Benefit obligations - end of year $ 190,873 $ 165,154 $ 23,397 $ 18,179 - ------------------------------------------------------------------------------------------------- CHANGE IN PLAN ASSETS: Fair value of plan assets - beginning of year $ 183,736 $ 223,524 $ 6,994 $ 6,411 Actual return on plan assets (8,345) (30,928) 144 190 Employer contributions - - 2,105 2,022 Benefits paid (9,327) (8,860) (1,397) (1,629) - ------------------------------------------------------------------------------------------------- Fair value of plan assets - end of year $ 166,064 $ 183,736 $ 7,846 $ 6,994 - ------------------------------------------------------------------------------------------------- Funded status of the plans $ (24,809) $ 18,582 $ (15,551) $(11,185) Unrecognized net actuarial loss 50,190 4,166 5,945 632 Unrecognized prior service cost 3,038 3,337 - - Unrecognized net transition (asset) obligation (3,004) (4,634) 7,059 7,743 - ------------------------------------------------------------------------------------------------- Prepaid (accrued) benefit cost - end of year $ 25,415 $ 21,451 $ (2,547) $ (2,810) - ------------------------------------------------------------------------------------------------- ASSUMPTIONS AS OF SEPTEMBER 30: Discount rate 6.8% 7.7% 6.8% 7.7% Expected return on plan assets 9.5% 9.5% 6.0% 6.0% Rate of increase in salary levels 4.5% 4.5% 4.5% 4.5% - -------------------------------------------------------------------------------------------------
Included in the end of year pension benefit obligations above are $13,955 at September 30, 2002 and $10,544 at September 30, 2001 relating to employees of UGI and certain of its other subsidiaries. Included in the end of year postretirement obligations above are $649 at September 30, 2002 and $471 at September 30, 2001 relating to employees of UGI and certain of its other subsidiaries. F-21 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Net periodic pension and other postretirement benefit costs relating to UGI Utilities employees include the following components:
- --------------------------------------------------------------------------------------------------------------------------- Pension Other Postretirement Benefits Benefits ------------------------------------- ------------------------------- 2002 2001 2000 2002 2001 2000 - --------------------------------------------------------------------------------------------------------------------------- Service cost $ 3,193 $ 2,785 $ 2,898 $ 84 $ 82 $ 70 Interest cost 11,600 11,319 11,090 1,453 1,326 1,168 Expected return on assets (17,778) (17,766) (16,010) (366) (366) (252) Amortization of: Transition (asset) obligation (1,518) (1,530) (1,534) 680 679 680 Prior service cost 646 625 626 - - - Actuarial gain (loss) - (1,104) - 20 - - - --------------------------------------------------------------------------------------------------------------------------- Net benefit cost (income) (3,857) (5,671) (2,930) 1,871 1,721 1,666 Change in regulatory assets and liabilities - - - 1,228 1,378 1,433 - --------------------------------------------------------------------------------------------------------------------------- Net expense (income) $ (3,857) $ (5,671) $ (2,930) $ 3,099 $ 3,099 $ 3,099 - ---------------------------------------------------------------------------------------------------------------------------
UGI Utilities Pension Plan assets are held in trust and consist principally of equity and fixed income mutual funds and a commingled bond fund. UGI Common Stock comprised approximately 6% of trust assets at September 30, 2002. Although the UGI Utilities Pension Plan projected benefit obligation exceeded plan assets at September 30, 2002, plan assets exceeded accumulated benefit obligation by $7,154. Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary Employees' Beneficiary Association ("VEBA") trust to pay retiree health care and life insurance benefits and to fund the UGI Utilities' postretirement benefit liability. UGI Utilities is required to fund its postretirement benefit obligations 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." The difference between such amounts and amounts included in UGI Utilities' rates is deferred for future recovery from, or refund to, ratepayers. VEBA investments consist principally of money market funds. The assumed health care cost trend rates are 12.0% for fiscal 2003, decreasing to 5.5% in fiscal 2010. A one percentage point change in the assumed health care cost trend rate would change the 2002 postretirement benefit cost and obligation as follows:
- -------------------------------------------------------------------------- 1% 1% Increase Decrease - -------------------------------------------------------------------------- Effect on total service and interest costs $ 87 $ (77) Effect on postretirement benefit obligation 1,345 (1,192) - --------------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key employees. At September 30, 2002 and 2001, the projected benefit obligations of these plans were not material. We recorded expense for these plans of $269 in 2002, $235 in 2001 and $131 in 2000. 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 F-22 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) before-tax and after-tax basis. We may, at our discretion, match a portion of participants' contributions. The cost of benefits under the savings plans totaled $932 in 2002, $936 in 2001, and $948 in 2000. 6. INVENTORIES Inventories comprise the following at September 30:
- ------------------------------------------------------- 2002 2001 - ------------------------------------------------------- Utility fuel and gases $ 36,208 $ 45,628 Appliances for sale 480 599 Materials, supplies and other 1,966 1,847 - ------------------------------------------------------- Total inventories $ 38,654 $ 48,074 - -------------------------------------------------------
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, 2002 and 2001, we had outstanding 200,000 shares of $7.75 Series cumulative preferred stock. We are required to establish a sinking fund to redeem on October 1 in each year, commencing October 1, 2004, 10,000 shares of our $7.75 Series at a price of $100 per share. The $7.75 Series is redeemable, in whole or in part, at our option on or after October 1, 2004, at a price of $100 per share. All outstanding shares of $7.75 Series are subject to mandatory redemption on October 1, 2009, at a price of $100 per share. 8. COMMITMENTS AND CONTINGENCIES We lease various buildings and transportation, computer and office equipment 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 $4,690 in 2002, $4,624 in 2001 and $4,594 in 2000. 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: 2003 - $2,819; 2004 - $2,579; 2005 - $2,139; 2006 - $1,812; 2007 - $1,554; after 2007 - $3,961. Gas Utility has gas supply agreements with producers and marketers with terms of less than one year. Gas Utility also has agreements for firm pipeline transportation and storage capacity which Gas Utility may terminate at various dates through 2015. Gas Utility's costs associated with F-23 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) transportation and storage capacity 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. 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 December 2006. Future contractual cash obligations under Gas Utility and Electric Utility supply agreements existing at September 30, 2002 are as follows: 2003 - $106,400; 2004 - $96,532; 2005 - $56,865; 2006 - $23,255; 2007 - $14,856; after 2007 - $92,446. 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 (1) MGPs were formerly operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or private parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating two 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 operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that the subsidiary's separate corporate form should be disregarded. UGI Utilities has filed suit against more than fifty insurance companies alleging that the defendants breached contracts of insurance by failing to indemnify UGI Utilities for certain environmental costs. The suit seeks to recover more than $11,000 in such costs. During 2002, 2001, and 2000, UGI Utilities entered into settlement agreements with several of the insurers and recorded pretax income of $390, $943 and $4,500, respectively, which amounts are included in operating and administrative expenses in the Consolidated Statements of Income. F-24 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) In addition to these environmental matters, there are other pending claims and legal actions arising in the normal course of our businesses. We cannot predict with certainty the final results of environmental and other matters. However, it is reasonably possible that some of them could be resolved unfavorably to us. We 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 but 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 The carrying amounts of financial instruments included in current assets and current liabilities (excluding current maturities of long-term debt) approximate their fair values because of their short-term nature. The estimated fair value of our long-term debt is approximately $263,000 at September 30, 2002 and $218,000 at September 30, 2001. 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. The estimated fair value of our Series Preferred Stock is approximately $20,400 at September 30, 2002 and $21,400 at September 30, 2001. We estimated the fair value of our Series Preferred Stock 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, 2002 and 2001, we had no significant concentrations of credit risk. F-25 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 comprising Electric Utility and our electricity generation business. 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 earnings before income taxes. No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments' revenues are derived from sources within the United States, and all of our reportable segments' long-lived assets are located in the United States. Financial information by business segment follows:
- ------------------------------------------------------------------------- Gas Electric Total Utility Operations - ------------------------------------------------------------------------- 2002 Revenues $ 490,552 $ 404,519 $ 86,033 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 - ------------------------------------------------------------------------- 2001 Revenues $ 584,762 $ 500,832 $ 83,930 Depreciation and amortization 23,767 20,171 3,596 Operating income 98,556 87,846 10,710 Interest expense 18,988 16,258 2,730 Income before income taxes 79,568 71,588 7,980 Total assets 784,409 678,947 105,462 Capital expenditures 36,783 31,757 5,026 - ------------------------------------------------------------------------- 2000 Revenues $ 436,942 $ 359,041 $ 77,901 Depreciation and amortization 23,612 19,098 4,514 Operating income 101,235 86,178 15,057 Interest expense 18,353 16,175 2,178 Income before income taxes 82,882 70,003 12,879 Total assets 751,137 653,766 97,371 Capital expenditures 36,391 31,665 4,726 - -------------------------------------------------------------------------
F-26 UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 11. 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, 2001 2000 2002 2001 2002 2001 2002 2001 - ----------------------------------------------------------------------------------------------------- Revenues $ 141,481 $ 166,503 $ 179,945 $ 231,591 $ 88,249 $ 103,772 $ 80,877 $ 82,896 Operating income 27,609 33,463 41,319 46,500 13,222 12,745 8,167 5,848 Net income 14,045 17,095 22,549 25,156 5,552 4,990 1,949 896 - -----------------------------------------------------------------------------------------------------
12. OTHER INCOME, NET Other income, net, comprises the following:
- --------------------------------------------------------------------- 2002 2001 2000 - --------------------------------------------------------------------- Non-tariff service income $ 5,701 $ 5,410 $ 3,182 Pension income 3,858 5,671 2,930 Interest income 1,110 235 2,860 Other 1,054 3,795 3,688 - --------------------------------------------------------------------- $ 11,723 $ 15,111 $ 12,660 - ---------------------------------------------------------------------
13. RELATED PARTY TRANSACTIONS UGI bills UGI Utilities for an allocated share of its general corporate expenses. This allocation is based upon a three-factor formula which includes revenues, costs and expenses, and net assets. These billed expenses are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income. 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, 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) YEAR ENDED SEPTEMBER 30, 2001 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 2,061 $ 8,269 $ (7,179)(1) $ 3,151 ========== ========= Other reserves (3) $ 1,954 $ 1,696 $ (276)(2) $ 3,467 ========== ========= 93 (4) YEAR ENDED SEPTEMBER 30, 2000 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 1,716 $ 4,386 $ (4,041)(1) $ 2,061 ========== ========= Other reserves (3) $ 1,345 $ 1,007 $ (455)(2) $ 1,954 ========== ========= 57 (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 - ----------- ----------- 3.2 Bylaws in effect since September 24, 2002 10.25 Storage Transportation Service Agreement (Rate Schedule SST) between Utilities and Columbia dated November 1, 1993, as modified pursuant to orders of the Federal Energy Regulatory Commission 10.26 No-Notice Transportation Service Agreement (Rate Schedule NTS) between Utilities and Columbia dated November 1, 1993, as modified pursuant to orders of the Federal Energy Regulatory Commission 10.27 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 10.28 No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern 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 FT-1) between Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission 10.30 Firm Transportation Service Agreement (Rate Schedule FT-1) between Utilities and Texas Eastern Transmission dated October 31, 2000, as modified pursuant to various orders of the Federal Energy Regulatory Commission 10.31 Firm Transportation Service Agreement (Rate Schedule FT) between Utilities and Transcontinental Gas Pipe Line dated October 1, 1996, as modified pursuant to various orders of the Federal Energy Regulatory Commission
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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 99 Certification by Chief Executive Officer and Chief Financial Officer
-53- EX-3.2 3 w66595exv3w2.txt BYLAWS IN EFFECT SINCE SEPTEMBER 24, 2002 Exhibit 3.2 BYLAWS OF UGI UTILITIES, INC. (A PENNSYLVANIA REGISTERED CORPORATION) ARTICLE I OFFICES AND FISCAL YEAR SECTION 1.01. REGISTERED OFFICE. The registered office of the corporation in the Commonwealth of Pennsylvania shall be at Valley Forge, Pennsylvania, until otherwise established by an amendment of the articles or by the board of directors and a record of such change is filed with the Department of State in the manner provided by law. SECTION 1.02. OTHER OFFICES. The corporation may also have offices at such other places within or without Pennsylvania as the board of directors may from time to time appoint or the business of the corporation may require. SECTION 1.03. FISCAL YEAR. The fiscal year of the corporation shall begin on the first day of October in each year. ARTICLE II NOTICE - WAIVERS - MEETINGS GENERALLY SECTION 2.01. MANNER OF GIVING NOTICE. (a) General Rule. Whenever written notice is required to be given to any person under the provisions of the Business Corporation Law or by the articles or these bylaws, it may be given to the person either personally or by sending a copy thereof by first class or express mail, postage prepaid, or by telegram (with messenger service specified), telex or TWX (with answerback received) or courier service, charges prepaid, or by telecopier, to the address (or to the telex, TWX, telecopier or telephone number) of the person appearing on the books of the corporation or, in the case of directors, supplied by the director to the corporation for the purpose of notice. If the notice is sent by mail, telegraph or courier service, it shall be deemed to have been given to the person entitled thereto when deposited in the United States mail or with a telegraph office or courier service for delivery to that person or, in the case of telex or TWX, when dispatched or, in the case of telecopier, when received. A notice of meeting shall specify the place, day and hour of the meeting and any other information required by any other provision of the Business Corporation Law, the articles or these bylaws. (b) Adjourned Shareholder Meetings. When a meeting of shareholders is adjourned, it shall not be necessary to give any notice of the adjourned meeting or of the business to be transacted at an adjourned meeting, other than by announcement at the meeting at which the adjournment is taken, unless the board fixes a new record date for the adjourned meeting. SECTION 2.02. NOTICE OF MEETINGS OF BOARD OF DIRECTORS. Notice of a regular meeting of the board of directors need not be given. Notice of every special meeting of the board of directors shall be given to each director by telephone or in writing at least 24 hours (in the case of notice by telephone, facsimile transmission, e-mail, or other electronic communication) or 48 hours (in the case of notice by telegraph, courier service or express mail) or five days (in the case of notice by first class mail) before the time at which the meeting is to be held. Every such notice shall state the time and place of the meeting. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the board need be specified in a notice of the meeting. SECTION 2.03. NOTICE OF MEETINGS OF SHAREHOLDERS. Written notice of every meeting of the shareholders shall be given by, or at the direction of, the secretary to each shareholder of record entitled to vote at the meeting at least (10) ten days prior to the day named for a meeting called to consider amendment of the articles or adoption of a plan of merger, consolidation, exchange, asset transfer, division or conversion or adoption of a proposal of dissolution or (2) five days prior to the day named for the meeting in any other case. If the secretary neglects or refuses to give notice of a meeting, the person or persons calling the meeting may do so. In the case of a special meeting of shareholders, the notice shall specify the general nature of the business to be transacted. SECTION 2.04. WAIVER OF NOTICE. (a) Written Waiver. Whenever any written notice is required to be given under the provisions of the Business Corporation Law, the articles or these bylaws, a waiver thereof in writing, signed by the person or persons entitled to the notice, whether before or after the time stated therein, shall be deemed equivalent to the giving of the notice. Except as otherwise required by this subsection, neither the business to be transacted at, nor the purpose of, a meeting need be specified in the waiver of notice of the meeting. In the case of a special meeting of shareholders, the waiver of notice shall specify the general nature of the business to be transacted. (b) Waiver by Attendance. Attendance of a person at any meeting shall constitute a waiver of notice of the meeting except where a person attends a meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting was not lawfully called or convened. SECTION 2.05. MODIFICATION OF PROPOSAL CONTAINED IN NOTICE. Whenever the language of a proposed resolution is included in a written notice of a meeting required to be given under the provisions of the Business Corporation Law or the articles or these bylaws, the meeting considering the resolution may without further notice adopt it with such clarifying or other amendments as do not enlarge its original purpose. -2- SECTION 2.06. EXCEPTION TO REQUIREMENT OF NOTICE. (a) General Rule. Whenever any notice or communication is required to be given to any person under the provisions of the Business Corporation Law or by the articles or these bylaws or by the terms of any agreement or other instrument or as a condition precedent to taking any corporate action and communication with that person is then unlawful, the giving of the notice or communication to that person shall not be required. (b) Shareholders Without Forwarding Addresses. Notice or other communications shall not be sent to any shareholder with whom the corporation has been unable to communicate for more than 24 consecutive months because communications to the shareholder are returned unclaimed or the shareholder has otherwise failed to provide the corporation with a current address. Whenever the shareholder provides the corporation with a current address, the corporation shall commence sending notices and other communications to the shareholder in the same manner as to other shareholders. SECTION 2.07. USE OF CONFERENCE TELEPHONE AND SIMILAR EQUIPMENT. Any director may participate in any meeting of the board of directors, and the board of directors may provide by resolution with respect to a specific meeting or with respect to a class of meetings that one or more persons may participate in a meeting of the shareholders of the corporation, by means of conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other. Participation in a meeting pursuant to this section shall constitute presence in person at the meeting. ARTICLE III SHAREHOLDERS SECTION 3.01. PLACE OF MEETING. All meetings of the shareholders of the corporation shall be held at the registered office of the corporation unless another place is designated by the board of directors in the notice of a meeting. SECTION 3.02. ANNUAL MEETING. The board of directors may fix and designate the date and time of the annual meeting of the shareholders, but if no such date and time is fixed and designated by the board, the meeting for any calendar year shall be held on the first Tuesday in March in such year, if not a legal holiday under the laws of Pennsylvania, and, if a legal holiday, then on the next succeeding business day, not a Saturday, at 10:00 o'clock A.M., and at said meeting the shareholders then entitled to vote shall elect directors and shall transact such other business as may properly be brought before the meeting. If the annual meeting shall not have been called and held within six months after the designated time, any shareholder may call the meeting at any time thereafter. -3- SECTION 3.03. SPECIAL MEETINGS. Special meetings of the shareholders may be called at any time by the chief executive officer or by the board of directors. At any time, upon written request of any person or persons who have duly called a special meeting, which written request shall state the object of the meeting, it shall be the duty of the secretary to fix the date, time and place of the meeting. The date fixed by the Secretary shall not be less than five nor more than 60 days after the receipt of the request. SECTION 3.04. QUORUM AND ADJOURNMENT. (a) General Rule. A meeting of shareholders of the corporation duly called shall not be organized for the transaction of business unless a quorum is present. The presence of shareholders entitled to cast at least a majority of the votes that all shareholders are entitled to cast on a particular matter to be acted upon at the meeting shall constitute a quorum for the purposes of consideration and action on the matter. Shares of the corporation owned, directly or indirectly, by it and controlled, directly or indirectly, by the board of directors of this corporation, as such, shall not be counted in determining the total number of outstanding shares for quorum purposes at any given time. (b) Withdrawal of a Quorum. The shareholders present at a duly organized meeting can continue to do business until adjournment notwithstanding the withdrawal of enough shareholders to leave less than a quorum. (c) Adjournments Generally. Any regular or special meeting of the shareholders, including one at which directors are to be elected and one which cannot be organized because a quorum has not attended, may be adjourned for such period and to such place as the shareholders present and entitled to vote shall direct. (d) Electing Directors at Adjourned Meeting. Those shareholders entitled to vote who attend a meeting called for the election of directors that has been previously adjourned for lack of a quorum, although less than a quorum as fixed in this section, shall nevertheless constitute a quorum for the purpose of electing directors. (e) Other Action in Absence of Quorum. Those shareholders entitled to vote who attend a meeting of shareholders that has been previously adjourned for one or more periods aggregating at least 15 days because of an absence of a quorum, although less than a quorum as fixed in this section, shall nevertheless constitute a quorum for the purpose of acting upon any matter set forth in the notice of the meeting if the notice states that those shareholders who attend the adjourned meeting shall nevertheless constitute a quorum for the purpose of acting upon the matter. -4- SECTION 3.05. ACTION BY SHAREHOLDERS. (a) General Rule. Except as otherwise provided in the Business Corporation Law or the articles or these bylaws, whenever any corporate action is to be taken by vote of the shareholders of the corporation, it shall be authorized by a majority of the votes cast at a duly organized meeting of shareholders by the holders of shares entitled to vote thereon. Except when acting by unanimous consent to remove a director or directors, the shareholders of the corporation may act only at a duly organized meeting. (b) Interested Shareholders. Any merger or other transaction authorized under 15 Pa.C.S. Subchapter 19C between the corporation or subsidiary thereof and a shareholder of this corporation, or any voluntary liquidation authorized under 15 Pa.C.S. Subchapter 19F in which a shareholder is treated differently from other shareholders of the same class (other than any dissenting shareholders), shall require the affirmative vote of the shareholders entitled to cast at least a majority of the votes that all shareholders other than the interested shareholder are entitled to cast with respect to the transaction, without counting the vote of the interested shareholder. For the purposes of the preceding sentence, interested shareholder shall include the shareholder who is a party to the transaction or who is treated differently from other shareholders and any person, or group of persons, that is acting jointly or in concert with the interested shareholder and any person who, directly or indirectly, controls, is controlled by or is under common control with the interested shareholder. An interested shareholder shall not include any person who, in good faith and not for the purpose of circumventing this subsection, is an agent, bank, broker, nominee or trustee for one or more other persons, to the extent that the other person or persons are not interested shareholders. (c) Exceptions. Subsection (b) shall not apply to a transaction: (1) that has been approved by a majority vote of the board of directors without counting the vote of directors who: (i) are directors or officers of, or have a material equity interest in, the interested shareholder; or (ii) were nominated for election as a director by the interested shareholder, and first elected as a director, within 24 months of the date of the vote on the proposed transaction; or (2) in which the consideration to be received by the shareholders for shares of any class of which shares are owned by the interested shareholder is not less than the highest amount paid by the interested shareholder in acquiring shares of the same class. -5- (d) Additional Approvals. The approvals required by subsection (b) shall be in addition to, and not in lieu of, any other approval required by the Business Corporation Law, the articles or these bylaws, or otherwise. SECTION 3.06. ORGANIZATION. At every meeting of the shareholders, the chairman of the board, if there be one, or, in the case of vacancy in office or absence of the chairman of the board, one of the following officers present in the order stated: the vice chairman of the board, if there be one, the president, the vice presidents in their order of rank and seniority, or a person chosen by vote of the shareholders present, shall act as chairman of the meeting. The secretary, or in the absence of the secretary, an assistant secretary, or, in the absence of both the secretary and assistant secretaries, a person appointed by the chairman of the meeting, shall act as secretary of the meeting. SECTION 3.07. VOTING RIGHTS OF SHAREHOLDERS. Unless otherwise provided in the articles, every shareholder of the corporation shall be entitled to one vote for every share standing in the name of the shareholder on the books of the corporation. SECTION 3.08. VOTING AND OTHER ACTION BY PROXY. (a) General Rule. (1) Every shareholder entitled to vote at a meeting of shareholders may authorize another person to act for the shareholder by proxy. (2) The presence of, or vote or other action at a meeting of shareholders by a proxy of a shareholder shall constitute the presence of, or vote or action by the shareholder. (3) Where two or more proxies of a shareholder are present, the corporation shall, unless otherwise expressly provided in the proxy, accept as the vote of all shares represented thereby the vote cast by a majority of them and, if a majority of the proxies cannot agree whether the shares represented shall be voted or upon the manner of voting the shares, the voting of the shares shall be divided equally among those persons. (b) Minimum Requirements. Every proxy shall be executed in writing by the shareholder or by the duly authorized attorney-in-fact of the shareholder and filed with the secretary of the corporation. A proxy, unless coupled with an interest, shall be revocable at will, notwithstanding any other agreement or any provision in the proxy to the contrary, but the revocation of a proxy shall not be effective until written notice thereof has been given to the secretary of the corporation. An unrevoked proxy shall not be valid after three years from the date of its execution unless a longer time is expressly provided therein. A proxy shall not be revoked by the death or incapacity of the maker unless, before the vote is counted or the authority is exercised, written notice of the death or incapacity is given to the secretary of the corporation. -6- (c) Expenses. The corporation shall pay the reasonable expenses of solicitation of votes or proxies of shareholders by or on behalf of the board of directors or its nominees for election to the board including solicitation by professional proxy solicitors and otherwise. SECTION 3.09. VOTING BY FIDUCIARIES AND PLEDGEES. Shares of the corporation standing in the name of a trustee or other fiduciary and shares held by an assignee for the benefit of creditors or by a receiver may be voted by the trustee, fiduciary, assignee or receiver. A shareholder whose shares are pledged shall be entitled to vote the shares until the shares have been transferred into the name of the pledgee, or a nominee of the pledgee, but nothing in this section shall affect the validity of a proxy given to a pledgee or nominee. SECTION 3.10. VOTING BY JOINT HOLDERS OF SHARES. (a) General Rule. Where shares of the corporation are held jointly or as tenants in common by two or more persons, as fiduciaries or otherwise: (1) if only one or more of such persons is present in person or by proxy, all of the shares standing in the names of such persons shall be deemed to be represented for the purpose of determining a quorum and the corporation shall accept as the vote of all the shares the vote cast by a joint owner or a majority of them; and (2) if the persons are equally divided upon whether the shares held by them shall be voted or upon the manner of voting the shares, the voting of the shares shall be divided equally among the persons without prejudice to the rights of the joint owners or the beneficial owners thereof among themselves. (b) Exception. If there has been filed with the secretary of the corporation a copy, certified by an attorney at law to be correct, of the relevant portions of the agreement under which the shares are held or the instrument by which the trust or estate was created or the order of court appointing them or of an order of court directing the voting of the shares, the persons specified as having such voting power in the document latest in date of operative effect so filed, and only those persons, shall be entitled to vote the shares but only in accordance therewith. SECTION 3.11. VOTING BY CORPORATIONS. (a) Voting by Corporate Shareholders. Any corporation that is a shareholder of this corporation may vote at meetings of shareholders of this corporation by any of its officers or agents, or by proxy appointed by any officer or agent, unless some other person, by resolution of the board of directors of the other corporation or a provision of its articles or bylaws, a copy of which resolution or provision certified to be correct by one of its officers has been filed with the secretary of this corporation, is appointed its general or special proxy in which case that person shall be entitled to vote the shares. -7- (b) Controlled Shares. Shares of this corporation owned, directly or indirectly, by it and controlled, directly or indirectly, by the board of directors of this corporation, as such, shall not be voted at any meeting and shall not be counted in determining the total number of outstanding shares for voting purposes at any given time. SECTION 3.12. DETERMINATION OF SHAREHOLDERS OF RECORD. (a) Fixing Record Date. The board of directors may fix a time prior to the date of any meeting of shareholders as a record date for the determination of the shareholders entitled to notice of, or to vote at, the meeting, which time, except in the case of an adjourned meeting, shall be not more than 60 days prior to the date of the meeting of shareholders. Only shareholders of record on the date fixed shall be so entitled notwithstanding any transfer of shares on the books of the corporation after any record date fixed as provided in this subsection. The board of directors may similarly fix a record date for the determination of shareholders of record for any other purpose. When a determination of shareholders of record has been made as provided in this section for purposes of a meeting, the determination shall apply to any adjournment thereof unless the board fixes a new record date for the adjourned meeting. (b) Determination When a Record Date is Not Fixed. If a record date is not fixed: (1) The record date for determining shareholders entitled to notice of or to vote at a meeting of shareholders shall be at the close of business on the day next preceding the day on which notice is given. (2) The record date for determining shareholders for any other purpose shall be at the close of business on the date on which the board of directors adopts the resolution relating thereto. (c) Certification by Nominee. The board of directors may adopt a procedure whereby a shareholder of the corporation may certify in writing to the corporation that all or a portion of the shares registered in the name of the shareholder are held for the account of a specified person or persons. Upon receipt by the corporation of a certification complying with the procedure, the persons specified in the certification shall be deemed, for the purposes set forth in the certification, to be the holders of record of the number of shares specified in place of the shareholder making the certification. SECTION 3.13. VOTING LISTS. (a) General Rule. The officer or agent having charge of the transfer books for shares of the corporation shall make a complete list of the shareholders entitled to vote at any meeting of shareholders, arranged in alphabetical order, with the address of and the number of shares held by each. The list shall be produced and kept open at the time and place of the meeting and shall be subject to the inspection of any shareholder during the whole time of the meeting for the purposes -8- thereof except that, if the corporation has 5,000 or more shareholders, in lieu of the making of the list the corporation may make the information therein available at the meeting by any other means. (b) Effect of List. Failure to comply with the requirements of this section shall not affect the validity of any action taken at a meeting prior to a demand at the meeting by any shareholder entitled to vote thereat to examine the list. The original share register or transfer book, or a duplicate thereof kept in the Commonwealth of Pennsylvania, shall be prima facie evidence as to who are the shareholders entitled to examine the list or share register or transfer book or to vote at any meeting of shareholders. SECTION 3.14. JUDGES OF ELECTION. (a) Appointment. In advance of any meeting of shareholders of the corporation, the board of directors may appoint judges of election, who need not be shareholders, to act at the meeting or any adjournment thereof. If judges of election are not so appointed, the presiding officer of the meeting may, and on the request of any shareholder shall, appoint judges of election at the meeting. The number of judges shall be one or three. A person who is a candidate for an office to be filled at the meeting shall not act as a judge. (b) Vacancies. In case any person appointed as a judge fails to appear or fails or refuses to act, the vacancy may be filled by appointment made by the board of directors in advance of the convening of the meeting or at the meeting by the presiding officer thereof. (c) Duties. The judges of election shall determine the number of shares outstanding and the voting power of each, the shares represented at the meeting, the existence of a quorum, and the authenticity, validity and effect of proxies, receive votes or ballots, hear and determine all challenges and questions in any way arising in connection with nominations by shareholders or the right to vote, count and tabulate all votes, determine the result and do such acts as may be proper to conduct the election or vote with fairness to all shareholders. The judges of election shall perform their duties impartially, in good faith, to the best of their ability and as expeditiously as is practical. If there are three judges of election, the decision, act or certificate of a majority shall be effective in all respects as the decision, act or certificate of all. (d) Report. On request of the presiding officer of the meeting or of any shareholder, the judges shall make a report in writing of any challenge or question or matter determined by them, and execute a certificate of any fact found by them. Any report or certificate made by them shall be prima facie evidence of the facts stated therein. SECTION 3.15. MINORS AS SECURITY HOLDERS. The corporation may treat a minor who holds shares or obligations of the corporation as having capacity to receive and to empower others to receive dividends, interest, principal and other payments or distributions, to vote or express consent or dissent and to make elections and exercise rights relating to such shares or obligations unless, in the case of payments or distributions on shares, the corporate officer responsible for maintaining the -9- list of shareholders or the transfer agent of the corporation or, in the case of payments or distributions on obligations, the treasurer or paying officer or agent has received written notice that the holder is a minor. ARTICLE IV BOARD OF DIRECTORS SECTION 4.01. POWERS; PERSONAL LIABILITY. (a) General Rule. Unless otherwise provided by statute, all powers vested by law in the corporation shall be exercised by or under the authority of, and the business and affairs of the corporation shall be managed under the direction of, the board of directors. (b) Standard of Care; Justifiable Reliance. A director shall stand in a fiduciary relation to the corporation and shall perform his or her duties as a director, including duties as a member of any committee of the board upon which the director may serve, in good faith, in a manner the director reasonably believes to be in the best interests of the corporation and with such care, including reasonably inquiry, skill and diligence, as a person of ordinary prudence would use under similar circumstances. In performing his or her duties, a director shall be entitled to rely in good faith on information, opinions, reports or statements, including financial statements and other financial data, in each case prepared or presented by any of the following: (1) One or more officers or employees of the corporation whom the director reasonably believes to be reliable and competent in the matters presented. (2) Counsel, public accountants or other persons as to matters which the director reasonably believes to be within the professional or expert competence of such person. (3) A committee of the board upon which the director does not serve, duly designated in accordance with law, as to matters within its designated authority, which committee the director reasonably believes to merit confidence. A director shall not be considered to be acting in good faith if the director has knowledge concerning the matter in question that would cause his or her reliance to be unwarranted. (c) Consideration of Factors. In discharging the duties of their respective positions, the board of directors, committees of the board and individual directors may, in considering the best interests of the corporation, consider the effects of any action upon employees, upon suppliers and customers of the corporation and upon communities in which offices or other establishments of the -10- corporation are located, and all other pertinent factors. The consideration of those factors shall not constitute a violation of subsection (b). (d) Presumption. Absent breach of fiduciary duty, lack of good faith or self-dealing, actions taken as a director or any failure to take any action shall be presumed to be in the best interests of the corporation. (e) Personal Liability of Directors. A director of the corporation shall not be personally liable for monetary damages as such for any action taken, or any failure to take any action, unless the director has breached or failed to perform the duties of his or her office under 42 Pa.C.S. Section 8363 and the breach or failure to perform constitutes self-dealing, willful misconduct or recklessness. The provisions of this subsection shall not apply to the responsibility or liability of a director pursuant to any criminal statute or the liability of a director for the payment of taxes pursuant to local, state or Federal law. (The provisions of this subsection (e) were first adopted by the shareholders of the corporation on May 12, 1987.) (f) Notation of Dissent. A director who is present at a meeting of the board of directors, or of a committee of the board, at which action on any corporate matter is taken shall be presumed to have assented to the action taken unless his or her dissent is entered in the minutes of the meeting or unless the director files a written dissent to the action with the secretary of the meeting before the adjournment thereof or transmits the dissent in writing to the secretary of the corporation immediately after the adjournment of the meeting. The right to dissent shall not apply to a director who voted in favor of the action. Nothing in this section shall bar a director from asserting that minutes of the meeting incorrectly omitted his or her dissent if, promptly upon receipt of a copy of such minutes, the director notifies the secretary, in writing, of the asserted omission or inaccuracy. SECTION 4.02. QUALIFICATIONS AND SELECTION OF DIRECTORS. (a) Qualifications. Each director of the corporation shall be a natural person or full age, provided that no person of age seventy (70) years or more is eligible for election as a director. Directors need not be residents of the Commonwealth of Pennsylvania or shareholders of the corporation. (b) Election of Directors. Except as otherwise provided in these bylaws, directors of the corporation shall be elected by the shareholders. In elections for directors, voting need not be by ballot, except upon demand made by a shareholder entitled to vote at the election and before the voting begins. In all elections for directors every shareholder entitled to vote shall have the right to multiply the number of votes to which such shareholder may be entitled by the total number of directors to be elected in the same election by the holders of the class of shares of which his or her shares are a part, and may cast the whole number of such votes for one candidate or may distribute -11- them among any two or more candidates. The candidates receiving the highest number of votes from each class or group of classes, if any, entitled to elect directors separately up to the number of directors to be elected by the class or group of classes shall be elected. If at any meeting of shareholders, directors of more than one class are to be elected, each class of directors shall be elected in a separate election. SECTION 4.03. NUMBER AND TERM OF OFFICE. (a) Number. The board of directors shall consist of such number of directors, not less than five (5) nor more than fifteen (15), as may be determined from time to time by resolution of the board of directors. (b) Term of Office. Each director shall hold office until the expiration of the term for which he or she was elected and until a successor has been selected and qualified or until his or her earlier death, resignation or removal. A decrease in the number of directors shall not have the effect of shortening the term of any incumbent director. (c) Resignation. Any director may resign at any time upon written notice to the corporation. The resignation shall be effective upon receipt thereof by the corporation or at such subsequent time as shall be specified in the notice of resignation. SECTION 4.04. VACANCIES. (a) General Rule. Vacancies in the board of directors, including vacancies resulting from an increase in the number of directors, may be filled by a majority vote of the remaining members of the board though less than a quorum, or by a sole remaining director, and each person so selected shall be a director to serve until the next selection of the class for which such director has been chosen, and until a successor has been selected and qualified or until his or her earlier death, resignation or removal. (b) Action by Resigned Directors. When one or more directors resign from the board effective at a future date, the directors then in office, including those who have so resigned, shall have power by the applicable vote to fill the vacancies, the vote thereon to take effect when the resignations become effective. SECTION 4.05. REMOVAL OF DIRECTORS. (a) Removal by the Shareholders. The entire board of directors, or any class of the board, or any individual director may be removed from office by vote of the shareholders entitled to vote thereon without assigning any cause. In case the board or a class of the board or any one or more directors are so removed, new directors may be elected at the same meeting. -12- (b) Removal by the Board. The board of directors may declare vacant the office of a director who has been judicially declared of unsound mind or who has been convicted of an offense punishable by imprisonment for a term of more than one year of if, within 60 days after notice of his or her selection, the director does not accept the office either in writing or by attending a meeting of the board of directors. SECTION 4.06. PLACE OF MEETINGS. Meetings of the board of directors may be held at such place within or without the Commonwealth of Pennsylvania as the board of directors may from time to time appoint or as may be designated in the notice of the meeting. SECTION 4.07. ORGANIZATION OF MEETINGS. At every meeting of the board of directors, the chairman of the board, if there be one, or, in the case of a vacancy in the office or absence of the chairman of the board, one of the following officers present in the order stated: the vice chairman of the board, if there be one, the president, the vice presidents in their order of rank and seniority, or a person chosen by a majority of the directors present, shall act as chairman of the meeting. The secretary or, in the absence of the secretary, an assistant secretary, or, in the absence of the secretary and the assistant secretaries, any person appointed by the chairman of the meeting, shall act as secretary of the meeting. SECTION 4.08. REGULAR MEETINGS. Regular meetings of the board of directors shall be held at such time and place as shall be designated from time to time by resolution of the board of directors. SECTION 4.09. SPECIAL MEETINGS. Special meetings of the board of directors shall be held whenever called by the chief executive officer or by two or more of the directors. SECTION 4.10. QUORUM OF AND ACTION BY DIRECTORS. (a) General Rule. A majority of the directors in office of the corporation shall be necessary to constitute a quorum for the transaction of business and the acts of a majority of the directors present and voting at a meeting at which a quorum is present shall be the acts of the board of directors. (b) Action by Written Consent. Any action required or permitted to be taken at a meeting of the directors may be taken without a meeting if, prior or subsequent to the action, a consent or consents thereto by all of the directors in office is filed with the secretary of the corporation. SECTION 4.11. EXECUTIVE AND OTHER COMMITTEES. (a) Establishment and Powers. The board of directors may, by resolution adopted by a majority of the directors in office, establish one or more committees to consist of one or more directors of the corporation. Any committee, to the extent provided in the resolution of the board of -13- directors, shall have and may exercise all of the powers and authority of the board of directors except that a committee shall not have any power or authority as to the following: (1) The submission to shareholders of any action requiring approval of shareholders under the Business Corporation Law. (2) The creation or filling of vacancies in the board of directors. (3) The adoption, amendment or repeal of these bylaws. (4) The amendment or repeal of any resolution of the board that by its terms is amendable or repealable only by the board. (5) Action on matters committed by a resolution of the board of directors to another committee of the board. (b) Alternate Committee Members. The board may designate one or more directors as alternate members of any committee who may replace any absent or disqualified member at any meeting of the committee or for the purposes of any written action by the committee. In the absence or disqualification of a member and alternate member or members of a committee, the member or members thereof present at any meeting and not disqualified from voting, whether or not constituting a quorum, may unanimously appoint another director to act at the meeting in the place of the absent or disqualified member. (c) Term. Each committee of the board shall serve at the pleasure of the board. (d) Committee Procedures. The term "board of directors" or "board," when used in any provision of these bylaws relating to the organization or procedures of or the manner of taking action by the board of directors, shall be construed to include and refer to any executive or other committee of the board. SECTION 4.12. COMPENSATION. The board of directors shall have the authority to fix the compensation of directors for their services as directors and a director may be a salaried officer of the corporation. ARTICLE V OFFICERS SECTION 5.01. OFFICERS GENERALLY. (a) Number, Qualifications and Designation. The officers of the corporation shall be a president (who may be the chief executive officer), one or more vice presidents, a secretary, a -14- treasurer, and such other officers as may be elected in accordance with the provisions of Section 5.03. Officers may but need not be directors or shareholders of the corporation. The president and secretary shall be natural persons of full age. The treasurer may be a corporation, but if a natural person shall be of full age. The board of directors may elect from among the members of the board a chairman of the board (who may be the chief executive officer) and a vice chairman of the board who may be officers of the corporation. Any number of offices may be held by the same person. (b) Bonding. The corporation may secure the fidelity of any or all of its officers by bond or otherwise. SECTION 5.02. ELECTION, TERM OF OFFICE AND RESIGNATIONS. (a) Election and Term of Office. The officers of the corporation (except those elected by delegated authority pursuant to Section 5.03 or filled pursuant to Section 5.05) shall be elected annually by the board of directors, and each such officer shall hold office for a term of one year and until a successor has been selected and qualified or until his or her earlier death, resignation or removal. (b) Resignation. Any officer may resign at any time upon written notice to the corporation. The resignation shall be effective upon receipt thereof by the corporation or at such subsequent time as may be specified in the notice of resignation. SECTION 5.03. SUBORDINATE OFFICERS, COMMITTEES AND AGENTS. The board of directors may from time to time elect such other officers and appoint such committees, employees or other agents as the business of the corporation may require, including one or more assistant secretaries, and one or more assistant treasurers, each of whom shall hold office for such period, have such authority, and perform such duties as are provided in these bylaws, or as the board of directors may from time to time determine. The board of directors may delegate to any officer or committee the power to elect subordinate officers and to retain or appoint employees or other agents, or committees thereof, and to prescribe the authority and duties of such subordinate officers, committees, employees or other agents. SECTION 5.04. REMOVAL OF OFFICERS AND AGENTS. Any officer or agent of the corporation may be removed by the board of directors with or without cause. The removal shall be without prejudice to the contract rights, if any, or any person so removed. Election or appointment of an officer or agent shall not of itself create contract rights. SECTION 5.05. VACANCIES. A vacancy in any office because of death, resignation, removal, disqualification, or any other cause, may be filled by the board of directors or the board of directors may delegate to any officer or committee the power to fill a vacancy in such office or to create a new such office, subject to ratification by the board of directors, and if the office is one for which these bylaws prescribe a term, shall be filled for the unexpired portion of the term. -15- SECTION 5.06. AUTHORITY. All officers of the corporation, as between themselves and the corporation, shall have such authority and perform such duties in the management of the corporation as may be provided by or pursuant to resolutions or orders of the board of directors or, in the absence of controlling provisions in the resolutions or orders of the board of directors, as may be determined by or pursuant to these bylaws. SECTION 5.07. THE CHAIRMAN AND VICE CHAIRMAN OF THE BOARD. The chairman of the board or in the absence of the chairman, the vice chairman of the board, shall preside at all meetings of the shareholders and of the board of directors, and shall perform such other duties as may from time to time be requested by the board of directors. SECTION 5.08. THE CHIEF EXECUTIVE OFFICER. The chief executive officer shall be the chief executive officer of the corporation and shall be in addition either the chairman of the board or the president of the corporation. The chief executive officer shall have general supervision over the business of the corporation and, in general, shall have the powers and perform the duties which by law and general usage appertain to the office, subject however, to the control of the board of directors. The chief executive officer shall sign, execute, and acknowledge, in the name of the corporation, deeds, mortgages, bonds, contracts or other instruments, authorized by the board of directors, except in cases where the signing and execution thereof shall be expressly delegated by the board of directors, or by these bylaws, to some other officer or agent of the corporation. SECTION 5.09. THE PRESIDENT. The president shall perform such duties as from time to time may be assigned by the board of directors or the chief executive officer (unless the president shall be the chief executive officer, in which case the president's duties shall be those specified in Section 5.08). SECTION 5.10. THE VICE PRESIDENT. The vice presidents shall perform the duties of the president in the absence of the president and such other duties as may from time to time be assigned to them by the board of directors or the chief executive officer. SECTION 5.11. THE SECRETARY. The secretary or an assistant secretary shall attend all meetings of the shareholders and of the board of directors and shall record all the votes of the shareholders and of the directors and the minutes of the meetings of the shareholders and of the board of directors and of committees of the board in a book or books to be kept for that purpose; shall see that notices are given and records and reports properly kept and filed by the corporation as required by law; shall be the custodian of the seal of the corporation and see that it is affixed to all documents to be executed on behalf of the corporation under its seal; and, in general, shall perform all duties incident to the office of secretary, and such other duties as may from time to time be assigned by the board of directors or the chief executive officer. SECTION 5.12. THE TREASURER. The treasurer or an assistant treasurer shall have or provide for the custody of the funds or other property of the corporation; shall collect and receive or provide for the collection and receipt of moneys earned by or in any manner due to or received by the -16- corporation; shall deposit all funds in his or her custody as treasurer in such banks or other places of deposit as shall be designated in accordance with resolutions adopted by the board of directors; shall, whenever so required by the board of directors, render an account showing all transactions as treasurer, and the financial condition of the corporation; and, in general, shall discharge such other duties as may from time to time be assigned by the board of directors or the chief executive officer. SECTION 5.13. SALARIES. The salaries of the officers elected by the board of directors shall be fixed from time to time by the board of directors or by such officer as may be designated by resolution of the board. The salaries or other compensation of any other officers, employees and other agents shall be fixed from time to time by the officer or committee to which the power to elect such officers or to retain or appoint such employees or other agents has been delegated pursuant to Section 5.03. No officer shall be prevented from receiving such salary or other compensation by reason of the fact that the officer is also a director of the corporation. ARTICLE VI CERTIFICATES OF STOCK, TRANSFER, ETC. SECTION 6.01. SHARE CERTIFICATES. (a) Form of Certificates. Certificates for shares of the corporation shall be in such form as approved by the board of directors, and shall state that the corporation is incorporated under the laws of the Commonwealth of Pennsylvania, the name of the person to whom issued, and the number and class of shares and the designation of the series (if any) that the certificate represents. If the corporation is authorized to issue shares of more than one class or series certificates for shares of the corporation shall set forth upon the face or back of the certificate (or shall state on the face or back of the certificate that the corporation will furnish to any shareholder upon request and without charge), a full or summary statement of the designations, voting rights, preferences, limitations and special rights of the shares of each class or series authorized to be issued so far as they have been fixed and determined and the authority of the board of directors to fix and determine the designations, voting rights, preferences, limitations and special rights of the classes and series of shares of the corporation. (b) Share Register. The share register or transfer book and blank share certificates shall be kept by the secretary or by any transfer agency or registrar designated by the board of directors for that purpose. SECTION 6.02. ISSUANCE. The share certificates of the corporation shall be numbered and registered in the share register or transfer books of the corporation as they are issued. They shall be executed in such manner as the board of directors shall determine. SECTION 6.03. TRANSFER. Transfers of shares shall be made on the share register or transfer books of the corporation upon surrender of the certificate therefor, endorsed by the person named in -17- the certificate or by an attorney lawfully constituted in writing. No transfer shall be made inconsistent with the provisions of the Uniform Commercial Code, 13 Pa.C.S.Sections 8101 et seq., and its amendments and supplements. SECTION 6.04. RECORD HOLDER OF SHARES. The corporation shall be entitled to treat the person in whose name any share or shares of the corporation stand on the books of the corporation as the absolute owner thereof, and shall not be bound to recognize any equitable or other claim to, or interest in, such share or shares on the part of any other person. SECTION 6.05. LOST, DESTROYED OR MUTILATED CERTIFICATES. The holder of any shares of the corporation shall immediately notify the corporation of any loss, destruction or mutilation of the certificate therefor, and the board of directors may, in its discretion, cause a new certificate or certificates to be issued to such holder, in case of mutilation of the certificate, upon the surrender of the mutilated certificate or, in case of loss or destruction of the certificate, upon satisfactory proof of such loss or destruction and, if the board of directors shall so determine, the deposit of a bond in such form and in such sum, and with such surety or sureties, as it may direct. ARTICLE VII INDEMNIFICATION OF DIRECTORS AND OFFICERS (This Article effective for acts occurring prior to May 12, 1987) The corporation shall indemnify any director or officer of the corporation who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that he is or was an authorized representative of the corporation (which for the purposes of this Article VII shall mean a director, officer, employee or agent of the corporation, or a person who is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise) against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in, or not opposed to, the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the person did not act in good faith and in a manner which he reasonably believed to be in, or not opposed to, the best interests of the corporation, and, with respect to any criminal action or proceeding, had reasonable cause to believe that his conduct was unlawful. The corporation shall indemnify any director or officer of the corporation who was or is a party or is threatened to be made a party to any threatened, pending or completed action or -18- suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was an authorized representative of the corporation against expenses (including attorneys' fees) actually and reasonably incurred by him in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in, or not opposed to, the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable for negligence or misconduct in the performance of his duty to the corporation unless and only to the extent that the court of common pleas of the county in which the registered office of the corporation is located or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the court of common pleas or such other court shall deem proper. To the extent that an authorized representative of the corporation who neither was nor is a director or officer of the corporation has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to in the two preceding paragraphs of this Article or in defense of any claim, issue or matter therein, he shall be indemnified by the corporation against expenses (including attorneys' fees) actually and reasonably incurred by him in connection therewith. Such an authorized representative may, at the discretion of the corporation, be indemnified by the corporation in any other circumstances to any extent if the corporation would be required by the two preceding paragraphs of this Article to indemnify such person in such circumstances and to such extent as if he were or had been a director or officer of the corporation. Indemnification under the three preceding paragraphs of this Article shall be made when ordered by court (in which case the expenses, including attorneys' fees, of the authorized representative in enforcing such right of indemnification shall be added to and be included in the final judgment against the corporation) and may be made in a specific case upon a determination that indemnification of the authorized representative is required or proper in the circumstances because he has met the applicable standard of conduct set forth in the first two paragraphs of this Article. Such determination shall be made: (1) By the board of directors by a majority vote of a quorum consisting of directors who were not parties to such action, suit or proceeding, or (2) If such a quorum is not obtainable, or, even if obtainable a majority vote of a quorum of disinterested directors so directs, by independent legal counsel in a written opinion, or (3) By the stockholders. Expenses (including attorneys' fees) incurred in defending a civil or criminal action, suit or proceeding shall be paid by the corporation in advance of the final disposition of such action, suit or proceeding, upon receipt of an undertaking by or on behalf of a director or officer to repay such amount unless it shall ultimately be determined that he is entitled to be indemnified by the -19- corporation as required in this Article or as authorized by law, and may be paid by the corporation in advance on behalf of any other authorized representative when authorized by the Board of Directors upon receipt of a similar undertaking. Each person who shall act as an authorized representative of the corporation shall be deemed to be doing so in reliance upon such rights of indemnification as are provided in this Article. The indemnification provided by this Article shall not be deemed exclusive of any other rights to which those seeking indemnification may be entitled under any agreement, vote of stockholders or disinterested directors, statute or otherwise, both as to action in his official capacity and as to action in another capacity while holding such office or position, and shall continue as to a person who has ceased to be an authorized representative of the corporation and shall inure to the benefit of the heirs, executors and administrators or of such a person. ARTICLE VIII MISCELLANEOUS SECTION 8.01. CORPORATE SEAL. The corporation shall have a corporate seal in the form of a circle containing the name of the corporation on the circumference, and the words "Penna.-1882" in the center. SECTION 8.02. CHECKS. All checks, notes, bills of exchange or other orders in writing shall be signed by such person or persons as shall be designated in accordance with resolutions adopted by the board of directors. SECTION 8.03. CONTRACTS. Except as otherwise provided in the Business Corporation Law in the case of transactions that require action by the shareholders, the board of directors may authorize any officer or agent to enter into any contract or to execute or deliver any instrument on behalf of the corporation, and such authority may be general or confined to specific instances. SECTION 8.04. INTERESTED DIRECTORS OR OFFICERS; QUORUM. (a) General Rule. A contract or transaction between the corporation and one or more of its directors or officers or between the corporation and another corporation, partnership, joint venture, trust or other enterprise in which one or more of its directors or officers are directors or officers or have a financial or other interest, shall not be void or voidable solely for that reason, or solely because the director or officer is present at or participates in the meeting of the board of directors that authorizes the contract or transaction, or solely because his, her or their votes are counted for that purpose, if: (1) the material facts as to the relationship or interest and as to the contract or transaction are disclosed or are known to the board of directors and the board authorizes the -20- contract or transaction by the affirmative votes of a majority of the disinterested directors even though the disinterested directors are less than a quorum; (2) the material facts as to his or her relationship or interest and as to the contract or transaction are disclosed or are known to the shareholders entitled to vote thereon and the contract or transaction is specifically approved in good faith by vote of those shareholders; or (3) the contract or transaction is fair as to the corporation as of the time it is authorized, approved or ratified by the board of directors or the shareholders. (b) Quorum. Common or interested directors may be counted in determining the presence of a quorum at a meeting of the board which authorizes a contract or transaction specified in subsection (a). SECTION 8.05. DEPOSITS. All funds of the corporation shall be deposited from time to time to the credit of the corporation in such banks, trust companies or other depositaries as shall be designated as banks of the corporation in accordance with resolutions adopted by the board of directors, and all such funds shall be withdrawn in accordance with resolutions adopted by the board of directors. SECTION 8.06. CORPORATE RECORDS. (a) Required Records. The corporation shall keep complete and accurate books and records of account, minutes of the proceedings of the incorporators, shareholders and directors and a share register giving the names and addresses of all shareholders and the number and class of shares held by each. The share register shall be kept at either the registered office of the corporation in the Commonwealth of Pennsylvania or at its principal place of business wherever situated or at the office of its registrar or transfer agent. Any books, minutes or other records may be in written form or any other form capable of being converted into written form within a reasonable time. (b) Right of Inspection. Every shareholder shall, upon written verified demand stating the purpose thereof, have a right to examine, in person or by agent or attorney, during the usual hours of business for any proper purpose, the share register, books and records of account, and records of the proceedings of the incorporators, shareholders and directors and to make copies or extracts therefrom. A proper purpose shall mean a purpose reasonably related to the interest of the person as a shareholder. In every instance where an attorney or other agent is the person who seeks the right of inspection, the demand shall be accompanied by a verified power of attorney or other writing that authorizes the attorney or other agent to so act on behalf of the shareholder. The demand shall be directed to the corporation at its registered office in the Commonwealth of Pennsylvania or at its principal place of business wherever situated. [SECTION 8.07 INAPPLICABILITY OF SECTION 910 OF THE PENNSYLVANIA BUSINESS CORPORATION LAW. Effective December 23, 1983, Section 910 of the Pennsylvania Business Corporation Law -21- (added by Pennsylvania Act No. 1983-92 enacted December 23, 1983) shall not be applicable to the corporation. This Section 8.07 shall continue in effect until rescinded by an amendment to the Articles of Incorporation of the corporation.] [Superseded by Statute.] SECTION 8.08. AMENDMENT OF BYLAWS. These bylaws may be amended or repealed, or new bylaws may be adopted, either (i) by vote of the shareholders at any duly organized annual or special meeting of shareholders, or (ii) with respect to those matters that are not by statute committed expressly to the shareholders and regardless of whether the shareholders have previously adopted or approved the bylaw being amended or repealed, by vote of a majority of the board of directors of the corporation in office at any regular or special meeting of directors. Any change in these bylaws shall take effect when adopted unless otherwise provided in the resolution effecting the change. SECTION 8.09. PREVENTION OF "GREENMAIL." The corporation shall not repurchase shares for more than the market value thereof from any shareholder who beneficially owns more than 5% of the outstanding Common Stock of the corporation and has beneficially owned such shares for less than two years from the date of repurchase without (1) first obtaining the affirmative vote of the shareholders entitled to cast at least a majority of the votes which all shareholders are entitled to cast thereon, or (2) offering to repurchase shares from all shareholders upon the same terms. "Beneficially owned" as used herein shall have the meaning set forth in Rule 13d-3 under the Securities Exchange Act of 1934, as amended, or any successor provision thereto. ARTICLE IX INDEMNIFICATION OF DIRECTORS, OFFICERS AND OTHER INDEMNIFIED REPRESENTATIVES (This Article effective for acts occurring on or after May 12, 1987) SECTION 9.01. SCOPE OF INDEMNIFICATION. (a) The corporation shall indemnify an indemnified representative against any liability incurred in connection with any proceeding in which the indemnified representative may be involved as a party or otherwise, by reason of the fact that such person is or was serving in an indemnified capacity, including without limitation any liabilities resulting from any actual or alleged breach or neglect of duty, error, misstatement or misleading statement, negligence, gross negligence or act giving rise to strict or products liability, except where such indemnification is for acts or failures to act constituting self-dealing, willful misconduct or recklessness. (b) If an indemnified representative is entitled to indemnification in respect of a portion, but not all, of any liabilities to which such person may be subject, the corporation shall -22- indemnify such indemnified representative to the maximum extent for such portion of the liabilities. (c) The termination of a proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent shall not, of itself, create a presumption that the indemnified representative is not entitled to indemnification. (d) For purposes of this Article: (1) "indemnified capacity" means any and all past, present and future service by an indemnified representative in one or more capacities as a director, officer, employee or agent of the corporation, or, at the request of the corporation, as a director, officer, employee, agent, fiduciary or trustee of another corporation, partnership, joint venture, trust, employee benefit plan or other entity or enterprise; (2) "indemnified representative" means any and all directors and officers of the corporation and any other person designated as an indemnified representative by the board of directors of the corporation (which may, but need not, include any person serving at the request of the corporation, as a director, officer, employee, agent, fiduciary or trustee of another corporation, partnership, joint venture, trust, employee benefit plan or other entity or enterprise); (3) "liability" means any damage, judgment, amount paid in settlement, fine, penalty, punitive damages, excise tax assessed with respect to an employee benefit plan, or cost or expense of any nature (including, without limitation, attorneys' fees and disbursements); (4) "proceeding" means any threatened, pending or completed action, suit, appeal or other proceeding of any nature, whether civil, criminal, administrative or investigative, whether formal or informal, and whether brought by or in the right of the corporation, a class of its security holders or otherwise; and (5) "self-dealing" means receipt of a personal benefit from the corporation to which the recipient is not legally entitled. SECTION 9.02. PROCEEDINGS INITIATED BY INDEMNIFIED REPRESENTATIVES. Notwithstanding any other provision of this Article, the corporation shall not indemnify under this Article an indemnified representative for any liability incurred in a proceeding initiated (which shall not be deemed to include counterclaims or affirmative defenses) or participated in as an intervenor or amicus curiae by the person seeking indemnification unless such initiation of or participation in the proceeding is authorized, either before or after its commencement, by the affirmative vote of a majority of the directors in office. This section does not apply to reimbursement of expenses incurred in successfully prosecuting or defending an arbitration under Section 9.06(d) of this Article or otherwise successfully prosecuting or defending the rights of an indemnified representative granted by or pursuant to this Article. -23- SECTION 9.03. ADVANCING EXPENSES. The corporation shall pay the expenses (including attorneys' fees and disbursements) incurred in good faith by an indemnified representative in advance of the final disposition of a proceeding described in Section 9.01 and 9.02 of this Article upon receipt of an undertaking by or on behalf of the indemnified representative to repay such amount if it shall ultimately be determined pursuant to Section 9.06(d) that such person is not entitled to be indemnified by the corporation pursuant to this Article. The financial ability of an indemnified representative to repay an advance shall not be a prerequisite to the making of such advance. SECTION 9.04 SECURING OF INDEMNIFICATION OBLIGATIONS. To further effect, satisfy or secure the indemnification obligations provided herein or otherwise, the corporation may maintain insurance, obtain a letter of credit, act as self-insurer, create a reserve, trust, escrow, cash collateral or other fund or account, enter into indemnification agreements, pledge or grant a security interest in any assets or properties of the corporation or use any other mechanism or arrangement whatsoever in such amounts, at such costs and upon such other terms and conditions as the board of directors shall deem appropriate. Absent fraud, the determination of the board of directors with respect to such amounts, costs, terms and conditions shall be conclusive against all security holders, officers and directors and shall not be subject to voidability. SECTION 9.05. PAYMENT OF INDEMNIFICATION. An indemnified representative shall be entitled to indemnification within 30 days after a written request for such indemnification has been delivered to the secretary of the corporation. SECTION 9.06. INDEMNIFICATION PROCEDURE. (a) An indemnified representative shall use such indemnified representative's best efforts to notify promptly the secretary of the corporation of the commencement of any proceeding or the occurrence of any event which might give rise to a liability under this Article, but the failure so to notify the corporation shall not relieve the corporation of any liability which it may have to the indemnified representative under this Article or otherwise. (b) The corporation shall be entitled, upon notice to any such indemnified representative, to assume the defense of any proceeding with counsel reasonably satisfactory to the indemnified representative, or a majority of the indemnified representatives involved in such proceeding if there be more than one. If the corporation notifies the indemnified representative of its election to defend the proceeding, the corporation shall have no liability for the expenses (including attorneys' fees) of the indemnified representative incurred in connection with the defense of such proceeding subsequent to such notice, unless (i) such expenses (including attorneys' fees) have been authorized by the corporation, (ii) the corporation shall not in fact have employed counsel reasonably satisfactory to such indemnified representative or indemnified representatives to assume the defense of such proceeding, or (iii) it shall have been determined pursuant to Section 9.06(d) that the indemnified representative was entitled to indemnification for such expenses under -24- this Article or otherwise. Notwithstanding the foregoing, the indemnified representative may elect to retain counsel at the indemnified representative's own cost and expense to participate in the defense of such proceeding. (c) The corporation shall not be required to obtain the consent of the indemnified representative to the settlement of any proceeding which the corporation has undertaken to defend if the corporation assumes full and sole responsibility for such settlement and the settlement grants the indemnified representative an unqualified release in respect of all liabilities at issue in the proceeding. Whether or not the corporation has elected to assume the defense of any proceeding, no indemnified representative shall have any right to enter into any full or partial settlement of the proceeding without the prior written consent of the corporation (which consent shall not be unreasonably withheld), nor shall the corporation be liable for any amount paid by an indemnified representative pursuant to any settlement to which the corporation has not so consented. (d) Any dispute related to the right to indemnification, contribution or advancement of expenses as provided under this Article, except with respect to indemnification for liabilities under the Securities Act of 1933 which the corporation has undertaken to submit to a court for adjudication, shall be decided only by arbitration in the metropolitan area in which the principal executive offices of the corporation are located, in accordance with the commercial arbitration rules then in effect of the American Arbitration Association, before a panel of three arbitrators, one of whom shall be selected by the corporation, the second of whom shall be selected by the indemnified representative and the third of whom shall be selected by the other two arbitrators. In the absence of the American Arbitration Association, or if for any reason arbitration under the arbitration rules of the American Arbitration Association cannot be initiated, or if one of the parties fails or refuses to select an arbitrator, or if the arbitrators selected by the corporation and the indemnified representative cannot agree on the selection of the third arbitrator within 30 days after such time as the corporation and the indemnified representative have each been notified of the selection of the other's arbitrator, the necessary arbitrator or arbitrators shall be selected by the presiding judge of the court of general jurisdiction in such metropolitan area. Each arbitrator selected as provided herein is required to be or have been a director or executive officer of a corporation whose shares of common stock were listed during at least one year of such service on the New York Stock Exchange or the American Stock Exchange or quoted on the National Association of Securities Dealers Automated Quotations System. The party or parties challenging the right of an indemnified representative to the benefits of this Article shall have the burden of proof. The corporation shall reimburse an indemnified representative for the expenses (including attorneys' fees and disbursements) incurred in successfully prosecuting or defending such arbitration. Any award entered by the arbitrators shall be final, binding and nonappealable and judgment may be entered thereon by any party in accordance with applicable law in any court of competent jurisdiction. This arbitration provision shall be specifically enforceable. (e) Upon a payment to any indemnified representative under this Article, the corporation shall be subrogated to the extent of such payment to all of the rights of the indemnified representative to recover against any person for such liability, and the indemnified representative -25- shall execute all documents and instruments required and shall take such other actions as may be necessary to secure such rights, including the execution of such documents as may be necessary for the corporation to bring suit to enforce such rights. SECTION 9.07. CONTRIBUTION. If the indemnification provided for in this Article or otherwise is unavailable for any reason in respect of any liability or portion thereof, the corporation shall contribute to the liabilities to which the indemnified representative may be subject in such proportion as is appropriate to reflect the intent of this Article or otherwise. SECTION 9.08. DISCHARGE OF DUTY. An indemnified representative shall be deemed to have discharged such person's duty to the corporation if he or she has relied in good faith on information, opinions, reports or statements prepared or presented by any of the following: (a) one or more officers or employees of the corporation whom such indemnified representative reasonably believes to be reliable and competent with respect to the matter presented; (b) legal counsel, public accountants or other persons as to matters that the indemnified representative reasonably believes are within the persons' professional or expert competence; or (c) a committee of the board of directors on which he or she does not serve as to matters within its area of designated authority, which committee he or she reasonably believes to merit confidence. SECTION 9.09. CONTRACT, RIGHTS; AMENDMENT OR REPEAL. All rights to indemnification, contribution and advancement of expenses under this Article shall be deemed a contract between the corporation and the indemnified representative pursuant to which the corporation and each indemnified representative intend to be legally bound. Any repeal, amendment or modification hereof shall be prospective only and shall not affect any rights or obligations then existing. SECTION 9.10. SCOPE OF ARTICLE. The rights granted by this Article shall not be deemed exclusive of any other rights to which those seeking indemnification or advancement of expenses may be entitled under any statute, agreement, vote of shareholders or disinterested directors or otherwise, both as to action in an indemnified capacity and as to action in any other capacity. The indemnification, and advancement of expenses provided by or granted pursuant to this Article shall continue as to a person who has ceased to be an indemnified representative in respect of matters arising prior to such time, and shall inure to the benefit of the heirs, executors, administrators and personal representatives of such a person. SECTION 9.11. RELIANCE ON PROVISIONS. Each person who shall act as an indemnified representative of the corporation shall be deemed to be doing so in reliance upon the rights of indemnification, and advancement of expenses provided by this Article. -26- SECTION 9.12. INTERPRETATION. The provisions of this Article have been adopted by the shareholders of the corporation and are intended to constitute By laws authorized by Section 410F of the Pennsylvania Business Corporation Law and 42 Pa.C.S.Section 8365. (The provisions of this Article IX were first adopted by the shareholders of the corporation on May 12, 1987.) Amended and Restated 2/27/90. As amended through September 24, 2002. -27- EX-10.25 4 w66595exv10w25.txt STORAGE TRANSPORTATION AGREEMENT EXHIBIT 10.25 Service Agreement No. 38022 Control No. 930905-054 SST SERVICE AGREEMENT THIS AGREEMENT, made and entered into this 1st day of November, 1993, by and between COLUMBIA GAS TRANSMISSION CORPORATION ("Seller") and UGI UTILITIES, INC. ("Buyer"). WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows: Section 1. Service to be Rendered. Seller shall perform and Buyer shall receive service in accordance with the provisions of the effective SST Rate Schedule and applicable General Terms and Conditions of Seller's FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Seller to deliver gas hereunder to or for Buyer, the designation of the points of delivery at which Seller shall deliver or cause gas to be delivered-to or for Buyer, and the points of receipt at which Buyer shall deliver or cause gas to be delivered, are specified in Appendix A. as the same may be amended from time to time by agreement between Buyer and Seller, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284.223 of Subpart G of the Commission's. regulations. Buyer warrants that service hereunder is being provided on behalf of Buyer. Section 2. Term. Service under this Agreement shall commence as of November 1, 1993, and shall continue in full force and effect until October 31, 2004, and from year-to-year thereafter unless terminated by either party upon six (6) months' written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Buyer may have under the Commission's regulations and Seller's Tariff. Section 3. Rates. Buyer shall pay- Seller the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Section 4. Notices. Notices to Seller under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager - Agreements Administration and notices to Buyer shall be addressed to it at Post Office Box 12677, 100 Kachel Boulevard, Suite 400, Reading, Pennsylvania 19612-2677, Attention: Earl Smith, until changed by either party by written notice. Service Agreement No. 38022 Control No. 930905-054 SST SERVICE AGREEMENT (Cont'd) Section 5. Prior Service Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: FSS Service Agreement No. 34637, effective November 1, 1989, as it may have been amended, providing for storage and transportation service under the FSS Rate Schedule. UGI UTILITIES, INC. COLUMBIA GAS TRANSMISSION CORPORATION By: /s/ R. J. Chaney By: /s/ Barry J. Towey --------------------------------- ------------------------------- Title: Vice President & General Manager Title: Manager - Agreements Admin. --------------------------------- ------------------------------- Revision No. 6 Control No. 1996-09-18-0014 Appendix A to Service Agreement No. 38022 Under Rate Schedule S S T Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION and (Buyer) UGI UTILITIES INC. October through March Transportation Demand 65,3590 Dth/day April through September Transportation Demand 32,678 Dth/day Primary Receipt Points Scheduling Scheduling Maximum Daily Point No. Point Name Quantity (Dth/Day) ----------------------------------------------------- STOW STORAGE WITHDRAWALS 65,359 Revision No. 6 Control No. 1996-09-18-0014 Appendix A to Service Agreement No. 38022 Under Rate Schedule S S T Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION and (Buyer) UGI UTILITIES INC. Primary Delivery Points
Maximum Maximum Daily Delivery Delivery Pressure Scheduling Measuring Obligation Obligation Point No. Scheduling Point Name Point No. Footnotes Measuring Point Name (Dth/Day) (PSIG) - ------------------------------------------------------------------------------------------------------------ 72 UGI CORPORATION 600011 02 UGI Allentown 85,000 400 600012 02 UGI Quakertown 6,170 100 600013 02 UGI Tatamy 7,800 400 600018 02 UGI Boyertown 4,050 400 600019 UGI Millway 15,376 400 600020 02 UGI Birdsboro 19,521 400 600021 01 TEMPLE 20,811 600023 01 BALLY 11,000 600030 01 Harrisburg 18,816 400 600032 01 DAUPHIN 20,811 600033 UGI Mt. Joy 1,686 100 600036 UGI Lititz 2,976 300 600037 MANHEIM 1,488 150 600038 UGI New Holland 17,856 200 603470 UGI Marlatta 3,800 400 604626 UGI Locust Point 27,700 500 630112 UGI - MORGANTOWN 2,500 60 C23 PENNSBURG 631929 01 PENNSBURG (74-00057 0 C22 EAGLE 632170 01 EAGLE C.S. (74-00001 0
Revision No. 6 Control No. 1996-09-l8-0014 Appendix A to Service Agreement No. 38022 Under Rate Schedule SST Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION and (Buyer) UGI UTILITIES INC. S1 / IF A MAXIMUM PRESSURE IS NOT SPECIFICALLY STATED, THEN SELLER'S OBLIGATION SHALL BE AS STATED IN SECTION 13 (DELIVERY PRESSURE) OF THE GENERAL TERMS AND CONDITIONS. FN01 / THIS METER IS IN THE TEXAS EASTERN DIRECTS AGGREGATE AREA AND THE LINE 1278 NORTH AGGREGATE AREA. FN02 / THIS METER IS IN THE LINE 1278 NORTH AGGREGATE AREA. GFNT / UNLESS STATION SPECIFIC MOODS ARE SPECIFIED IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN SELLER AND BUYER, SELLER'S AGGREGATE MAXIMUM DAILY DELIVERY OBLIGATION, UNDER THIS AND ANY OTHER SERVICE AGREEMENT BETWEEN SELLER AND BUYER, AT THE STATIONS, LISTED ABOVE SHALL NOT EXCEED THE MOOD QUANTITIES SET FORTH ABOVE FOR EACH STATION IN ADDITION, SELLER SHALL NOT BE OBLIGATED ON ANY DAY TO DELIVER MORE THAN THE AGGREGATE DAILY QUANTITIES,(ADQ) LISTED BELOW IN THE AGGREGATE AREAS LISTED BELOW. THE STATIONS FOOTNOTED ABOVE WITH A 1 OR 2 ARE IN THE AGGREGATE AREAS SET FORTH IN GREATER DETAIL BELOW. ANY STATION SPECIFIC MOODS IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN SELLER AND BUYER SHALL BE ADDITIVE BOTH TO THE INDIVIDUAL STATION MOODS SET FORTH HEREIN AND TO ANY APPLICABLE AGGREGATE DAILY QUANTITY SET FORTH BELOW.
FOOTNOTE AGGREGATE NUMBER AGGREGATE AREA NAME DAILY QUANTITY - -------------------------------------------------------------------------- 1 TEXAS EASTERN DIRECTS AGGREGATE AREA 20,811 DTH/D (FROM NOVEMBER 1 - MARCH 31) 1 TEXAS EASTERN DIRECTS AGGREGATE AREA 22,524 DTH/D (FROM APRIL 1 - OCTOBER 31) 1+2 ADQ FOR AGGREGATE AREA FOOTNOTE 100,000 DTH/D NUMBERS 1 AND 2
Revision No. 6 Control No. 1996-09-18-0014 Appendix A to Service Agreement No. 38022 Under Rate Schedule S S T Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION and (Buyer) UGI UTILITIES INC The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Seller's Tariff is incorporated herein by reference for the purposes of listing valid secondary receipt and delivery points. Service changes pursuant to this Appendix A shall become effective as of OCTOBER 01, 1996. This Appendix A shall cancel and supersede the previous Appendix A effective as of APRIL 01, 1996, to the Service Agreement referenced above. With the exception of this Appendix A, all other terms and conditions of said Service Agreement shall remain in full force and effect. UGI UTILITIES INC By: ----------------------------------- Name: --------------------------------- Title: -------------------------------- Date: --------------------------------- COLUMBIA GAS TRANSMISSION CORPORATION By: ----------------------------------- Name: --------------------------------- Title: -------------------------------- Date: --------------------------------- EX-10.26 5 w66595exv10w26.txt NO-NOTICE TRANSPORTATION SERVICE AGREEMENT EXHIBIT 10.26 Service Agreement No. 39527 Control No. 931002-2080 NTS SERVICE AGREEMENT THIS AGREEMENT, made and entered into this 1st day of November, 1993, by and between COLUMBIA GAS TRANSMISSION CORPORATION ("Seller") and UGI UTILITIES, INC. ("Buyer"). WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows: Section 1. Service to be Rendered. Seller shall perform and Buyer shall receive service in accordance with the provisions of the effective NTS Rate Schedule and applicable General Terms and Conditions of Seller's FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on fife with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Seller to deliver gas hereunder to or for Buyer, the designation of the points of delivery at which Seller shall deliver or cause gas to be delivered to or for Buyer, and the points of receipt at which Buyer shall deliver or cause gas to be delivered, are - specified in Appendix A, as the same may be amended from time to time by agreement between Buyer and Seller, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284.102 of Subpart B of the Commission's regulations. Buyer warrants that service hereunder is being provided on behalf of UGI UTILITIES, INC., a local distribution company. Section 2. Term. Service under this Agreement shall commence as of - November 1, 1993, and shall continue in full force and effect until October 31, 2004, and from year-to-year thereafter unless terminated by either party upon six (6) months' written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Buyer may have under the Commission's regulations and Seller's Tariff. Section 3. Rates. Buyer shall pay Seller the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Section 4. Notices. Notices to Seller under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager - Agreements Administration and notices to Buyer shall be addressed to it at P. 0. Box 12677, 100 Kachel Boulevard, Suite 400, Reading, PA 19612-2677, Attention: Earl Smith, until changed by either party by written notice. Service Agreement No. 39527 Control No. 1993-10-02-2080 NTS SERVICE AGREEMENT (Cont'd) Section 5. Prior Service Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: FTS Service Agreement No. 34227, effective June 1, 1987, as it may have been amended, providing for transportation service under the FTS Rate Schedule. UGI UTILITIES, INC. COLUMBIA GAS TRANSMISSION CORPORATION By: /s/ Robert J. Chaney By: /s/ Barry J. Lowery ----------------------------- ----------------------------- Title: Vice President & General Manager Title: Manager - Agreements Admin. -------------------------------- ------------------------------ Revision No. Control No. 1995-03-28-0032 Appendix A to Service Agreement No. 39527 Under Rate Schedule NTS Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION and (Buyer) UGI, UTILITIES INC. Transportation Demand 19,520 Dth/day Primary Receipt Points
Maximum Daily Scheduling Scheduling Measuring Measuring Quantity Point No. Point Name Point No. Footnotes Point Name (Dth/Day) - -------------------------------------------------------------------------------- F2 LEBANON F2 19,520
Revision No. Control No. 1995-03-28-0032 Appendix A to Service Agreement No. 39527 Under Rate Schedule NTS Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION and (Buyer) UGI UTILITIES, INC. Primary Delivery Points
Scheduling Measuring Maximum Daily Point No. Scheduling Point Name Point No. Footnotes Measuring Point Name Quantity (Dth/Day) - ------------------------------------------------------------------------------------------------------ 72 UGI CORPORATION 60030 UGI Harrisburg 7,380 603470 UGI Marletta 2,700 604626 UGI Locust Point 8,300 72 1,140
Revision No. Control No. 1993-10-02-2080 Appendix A to Service Agreement No. 39527 Under Rate Schedule NTS Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION and (Buyer) UGI UTILITIES, INC. The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Seller's Tariff is incorporated herein by reference for the purpose of listing valid secondary interruptible receipt points and delivery points. Service changes pursuant to this Appendix A shall become effective as of November 1, 1993. This Appendix A shall cancel and supersede the previous Appendix A effective as of N/A to the Service Agreement referenced above. With the except of this Appendix A, all other terms and conditions of said Service Agreement shall remain in full force and effect. UGI UTILITIES, INC. By: /s/ Robert J. Chaney ------------------------------------ Name: Robert J. Chaney ------------------------------------ Title: Vice President & General Manager ------------------------------------ Date: 2/3/97 ------------------------------------ COLUMBIA GAS TRANSMISSION CORPORATION By: /s/ Barry J. Lowery ------------------------------------ Name: Barry J. Lowery ------------------------------------ Title: Manager-Agreements Administration ------------------------------------ Date: 10/2/96 ------------------------------------ EX-10.27 6 w66595exv10w27.txt NO-NOTICE TRANSPORTATION AGREEMENT EXHIBIT 10.27 Contract #: 800397R SERVICE AGREEMENT FOR RATE SCHEDULE CDS THIS Service Agreement made and entered into this day of , 1999 by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware Corporation (herein called "Pipeline") and UGI UTILITIES, INC. (herein called "Customer", whether one or more), W I T N E S S E T H: WHEREAS, Customer and Pipeline are parties to an executed service agreement dated December 8, 1995, under Pipeline's Rate Schedule CDS (Pipeline's Contract No. 800397); and WHEREAS, Pipeline and Customer desire to enter into this Service Agreement to supersede Pipeline's currently effective Contract No. 800397; NOW,-THEREFORE, in consideration of the premises and of the mutual covenants and agreements herein contained, the parties do covenant and agree as follows: ARTICLE I SCOPE OF AGREEMENT Subject to the terms, conditions and limitations hereof, of Pipeline's Rate Schedule CDS, and of the General Terms and Conditions, transportation service hereunder will be firm. Subject to the terms, conditions and limitations hereof and of Sections 2.3 and 2.4 of Pipeline's Rate Schedule CDS, Pipeline shall deliver to those points on Pipeline's system as specified in Article IV herein or available to Customer pursuant to Section 14 of the General Terms and Conditions (hereinafter referred to as Point(s) of Delivery), for Customer's account, as requested for any day, natural gas quantities up to Customer's MDQ. Customer's MDQ is as follows: Maximum Daily Quantity (MDQ) 41,000 dth; provided, however, that Customer upon provision of two (2) years prior written notice to Pipeline may reduce the MDQ under this Service Agreement by an aggregate quantity not in excess of 41,000 dth, with any such reduction to be effective on November 1, 2001, or any subsequent November 1 thereafter. SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) Subject to variances as may be permitted by Sections 2.4 of Rate Schedule CDS or the General Terms and Conditions, Customer shall deliver to Pipeline and Pipeline shall receive, for Customer's account, at those points on Pipeline's system as specified in Article IV herein or available to Customer pursuant to Section 14 of the General Terms and Conditions (hereinafter referred to as Point(s) of Receipt) daily quantities of gas equal to the daily quantities delivered to Customer pursuant to this Service Agreement up to Customer's MDQ, plus Applicable Shrinkage as specified in the General Terms and Conditions. Pipeline shall not be obligated to, but may at its discretion, receive at any Point of Receipt on any day a quantity of gas in excess of the applicable Maximum Daily Receipt Obligation (MDRO), plus Applicable Shrinkage, but shall not receive in the aggregate at all Points of Receipt on any day a quantity of gas in excess of the applicable MDQ, plus Applicable Shrinkage. Pipeline shall not be obligated to, but may at its discretion, deliver at any Point of Delivery on any day a quantity of gas in excess of the applicable Maximum Daily Delivery Obligation (MDDO), but shall not deliver in the aggregate at all Points of Delivery on any day a quantity of gas in excess of the MDQ. In addition to the MDQ and subject to the terms, conditions and limitations hereof, Rate Schedule CDS and the General Terms and Conditions, Pipeline shall deliver within the Access Area under this and all other service agreements under Rate Schedules CDS, FT-1, and/or SCT, quantities up to Customer's Operational Segment Capacity Entitlements, excluding those Operational Segment Capacity Entitlements scheduled to meet Customer's MDQ, for Customer's account, as requested on any day. ARTICLE II TERM OF AGREEMENT The term of this Service Agreement shall commence on the first day of the first month after Customer fully executes this Service Agreement and shall continue in force and effect until October 31, 2001 and year to year thereafter unless this Service Agreement is terminated as hereinafter provided. This Service Agreement may be terminated by either Pipeline or Customer upon two (2) years prior written notice to the other specifying a termination date of October 31, 2001 or any October 31 thereafter. Subject to Section 22 of Pipeline's General Terms and Conditions and without prejudice to such rights, this Service Agreement may be terminated at any time by Pipeline in the event Customer fails to pay part or all of the amount of any bill for service hereunder and such failure continues for thirty (30) days after payment is due; provided, Pipeline gives thirty (30) days prior written notice to Customer of such termination and provided further such termination shall not be effective if, prior to the date of termination, Customer either pays such outstanding bill or furnishes a good and sufficient surety bond guaranteeing payment to Pipeline of such outstanding bill. THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT TERM OR THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER TRIGGERS PREGRANTED ABANDONMENT UNDER SECTION 7 OF THE NATURAL SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) GAS ACT AS OF THE EFFECTIVE DATE OF THE TERMINATION. PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS AND CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION. Any portions of this Service Agreement necessary to correct or cash-out imbalances under this Service Agreement as required by the General Terms and Conditions of Pipeline's FERC Gas Tariff, Volume No. 1, shall survive the other parts of this Service Agreement until such time as such balancing has been accomplished. ARTICLE III RATE SCHEDULE This Service Agreement in all respects shall be and remain subject to the applicable provisions of Rate Schedule CDS and of the General Terms and Conditions of Pipeline's FERC Gas Tariff on file with the Federal Energy Regulatory Commission, all of which are by this reference made a part hereof. Customer shall pay Pipeline, for all services rendered hereunder and for the availability of such service in the period stated, the applicable prices established under Pipeline's Rate Schedule CDS as filed with the Federal Energy Regulatory Commission, and as same may hereafter be legally amended or superseded. Customer agrees that Pipeline shall have the unilateral right to file with the appropriate regulatory authority and make changes effective in (a) the rates and charges applicable to service pursuant to Pipeline's Rate Schedule CDS, (b) Pipeline's Rate Schedule CDS pursuant to which service hereunder is rendered or (c) any provision of the General Terms and Conditions applicable to Rate Schedule CDS. Notwithstanding the foregoing, Customer does not agree that Pipeline shall have the unilateral right without the consent of Customer subsequent to the execution of this Service Agreement and Pipeline shall not have the right during the effectiveness of this Service Agreement to make any filings pursuant to Section 4 of the Natural Gas Act to change the MDQ specified in Article I, to change the term of the agreement as specified in Article II, to change Point(s) of Receipt specified in Article IV, to change the Point(s) of Delivery specified in Article IV, or to change the firm character of the service hereunder. Pipeline agrees that Customer may protest or contest the aforementioned filings, and Customer does not waive any rights it may have with respect to such filings. SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) ARTICLE IV POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY The Point(s) of Receipt and Point(s) of Delivery at which Pipeline shall receive and deliver gas, respectively, shall be specified in Exhibit(s) A and B of the executed service agreement. Customer's Zone Boundary Entry Quantity and Zone Boundary Exit Quantity for each of Pipeline's zones shall be specified in Exhibit C of the executed service agreement. Exhibit(s) A, B and C are hereby incorporated as part of this Service Agreement for all intents and purposes as if fully copied and set forth herein at length. ARTICLE V QUALITY All natural gas tendered to Pipeline for Customer's account shall conform to the quality specifications set forth in Section 5 of Pipeline's General Terms and Conditions. Customer agrees that in the event Customer tenders for service hereunder and Pipeline agrees to accept natural gas which does not comply with Pipeline's quality specifications, as expressly provided for in Section 5 of Pipeline's General Terms and Conditions, Customer shall pay all costs associated with processing of such gas as necessary to comply with such quality specifications. Customer shall execute or cause its supplier to execute, if such supplier has retained processing rights to the gas delivered to Customer, the appropriate agreements prior to the commencement of service for the transportation and processing of any liquefiable hydrocarbons and any PVR quantities associated with the processing of gas received by Pipeline at the Point(s) of Receipt under such Customer's service agreement. In addition, subject to the execution of appropriate agreements, Pipeline is willing to transport liquids associated with the gas produced and tendered for transportation hereunder. ARTICLE VI ADDRESSES Except as herein otherwise provided or as provided in the General Terms and Conditions of Pipeline's FERC Gas Tariff, any notice, request, demand, statement, bill or payment provided for in this Service Agreement, or any notice which any party may desire to give to the other, shall be in writing and shall be considered as duly delivered when mailed by registered, certified, or regular mail to the post office address of the parties hereto, as the case may be, as follows: (a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION 5400 Westheimer Court Houston, TX 77056-5310 SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) (b) Customer: UGI UTILITIES, INC. 100 Kachel Blvd. P.O. Box 12677 Reading, PA 19612-2677 or such other address as either party shall designate by formal written notice. ASSIGNMENTS Any Company which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of Customer, or of Pipeline, as the case may be, shall be entitled to the rights and shall be subject to the obligations of its predecessor in title under this Service Agreement; and either Customer or Pipeline may assign or pledge this Service Agreement under the provisions of any mortgage, deed of trust, indenture, bank credit agreement, assignment, receivable sale, or similar instrument which it has executed or may execute hereafter; otherwise, neither Customer nor Pipeline shall assign this Service Agreement or any of its rights hereunder unless it first shall have obtained the consent thereto in writing of the other; provided further, however, that neither Customer nor Pipeline shall be released from its obligations hereunder without the consent of the other. In addition, Customer may assign its rights to capacity pursuant to Section 3.14 of the General Terms and Conditions. To the extent Customer so desires, when it releases capacity pursuant to Section 3.14 of the General Terms and Conditions, Customer may require privacy between Customer and the Replacement Customer, as further provided in the applicable Capacity Release Umbrella Agreement. ARTICLE VIII INTERPRETATION The interpretation and performance of this Service Agreement shall be in accordance with the laws of the State of Texas without recourse to the law governing conflict of laws. This Service Agreement and the obligations of the parties are subject to all present and future valid laws with respect to the subject matter, State and Federal, and to all valid present and future orders, rules, and regulations of duly constituted authorities having jurisdiction. ARTICLE IX CANCELLATION OF PRIOR CONTRACTS This Service Agreement supersedes and cancels, as of the effective date of this Service Agreement, the contract(s) between the parties hereto as described below: service agreement dated December 8, 1995, between Pipeline and Customer under Pipeline's Rate Schedule CDS (Pipeline's Contract No. 800397). SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) IN WITNESS WHEREOF, the parties hereto have caused this Service Agreement to be signed by their respective Presidents, Vice Presidents or other duly authorized agents and their respective corporate seals to be hereto affixed and attested by their respective Secretaries or Assistant Secretaries, the day and year first above written. TEXAS EASTERN TRANSMISSION CORPORATION By {signature unknown) ---------------------------------- ATTEST: (signature not legible) - ---------------------------------- Asst. Secretary UGI UTILITIES, INC. BY: ---------------------------------- Robert J. Chaney ATTEST: Executive Vice President /s/ Brendan P. Bovaird - ---------------------------------- BRENDAN P BOVAIRD Secretary Contract #:800397R EXHIBIT A, TRANSPORTATION PATHS FOR BILLING PURPOSES, DATED 2/23/99 TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND UGI UTILITIES ("Customer"), DATED 2/23/99 (1) Customer's firm Point(s) of Receipt:
Maximum Daily Receipt Obligation (plus Point of Applicable Shrinkage) Measurement Receipt Description (dth) Responsibilities Owner Operator* - --------------------------------------------------------------------------------------------------------------- 71200 CHEVRON - VENICE, LA 16,475 CHEVRON CHEVRON CHEVRON USA PLAQUEMINES, PA., LA USA USA 71750 COLUMBIA GULF - ST. LANDRY PA., 24,525 COLUMBIA COLUMBIA COLUMBIA LA ST LANDRY PA., LA GULF GULF GULF 70011 COLUMBIA GAS - EAGLE, PA., 0 TX EAST TX EAST COLUMBIA CHESTER CO., PA TRAN TRAN GAS 75577 COLUMBIA GAS - PENNSBURG, PA., 0 TX EAST TX EAST COLUMBIA BUCKS CO., PA TRAN TRAN GAS
* Confirming Party (2) Customer shall have Pipeline's Master Receipt Point List ("MRPL"). Customer hereby agrees that Pipeline's MRPL as revised and published by Pipeline from time to time is incorporated herein by reference. Customer hereby agrees to comply with the Receipt Pressure obligation as set forth in Section 6 of Pipeline's General Terms and Conditions at such Point(s) of Receipt. A-1 Contract #800397R EXHIBIT A, TRANSPORTATION PATHS, continued UGI UTILITIES, INC.
Transportation Transportation Path Path Quantity (Dth/D) --------------------------------------------------------------- M1 to M3 41,000
SIGNED FOR IDENTIFICATION PIPELINE: (signature not legible) -------------------------------- CUSTOMER: /s/ R. J. Chaney -------------------------------- SUPERSEDES EXHIBIT A DATED: -------------- A - 2 Contract #:800397R EXHIBIT B, POINT (S) OF DELIVERY, EFFECTIVE 2/23/99 TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS' BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND UGI UTILITIES, INC. ("Customer") EFFECTIVE 2/23/99
Maximum Daily Delivery Point of Obligation Deliverer Pressure Measurement Delivery Description (dth) Obligation Responsibilities Owner Operator - ------------------------------------------------------------------------------------------------------------------------------------ 1. 70011 COLUMBIA GAS - 41,000 dth DURING AS PROVIDED IN SECTION 6 OF THE TX EAST TX EAST COLUMBIA EAGLE PA THE PERIOD April GENERAL TERMS AND CONDITIONS OF TRAN TRAN GAS CHESTER CO.,PA 16 through PIPELINE'S FERC GAS TARIFF November 15 of each year - otherwise 35,593 dth 2. 70069 UGI UTILITIES - 5,190 AS PROVIDED IN SECTION 6 OF THE TX EAST TX EAST UGI COLUMBIA, PA GENERAL TERMS AND CONDITIONS OF TRAN TRAN UTILITIES LANCASTER CO., PA PIPELINE'S FERC GAS TARIFF 3. 70070 UGI UTILITIES - 41,000 AS PROVIDED IN SECTION 6 OF THE TX EAST TX EAST UGI LANCASTER, PA GENERAL TERMS AND CONDITIONS OF TRAN TRAN UTILITIES LANCASTER CO., PA PIPELINE'S FERC GAS TARIFF 4. 70321 UGI UTILITIES - 17,000 TX EAST TX EAST UGI LEBANON, PA TRAN TRAN UTILITIES LEBANON CO., PA 5. 70322 UGI UTILITIES - 41,000 400 POUNDS PER SQUARE INCH TX EAST TX EAST UGI READING, PA GAUGE TRAN TRAN UTILITIES BERKS CO., PA 6. 70486 UGI UTILITIES - 6,500 400 POUNDS PER SQUARE INCH TX EAST TX EAST UGI WOMELSDORF, PA GAUGE TRAN TRAN UTILITIES BERKS CO., PA 7. 70519 UGI UTILITIES - 41,000 400 POUNDS PER SQUARE INCH TX EAST TX EAST UGI DAUPHIN CO., PA GAUGE TRAN TRAN UTILITIES DAUPHIN CO., 8. 71461 COLUMBIA GAS - 5,190 SUCH PRESSURE AS MAY BE TX EAST COLUMBIA UGI RICH HILL, BUCKS AVAILABLE BY PIPELINE AT THE TRAN GAS UTILITIES CO., PA POINT OF DELIVERY 9. 71528 UGI UTILITIES - 7,200 300 POUNDS PER SQUARE INCH TX EAST TX EAST UGI LANCASTER CO., PA GAUGE TRAN TRAN UTILITIES
B-1 Contract #: 800397R EXHIBIT B POINT (S) OF DELIVERY (Continued) UGI UTILITIES, INC.
Maximum Daily Delivery Point of Obligation Deliverer Pressure Measurement Delivery Description (dth) Obligation Responsibilities Owner Operator - ------------------------------------------------------------------------------------------------------------------------------------ 10. 72571 COLUMBIA GAS - 519 400 POUNDS PER SQUARE INCH TX EAST COLUMBIA UGI BERKS CO., PA GAUGE TRAN GAS UTILITIES 11. 79513 SS-1 STORAGE POINT 3,612 N/A N/A N/A N/A 04/01-10/31 3,612 11/01-03/31 12. 75577 COLUMBIA GAS - 0 AS PROVIDED IN SECTION 6 OF THE TX EAST TX EAST COLUMBIA PENNSBURG, PA, GENERAL TERMS AND CONDITIONS OF TRAN TRAN GAS BUCKS CO., PA PIPELINE'S FERC GAS TARIFF
* Confirming Party provided, however, that Pipeline is not obligated to deliver under Rate Schedules FT-1, CDS and FTS5 on any one day an aggregate of more than 88,418 dth per day to points of delivery 70011, 70069, 70070 and 71528 during the period November 16 through April 15, and further provided, that during this time period Pipeline is not obligated to deliver under Rate Schedules FT-1, CDS and FTS-5 on any one day an aggregate of more than 94,904 dth to points of delivery 70321, 70322, 70486, 70519, 71461 and 72571; and further provided, however, that until changed by a subsequent Agreement between Pipeline and Customer, Pipeline's aggregate maximum daily delivery obligations under this and all other firm Service Agreements existing between Pipeline and Customer, shall in no event exceed the following: B-2 Contract #: 8003978 EXHIBIT B POINT (S) OF DELIVERY (Continued) UGI UTILITIES, INC.
Point of Delivery Aggregate Maximum Daily Delivery Obligation (dth -------- --------------- No. 1 68,785 No. 2 5,190 No. 3 49,000 No. 4 17,000 No. 5 65,880 No. 6 6,500 No. 7 53,000 No. 8 5,190 No. 9 17,200 No. 10 7,186 No. 11 3,612
Further, pursuant to Section 14.9 of the General Terms and Conditions of Pipeline's FERC Gas Tariff Sixth Revised Volume No. 1, Customer has been allocated firm capacity at the Points of Delivery as shown below for deliveries under Rate Schedules CDS, FT-1, SCT, and/or SS-1 at such pressure available in Pipeline's facilities at the point of delivery, subject to receipt of such quantities being acceptable to the Owner and Operator of the Point of Delivery:
Point of Section 14.9 Firm Measurement Delivery Description Capacity (dth/d) Responsibilities Owner Operator 1. 70011 COLUMBIA GAS (MFGRS.) - 85,635 TX EAST TRAN TX EAST TRAN COLUMBIA GAS EAGLE, PA CHESTER CO., 4/1/97-0/31/97 PA 49,635 11/1/97-0/31/98 2. 70069 UGI UTILITIES - 12,700 TX EAST TRAM TX EAST TRAN UGI UTILITIES COLUMBIA, PA LANCASTER CO., PA
B-3 Contract #: 800397R EXHIBIT B POINT (S) OF DELIVERY (Continued) UGI UTILITIES, INC.
Point of Section 14.9 Firm Measurement Delivery Description Capacity (dth/d) Responsibilities Owner Operator 3. 70070 UGI UTILITIES - 31,328 TX EAST TRAN TX EAST TRAN UGI COLUMBIA, PA UTILITIES LANCASTER, PA LANCASTER CO., PA 4. 70321 UGI UTILITIES - 1,253 TX EAST TRAN TX EAST TRAN UGI UTILITIES LEBANON, PA LEBANON CO., PA 5. 70486 UGI UTILITIES - 3,670 TX EAST TRAN TX EAST TRAN UGI UTILITIES WOMELSDORF, PA BERKS CO., PA 6. 71438 DAUPHIN CO. GAS - 2,580 TX EAST TRAN TX EAST TRAN PENN FUEL ANNVILLE, LEBANON CO, PA 7. 71461 UGI UTILITIES - 840 TX EAST TRAN COLUMBIA GAS COLUMBIA GAS RICH HILL, BUCKS CO., PA 8. 72571 UGI UTILITIES - 13,984 TX EAST TRAN COLUMBIA GAS COLUMBIA GAS BERKS, CO., PA 9. 75577 UGI UTILITIES - 75,440 TX EAST TRAN COLUMBIA GAS COLUMBIA GAS PENNSBURG, PA BUCKS CO., PA
SIGNED FOR IDENTIFICATION PIPELINE: (signature not legible) ------------------------------------ CUSTOMER: /s/ R. J. Chaney ------------------------------------ SUPERSEDES EXHIBIT B EFFECTIVE ----------------- B-4 Contract #:800397R EXHIBIT C, ONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY, DATED 2/23/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS BETWEEN 14 TEXAS EASTERN TRANSMISSION CORPORATION ("PIPELINE") AND UGI UTILITIES, INC. ("CUSTOMER"), DATED 2/23/99 ZONE BOUNDARY ENTRY QUANTITY Dth/D To
FROM STX ETX WLA ELA M1-24 M1-30 M1-TXG M1-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3 STX 1487 ETX 194 2249 WLLA 684 1487 ELLA 34899 I Ml-24 194 M1-30 34899 M1-TXG 2933 M1-TGC 2974 M2-24 M2-30 M2-TXG M2-TGC M2 41000 M3
C-1 Contract #:800397R EXHIBIT C (Continued) UGI UTILITIES, INC. ZONE BOUNDARY EXIT QUANTITY Dth/D To
FROM STX ETX WLA ELA Ml-24 M1-30 M1-TXG M1-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3 STX ETX WLA ELA M1-24 194 M1-30 34899 Ml-TXG 2933 M1-TGC 2974 M2-24 M2-30 M2-TXG M2-TGC M2 41000 M3
SIGNED FOR IDENTIFICATION PIPELINE: (signature not legible) ------------------------------------ CUSTOMER: /s/ R. J. Chaney ------------------------------------ SUPERSEDES EXHIBIT C DATED ----------------- C-2 EX-10.28 7 w66595exv10w28.txt NO-NOTICE TRANSPORTATION AGREEMENT EXHIBIT 10.28 Contract #: 800239R1 SERVICE AGREEMENT FOR RATE SCHEDULE CDS This Service Agreement, made and entered into this 31st day of October, 2000, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware Corporation (herein called "Pipeline") and UGI UTILITIES, INC. (herein called "Customer", whether one or more), W I T N E S S E T H: WHEREAS, Customer and Pipeline are parties to an executed service agreement dated February 23, 1999, under Pipeline's Rate Schedule CDS (Pipeline's Contract No. 800239R); and WHEREAS, Pipeline and Customer desire to enter into this Service Agreement to supersede Pipeline's currently effective Contract No. 8002398 and to extend the primary term of such service agreement; NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements herein contained, the parties do covenant and agree as follows: ARTICLE I SCOPE OF AGREEMENT Subject to the terms, conditions and limitations hereof, of Pipeline's Rate Schedule CDS, and of the General Terms and Conditions, transportation service hereunder will be firm. Subject to the terms, conditions and limitations hereof and of Sections 2.3 and 2.4 of Pipeline's Rate Schedule CDS, Pipeline shall deliver to those points on Pipeline's system as specified in Article IV herein or available to Customer, pursuant to, Section 14 of the General Terms and Conditions (hereinafter referred to as Point(s) of Delivery), for Customer's account, as requested for any day, natural gas quantities up to Customer's MDQ. Customer's MDQ is as follows: Maximum Daily Quantity (MDQ) 25,000 dth Subject to variances as may be permitted by Sections 2.4 of Rate Schedule CDS or the General Terms and Conditions, Customer shall deliver to Pipeline and Pipeline shall receive, for Customer's account, at those points on Pipeline's system as specified in Article IV herein or available to Customer pursuant to Section 14 of the General Terms and Conditions (hereinafter (Continued) referred to as Point(s) of Receipt) daily quantities of gas equal to the daily quantities delivered to Customer. Pursuant to this Service Agreement up to Customer's MDQ, plus Applicable Shrinkage as specified in the General Terms and Conditions. Pipeline shall not be obligated to, but may at its discretion, receive at any Point of Receipt on any day a quantity of gas in excess of the applicable Maximum Daily Receipt Obligation (MDRO), plus Applicable Shrinkage, but shall not receive in the aggregate at all Points of Receipt on any day a quantity of gas in excess of the applicable MDQ, plus Applicable 1 Shrinkage. Pipeline shall not be obligated to, but may at its discretion, deliver at any Point of Delivery on any day a quantity of gas in excess of the applicable Maximum Daily Delivery Obligation (MDDO), but shall not deliver in the aggregate at all Points of Delivery on any day a quantity of gas in excess of the MDQ. In addition to the MDQ and subject to the terms, conditions and limitations hereof, Rate Schedule CDS and the General Terms and Conditions, Pipeline shall deliver within the Access Area under this and all other service agreements under Rate Schedules CDS, FT-1, and/or SCT, quantities up to Customer's Operational Segment Capacity Entitlements, excluding those Operational Segment Capacity Entitlements scheduled to meet Customer's MDQ, for Customer's account, as requested on any day. ARTICLE II TERM OF AGREEMENT The term of this Service Agreement shall commence on the first day of the first month after Customer fully executes this Service Agreement and shall continue in force and effect until October 31, 2004 and year to year thereafter unless this Service Agreement is terminated as hereinafter provided. This Service Agreement may be terminated by either Pipeline or Customer upon one (1) year prior written notice to the other specifying a termination date of October 31, 2004 or any October 31 thereafter. Subject to Section 22 of Pipeline's General Terms and Conditions and without prejudice to such rights, this Service Agreement may be terminated at any time by Pipeline in the event Customer fails to pay part or all of the amount of any bill for service hereunder and such failure continues for thirty (30) days after payment is due; provided, Pipeline gives thirty (30) days prior written notice to Customer of such termination and provided further such termination shall not be effective if, prior to the date of termination, Customer either pays such outstanding bill or furnishes a good and sufficient surety bond guaranteeing payment to Pipeline of such outstanding bill. THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT TERM OR THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER TRIGGERS PREGRANTED ABANDONMENT UNDER SECTION 7 OF THE NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF THE TERMINATION. PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS AND CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION. Any portions of this Service Agreement necessary to correct or cash-out imbalances under this Service Agreement as required by the General Terms and Conditions of Pipeline's FERC Gas Tariff, Volume No. 1, shall survive the other parts of this Service Agreement until such time as such balancing has been accomplished. 2 ARTICLE III RATE SCHEDULE This Service Agreement in all respects shall be and remain subject to the applicable provisions of Rate Schedule CDS and of the General Terms and Conditions of Pipeline's FERC Gas Tariff on file with the Federal Energy Regulatory Commission, all of which are by this reference made a part hereof. Customer shall pay Pipeline, for all services rendered hereunder and for the availability of such service in the period stated, the applicable prices established under Pipeline's Rate Schedule CDS as filed with the Federal Energy Regulatory Commission, and as same may hereafter be legally amended or superseded. Customer agrees that Pipeline shall have the unilateral right to file with the appropriate regulatory authority and make changes effective in (a) the rates and charges applicable to service pursuant to Pipeline's Rate Schedule CDS, (b) Pipeline's, Rate Schedule CDS pursuant to which service hereunder is rendered or (c) any provision of the General Terms and Conditions applicable to Rate Schedule CDS. Notwithstanding the foregoing, Customer does not agree that Pipeline shall have the unilateral right without the Consent of Customer subsequent to the execution of this Service Agreement and Pipeline shall not have the right during the effectiveness of this Service Agreement to make any filings pursuant to Section 4 of the Natural Gas Act to change the MDQ specified in Article I, to change the term of the agreement as specified in Article II, to change Point(s) of Receipt specified in Article IV, to change the Point(s) of Delivery specified in Article IV, or to change the firm character of the service hereunder. Pipeline agrees that Customer may protest or contest the aforementioned filings, and Customer does not waive any rights it may have with respect to such filings. ARTICLE IV POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY The Point(s) of Receipt and Point(s) of Delivery at which Pipeline shall receive and deliver gas, respectively, shall be specified in Exhibit(s) A and B of the executed service agreement. Customer's Zone Boundary Entry Quantity and Zone Boundary Exit Quantity for each of Pipeline's zones shall be specified in Exhibit C of the executed service agreement. Exhibit(s) A, B and C are hereby incorporated as part of this Service Agreement for all intents and purposes as if fully copied and set forth herein at length. ARTICLE V QUALITY All natural gas tendered to Pipeline for Customer's account shall conform to the quality specifications set forth in Section 5 of Pipeline's General Terms and Conditions. Customer agrees that in the event Customer tenders for service hereunder and Pipeline agrees to accept natural gas which does not comply with Pipeline's quality specifications, as expressly provided for in Section 5 of Pipeline's General Terms and Conditions, Customer shall pay all costs associated with processing of such gas as necessary to comply with such quality specifications. 3 Customer shall execute or cause its supplier to execute, if such supplier has retained processing rights to the gas delivered to Customer, the appropriate agreements prior to the commencement of service for the transportation and processing of any liquefiable hydrocarbons and any PVR quantities associated with the processing of gas received by Pipeline at the Point (s) of Receipt under such Customer's service agreement. In addition, subject to the execution of appropriate agreements, Pipeline is willing to transport liquids associated with the gas produced and tendered for transportation hereunder. ARTICLE VI ADDRESSES Except as herein otherwise provided or as provided in the General Terms and Conditions of Pipeline's FERC Gas Tariff, any notice, request, demand, statement, bill or payment provided for in this Service Agreement, or any notice which any party may desire to give to the other, shall be in writing and shall be considered as duly delivered when mailed by registered, certified, or regular mail to the post office address of the parties hereto, as the case may be, as follows: (a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION 5400 Westheimer Court Houston, TX 77056-5310 (b) Customer: UGI UTILITIES, INC. 100 Kachel Blvd. P.O. Box 12677 Reading, PA 19612-2677 or such other address as either party shall designate by formal written notice. ARTICLE VII ASSIGNMENTS Any Company which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of Customer, or of Pipeline, as the case may be, shall be entitled to the rights and shall be subject to the obligations of its predecessor in title under this Service Agreement; and either Customer or Pipeline may assign or pledge this Service Agreement under the provisions of any mortgage, deed of trust, indenture, bank credit agreement, assignment, receivable sale, or similar instrument which it has executed or may execute hereafter; otherwise, neither Customer nor Pipeline shall assign this Service Agreement or any of its rights hereunder unless it first shall have obtained the consent thereto in writing of the other; provided further, however, that neither Customer nor Pipeline shall be released from its obligations hereunder without the consent of the other. In addition, Customer may assign its rights to capacity pursuant to Section 3.14 of the General Terms and Conditions. To the extent Customer so desires, when it releases capacity pursuant to Section 3.14 of the General Terms and Conditions, Customer may require privity between Customer and the Replacement Customer, as further provided in the applicable Capacity Release Umbrella Agreement. 4 ARTICLE VIII INTERPRETATION The interpretation and performance of this Service Agreement shall be in accordance with the laws of the State of Texas without recourse to the law governing conflict of laws. This Service Agreement and the obligations of the parties are subject to all present and future valid laws with respect to the subject matter, State and Federal, and to all valid present and future orders, rules, and regulations of duly constituted authorities having jurisdiction. ARTICLE IX CANCELLATION OF PRIOR CONTRACT(S) This Service Agreement supersedes and cancels, as of the effective date of this Service Agreement, the contract(s) between the parties hereto as described below: service agreement dated February 23, 1999, between Pipeline and Customer under Pipeline's Rate Schedule CDS (Pipeline's Contract No. 800239R). IN WITNESS WHEREOF, the parties hereto have caused this Service Agreement to be signed by their respective Presidents, Vice Presidents or other duly authorized agents and their respective corporate seals to be hereto affixed and attested by their respective Secretaries or Assistant Secretaries, the day and year first above written. TEXAS EASTERN TRANSMISSION CORPORATION BY /s/ Gregory J. Rizzo ---------------------------------------- Gregory J. Rizzo Vice President, Marketing ATTEST: (SIGNATURE NOT LEGIBLE) - ------------------------------------------ UGI UTILITIES, INC. BY /s/ Vicki O. Ebner ---------------------------------- ATTEST: - ------------------------------------------ 5 EX-10.29 8 w66595exv10w29.txt FIRM TRANSPORTATION SERVICE AGREEMENT EXHIBIT 10.29 Contract #: 800394R2 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 This Service Agreement, made and entered into this 15th day of June ,1999, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware Corporation (herein called "Pipeline") and UGI UTILITIES, INC. (herein called "Customer", whether one or more), W I T N E S S E T H: WHEREAS, Customer and Pipeline are currently parties to an executed service agreement dated February 23, 1999 under Pipeline's Rate Schedule FT-1 (Pipeline's Contract No. 8003948); and WHEREAS, Customer and Pipeline desire to enter into this Service Agreement to supersede Pipeline's currently effective Contract No. 8003948; NOW, THEREFORE., in consideration of the premises and of the mutual covenants and agreements herein contained, the parties do covenant and agree as follows: ARTICLE I SCOPE OF AGREEMENT Subject to the terms, conditions and limitations hereof, of Pipeline's Rate Schedule FT-1, and of the General Terms and Conditions, transportation service hereunder will be firm. Subject to the terms, conditions and limitations hereof and of Pipeline's Rate Schedule FT-1, Pipeline agrees to deliver for Customer's account quantities of natural gas up to the following quantity: Maximum Daily Quantity (MDQ) 32,475 dth Pipeline shall receive for Customer's account, at those points on Pipeline's system as specified in Article IV herein or available to Customer pursuant to Section 14 of the General Terms and Conditions (hereinafter referred to as Point(s) of Receipt) for transportation hereunder daily quantities of gas up to Customer's MDQ, plus Applicable Shrinkage. Pipeline shall SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) transport and deliver for Customer's account, at those points on Pipeline's system as specified in Article IV herein or available to Customer pursuant to Section 14 of the General Terms and Conditions (hereinafter referred to as Point(s) of Delivery), such daily quantities tendered up to such Customer's MDQ. Pipeline shall not be obligated to, but may at its discretion, receive at any Point of Receipt on any day a quantity of gas in excess of the applicable Maximum Daily Receipt Obligation (MDRO), plus Applicable Shrinkage, but shall not receive in the aggregate at all Points of Receipt on any day a quantity of gas in excess of the applicable MDQ, plus Applicable Shrinkage. Pipeline shall not be obligated to, but may at its discretion, deliver at any Point of Delivery on any day a quantity of gas in excess of the applicable Maximum Daily Delivery Obligation (MDDO), but shall not deliver in the aggregate at all Points of Delivery on any day a quantity of gas in excess of the applicable MDQ. In addition to the MDQ and subject to the terms, conditions and limitations hereof, Rate Schedule FT-1 and the General Terms and Conditions, Pipeline shall deliver within the Access Area under this and all other service agreements under Rate Schedules CDS, FT-1, and/or SCT, quantities up to Customer's Operational Segment Capacity Entitlements, excluding those operational Segment Capacity Entitlements scheduled to meet Customer's MDQ, for Customer's account, as requested on any day. ARTICLE II TERM OF AGREEMENT The term of this Service Agreement shall commence on the first day of the first month after Customer fully executes this Service Agreement and shall continue in force and effect until December 31, 2001 and year to year thereafter unless this Service Agreement is terminated as hereinafter provided. This Service Agreement may be terminated by either Pipeline or Customer upon two (2) years prior written notice to the other specifying a termination date of December 31, 2001, or any December 31 thereafter. Subject to Section 22 of Pipeline's General Terms and Conditions and without prejudice to such rights, this Service Agreement may be terminated at any time by Pipeline in the event Customer fails to pay part or all of the amount of any bill for service hereunder and such failure 2 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) continues for thirty (30) days after payment is due; provided, Pipeline gives thirty (30) days prior written notice to Customer of such termination and provided further such termination shall not be effective if, prior to the date of termination, Customer either pays such outstanding bill or furnishes a good and sufficient surety bond guaranteeing payment to Pipeline of such outstanding bill. THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT TERM OR THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER TRIGGERS PREGRANTED ABANDONMENT UNDER SECTION 7 OF THE NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF THE TERMINATION. PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS AND CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION. Any portions of this Service Agreement necessary to correct or cash-out imbalances under this Service Agreement as required by the General Terms and Conditions of Pipeline's FERC Gas Tariff, Volume No. 1, shall survive the other parts of this Service Agreement until such time as such balancing has been accomplished. ARTICLE III RATE SCHEDULE This Service Agreement in all respects shall be and remain subject to the applicable provisions of Rate Schedule FT-1 and of the General Terms and Conditions of Pipeline's FERC Gas Tariff on file with the Federal Energy Regulatory Commission, all of which are by this reference made a part hereof. Customer shall pay Pipeline, for all services rendered hereunder and for the availability of such service in the period stated, the applicable prices established under Pipeline's Rate Schedule FT-1 as filed with the Federal Energy Regulatory Commission, and as same may hereafter be legally amended or superseded. Customer agrees that Pipeline shall have the unilateral right to file with the appropriate regulatory authority and make changes effective in (a) the rates and charges applicable to service pursuant to Pipeline's Rate Schedule FT-1, (b) Pipeline's Rate Schedule FT-1 pursuant to which service 3 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) hereunder is rendered or (c)any provision of the General Terms and Conditions applicable to Rate Schedule FT-1. Notwithstanding the foregoing, Customer does not agree that Pipeline shall have the unilateral right without the consent of Customer subsequent to the execution of this Service Agreement and Pipeline shall not have the right during the effectiveness of this Service Agreement to make any filings pursuant to Section 4 of the Natural Gas Act to change the MDQ specified in Article. I, to change the term of the agreement as specified in Article II to change Point(s) of Receipt specified in. Article IV, to change the Point(s) of Delivery specified in Article IV, or to change the firm character of the service hereunder. Pipeline agree that Customer may protest or contest the aforementioned filings, and Customer does not waive any rights it may have with respect to such filings. ARTICLE IV POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY The Point(s) of Receipt and Point(s) of Delivery at which Pipeline shall receive and deliver gas, respectively, shall be specified in Exhibit(s) A and B of the executed service agreement. Customer's Zone Boundary Entry Quantity and Zone Boundary Exit Quantity for each of Pipeline's zones shall be specified in Exhibit C of the executed service agreement. Exhibit(s) A, B and C are hereby incorporated as part of this Service Agreement for all intents and purposes as if fully copied and set forth herein at length. ARTICLE V QUALITY All natural gas tendered to Pipeline for Customer's account shall conform to the quality specifications set forth in Section 5 of Pipeline's General Terms and Conditions. Customer agrees that in the event Customer tenders for service hereunder and Pipeline agrees to accept natural gas which does not comply with Pipeline's quality specifications, as expressly provided for in Section 5 of Pipeline's General Terms and Conditions, Customer shall pay all costs associated with processing of such gas as necessary to comply with such quality specifications. Customer shall execute or cause its supplier to execute, if such supplier 4 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) has retained processing rights to the gas delivered to Customer, the appropriate agreements prior to the commencement of service for the transportation and processing of any liquefiable hydrocarbons and any PVR quantities associated with the processing of gas received by Pipeline at the Point(s) of Receipt under such Customer's service agreement. In addition, subject to the execution of appropriate agreements, Pipeline is willing to transport liquids associated with the gas produced and tendered for transportation hereunder. ARTICLE VI ADDRESSES Except as herein otherwise provided or as provided in the General Terms and Conditions of Pipeline's FERC Gas Tariff, any notice, request, demand, statement, bill or payment provided for in this Service Agreement, or any notice which any party may desire to give to the other, shall be in writing and shall be considered as duly delivered when mailed by registered, certified, or regular mail to the post office address of the parties hereto, as the case may be, as follows: (a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION 5400 Westheimer Court Houston, TX 77056-5310 (b) Customer: UGI UTILITIES, INC. 100 Kachel Blvd. P.O. BOX 12667 Reading, PA 19612-2667 or such other address as either party shall designate by formal written notice. ARTICLE VII ASSIGNMENTS Any Company which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of Customer, or of Pipeline, as the case may be, shall be entitled to the rights and shall be subject to the obligations of its predecessor in title under this Service Agreement; and either Customer or Pipeline may assign or pledge this Service 5 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) Agreement under the provisions of any mortgage, deed of trust, indenture, bank credit agreement, assignment, receivable sale, or similar instrument which it has executed or may execute hereafter; otherwise, neither Customer nor Pipeline shall assign this Service Agreement or any of its rights hereunder unless it first shall have obtained the consent thereto in writing of the other; provided further, however, that neither Customer nor Pipeline shall be released from its obligations hereunder without the consent of the other. In addition, Customer may assign its rights to capacity pursuant to Section 3.14 of the General Terms and Conditions. To the extent Customer so desires, when it releases capacity pursuant to Section 3.14 of the General Terms and Conditions, Customer may require privity between Customer and the Replacement Customer, as further provided in the applicable Capacity Release Umbrella Agreement. ARTICLE VIII INTERPRETATION The interpretation and performance of this Service Agreement shall be in accordance with the laws of the State of Texas without recourse to the law governing conflict of laws. This Service Agreement and the obligations of the parties are subject to all present and future valid laws with respect to the subject matter, State and Federal, and to all valid present and future orders, rules, and regulations of duly constituted authorities having jurisdiction. ARTICLE IX CANCELLATION OF PRIOR CONTRACT(S) This Service Agreement supersedes and cancels, as of the effective date of this Service Agreement, the contract(s) between the parties hereto as described below: service agreement dated February 23, 1999 between Pipeline and Customer under Pipeline's Rate Schedule FT-1 (Pipeline's Contract No. 8003948). IN WITNESS WHEREOF, the parties hereto have caused this Service Agreement to be signed by their respective Presidents, Vice Presidents or other duly authorized agents and their 6 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) respective corporate seals to be hereto affixed and attested by their respective Secretaries or Assistant Secretaries, the day and year first above written. TEXAS EASTERN TRANSMISSION CORPORATION By /s/ [Illegible] ---------------------------------- ATTEST: /s/ Alan [Illegible] - -------------------- UGI UTILITIES, INC. By /s/ [Illegible] ----------------------------------- ATTEST: /s/ Brendan P. Bovaird - ---------------------- 7 Contract #: 800394R EXHIBIT A, TRANSPORTATION P THS FOR BILLING PURPOSES, DATED 6/15/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1 BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND UGI UTILITIES, INC ("Customer"), DATED 6/15/99: (1) Customer's firm Point(s) of Receipt:
Maximum Daily Receipt Obligation (plus Measurement Point of Applicable Responsi- Receipt Description Shrinkage) (dth) bilities Owner Operator* - ------- ----------- ---------------- -------- ----- --------- 71200 CHEVRON - VENICE, LA PLAQUEMINES 13,050 CHEVRON USA CHEVRON CHEVRON USA PA., LA USA 71750 COLUMBIA GULF - ST. LANDRY PA., 19,425 COLUMBIA COLUMBIA COLUMBIA LA ST LANDRY PA., LA GULF GULF GULF 70011 COLUMBIA GAS - EAGLE, PA 0 TX EAST TX EAST COLUMBIA CHESTER CO., PA TRAM TRAN GAS 75577 COLUMBIA GAS - PENNSBURG, PA 0 TX EAST TX EAST COLUMBIA BUCKS CO., PA TRAN TRAN GAS
* Confirming Party (2) Customer shall have Pipeline's Master Receipt Point List ("MRPL"). Customer hereby agrees that Pipeline's MRPL as revised and published by Pipeline - from time to time is incorporated herein by reference. Customer hereby agrees to comply with the Receipt Pressure obligation as set forth in Section 6 of Pipeline's General Terms and Conditions at such Point(s) of Receipt. A-1 Contract #: 800394R EXHIBIT A,TRANSPORTATION PATHS, continued UGI UTILITIES, INC.
Transportation Transportation Path Path Quantity (Dth/D) ------------------- --------------------- Ml to M3 32,475
SIGNED FOR IDENTIFICATION PIPELINE: /s/ [Illegible] -------------------------- CUSTOMER: /s/ [Illegible] -------------------------- SUPERSEDES EXHIBIT A DATED: ---------------------------------- A-2 Contract #: 800394R EXHIBIT B, POINT(S) OF DELIVERY, DATED 6/15/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1 BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND UGI UTILITIES, INC. ("Customer"), DATED 6/15/99
Maximum Measure- Daily ment Point of Delivery Delivery Pressure Responsi- Delivery Description Obligation Obligation bilities Owner Operator * -------- ----------- ---------- ---------- -------- ----- ---------- (dth) 1. 70011 COLUMBIA GAS - EAGLE, PA 32,475 dth AS PROVIDED IN TX EAST TX EAST COLUMBIA CHESTER CO., PA during the SECTION 6 OF THE TRAN TRAN GAS period April GENERAL TERMS AND 16 through CONDITIONS OF November 15 PIPELINE'S FERC GAS of each year TARIFF otherwise 28,192 dth 2. 70069 UGI UTILITIES - 5,190 AS PROVIDED IN TX EAST TX EAST UGI COLUMBIA, PA LANCASTER SECTION 6 OF THE TRAN TRAN UTILITIES CO., PA GENERAL TERMS AND CONDITIONS OF PIPELINE'S FERC GAS TARIFF 3. 70070 UGI UTILITIES - LANCASTER, 32,475 AS PROVIDED IN TX EAST TX EAST UGI PA LANCASTER CO., PA SECTION 6 OF THE TRAN TRAN UTILITIES GENERAL TERMS AND CONDITIONS OF PIPELINE'S FERC GAS TARIFF 4. 70321 UGI UTILITIES - LEBANON, 17,000 400 POUNDS PER SQUARE TX EAST TX EAST UGI PA LEBANON CO., PA INCH GAUGE TRAN TRAN UTILITIES 5. 70322 UGI UTILITIES - READING, 32,475 400 POUNDS PER SQUARE TX EAST TX EAST UGI PA BERKS CO., PA INCH GAUGE TRAN TRAN UTILITIES 6. 70486 UGI UTILITIES - 6,500 400 POUNDS PER SQUARE TX EAST TX EAST UGI WOMELSDORF, PA BERKS INCH GAUGE TRAN TRAN UTILITIES CO., PA 7. 70519 UGI UTILITIES - DAUPHIN 32,475 400 POUNDS PER SQUARE TX EAST TX EAST UGI CO., PA DAUPHIN CO., INCH GAUGE TRAN TRAN UTILITIES
B-1 EXHIBIT B, POINT(S) OF DELIVERY (Continued) UGI UTILITIES, INC. Contract #: 800394R
Maximum Measure- Daily ment Point of Delivery Delivery Pressure Responsi- Delivery Description Obligation Obligation bilities Owner Operator * -------- ----------- ---------- ---------- -------- ----- ---------- (dth) 8. 71461 COLUMBIA GAS - RICH 5,190 SUCH PRESSURE AS MAY TX EAST COLUMBIA UGI HILL, BUCKS CO., PA BE AVAILABLE BY TRAN GAS UTILITIES PIPELINE AT THE POINT OF DELIVERY 9. 71528 UGI UTILITIES - 7,200 300 POUNDS PER SQUARE TX EAST TX EAST UGI LANCASTER CO., PA INCH GAUGE TRAN TRAN UTILITIES 10. 72571 COLUMBIA GAS - BERKS 519 400 POUNDS PER SQUARE TX EAST COLUMBIA UGI CO., PA INCH GAUGE TRAN GAS UTILITIES 11. 79513 SS-1 STORAGE POINT 3,612 N/A N/A N/A N/A 04/01-10/31 3,612 11/01-03/31 12. 75577 COLUMBIA GAS - 0 AS PROVIDED IN TX EAST TX EAST COLUMBIA PENNSBURG, PA, BUCKS SECTION 6 OF THE TRAN TRAN GAS CO., PA GENERAL TERMS AND CONDITIONS OF PIPELINE'S FERC GAS TARIFF
*Confirming Party provided, however, that Pipeline is not obligated to deliver under Rate Schedules FT-1, CDS and FTS-5 on any one day an aggregate of more than 88,418 dth per day to points of delivery 70011, 70069, 70070 and 71528 during the period November 16 through April 15, and further provided, that during this time period Pipeline is not obligated to deliver under Rate Schedules FT-1, CDS and FTS-5 on any one day an aggregate of more than 94,904 dth to points of delivery 70321, 70322, 70486, 70519, 71461 and 72571; and further provided, however, that until changed by a subsequent Agreement between Pipeline and Customer, Pipeline's aggregate maximum daily delivery obligations under this and all other firm Service Agreements existing between Pipeline and Customer, shall in no event exceed the following:
Aggregate Maximum Daily Point of Delivery Delivery Obligation (dth) ----------------- ------------------------- No. 1 68,785 No. 2 5,190 No. 3 49,000 No. 4 17,000 No. 5 65,880
B-2 Contract #: 800394R EXHIBIT B, POINT(S) OF DELIVERY (Continued) UGI UTILITIES, INC.
Aggregate Maximum Daily Point of Delivery Delivery Obligation (dth) ----------------- ------------------------- No. 6 6,500 No. 7 53,000 No. 8 5,190 No. 9 17,200 No. 10 7,186 No. 11 3,612
Further, pursuant to Section 14.9 of the General Terms and Conditions of Pipeline's FERC Gas Tariff Sixth Revised Volume/No. 1, Customer has been allocated firm capacity at the Points of Delivery as shown below for deliveries under Rate Schedules CDS, FT-1, SCT, and/or SS-1 at such pressure available in Pipeline's facilities at the point of delivery, subject to receipt of such quantities being acceptable to the Owner and Operator of the Point of Delivery: Section 14.9
Measurement Point of Firm Responsi- Delivery Description Capacity bilities Owner Operator -------- ----------- -------- -------- ----- -------- (dth/d) 1. 70011 COLUMBIA GAS (MFGRS.) - 85,635 TX EAST TRAN TX EAST TRAN COLUMBIA GAS EAGLE, PA CHESTER CO., 4/1/97-10/31/97 PA 49,635 11/1/97-10/31/98 2. 70069 UGI UTILITIES - 12,700 TX EAST TRAN TX EAST TRAN UGI COLUMBIA, PA LANCASTER UTILITIES CO., PA 3. 70070 UGI UTILITIES - 31,328 TX EAST TRAN TX EAST TRAN UGI COLUMBIA, PA LANCASTER, UTILITIES PA LANCASTER CO., PA/ 4. 70321 UGI UTILITIES - LEBANON, 1,253 TX EAST TRAN TX EAST TRAN UGI PA LEBANON CO., PA UTILITIES
B-3 Contract #: 800394R EXHIBIT B, POINT(S) OF DELIVERY (Continued) UGI UTILITIES, INC.
Section 14.9 Measurement Point of Firm Responsi- Delivery Description Capacity bilities Owner Operator -------- ----------- -------- -------- ----- -------- (dth/d) 5. 70486 UGI UTILITIES - 3,670 TX EAST TRAN TX EAST TRAN UGI UTILITIES WOMELSDORF, PA BERKS CO., PA 6. 71438 DAUPHIN CO. GAS - 2,580 TX EAST TRAN TX EAST TRAN PENN FUEL ANNVILLE, LEBANON CO, PA 7. 71461 UGI UTILITIES - RICH 840 TX EAST TRAN COLUMBIA GAS COLUMBIA GAS HILL, BUCKS CO., PA 8. 72571 UGI UTILITIES - BERKS, 13,984 TX EAST TRAN COLUMBIA GAS COLUMBIA GAS CO., PA 9. 75577 UGI UTILITIES - 75,440 TX EAST TRAN COLUMBIA GAS COLUMBIA GAS PENNSBURG, PA BUCKS CO., PA
SIGNED FOR IDENTIFICATION PIPELINE: /s/ [Illegible] -------------------------- CUSTOMER: /s/ [Illegible] -------------------------- SUPERSEDES EXHIBIT B DATED: ---------------------------------- B-4 Contract#: 800394R2 EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY, DATED 6/15/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1 BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION "PIPELINE") AND UGI UTILITIES, INC. ("CUSTOMER"), DATED 6/15/99: ZONE BOUNDARY ENTRY QUANTITY Dth/D To
FROM STX ETX WLA ELA M1-24 Ml-30 M1-TXG Ml-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- STX 1177 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- ETX 154 1781 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- WLA 543 1177 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- ELA 27643 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M1-24 154 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M1-30 27643 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- Ml-TXG 2324 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- Ml-TGC 2354 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M2-24 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M2-30 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M2-TXG - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M2-TGC - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M2 32475 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M3 ==== === === === === ===== ====== ====== ====== ===== ===== ====== ====== == =====
C-1 Contract #: 800394R EXHIBIT C (Continued) UGI UTILITIES, INC. ZONE BOUNDARY EXIT QUANTITY Dth/D To
FROM STX ETX WLA ELA M1-24 Ml-30 M1-TXG Ml-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- STX - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- ETX - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- WLA - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- ELA - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- Ml-24 154 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M1-30 27643 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- Ml-TXG 2324 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M1-TGC 2354 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M2-24 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M2-30 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M2-TXG - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M2-TUC - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M2 32475 - ---- --- --- --- --- ----- ------ ------ ------ ----- ----- ------ ------ -- ----- M3 ==== === === === === ===== ====== ====== ====== ===== ===== ====== ====== == =====
SIGNED FOR IDENTIFICATION PIPELINE: /s/ [Illegible] -------------------------- CUSTOMER: /s/ [Illegible] -------------------------- SUPERSEDES EXHIBIT C DATED: ---------------------------------- C-2 EX-10.30 9 w66595exv10w30.txt FIRM TRANSPORTATION SERVICE AGREEMENT EXHIBIT 10.30 Contract #: 800240R1 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 This Service Agreement, made and entered into this 31st day of October, 2000, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware Corporation (herein called "Pipeline") and UGI UTILITIES, INC. (herein called "Customer", whether one or more), W I T N E S S E T H: WHEREAS, Customer and Pipeline are currently parties to an executed service agreement dated February 23, 1999, under Pipeline's Rate Schedule FT-1 (Pipeline's Contract No. 8002408); and WHEREAS, Customer and Pipeline desire to enter into this Service Agreement to supersede Pipeline's currently effective Contract No. 8002408 and to extend the primary term of such service agreement; NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements herein contained, the parties do covenant and agree as follows: ARTICLE I SCOPE OF AGREEMENT Subject to the terms, conditions and limitations hereof, of Pipeline's Rate Schedule FT-1, and of the General Terms and Conditions, transportation service hereunder will be firm. Subject to the terms, conditions and limitations hereof and of Pipeline's Rate Schedule FT-1, Pipeline agrees to deliver for Customer's account quantities of natural gas up to the following quantity: Maximum Daily Quantity (MDQ) 25,000 dth Pipeline shall receive for Customer's account, at those points on Pipeline's system as specified in Article IV herein or available to Customer pursuant to Section 14 of the General Terms and Conditions (hereinafter referred to as Point(s) of Receipt) for transportation hereunder daily quantities of gas up to Customer's MDQ, plus Applicable Shrinkage. Pipeline shall transport and deliver for Customer's account, at those points on SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) Pipeline's system as specified in Article IV herein or available to Customer pursuant to Section 14 of the General Terms and Conditions (hereinafter referred to as Point(s) of Delivery), such daily quantities tendered up to such Customer's MDQ. Pipeline shall not be obligated to, but may at its discretion, receive at any Point of Receipt on any day a quantity of gas in excess of the applicable Maximum Daily Receipt Obligation (MDRO), plus Applicable Shrinkage, but shall not receive in the aggregate at all Points of Receipt on any day a quantity of gas in excess of the applicable MDQ, plus Applicable Shrinkage. Pipeline shall not be obligated to, but may at its discretion, deliver at any Point of Delivery on any day a quantity of gas in excess of the applicable Maximum Daily Delivery Obligation (MDDO), but shall not deliver in the aggregate at all Points of Delivery on any day a quantity of gas in excess of the applicable MDQ. In addition to the MDQ and subject to the terms, conditions and limitations hereof; Rate Schedule FT-1 and the General Terms and Conditions, Pipeline shall deliver within the Access Area under this and all other, service agreements under Rate Schedules CDS, FT-1, and/or SCT, quantities up to Customer's Operational Segment Capacity Entitlements, excluding those Operational Segment Capacity Entitlements scheduled to meet Customer's MDQ, for Customer's account, as requested on any day. ARTICLE II TERM OF AGREEMENT The term of this Service Agreement shall commence on the first day of the first month after Customer fully executes this Service Agreement and shall continue in force and effect until October 31, 2004 and year to year thereafter unless this Service Agreement is terminated as hereinafter provided. This Service Agreement may be terminated by either Pipeline or Customer upon one (1) year prior written notice to the other specifying a termination date of October 31, 2004 or any October 31 thereafter. Subject to Section 22 of Pipeline's General Terms and Conditions and without prejudice to such rights, this Service Agreement may be terminated at any time by Pipeline in the event Customer fails to pay part or all of the amount of any bill for service hereunder and such failure continues for thirty (30) days after payment is due; provided, Pipeline gives thirty 2 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) (30) days prior written notice to Customer of such termination and provided further such termination shall not be effective if, prior to the date of termination, Customer either pays such outstanding bill or furnishes a good and sufficient surety bond guaranteeing payment to Pipeline of such outstanding bill. THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT TERM OR THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER TRIGGERS PREGRANTED ABANDONMENT UNDER SECTION 7 OF THE NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF THE TERMINATION. PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS AND CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION. Any portions of this Service Agreement necessary to correct or cash-out imbalances under this Service Agreement as required by the General Terms and Conditions of Pipeline's FERC Gas Tariff, Volume No: 1, shall survive the other parts of this Service Agreement until such time as such balancing has been accomplished. ARTICLE III RATE SCHEDULE This Service Agreement in all respects shall be and remain subject to the applicable provisions of Rate Schedule FT-1 and of the General Terms and Conditions of Pipeline's FERC Gas Tariff on file with the Federal Energy Regulatory Commission, all of which are by this reference made a part hereof. Customer shall pay Pipeline, for all services rendered hereunder and for the availability of such service in the period stated, the applicable prices established under Pipeline's Rate Schedule FT-1 as filed with the Federal Energy Regulatory Commission, and as same may hereafter be legally amended or superseded. Customer agrees that Pipeline shall have the unilateral right to file with the appropriate regulatory authority and make changes effective in (a) the rates and charges applicable to service pursuant to Pipeline's Rate Schedule FT-1, (b) Pipeline's Rate Schedule FT-1 pursuant to which service hereunder is rendered or (c) any provision of the General Terms 3 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) and Conditions applicable to Rate Schedule FT-1. Notwithstanding the foregoing, Customer does not agree that Pipeline shall have the unilateral right without the consent of Customer subsequent to the execution of this Service Agreement and Pipeline shall not have the right during the effectiveness of this Service Agreement to make any filings pursuant to Section 4 of the Natural Gas Act to change the MDQ specified in Article I, to change the term of the agreement as specified in Article II, to change Point(s) of Receipt specified in Article IV, to change the Point(s) of Delivery specified in Article IV, or to change the firm character of the service hereunder. Pipeline agrees that Customer may protest or contest the aforementioned filings, and Customer does not waive any rights it may have with respect to such filings. ARTICLE IV POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY The Point(s) of Receipt and Point(s) of Delivery at which Pipeline shall receive and deliver gas, respectively, shall be specified in Exhibit(s) A and B of the executed service agreement. Customer's Zone Boundary Entry Quantity and Zone Boundary Exit Quantity for each of Pipeline's zones shall be specified in Exhibit C of the executed service agreement. Exhibit(s) A, B and C are hereby incorporated as part of this Service Agreement for all intents and purposes as if fully copied and set forth herein at length. ARTICLE V QUALITY All natural gas tendered to Pipeline for Customer's account shall conform to the quality specifications set forth in Section 5 of Pipeline's General Terms and Conditions. Customer agrees that in the event Customer tenders for service hereunder and Pipeline agrees to accept natural gas which does not comply with Pipeline's quality specifications, as expressly provided for in Section 5 of Pipeline's General Terms and Conditions, Customer shall pay all costs associated with processing of such gas as necessary to comply with such quality specifications. Customer shall execute or cause its supplier to execute, if such supplier has retained processing rights to the gas delivered to Customer, the appropriate agreements prior to the commencement of service 4 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) for the transportation and processing of any liquefiable hydrocarbons and any PVR quantities associated with the processing of gas received by Pipeline at the Point(s) of Receipt under such Customer's service agreement. In addition, subject to the execution of appropriate agreements, Pipeline is willing to transport liquids associated with the gas produced and tendered for transportation hereunder. ARTICLE VI ADDRESSES Except as herein otherwise provided or as provided in the General Terms and Conditions of Pipeline's FERC Gas Tariff, any notice, request, demand, statement, bill or payment provided for in this Service Agreement, or any notice which any party may desire to give to the other, shall be in writing and shall be considered as duly delivered when mailed by registered, certified, or regular mail to the post office address of the parties hereto, as the case may be, as follows: (a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION 5400 Westheimer Court Houston, TX 77056-5310 (b) Customer: UGI UTILITIES, INC. 100 Kachel Blvd. P.O. Box 12667 Reading, PA 19612-2667 or such other address as either party shall designate by formal written notice. ARTICLE VII ASSIGNMENTS Any Company which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of Customer, or of Pipeline, as the case may be, shall be entitled to the rights and shall be subject to the obligations of its predecessor in title under this Service Agreement; and either Customer or Pipeline may assign or pledge this Service Agreement under the provisions of any mortgage, deed of trust, indenture, bank credit agreement, assignment, receivable sale, 5 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) or similar instrument which it has executed or may execute hereafter; otherwise, neither Customer nor Pipeline shall assign this Service Agreement or any of its rights hereunder unless it first shall have obtained the consent thereto in writing of the other; provided further, however, that neither Customer nor Pipeline shall be released from, its obligations hereunder without the consent of the other. In addition, Customer may assign its rights to capacity pursuant to Section 3.14 of the General Terms and Conditions. To the extent Customer so desires, when it releases capacity pursuant to Section 3.14 of the General Terms and Conditions, Customer may require privity between Customer and the Replacement Customer, as further provided in the applicable Capacity Release Umbrella Agreement. ARTICLE VIII INTERPRETATION The interpretation and performance of this Service Agreement shall be in accordance with the laws of the State of Texas without recourse to the law governing conflict of laws. This Service Agreement and the obligations of the parties are subject to all present and future valid laws with respect to the subject matter, State and Federal, and to all valid present and future orders, rules, and regulations of duly constituted authorities having jurisdiction. ARTICLE IX CANCELLATION OF PRIOR CONTRACT(S) This Service Agreement supersedes and cancels, as of the effective date of this Service Agreement, the contract(s) between the parties hereto as described below: service agreement dated February 23, 1999, between Pipeline and Customer under Pipeline's Rate Schedule FT-1 (Pipeline's Contract No. 800240R). 6 SERVICE AGREEMENT FOR RATE SCHEDULE FT-1 (Continued) IN WITNESS WHEREOF, the parties hereto have caused this Service Agreement to be signed by their respective Presidents, Vice Presidents or other duly authorized agents and their respective corporate seals to be hereto affixed and attested by their respective Secretaries or Assistant Secretaries, the day and year first above written. TEXAS EASTERN TRANSMISSION CORPORATION By /s/ Gregory J. Rizzo ----------------------------------- Gregory J Rizzo Vice President, Marketing ATTEST: /s/ Beverly J. Lite - ------------------------------ Assistant Secretary UGI UTILITIES, INC. By /s/ [Illegible] --------------------------------- ATTEST: - ------------------------------ 7 EX-10.31 10 w66595exv10w31.txt FIRM TRANSPORTATION SERVICE AGREEMENT EXHIBIT 10.31 SERVICE AGREEMENT between TRANSCONTINENTAL GAS PIPE LINE CORPORATION and UGI UTILITIES, INC. SERVICE AGREEMENT (CONTINUED) SERVICE AGREEMENT THIS AGREEMENT entered into this 1st day of October, 1996, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as "Seller," first party, and UGI UTILITIES, INC., hereinafter referred to as "Buyer," second party, WITNESSETH WHEREAS, pursuant to the Federal Energy Regulatory Commission's (Commission) Order No. 636 and Seller's procedures set forth on page 7 of Seller's August 4, 1993 Order No. 636 Compliance Filing in Docket No. RS92-86, Buyer has notified Seller of its desire to unbundle its bundled firm transportation service under Seller's Rate Schedule FT-NT and convert such service from Part 157 of the Commission's regulations to service with Seller and the upstream pipeline(s) under Part 284(g) of the Commission's regulations; and WHEREAS, Buyer has designated that Seller's Part 284(g) service will be rendered under Seller's Rate Schedule FT; and WHEREAS, Seller has prepared this agreement for service for Buyer under Rate Schedule FT, and this agreement will supersede and terminate the existing service agreement between Seller and Buyer under Rate Schedule FT-NT; and WHEREAS, this agreement shall not be effective until Seller's service agreements) with the upstream transporter(s) has (have) been amended to reflect Seller's reduced transportation service entitlement. NOW, THEREFORE, Seller and Buyer agree as follows: ARTICLE I GAS TRANSPORTATION SERVICE 1. Subject to the terms and provisions of this agreement and of Seller's Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up to the dekatherm equivalent of a Transportation Contract Quantity ("TCQ") of ) 22,000 Mcf per day. 2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 of the General Terms and Conditions of Seller's FERC Gas Tariff. ARTICLE II POINT(S) OF RECEIPT Buyer shall deliver or cause to be delivered gas at the points) of receipt hereunder at a pressure sufficient to allow the gas to enter Seller's pipeline system at the varying pressures that may exist in such system from time to time; provided, however, the pressure of the gas delivered or caused to be delivered by Buyer shall not exceed the maximum operating pressure(s) of Seller's pipeline system at such point(s) of receipt. In the event the maximum 2 SERVICE AGREEMENT (CONTINUED) operating, pressure(s) of Seller's pipeline system, at the point(s) of receipt hereunder, is from time to time increased or decreased, then the maximum allowable pressure(s) of the gas delivered or caused to be delivered by Buyer to Seller at the point(s) of receipt shall be correspondingly increased or decreased upon written notification of Seller to Buyer. The point(s) of receipt for natural gas received for transportation pursuant to this agreement shall be: See Exhibit A, attached hereto, for points of receipt. ARTICLE III POINT(S) OF DELIVERY Seller shall redeliver to Buyer or for the account of Buyer the gas transported hereunder at the following points) of delivery and at a pressure(s) of: See Exhibit B, attached hereto, for points of delivery and pressures. ARTICLE IV TERM OF AGREEMENT This agreement shall be effective as of October 1, 1996 and shall remain in force and effect until 8:00 a.m. Eastern Standard Time October 31, 2006 and thereafter until terminated by Seller or Buyer upon at least twelve (12) months written notice; provided, however, this agreement shall terminate immediately and, subject to the receipt of necessary authorizations, if any. Seller may discontinue service hereunder if (a) Buyer, in Seller's reasonable judgement fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate security in accordance with Section 32 of the General Terms and Conditions of Seller's Volume No. 1 Tariff. As set forth in Section 8 of Article II of Seller's August 7, 1989 revised Stipulation and Agreement in Docket Nos. RP88-68 et. al., (a) pregranted abandonment under Section 284.221 (d) of the Commission's Regulations shall not apply to any long term conversions from firm sales service to transportation service under Seller's Rate Schedule FT and (b) Seller shall not exercise its right to terminate this service agreement as it applies to transportation service resulting from conversions from firm sales service so long as Buyer is willing to pay rates no less favorable than Seller is otherwise able to collect from third parties for such service. ARTICLE V RATE SCHEDULE AND PRICE 1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in accordance with Seller's Rate Schedule FT and the applicable provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be legally amended or superseded from time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof. 2. Seller and Buyer agree that the quantity of gas that Buyer delivers or causes to be delivered to Seller shall include the quantity of gas retained by Seller for applicable compressor fuel, line loss make-up (and injection fuel under Seller's Rate Schedule GSS, if applicable) in providing the transportation service hereunder, which quantity may be changed from time to time and which 3. In addition to the applicable charges for firm transportation service pursuant to Section 3 of Seller's Rate Schedule FT, Buyer shall reimburse Seller for any and all filing fees 3 SERVICE AGREEMENT (CONTINUED) incurred as a result of Buyer's request for service under Seller's Rate Schedule FT, to the extent such fees are imposed upon Seller by the Federal Energy Regulatory Commission or any successor governmental authority having jurisdiction. ARTICLE VI MISCELLANEOUS 1. This Agreement supersedes and cancels as of the effective date hereof the following contract(s) between the parties hereto: Rate Schedule FT-NT Service Agreement between Seller and Buyer dated July 20, 1992 as amended October 1, 1992 and February 1, 1993. 2. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character. 3. The interpretation and performance of this agreement shall be in accordance with the laws of the State of Texas, without recourse to the law governing conflict of laws, and to all present and future valid laws with respect to the subject matter, including present and future orders, rules and regulations of duly constituted authorities. 4. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns. 5. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address: (a) If to Seller: Transcontinental Gas Pipe Line Corporation P.O. Box 1396 Houston, Texas, 77251 Attention: Customer Services (b) If to Buyer: UGI UTILITIES, INC. P.O. Box 13009 Reading, Pennsylvania 19612-3009 Attention: Vice President - Gas Supply Such addresses may be changed from time to time by mailing appropriate notice thereof to the other party by certified or registered mail. IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized. 4 SERVICE AGREEMENT (CONTINUED) TRANSCONTINENTAL GAS PIPE LINE CORPORATION (Seller) By: /s/ Rosemary W. Schatzman ----------------------------------------- Rosemary W. Schatzman Director of Customer Service & Scheduling UGI UTILITIES, INC. (Buyer) By: /s/ R.J. Chaney ----------------------------------------- Title: -------------------------------------- 5 EXHIBIT A
BUYER'S CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d) 1/ ------------------- ---------------------- The point of interconnection between the 22,000 facilities of Seller and CNG Transmission Corporation at Leidy in Clinton County, Pennsylvania.
1/ These quantities do not include the additional quantities of gas retained by Seller for applicable compressor fuel and line loss make-up provided for in Article V, 2 of this Service Agreement, which are subject to change as provided for in Article V, 2 hereof. EXHIBIT B
POINT(S) OF DELIVERY PRESSURE(S) -------------------- ----------- Hazelton District Meter Station, located at Not less than fifty (50) pounds per square mile post 61.73 on Seller's Leidy inch gauge or at such other pressures as may Transmission Line approximately 3,400 feet be agreed upon in the day to day operations east of Junction of Pennsylvania Highways of Buyer and Seller. 940 and 115 in Tobyhanna Township, Monroe County, Pennsylvania. TEVCO-UGI Meter Station (Humbolt), Luzerne Not less than fifty (50) pounds per square County, Pennsylvania. inch gauge or at such other pressures as may be agreed upon in the day to day operations of Buyer and Seller. Quarryville Meter Station, Lancaster County, Not less than fifty (50) pounds per square Pennsylvania. inch gauge or at such other pressures as may be agreed upon in the day to day operations of Buyer and Seller.
EX-12.1 11 w66595exv12w1.txt RATIO OF EARNINGS TO FIXED CHARGES UGI UTILITIES INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1 (THOUSANDS OF DOLLARS)
Year Ended September 30, ----------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ----------- ------------ ------------ ----------- ------------ EARNINGS: Earnings before income taxes $ 73,665 $ 79,568 $ 82,882 $ 63,139 $ 57,007 Interest expense 16,365 18,724 18,135 17,317 17,383 Amortization of debt discount and expense 287 264 218 215 200 Interest component of rental expense 1,563 1,541 1,318 1,539 1,624 ---------- ---------- ----------- ---------- ---------- $ 91,880 $ 100,097 $ 102,553 $ 82,210 $ 76,214 ========== ========== =========== ========== ========== FIXED CHARGES: Interest expense $ 16,365 $ 18,724 $ 18,135 $ 17,317 $ 17,383 Amortization of debt discount and expense 287 264 218 215 200 Allowance for funds used during construction (capitalized interest) 19 12 17 36 39 Interest component of rental expense 1,563 1,541 1,318 1,539 1,624 ---------- ---------- ----------- ---------- ---------- $ 18,234 $ 20,541 $ 19,688 $ 19,107 $ 19,246 ========== ========== =========== ========== ========== Ratio of earnings to fixed charges 5.04 4.87 5.21 4.30 3.96 ========== ========== =========== ========== ==========
EX-12.2 12 w66595exv12w2.txt RATIO OF EARNINGS TO COMBINED FIXED CHARGES UGI UTILITIES INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS - EXHIBIT 12.2 (THOUSANDS OF DOLLARS)
Year Ended September 30, ----------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ----------- ------------ ------------ ----------- ------------ EARNINGS: Earnings before income taxes $ 73,665 $ 79,568 $ 82,882 $ 63,139 $ 57,007 Interest expense 16,365 18,724 18,135 17,317 17,383 Amortization of debt discount and expense 287 264 218 215 200 Interest component of rental expense 1,563 1,541 1,318 1,539 1,624 ---------- ---------- ---------- --------- --------- $ 91,880 $ 100,097 $ 102,553 $ 82,210 $ 76,214 ========== ========== ========== ========= ========= COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS: Interest expense $ 16,365 $ 18,724 $ 18,135 $ 17,317 $ 17,383 Amortization of debt discount and expense 287 264 218 215 200 Allowance for funds used during construction (capitalized interest) 19 12 17 36 39 Interest component of rental expense 1,563 1,541 1,318 1,539 1,624 Preferred stock dividend requirements 1,550 1,550 1,550 1,550 2,160 Adjustment required to state preferred stock dividend requirements on a pretax basis 1,039 1,012 995 968 1,304 ---------- ---------- ---------- --------- --------- $ 20,823 $ 23,103 $ 22,233 $ 21,625 $ 22,710 ========== ========== ========== ========= ========= Ratio of earnings to combined fixed charges and preferred stock dividends 4.41 4.33 4.61 3.80 3.36 ========== ========== ========== ========= =========
EX-23 13 w66595exv23.txt CONSENT OF PRICEWATERHOUSECOOPERS LLP EXHIBIT 23 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-4288 and 333-72540) of UGI Utilities, Inc. of our report dated November 15, 2002 relating to the financial statements and financial statement schedule, which appears in this Form 10-K. PricewaterhouseCoopers LLP Philadelphia, Pennsylvania December 23, 2002 EX-99 14 w66595exv99.txt CERTIFICATION BY CEO AND CFO EXHIBIT 99 CERTIFICATION BY THE CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER RELATING TO A PERIODIC REPORT CONTAINING FINANCIAL STATEMENTS I, Robert J. Chaney, Chief Executive Officer, and I, John C. Barney, Chief Financial Officer, of UGI Utilities, Inc., a Pennsylvania corporation (the "Company"), hereby certify that: (1) The Company's periodic report on Form 10-K for the period ended September 30, 2002 (the "Form 10-K") fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and (2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company. * * * CHIEF EXECUTIVE OFFICER CHIEF FINANCIAL OFFICER Robert J. Chaney John C. Barney - --------------------------- -------------------------- Robert J. Chaney John C. Barney Date: December 20, 2002 Date: December 20, 2002 -------------------- ------------------- -----END PRIVACY-ENHANCED MESSAGE-----