-----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, RODMu2FmiCo6IqOvPmfCwyzV6KUu6YCPlDiL5DUS62bSE2f+fx96qesqkdJLIMLF GnUgq9IkfHLFw13yR9zv9w== 0000893220-00-001436.txt : 20001225 0000893220-00-001436.hdr.sgml : 20001225 ACCESSION NUMBER: 0000893220-00-001436 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 20000930 FILED AS OF DATE: 20001222 FILER: COMPANY DATA: COMPANY CONFORMED NAME: UGI CORP /PA/ CENTRAL INDEX KEY: 0000884614 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 232668356 STATE OF INCORPORATION: PA FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-11071 FILM NUMBER: 794829 BUSINESS ADDRESS: STREET 1: 460 N GULPH RD STREET 2: P O BOX 858 CITY: KING OF PRUSSIA STATE: PA ZIP: 19406 BUSINESS PHONE: 6103371000 MAIL ADDRESS: STREET 1: 460 NORTH GULPH ROAD CITY: KING OF PRUSSIA STATE: PA ZIP: 19406 FORMER COMPANY: FORMER CONFORMED NAME: NEW UGI CORP DATE OF NAME CHANGE: 19600201 10-K 1 w43405e10-k.txt ANNUAL REPORT FOR FISCAL YEAR ENDED 09/30/2000 1 ================================================================================ 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, 2000 Commission file number 1-11071 UGI CORPORATION (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) Pennsylvania 23-2668356 (STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.) INCORPORATION OR ORGANIZATION) 460 North Gulph Road, King of Prussia, PA 19406 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) (610) 337-1000 (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE TITLE OF CLASS ON WHICH REGISTERED Common Stock, without par value New York Stock Exchange, Inc. Philadelphia Stock Exchange, Inc. 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. [ ] The aggregate market value of UGI Corporation Common Stock held by nonaffiliates of the registrant on December 1, 2000 was $630,716,648. At December 8, 2000 there were 27,024,689 shares of UGI Corporation Common Stock issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Annual Report to Shareholders for the year ended September 30, 2000 are incorporated by reference into Parts I and II of this Form 10-K. Portions of the Proxy Statement for the Annual Meeting of Shareholders to be held on February 27, 2001 are incorporated by reference into Part III of this Form 10-K. ================================================================================ 2
TABLE OF CONTENTS PART I BUSINESS PAGE Items 1 and 2 Business and Properties.................................................... 1 AmeriGas Propane Business.................................................. 2 Utility Operations......................................................... 9 UGI Enterprises, Inc....................................................... 17 - Domestic Businesses ....................................... 17 - International Businesses .................................. 17 Item 3 Legal Proceedings.......................................................... 19 Item 4 Submission of Matters to a Vote of Security Holders........................................................... 21 PART II SECURITIES AND FINANCIAL INFORMATION Item 5 Market for Registrant's Common Equity and Related Stockholder Matters............................................ 21 Item 6 Selected Financial Data.................................................... 23 Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations.............................. 24 Item 7A Quantitative and Qualitative Disclosures About Market Risk................. 24 Item 8 Financial Statements and Supplementary Data................................ 24 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure......................... 24 PART III UGI MANAGEMENT AND SECURITY HOLDERS Item 10 Directors and Executive Officers of the Registrant......................... 25 Item 11 Executive Compensation..................................................... 25 Item 12 Security Ownership of Certain Beneficial Owners and Management...................................................... 25 Item 13 Certain Relationships and Related Transactions............................. 25 PART IV ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS Item 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K.................................................... 28 Signatures................................................................. 34 Index to Financial Statements and Financial Statement Schedules.............................................. F-2
(i) 3 PART I: BUSINESS ITEMS 1 AND 2. BUSINESS AND PROPERTIES UGI Corporation is a holding company that operates propane distribution, gas and electric utility, energy marketing and related businesses through subsidiaries. Our majority-owned subsidiary, AmeriGas Partners, L.P., a Delaware limited partnership ("AmeriGas Partners" or the "Partnership"), conducts one of the nation's largest retail propane distribution businesses through its 98.99% owned subsidiary AmeriGas Propane, L.P. (the "Operating Partnership"). We have been in the retail propane distribution business for over 40 years, operating through various subsidiaries. The Partnership's sole general partner is our subsidiary, AmeriGas Propane, Inc. ("AmeriGas Propane" or the "General Partner"). The common units of AmeriGas Partners, which represent limited partner interests, are traded on the New York Stock Exchange under the symbol "APU." We have a 55.5% combined ownership interest in the Partnership and the Operating Partnership. The remaining interest is publicly held. Our subsidiary UGI Utilities, Inc. ("Utilities") owns and operates a natural gas distribution utility and an electric distribution utility in eastern Pennsylvania. In response to state deregulation legislation, effective October 1, 1999, Utilities' transferred its electric generation assets to its 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. Utilities is the successor to a business founded in 1882. It serves 272,000 natural gas customers and 61,000 electric customers. Our subsidiary UGI Enterprises, Inc. ("Enterprises") conducts domestic and international businesses through subsidiaries. The domestic businesses include retail gas and electric marketing, a retailer of hearth, spa and grill products, Hearth USA(TM), and a heating, ventilation and air-conditioning business. In September 1999, Enterprises acquired FLAGA GmbH, the largest retail propane distributor in Austria. Enterprises also has two international energy-related joint ventures. We expect Enterprises to continue to evaluate and develop new related and complementary business opportunities for us. UGI was incorporated in Pennsylvania in 1991. UGI is not subject to regulation by the Pennsylvania Public Utility Commission ("PUC"). It is also exempt from registration as a holding company and not otherwise subject to the Public Utility Holding Company Act of 1935, except for Section 9(a)(2), which regulates the acquisition of voting securities of an electric or gas utility company. Our executive offices are located at 460 North Gulph Road, King of Prussia, Pennsylvania 19406, and our telephone number is (610) 337-1000. In this report, the terms "Company" and "UGI," as well as the terms "our," "we," and "its," are sometimes used as abbreviated references to UGI Corporation or, collectively, UGI Corporation and its consolidated subsidiaries. Similarly, the terms "AmeriGas Partners" and the "Partnership" are sometimes used as abbreviated references to AmeriGas Partners, L.P. or, collectively, AmeriGas Partners, L.P. and its subsidiaries, including the Operating Partnership. BUSINESS STRATEGY In July 1999, following a comprehensive study, we announced our intention to refocus our strategic direction on growing our existing natural gas, electric and propane businesses while seeking additional related and complementary growth opportunities. We are employing our core -1- 4 competencies from our existing businesses, as well as using our national scope, extensive asset base and access to customers, to accelerate growth in related and complementary businesses, both domestic and international. During fiscal year 2000, we completed four transactions in pursuit of this strategy. AMERIGAS PROPANE BUSINESS Our domestic propane distribution business is conducted through AmeriGas Partners. The Partnership is one of the largest retail propane distributors in the United States, based on fiscal year 2000 retail volume of 771 million gallons. The Partnership operates from approximately 550 district locations in 45 states. AmeriGas Propane manages the Partnership. Although our consolidated financial statements include 100% of the Partnership's revenues, assets and liabilities, our net income reflects only our majority interest in the income or loss of the Partnership, due to the publicly-owned limited partner interest. See Note 1 to the Company's Consolidated Financial Statements. GENERAL INDUSTRY INFORMATION Propane is separated from crude oil during the refining process and also extracted from natural gas or oil wellhead gas at processing plants. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for economy and ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is colorless and odorless; an odorant is added to allow its detection. Propane is clean burning, producing negligible amounts of pollutants when properly consumed. The primary customers for propane are residential, commercial, agricultural, motor fuel and industrial users to whom natural gas is not readily available. Propane is typically more expensive than natural gas, competitive with fuel oil when operating efficiencies are taken into account and, in most areas, cheaper than electricity on an equivalent energy basis. Several states have adopted or are considering proposals that would substantially deregulate the generation portion of the electric utility industry and thereby permit retail electric customers to choose their electric supplier. While proponents of electric utility deregulation believe that competition will ultimately reduce the cost of electricity, we are unable to predict whether, or the extent to which, the price of electricity may drop. Therefore, we cannot predict the ultimate impact that electric utility deregulation may have on propane's existing competitive price advantage over electricity. -2- 5 PRODUCTS, SERVICES AND MARKETING As of September 30, 2000, the Partnership distributed propane to approximately 968,000 customers from approximately 550 district locations. The Partnership's operations are located primarily in the Northeast, Southeast, Great Lakes and West Coast regions of the United States. The Partnership also sells, installs and services propane appliances, including heating systems. In certain markets, the Partnership also installs and services propane fuel systems for motor vehicles. Typically, district locations are found in suburban and rural areas where natural gas is not available. Districts generally consist of an office, appliance showroom, warehouse and service facilities, with one or more 18,000 to 30,000 gallon storage tanks on the premises. As part of its overall transportation and distribution infrastructure, the Partnership operates as an interstate carrier in 48 states throughout the United States. It is also licensed as a carrier in Canada. The Partnership sells propane primarily to five markets: residential, commercial/industrial, motor fuel, agricultural and wholesale. Approximately 75% of the Partnership's 2000 fiscal year sales (based on gallons sold) were to retail accounts and approximately 25% were to wholesale customers. Sales to residential customers in fiscal 2000 represented approximately 40% of retail gallons sold, industrial/commercial customers 37%, motor fuel customers 15%, and agricultural customers 8%. Residential customers represented 49% of the Partnership's total propane margin. No single customer accounts for 1% or more of the Partnership's consolidated revenues. In the residential market, which includes both conventional and manufactured housing, propane is used primarily for home heating, water heating and cooking purposes. Commercial users, which include motels, hotels, restaurants and retail stores, generally use propane for the same purposes as residential customers. The PPX Prefilled Propane Xchange program ("PPX(R)") enables consumers to exchange their empty 20-pound propane grill cylinders for filled cylinders at various retail locations such as home center and convenience stores. Sales of our PPX(R) grill cylinders to retailers are included in the commercial/industrial market. Industrial customers use propane to fire furnaces, as a cutting gas and in other process applications. Other industrial customers are large-scale heating accounts and local gas utility customers who use propane as a supplemental fuel to meet peak load deliverability requirements. As a motor fuel, propane is burned in internal combustion engines that power over-the-road vehicles, forklifts and stationary engines. Agricultural uses include tobacco curing and crop drying. In its wholesale operations, the Partnership principally sells propane to large industrial end-users and other propane distributors. Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from the bobtail truck, which generally holds 2,400 to 3,000 gallons of propane, into a stationary storage tank on the customer's premises. The Partnership owns most of these storage tanks and leases them to its customers. The capacity of these tanks ranges from approximately 100 gallons to approximately 1,200 gallons. The Partnership also delivers propane to retail customers in portable cylinders with capacities of 4 to 30 gallons. Some of these deliveries are made to the customer's location, where empty cylinders are either picked up for replenishment or filled in place. The Partnership continues to expand its PPX(R) program. At September 30, 2000, PPX(R) was available at approximately 10,700 retail locations throughout the country. -3- 6 PROPANE SUPPLY AND STORAGE Supplies of propane from the Partnership's sources historically have been readily available. During the year ended September 30, 2000, the Partnership purchased approximately 65% of its propane from 10 suppliers, including Enterprise Products Operating LP (approximately 18%), the BP companies (approximately 17%) and Dynegy (approximately 13%). The availability of propane supply is dependent upon, among other things, the severity of winter weather and the price and availability of competing fuels such as natural gas and heating oil. Although no assurance can be given that supplies of propane will be readily available in the future, management currently expects to be able to secure adequate supplies during fiscal year 2001. If supply from major sources were interrupted, however, the cost of procuring product might be materially higher and, at least on a short-term basis, margins could be affected. Aside from Enterprise Products Operating LP, the BP companies and Dynegy, no single supplier provided more than 10% of the Partnership's total propane supply in fiscal year 2000. In certain market areas, however, some suppliers provide 70% to 80% of the Partnership's requirements. Disruptions in supply in these areas could also have an adverse impact on the Partnership's margins. The Partnership has over 200 sources of supply, and it also makes purchases on the spot market. The Partnership purchases its propane supplies from domestic and international suppliers. Over 90% of propane purchases by the Partnership in fiscal year 2000 were on a contractual basis under one- or two-year agreements subject to annual review. More than 90% of those contracts provided for pricing based upon posted prices at the time of delivery or the current prices established at major storage points such as Mont Belvieu, Texas, or Conway, Kansas. In addition, some agreements provided maximum and minimum seasonal purchase volume guidelines. The percentage of contract purchases, and the amount of supply contracted for at fixed prices, will vary from year to year as determined by the General Partner. The Partnership uses a number of interstate pipelines, as well as railroad tank cars, delivery trucks and barges, to transport propane from suppliers to storage and distribution facilities. The Partnership stores propane at facilities in Arizona, Rhode Island and several other states. Because the Partnership's profitability is sensitive to changes in wholesale propane costs, the Partnership generally seeks to pass on increases in the cost of propane to customers. There is no assurance, however, that the Partnership will always be able to pass on product cost increases fully, particularly when product costs rise rapidly. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, or other unforeseen events. The General Partner has adopted supply acquisition and product price risk management practices to reduce the effect of price volatility on product costs. These practices currently include the use of summer storage, forward purchases and derivative commodity instruments such as options and propane price swaps. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures." -4- 7 The following graph shows the average prices of propane on the propane spot market during the last five fiscal years at Mont Belvieu, Texas and Conway, Kansas, two major storage areas. [PLOT POINTS FOR AVERAGE PROPANE SPOT MARKET PRICES] LP History for Mt Be Mont Belvieu Conway 1995 October Avg. Oct-95 30.946 32.7784 1995 November Avg. Nov-95 30.9531 32.7406 1995 December Avg. Dec-95 35.3219 38.1719 1996 January Avg. Jan-96 36 36.2415 1996 February Avg. Feb-96 40.8563 37.7688 1996 March Avg. Mar-96 37.2292 36.0119 1996 April Avg. Apr-96 35.5744 34.1071 1996 May Avg. May-96 34.9233 34.4773 1996 June Avg. Jun-96 34.925 36.3531 1996 July Avg. Jul-96 35.6339 37.2679 1996 August Avg. Aug-96 38.4403 37.9773 1996 September Avg. Sep-96 47.0156 44.7844 1996 October Avg. Oct-96 51.5734 51.5272 1996 November Avg. Nov-96 58.0493 63.4112 1996 December Avg. Dec-96 61.0446 84.2917 1997 January Avg. Jan-97 47.4545 63.392 1997 February Avg. Feb-97 38.7105 39.0197 1997 March Avg. Mar-97 38.5 37.2563 1997 April Avg. Apr-97 34.875 35.2614 1997 May Avg. May-97 35.3095 36.4762 1997 June Avg. Jun-97 34.4286 35.8631 1997 July Avg. Jul-97 34.9063 34.6278 1997 August Avg. Aug-97 37.0268 36.5268 1997 September Avg. Sep-97 38.6786 37.9524 1997 October Avg. Oct-97 39.8261 37.3207 1997 November Avg. Nov-97 35.9479 35.0035 1997 December Avg. Dec-97 33.571 31.3636 1998 January Avg. Jan-98 30.0656 28.2063 1998 February Avg. Feb-98 29.7862 28.3237 1998 March Avg. Mar-98 27.3892 27.8381 1998 April Avg. Apr-98 29.0565 29.4702 1998 May Avg. May-98 27.4188 27.8231 1998 June Avg. Jun-98 24.4205 24.8409 1998 July Avg. Jul-98 24.5398 24.5483 1998 August Avg. Aug-98 24.1161 23.8661 1998 September Avg. Sep-98 24.8304 24.0417 1998 October Avg. Oct-98 25.7188 24.5682 1998 November Avg. Nov-98 24.7862 23.2007 1998 December Avg. Dec-98 20.8949 18.7188 1999 January Avg. Jan-99 21.7467 19.6086 1999 February Avg. Feb-99 22.4342 20.5822 1999 March Avg. Mar-99 24.1005 23.4022 1999 April Avg. Apr-99 28.2619 27.5774 1999 May Avg. May-99 28.3063 26.8813 1999 June Avg. Jun-99 30.9517 28.679 1999 July Avg. Jul-99 37.2619 34.622 1999 August Avg. Aug-99 40.5085 37.5597 1999 September Avg. Sep-99 43.1786 42.4048 1999 October Avg. Oct-99 45.4554 43.3899 1999 November Avg. Nov-99 43.4406 38.7781 1999 December Avg. Dec-99 42.8304 35.1012 2000 January Avg. Jan-00 56.1086 42.3191 2000 February Avg. Feb-00 59.7219 47.2625 2000 March Avg. Mar-00 51.1277 47.6495 2000 April Avg. Apr-00 46.875 43.6414 2000 May Avg. May-00 51.3068 50.8068 2000 June Avg. Jun-00 55.4716 56.2244 2000 July Avg. Jul-00 54.875 56.2862 2000 August Avg. Aug-00 58.5408 63.5245 2000 September Avg. Sep-00 64.20945 70.9466 COMPETITION Propane competes with other sources of energy, some of which are less costly for equivalent energy value. Propane distributors compete for customers against suppliers of electricity, fuel oil and natural gas, principally on the basis of price, service, availability and portability. Electricity is a major competitor of propane, but propane generally enjoys a competitive price advantage over electricity for space heating, water heating and cooking. As previously stated, we are unable to predict the ultimate impact that deregulation of electric generation may have on propane's current competitive price advantage. Since the 1970s, many new homes have been built to use electrical heating systems and appliances. Fuel oil is also a major competitor of propane and is generally less expensive than propane. Operating efficiencies and other factors such as air quality and environmental advantages, however, generally make propane competitive with fuel oil as a heating source. Furnaces and appliances that burn propane will not operate on fuel oil, and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new equipment. Propane serves as an alternative to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Natural gas is generally a less expensive source of energy than propane, although in areas where natural gas is available, propane is used for certain industrial and commercial applications and as a standby fuel during interruptions in natural gas service. The gradual expansion of the nation's natural gas distribution systems has resulted in the availability of natural gas in some areas that previously depended upon propane. However, natural gas pipelines are not present in many regions of the country where propane is sold for heating and cooking purposes. -5- 8 The domestic propane retail distribution business is highly competitive. The Partnership competes in this business with other large propane marketers, including other full-service marketers, and thousands of small independent operators. In recent years, some rural electric cooperatives and fuel oil distributors have expanded their businesses to include propane distribution and the Partnership competes with them as well. Based on the most recent annual survey by the American Petroleum Institute, the 1998 domestic retail market for propane (annual sales for other than chemical uses) was approximately 9.5 billion gallons and, based on LP-GAS magazine rankings, 1999 sales volume of the ten largest propane companies (including AmeriGas Partners) represented approximately 41% of domestic retail sales. Management believes the Partnership's 2000 retail volume represents approximately 8% of the domestic retail market. The ability to compete effectively depends on supplying customer service, maintaining competitive retail prices and controlling operating expenses. Competition can intensify in response to a variety of factors, including significantly warmer-than-normal weather, higher prices resulting from extraordinary increases in the cost of propane, and recessionary economic factors. The Partnership may experience greater than normal customer losses in certain years when competitive conditions reflect any of these factors. In the motor fuel market, propane competes with gasoline and diesel fuel. When gasoline prices are high relative to propane, propane competes effectively. Wholesale propane distribution is a highly competitive, low margin business. Propane sales to other retail distributors and large-volume, direct-shipment industrial end users are price sensitive and frequently involve a competitive bidding process. PROPERTIES As of September 30, 2000, the Partnership owned approximately 83% of its district locations. In addition, the Partnership subleases three one-million barrel underground storage caverns in Arizona to store propane and butane for itself and third parties. The Partnership also leases a 600,000 barrel refrigerated, above-ground storage facility in California, which could be used in connection with waterborne imports or exports of propane or butane. The California facility, which the Partnership operates, is currently subleased to several refiners for the storage of butane. In Rhode Island, the Partnership leases storage with a 400,000 barrel capacity. The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 30, 2000, the Partnership operated a fleet of approximately 165 transport trucks, approximately 40% of which were leased. It owned approximately 320 transport trailers and leased 270 railroad tank cars. In addition, the Partnership fleet included approximately 2,600 bobtail and rack trucks, and approximately 1,800 other delivery and service vehicles. The vehicle fleet is 62% leased. Other assets owned at September 30, 2000 included approximately 1.0 million stationary storage tanks with typical capacities of 100 to 1,000 gallons and approximately 1.3 million portable propane cylinders with typical capacities of 4 to 100 gallons. The Partnership also owned more than 2,200 large volume tanks which are used for its own storage requirements. Most of the Partnership's debt is secured by liens and mortgages on the Partnership's real and personal property. TRADE NAMES, TRADE AND SERVICE MARKS The Partnership markets propane principally under the "AmeriGas(R)," "America's Propane -6- 9 Company(R)" and "PPX Prefilled Propane Xchange(R)" trade names and related service marks. UGI owns, directly or indirectly, all the right, title and interest in the "AmeriGas" and related trade and service marks. The General Partner owns all right, title and interest in the "America's Propane Company" and "PPX Prefilled Propane Xchange" trade names and related service marks. The Partnership has an exclusive (except for use by UGI, AmeriGas, Inc. and the General Partner), royalty-free license to use these names and trade and service marks. UGI and the General Partner each have the option to terminate its respective license agreement (on 12 months prior notice in the case of UGI), without penalty, if the General Partner is removed as general partner of the Partnership other than for cause. If the General Partner ceases to serve as the general partner of the Partnership for cause, the General Partner has the option to terminate its license agreement upon payment of a fee equal to the fair market value of the licensed trade names. UGI has a similar termination option, however, UGI must provide 12 months prior notice in addition to paying the fee. SEASONALITY Because many customers use propane for heating purposes, the Partnership's retail sales volume is seasonal, with approximately 55% of the Partnership's fiscal year 2000 retail sales volume and approximately 83% of its earnings before interest expense, income taxes, depreciation and amortization occurring during the five-month peak heating season from November through March. As a result of this seasonality, sales are concentrated in the Partnership's first and second fiscal quarters (October 1 through March 31). Cash receipts are greatest during the second and third fiscal quarters when customers pay for propane purchased during the winter heating season. Sales volume for the Partnership traditionally fluctuates from year-to-year in response to variations in weather, prices, competition, customer mix and other factors, such as conservation efforts and general economic conditions. For historical information on national weather statistics, see "Management's Discussion and Analysis of Financial Condition and Results of Operations." GOVERNMENT REGULATION The Partnership is subject to various federal, state and local environmental, safety and transportation laws and regulations governing the storage, distribution and transportation of propane. These laws include, among others, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or, the "Superfund Law"), the Clean Air Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA imposes joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a "hazardous substance" into the environment without regard to fault or the legality of the original conduct. Propane is not a hazardous substance within the meaning of federal and state environmental laws. However, the Partnership owns and operates real property where such hazardous substances may exist. See Notes 1 and 11 to the Company's Consolidated Financial Statements. All states in which the Partnership operates have adopted fire safety codes that regulate the storage and distribution of propane. In some states these laws are administered by state agencies, and in others they are administered on a municipal level. The Partnership conducts training programs to help ensure that its operations are in compliance with applicable governmental regulations. With respect to general operations, National Fire Protection Association Pamphlets No. 54 and No. 58, which establish a set of rules and procedures governing the safe handling of -7- 10 propane, or comparable regulations, have been adopted as the industry standard in a majority of the states in which the Partnership operates. The Partnership maintains various permits under environmental laws that are necessary to operate certain of its facilities, some of which may be material to the operations of the Partnership. Management believes that the procedures currently in effect at all of its facilities for the handling, storage and distribution of propane are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws. With respect to the transportation of propane by truck, the Partnership is subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation ("DOT"). During 1999, the Research and Special Programs Administration ("RSPA"), a division of the DOT, issued new regulations applicable to cargo tanks used to transport propane and procedures for loading propane on and off cargo tanks. Specific provisions include, among other things, revised attendance requirements for unloading propane and new requirements for emergency discharge control equipment, such as remote control devices that enable the driver to stop the unloading process at a distance from the vehicle and passive systems that will shut down loading and unloading without human intervention. The Partnership is in compliance with the new regulations and is evaluating the equipment that is being developed to comply with the passive systems requirements that will become effective in July 2001. The Natural Gas Safety Act of 1968 required the DOT to develop and enforce minimum safety regulations for the transportation of gases by pipeline. The DOT's pipeline safety code applies to, among other things, a propane gas system which supplies 10 or more customers from a single source and a propane gas system any portion of which is located in a public place. The code requires operators of all gas systems to provide training and written instructions for employees, establish written procedures to minimize the hazards resulting from gas pipeline emergencies, and keep records of inspections and testing. EMPLOYEES The Partnership does not directly employ any persons responsible for managing or operating the Partnership. The General Partner provides these services and is reimbursed for its direct and indirect costs and expenses, including all compensation and benefit costs. At September 30, 2000, the General Partner had 4,874 employees, including 311 temporary and part-time employees. UGI also performs certain financial and administrative services for the General Partner on behalf of the Partnership and is reimbursed by the Partnership for its direct and indirect costs and expenses. -8- 11 UTILITY OPERATIONS Our utility business is conducted by UGI Utilities, Inc. a wholly owned subsidiary. Utilities operates its business through two divisions, the gas division ("Gas Utility") and the electric division ("Electric Utility"). The business conducted by each of these divisions is described below. GAS UTILITY 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 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 Pennsylvania Public Utility Commission ("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. Gas Utility designed its restructuring plan to ensure reliability of gas supply deliveries to Gas Utility on behalf of residential and small commercial customers. The plan also provides for recovery of costs associated with existing pipeline capacity and gas supply contracts. In addition, the plan changes Gas Utility's base rates for firm customers. It also changes the calculation of purchased gas cost rates. See "Utility Regulation and Rates." The effect of these two changes is to lessen the financial impact of volatility in revenues associated with customers who have the ability to switch to another fuel and are served under "interruptible rates." On June 29, 2000, the PUC entered its order ("Gas Restructuring Order") approving Gas Utility's restructuring plan substantially as filed. Effective October 1, 2000, all of Gas Utility's customers have 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. Management believes neither the Gas Competition Act nor the Gas Restructuring Order 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 272,000 customers in portions of 14 eastern and southeastern Pennsylvania counties through its distribution system of approximately 4,500 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 -9- 12 industries such as specialty metals, aluminum and glass. For the fiscal years ended September 30, 2000, 1999 and 1998, revenues of Gas Utility accounted for approximately 20%, 25% and 24%, respectively, of our total consolidated revenues. System throughput (the total volume of gas sold to or transported for customers within Gas Utility's distribution system) for the 2000 fiscal year was approximately 79.7 billion cubic feet ("bcf"). System sales of gas accounted for approximately 40% of system throughput, while gas transported for commercial and industrial customers (who bought their gas from others) accounted for approximately 60% of system throughput. Based on industry data for 1999, residential customers account for approximately 33% of total system throughput by local gas distribution companies in the United States. By contrast, for the 2000 fiscal year, Gas Utility's residential customers represented 23% 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, storage and transportation services from pipeline companies, and its own propane-air and liquefied natural gas peak-shaving facilities. Purchases of natural gas in the spot market are also made to reduce costs and manage storage inventory levels. 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 the 2000 fiscal year, Gas Utility purchased approximately 31.5 bcf of natural gas for sale to customers. Approximately 87% of the volumes purchased were supplied under agreements with ten major suppliers of natural gas. The remaining 13% of gas purchased was supplied by producers and marketers under other arrangements, including multi-month agreements at spot prices. In fiscal year 2001, Gas Utility will continue to obtain necessary gas supplies under contracts no longer than 12 months in duration. SEASONAL VARIATION Because many of its customers use gas for heating purposes, Gas Utility's sales are seasonal. Approximately 58% of fiscal year 2000 throughput and approximately 71% 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. Competition with fuel oil dealers is focused on industrial customers. Gas Utility responds to this competition with marketing efforts designed to retain and grow its customer base. -10- 13 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 distribution services. Under the Gas Competition Act, retail customers now have the option to 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 for over 15 years. Gas Utility will provide transportation services for residential and small commercial retail customers who purchase natural gas from others, however, as of October 1, 2000, no marketers had completed the requirements to serve those customers. Commercial and industrial customers representing approximately 44% of Gas Utility's transportation system throughput (27% of transportation revenues) 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 margins from these customers, therefore, are affected by the difference, or "spread," between the customers' delivered cost of gas and the customers' delivered alternate fuel cost. In addition, other customers representing 30% of transportation system throughput (17% of transportation revenues) 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 the latter 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, seven of which extend into fiscal year 2004. No single customer represents, or is anticipated to represent, more than 1% 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 2001. 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. Gas Utility also operates propane air and liquefied natural gas facilities to meet winter peak service requirements. During fiscal year 2000, Gas Utility supplied transportation service to three major cogeneration installations and two utility generation sites. 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 7,968 residential heating customers during fiscal year 2000, a 12% increase from the previous year. Of those new customers, new home construction accounted for a record 6,261 heating customers, an increase of approximately 10% from the prior year. Customers converting from other energy sources, primarily oil, 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 total number of new commercial and industrial customers was 1,226. 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' -11- 14 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. ELECTRIC UTILITY 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's rates for transmission and distribution services provided through June 30, 2001 are capped at levels in effect on January 1, 1997. In addition, 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 expects to collect a CTC from all distribution customers until December 31, 2002. Under the ECC Act, Electric Utility remains 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 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%. Electric Utility's recoverable stranded costs include approximately $8.7 million for the termination of a 1993 power purchase agreement with Foster Wheeler Penn Resources, Inc., an independent power producer. Since January 1, 1999, all of Electric Utility's customers have been permitted to select an alternative electric generation supplier. Customers choosing another supplier currently receive an average generation "shopping credit" (developed from system-wide generation rates) of 3.67 cents per kilowatt hour ("kwh"), which will remain in effect through December 31, 2000. The shopping credit will increase to 4.3 cents per kwh in calendar years 2001 and 2002. As noted above, Electric Utility's power generation rates are capped until December 31, -12- 15 2002. Because Electric Utility has discontinued regulatory accounting, which permitted it to adjust customer charges to reflect changes in Electric Utility's power costs, quarterly results have been, and future results are likely to be, more volatile than they were prior to deregulation, due in large part to seasonal variations in such costs. Results will also be affected by the number of customers who choose to purchase their power from other suppliers during any given time period. SERVICE AREA; REVENUE ANALYSIS Electric Utility supplies electric service to approximately 61,000 customers in portions of Luzerne and Wyoming Counties in northeastern Pennsylvania through a system consisting of approximately 2,100 miles of transmission and distribution lines and 14 transmission substations. For fiscal year 2000, about 52% of sales volume came from residential customers, 35% from commercial customers and 13% from industrial customers. Electricity transported for customers who purchased their power from others pursuant to the ECC Act represented approximately 5% of this sales volume. For the 2000, 1999 and 1998 fiscal years, revenues of Electric Utility accounted for approximately 4%, 5% and 5%, respectively, of our total consolidated revenues. 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. These two coal-fired stations provided approximately 50% of Electric Utility's energy requirements during fiscal year 2000. Effective December 8, 2000, UGID entered into a partnership 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 the partnership's generation at cost. Electric Utility has contracts in place or control over generation representing in the aggregate approximately 90% of its expected on-peak energy requirements for fiscal year 2001. It plans to meet the balance of its energy needs with short-term contracts and spot market purchases. Electric Utility distributes both electricity that it purchases from others (including UGID) and electricity that customers purchase from other suppliers. At September 30, 2000, alternate suppliers served approximately 3% of system load. Electric Utility expects to continue to provide energy to the great majority of its customers. ENVIRONMENTAL FACTORS The 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 the Conemaugh Station and the Hunlock Station are in material compliance with these emission standards. -13- 16 SEASONALITY Sales and distribution of electricity for residential heating purposes accounted for approximately 20% of the total sales of Electric Utility during fiscal year 2000. Electricity competes with natural gas, oil, propane and other heating fuels in this use. Approximately 53% of volume occurred during the six coldest months of fiscal year 2000 (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 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 provides that Gas Utility must reduce its purchased gas cost rates by $16.7 million in the first year of the base rate increase. As a result, customers who purchase their gas from Gas Utility will not be affected by the increase in base rates for twelve months. Beginning in fiscal year 2002, Gas Utility must reduce its purchased gas cost rates by an amount equal to the revenues it receives from customers served under interruptible rates who do not obtain their own pipeline capacity. As a result of these changes in its regulated rates, Gas Utility expects that the risk to operating results associated with year- to- year fluctuations in interruptible revenues will be mitigated. Due to the required allocation of interruptible revenues under the Gas Restructuring Order, beginning with fiscal year 2001, Gas Utility operating results are expected to be more sensitive to heating season weather and less sensitive to the market prices of alternative fuel than in the past. -14- 17 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 2 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. The Gas Restructuring Order provides for a one-time adjustment to Gas Utility's PGC rates as described above, as well as ongoing adjustments to reflect revenues, if any, from interruptible rate customers who do not obtain their own pipeline capacity. ELECTRIC UTILITY RATES Electric Utility's rates for transmission and distribution services provided through June 30, 2001 are capped at levels in effect on January 1, 1997. Its rates for electric generation are capped through December 2002. 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. Electric Utility is actively participating in the regulatory process for establishing rules to ensure that Electric Utility recovers all its costs of providing generation when the rate cap period ends in December 2002. 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, however, any increase in Electric Utility's state tax surcharge is generally subject to the rate caps discussed above. 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 -15- 18 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 Utility - Environmental Factors." EMPLOYEES At September 30, 2000, Utilities and its subsidiaries had 1,120 employees. -16- 19 UGI ENTERPRISES, INC. UGI Enterprises, Inc. is a wholly owned subsidiary of UGI that was formed in 1994. Through its subsidiaries, Enterprises is developing the domestic and international businesses described below. DOMESTIC BUSINESSES NATURAL GAS AND ELECTRICITY MARKETING In 1995, the gas marketing business previously conducted by a subsidiary of Utilities was transferred to UGI Energy Services, Inc. ("Energy Services"), a wholly owned subsidiary of Enterprises. Energy Services conducts this business under the trade name GASMARK(R). GASMARK(R) sells natural gas directly to approximately 3,000 commercial and industrial customers in the Mid-Atlantic region through the transportation systems of 16 utility systems. Energy Services also sells electricity to over 200 commercial and industrial customers in Pennsylvania. During fiscal year 2000, GASMARK(R) acquired the gas marketing operations of two large regional energy marketers. These acquisitions doubled GASMARK(R)'s customer base. RETAIL HEARTH PRODUCTS In September 1999, Enterprises opened the first Hearth USA(TM) retail store in Rockville, Maryland. Hearth USA(TM) is the nation's first large-scale retailer to offer a wide selection of hearth, grill and spa products together with installation services. A second store opened in the Washington, DC area during fiscal year 2000. Enterprises expects to refine the Hearth retail concept further prior to scheduling openings in other markets. HVAC SERVICE Effective September 1, 2000, a subsidiary of Enterprises acquired a heating, ventilation and air-conditioning service business serving portions of Utilities' gas service area and adjacent market areas, including portions of northern Delaware. In the prior year, this business generated over $40 million in annual revenues and employed over 450 people. INTERNATIONAL BUSINESSES ENERGY-RELATED JOINT VENTURES During 1996, Enterprises formed a partnership with affiliates of Energy Transportation Group, Inc. ("ETG") and North American World Trade, Ltd. to develop, build and operate a liquefied petroleum gas ("LPG") import project in Romania. ETG has extensive experience in the transportation of liquefied natural gas, and North American World Trade, Ltd. is a consulting firm with Romanian expertise. The joint venture is known as Black Sea LPG Romania, S.A. The Romanian partners in this venture are Regia Autonoma a Gazelor Naturale "Romgaz" Medias, the Romanian national gas utility; Regia Autonoma de Electricitate "Renel", the Romanian national electric utility; and Rompetrol, S.A., a privately-held energy services company. The economic climate in Romania in recent years has slowed project development. During 1998, Enterprises formed ChinaGas Partners, L.P. ("ChinaGas") with affiliates of -17- 20 ETG to develop, build and operate LPG projects in the People's Republic of China. On October 28, 1998, ChinaGas and its wholly owned subsidiary together acquired 50% of the shares of an existing Chinese company known as the Nantong Huayang LPG Port Co., Ltd. ("Port Company") which operates an integrated LPG business, including an import terminal and distribution business, serving the provinces along the lower and middle reaches of the Yangtze River. At September 30, 2000, retail sales of propane represented over 25% of Port Company total sales. The other shareholders in the Port Company are China National Chemical Supply & Sales Corporation and two of its affiliates. Our effective ownership interest in the Port Company is 25%. PROPANE DISTRIBUTION In September 1999, subsidiaries of Enterprises acquired all of the stock of FLAGA GmbH, a privately-held company founded in 1947. FLAGA is the largest retail propane distributor in Austria and a leading distributor in the Czech Republic. FLAGA operates from 7 distribution locations in Austria, 8 in the Czech Republic and 2 in Slovakia. FLAGA marketed approximately 39 million gallons of propane in fiscal year 2000. Its assets totaled approximately $108 million at September 30, 2000. BUSINESS SEGMENT INFORMATION The table stating the amounts of revenues, operating income (loss) and identifiable assets attributable to each of UGI's business segments for the 2000, 1999 and 1998 fiscal years appears in Note 17 to the Consolidated Financial Statements contained in our 2000 Annual Report and is incorporated in this Report by reference. EMPLOYEES At September 30, 2000, UGI and its subsidiaries had 6,966 employees. -18- 21 ITEM 3. LEGAL PROCEEDINGS With the exception of the matters set forth below, no material legal proceedings are pending involving UGI, any of its subsidiaries or any of their properties, and no such proceedings are known to be contemplated by governmental authorities. ENVIRONMENTAL MATTERS - MANUFACTURED GAS PLANTS Prior to the general availability of natural gas, in the 1800s through the mid-1900s, most gas for lighting and heating nationwide was manufactured from combustibles such as coal, oil and coke. 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 manufactured gas plants. Utilities and its former subsidiaries owned and operated a number of manufactured gas plants. Between 1882 and 1953, Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the mid-1930s, Utilities was one of the largest public utility holding companies in the country. 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 the Gas Utility and the Electric Utility. Utilities has been notified of several sites outside Pennsylvania on which (i) gas plants were formerly operated by it or owned or operated by its former subsidiaries and (ii) 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. At one such site, in July 1993, Public Service Electric and Gas Company ("PSE&G") joined Utilities as a third-party defendant in the civil action Fishbein Family Partnership v. PPG Industries, Inc., et al 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 Halladay Street gas plant operated from approximately 1884 until 1950. PSE&G has asserted that Utilities is liable for that portion of the costs associated with operations of the plant between 1886 and 1940. PPG Industries, Inc. is also a defendant in the action for costs associated with chemical contamination at the site unrelated to gas plant operations. To date, that action has focused on the chemical contamination allegedly associated with PPG Industries' activities and the third-party action against Utilities has been stayed. Investigations of the site conducted to date are insufficient to establish the extent of environmental remediation necessary, if any. Hence, Utilities is unable to estimate the total cost of cleanup associated with manufactured gas plant wastes at this site. Management believes that Utilities should not have significant liability in those instances in which a former subsidiary operated a manufactured gas plant because Utilities generally is not legally liable for the obligations of its subsidiaries. Under certain circumstances, however, a court could find a parent company liable for environmental damage caused by a subsidiary company when the parent company either (i) itself operated the facility causing the environmental damage or (ii) otherwise so controlled the subsidiary that the subsidiary's separate corporate form should be -19- 22 disregarded. There could be, therefore, significant future costs of an uncertain amount associated with environmental damage caused by manufactured gas plants that Utilities owned or directly operated, or that were owned or operated by former subsidiaries of Utilities, if a court were to conclude that the subsidiary's separate corporate form should be disregarded. See also Notes 1 and 11 to the Company's Consolidated Financial Statements. Utilities has identified 40 sites in Pennsylvania where either (i) Utilities formerly conducted some manufactured gas operations or (ii) Utilities owns or at one time owned the site. Most of the sites are no longer owned by Utilities and there have been no manufactured gas operations at any of the sites since at least the early 1950s. Utilities or other parties are currently conducting or have completed investigative and remedial activities at eleven of the 40 sites. Based on the 1995 settlement agreement with the PUC relating to Gas Utilities' 1995 base rate increase filing, rate relief will be permitted for certain remediation expenditures on environmentally contaminated sites located in Pennsylvania. Because of this, Utilities does not expect its costs for Pennsylvania sites to be material to its results of operations. 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 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. See Note 11 to the Company's Consolidated Financial Statements. -20- 23 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 2000. EXECUTIVE OFFICERS Information regarding our executive officers is included in Part III of this Report and is incorporated in Part I by reference. PART II: SECURITIES AND FINANCIAL INFORMATION ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS MARKET INFORMATION Our Common Stock is traded on the New York and Philadelphia stock exchanges under the symbol "UGI." The following table sets forth the high and low sales prices for the Common Stock on the New York Stock Exchange Composite Transactions tape as reported in The Wall Street Journal for each full quarterly period within the two most recent fiscal years:
2000 FISCAL YEAR HIGH LOW 4th Quarter $24.313 $20.563 3rd Quarter 22.625 19.750 2nd Quarter 22.313 18.188 1st Quarter 24.000 19.125
1999 FISCAL YEAR HIGH LOW 4th Quarter $24.688 $19.750 3rd Quarter 21.000 16.563 2nd Quarter 24.375 15.000 1st Quarter 25.750 21.625
-21- 24 DIVIDENDS Quarterly dividends on our Common Stock were paid in the 2000 and 1999 fiscal years as follows:
2000 FISCAL YEAR AMOUNT 4th Quarter $0.3875 3rd Quarter 0.375 2nd Quarter 0.375 1st Quarter 0.375
1999 FISCAL YEAR AMOUNT 4th Quarter $0.365 3rd Quarter 0.365 2nd Quarter 0.365 1st Quarter 0.365
HOLDERS On December 1, 2000, UGI had 11,049 holders of record of Common Stock. -22- 25 ITEM 6. SELECTED FINANCIAL DATA
Year Ended September 30, ---------------------------------------------------------- 2000 1999 1998 1997 1996 --------- --------- --------- --------- --------- (Millions of dollars, except per share amounts) FOR THE PERIOD: INCOME STATEMENT DATA: Revenues $ 1,761.7 $ 1,383.6 $ 1,439.7 $ 1,642.0 $ 1,557.6 ========= ========= ========= ========= ========= Net income $ 44.7 $ 55.7 $ 40.3 $ 52.1 $ 39.5 ========= ========= ========= ========= ========= Earnings per common share - diluted (a) $ 1.64 $ 1.74 $ 1.22 $ 1.57 $ 1.19 ========= ========= ========= ========= ========= Cash dividends declared per common share $ 1.525 $ 1.47 $ 1.45 $ 1.43 $ 1.41 ========= ========= ========= ========= ========= AT PERIOD END: BALANCE SHEET DATA: Total assets $ 2,278.8 $ 2,140.5 $ 2,074.6 $ 2,151.7 $ 2,133.0 ========= ========= ========= ========= ========= Capitalization: Debt: Bank loans - AmeriGas Propane $ 30.0 $ 22.0 $ 10.0 $ 28.0 $ 15.0 Bank loans - UGI Utilities 100.4 87.4 68.4 67.0 50.5 Bank loans - other 4.3 11.6 - - - Long-term debt (including current maturities): AmeriGas Propane 857.2 744.7 709.0 691.1 692.5 UGI Utilities 172.9 180.0 187.2 169.3 174.8 Other 85.5 91.6 8.2 8.6 9.0 --------- --------- --------- --------- --------- Total debt 1,250.3 1,137.3 982.8 964.0 941.8 ========= ========= ========= ========= ========= Minority interest in AmeriGas Partners 177.1 209.9 236.5 266.5 284.4 UGI Utilities preferred stock subject to mandatory redemption 20.0 20.0 20.0 35.2 35.2 Common stockholders' equity 247.2 249.2 367.1 376.1 377.6 --------- --------- --------- --------- --------- Total capitalization $ 1,694.6 $ 1,616.4 $ 1,606.4 $ 1,641.8 $ 1,639.0 ========= ========= ========= ========= ========= RATIO OF CAPITALIZATION: Total debt 73.8% 70.4% 61.2% 58.7% 57.5% Minority interest 10.5% 13.0% 14.7% 16.3% 17.4% UGI Utilities preferred stock 1.2% 1.2% 1.2% 2.1% 2.1% Common stockholders' equity 14.5% 15.4% 22.9% 22.9% 23.0% --------- --------- --------- --------- --------- 100.0% 100.0% 100.0% 100.0% 100.0% ========= ========= ========= ========= =========
(a) Basic earnings per share was $1.58 in 1997. For all other periods presented, basic earnings per share was the same as diluted earnings per share. -23- 26 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Management's Discussion and Analysis of Financial Condition and Results of Operations, entitled "Financial Review" and contained on pages 13 through 23 of UGI's 2000 Annual Report to Shareholders, is incorporated in this report by reference. 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" on page 20 of the UGI 2000 Annual Report to Shareholders and are incorporated in this Report by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Financial Statements and Financial Statement Schedules referred to in the Index contained on pages F-2 and F-3 of this Report are incorporated in this Report by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. -24- 27 PART III: UGI MANAGEMENT AND SECURITY HOLDERS ITEMS 10 THROUGH 13. In accordance with General Instruction G(3), and except as set forth below, the information required by Items 10, 11, 12 and 13 is incorporated in this Report by reference to the following portions of UGI's Proxy Statement, which will be filed with the Securities and Exchange Commission by January 28, 2001:
CAPTIONS OF PROXY STATEMENT INFORMATION INCORPORATED BY REFERENCE Item 10. Directors and Executive Election of Directors - Nominees Officers of Registrant. Item 11. Executive Compensation. Compensation of Executive Officers Compensation of Directors Item 12. Security Ownership of Securities Ownership of Management Certain Beneficial Owners and Management. Item 13. Certain Relationships Compensation of Executive Officers - and Related Transactions. Stock Ownership Policy and Indebtedness of Management
The information concerning the Company's executive officers required by Item 10 is set forth below. EXECUTIVE OFFICERS
NAME AGE POSITION ---- --- -------- Lon R. Greenberg 50 Chairman, Director, President and Chief Executive Officer Eugene V.N. Bissell 47 President and Chief Executive Officer, AmeriGas Propane, Inc. Robert J. Chaney 58 President and Chief Executive Officer, UGI Utilities, Inc. Brendan P. Bovaird 52 Vice President and General Counsel Bradley C. Hall 47 Vice President - New Business Development Anthony J. Mendicino 52 Vice President - Finance and Chief Financial Officer
-25- 28 All officers are elected for a one-year term at the organizational meetings of the respective Boards of Directors held each year. There are no family relationships between any of the officers or between any of the officers and any of the directors. Lon R. Greenberg Mr. Greenberg was elected Chairman of UGI effective August 1, 1996, having been elected Chief Executive Officer effective August 1, 1995. He was elected Director and President of UGI and a Director of UGI Utilities in July 1994. He was elected a Director of AmeriGas Propane, Inc. in 1994 and has been Chairman since 1996. He also served as President and Chief Executive Officer of AmeriGas Propane (1996 to 2000). Mr. Greenberg was Senior Vice President - Legal and Corporate Development (1989 to 1994), and also served as Vice President - Legal and Corporate Development (1987 to 1989). Previously, he was Vice President - Legal (1984 to 1987), General Counsel (1983 to 1994) and Secretary (1982 to 1988). He joined the Company in 1980 as Corporate Development Counsel. Mr. Greenberg is also a director on the Mellon PSFS Advisory Board. Eugene V.N. Bissell Mr. Bissell is President and Chief Executive Officer of AmeriGas Propane, Inc. (since July 2000), having served as Senior Vice President - Sales and Marketing (1999 to 2000) and Vice President - Sales and Operations (1995 to 1999). Previously, he was Vice President - Distributors and Fabrication, BOC Gases (1995), having been Vice President - National Sales (1993 to 1995) and Regional Vice President Southern Region for Distributor and Cylinder Gases Division, BOC Gases (1989 to 1993). From 1981 to 1987, Mr. Bissell held various positions with the Company and its subsidiaries, including Director, Corporate Development. Robert J. Chaney Mr. Chaney is President and Chief Executive Officer of UGI Utilities, Inc., (since March 1999). He previously served as Executive Vice President (1998 to 1999), Vice President and General Manager - Gas Utility Division (1991 to 1998) and Vice President - Rates and Energy Utilization - Gas Utility Division (1981 to 1991). Brendan P. Bovaird Mr. Bovaird is Vice President and General Counsel of UGI (since April 1995). He is also Vice President and General Counsel of UGI Utilities, Inc., 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) and Senior Vice President, General Counsel and Secretary of Orion Pictures Corporation (1990 to 1991). Bradley C. Hall Mr. Hall was elected Vice President - New Business Development on October 25, 1994, having been Vice President - Marketing and Rates, UGI Utilities, Inc. Gas Division. He also serves as President of UGI Enterprises, Inc. (since 1994). He joined the Company in 1982 and held -26- 29 various positions in Gas Utility. Anthony J. Mendicino Mr. Mendicino was elected Vice President - Finance and Chief Financial Officer on September 8, 1998. He previously served as President and Chief Operating Officer (July 1997 to June 1998) and as Senior Vice President (January 1997 to June 1997) of Eastwind Group, Inc., a holding company formed to acquire and consolidate middle-market manufacturing businesses. Mr. Mendicino was Senior Vice President and Chief Financial Officer and a director (1987 to 1996) of UTI Energy Corp., a diversified oil field service company. From 1981 to 1987 Mr. Mendicino held various positions with UGI, including Treasurer from 1984 to 1987. -27- 30 PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) DOCUMENTS FILED AS PART OF THIS REPORT: (1), (2) The financial statements and financial statement schedules incorporated by reference or included in this report are listed in the accompanying Index to Financial Statements and Financial Statement Schedules set forth on pages F-2 through F-3 of this report, which is incorporated herein by reference. (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): -28- 31
- --------------------------------------------------------------------------------------------------------------------------------- INCORPORATION BY REFERENCE - --------------------------------------------------------------------------------------------------------------------------------- EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - --------------------------------------------------------------------------------------------------------------------------------- 3.1 (Second) Amended and Restated Articles of UGI Amendment No. 1 on 3.(3)(a) Incorporation of the Company Form 8 to Form 8-B (4/10/92) 3.2 Bylaws of UGI as in effect since October UGI Form 10-K (9/30/98) 3.2 27, 1998 - --------------------------------------------------------------------------------------------------------------------------------- 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 long-term debt not required to be filed pursuant to Item 601(b)(4) of Regulation S-K) - --------------------------------------------------------------------------------------------------------------------------------- 4.1 Rights Agreement, as amended as of August UGI Registration 4.3 18, 2000, between the Company and Mellon Statement No. Bank, N.A., successor to Mellon Bank (East) 333-49080 N.A., as Rights Agent, and Assumption Agreement dated April 7, 1992 - --------------------------------------------------------------------------------------------------------------------------------- 4.2 The description of the Company's Common UGI Form 8-B/A (4/17/96) 3.(4) Stock contained in the Company's registration statement filed under the Securities Exchange Act of 1934, as amended - --------------------------------------------------------------------------------------------------------------------------------- 4.3 UGI's (Second) Amended and Restated Articles of Incorporation and Bylaws referred to in 3.1 and 3.2 above - --------------------------------------------------------------------------------------------------------------------------------- 4.4 Note Agreement dated as of April 12, 1995 AmeriGas Partners, Form 10-Q 10.8 among The Prudential Insurance Company of L.P. America, Metropolitan Life Insurance (3/31/95) Company, and certain other institutional investors and AmeriGas Propane, L.P., New AmeriGas Propane, Inc. and Petrolane Incorporated - --------------------------------------------------------------------------------------------------------------------------------- 4.5 First Amendment dated as of September 12, AmeriGas Partners, Form 10-K (9/30/97) 4.5 1997 to Note Agreement dated as of April L.P. 12, 1995 - --------------------------------------------------------------------------------------------------------------------------------- 4.6 Second Amendment dated as of September 15, AmeriGas Partners, Form 10-K (9/30/98) 4.6 1998 to Note Agreement dated as of April L.P. 12, 1995 - --------------------------------------------------------------------------------------------------------------------------------- 4.7 Third Amendment dated as of March 23, 1999 AmeriGas Partners, Form 10-Q (3/31/99) 10.2 to Note Agreement dated as of April 12, 1995 L.P. - --------------------------------------------------------------------------------------------------------------------------------- 4.8 Fourth Amendment dated as of March 16, 2000 AmeriGas Partners, Form 10-Q (6/30/00) 10.2 to Note Agreement dated as of April 12, 1995 L.P. - ---------------------------------------------------------------------------------------------------------------------------------
-29- 32
- --------------------------------------------------------------------------------------------------------------------------------- INCORPORATION BY REFERENCE - --------------------------------------------------------------------------------------------------------------------------------- EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - --------------------------------------------------------------------------------------------------------------------------------- 4.9 Second Amended and Restated Agreement of AmeriGas Partners, Form 8-K 1 Limited Partnership of AmeriGas Partners, L.P. (9/30/00) L.P. - --------------------------------------------------------------------------------------------------------------------------------- 10.1 Service Agreement (Rate FSS) dated as of UGI Form 10-K (9/30/95) 10.5 November 1, 1989 between Utilities and Columbia, as modified pursuant to the orders of the Federal Energy Regulatory Commission at Docket No. RS92-5-000 reported at Columbia Gas Transmission Corp., 64 FERC Paragraph 61,060 (1993), order on rehearing, 64 FERC Paragraph 61,365 (1993) - --------------------------------------------------------------------------------------------------------------------------------- 10.2 Service Agreement (Rate FTS) dated June 1, Utilities Form 10-K (12/31/90) (10)o. 1987 between Utilities and Columbia, as modified by 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 Utilities Form 10-K (12/31/90) (10)p. FTS-1) dated November 1, 1989 between Utilities and Columbia Gulf 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) - --------------------------------------------------------------------------------------------------------------------------------- 10.4 Amended and Restated Sublease Agreement UGI Form 10-K (9/30/94) 10.35 dated April 1, 1988 between Southwest Salt Co. and AP Propane, Inc. (the "Southwest Salt Co. Agreement") - --------------------------------------------------------------------------------------------------------------------------------- 10.5 Letter dated July 8, 1998 pursuant to UGI Form 10-K (9/30/99) 10.5 Article 1, Section 1.2 of the Southwest Salt Co. Agreement re: option to renew for period of June 1, 2000 to May 31, 2005 and related extension notice - --------------------------------------------------------------------------------------------------------------------------------- *10.6** UGI Corporation Directors Deferred Compensation Plan Amended and Restated as of January 1, 2000 - ---------------------------------------------------------------------------------------------------------------------------------
-30- 33
- --------------------------------------------------------------------------------------------------------------------------------- INCORPORATION BY REFERENCE - --------------------------------------------------------------------------------------------------------------------------------- EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - --------------------------------------------------------------------------------------------------------------------------------- 10.7** UGI Corporation 1992 Stock Option and UGI Form 10-Q (6/30/92) (10)ee Dividend Equivalent Plan, as amended May 19, 1992 - --------------------------------------------------------------------------------------------------------------------------------- 10.8** UGI Corporation Annual Bonus Plan dated UGI Form 10-Q (6/30/96) 10.4 March 8, 1996 - --------------------------------------------------------------------------------------------------------------------------------- *10.9** UGI Corporation Directors' Equity Compensation Plan Amended and Restated as of January 1, 2000 - --------------------------------------------------------------------------------------------------------------------------------- 10.10** UGI Corporation 1997 Stock Option and UGI Form 10-Q (3/31/97) 10.2 Dividend Equivalent Plan - --------------------------------------------------------------------------------------------------------------------------------- 10.11** UGI Corporation 1992 Directors' Stock Plan UGI Form 10-Q (6/30/92) (10)ff - --------------------------------------------------------------------------------------------------------------------------------- 10.12** UGI Corporation Senior Executive Employee UGI Form 10-K (9/30/97) 10.12 Severance Pay Plan effective January 1, 1997 - --------------------------------------------------------------------------------------------------------------------------------- 10.13** UGI Corporation 2000 Directors' Stock UGI Form 10-K (9/30/99) 10.13 Option Plan - --------------------------------------------------------------------------------------------------------------------------------- 10.14** UGI Corporation 2000 Stock Incentive Plan UGI Form 10-Q (6/30/00) 10.1 - --------------------------------------------------------------------------------------------------------------------------------- 10.15** 1997 Stock Purchase Loan Plan UGI Form 10-K (9/30/97) 10.16 - --------------------------------------------------------------------------------------------------------------------------------- 10.16** UGI Corporation Supplemental Executive UGI Form 10-Q (6/30/98) 10 Retirement Plan Amended and Restated effective October 1, 1996 - --------------------------------------------------------------------------------------------------------------------------------- 10.17** Summary of Terms of UGI Corporation 1999 UGI Form 10-Q (6/30/99) 10 Restricted Stock Awards - --------------------------------------------------------------------------------------------------------------------------------- 10.18 Amended and Restated Credit Agreement AmeriGas Form 10-K 10.1 dated as of September 15, 1997 among Partners, L.P. AmeriGas Propane, L.P., AmeriGas Propane, (9/30/97) Inc., Petrolane Incorporated, Bank of America National Trust and Savings Association, as Agent, First Union National Bank, as Syndication Agent and certain banks - --------------------------------------------------------------------------------------------------------------------------------- 10.19 First Amendment dated as of September 15, AmeriGas Form 10-K (9/30/98) 10.2 1998 to Amended and Restated Credit Partners, L.P. Agreement - --------------------------------------------------------------------------------------------------------------------------------- 10.20 Second Amendment dated as of March 25, AmeriGas Form 10-Q (3/31/99) 10.1 1999 to Amended and Restated Credit Partners, L.P. Agreement - --------------------------------------------------------------------------------------------------------------------------------- 10.21 Third Amendment dated as of March 22, 2000 AmeriGas Form 10-Q (6/30/00) 10.3 to Amended and Restated Credit Agreement Partners, L.P. - ---------------------------------------------------------------------------------------------------------------------------------
-31- 34
- --------------------------------------------------------------------------------------------------------------------------------- INCORPORATION BY REFERENCE - --------------------------------------------------------------------------------------------------------------------------------- EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - --------------------------------------------------------------------------------------------------------------------------------- 10.22 Fourth Amendment dated as of June 6, 2000 AmeriGas Form 10-Q (6/30/00) 10.4 to Amended and Restated Credit Agreement Partners, L.P. - --------------------------------------------------------------------------------------------------------------------------------- 10.23 Intercreditor and Agency Agreement dated as AmeriGas Form 10-Q (3/31/95) 10.2 of April 19, 1995 among AmeriGas Propane, Partners, L.P. Inc., Petrolane Incorporated, AmeriGas Propane, L.P., Bank of America National Trust and Savings Association ("Bank of America") as Agent, Mellon Bank, N.A. as Cash Collateral Sub-Agent, Bank of America as Collateral Agent and certain creditors of AmeriGas Propane, L.P. - --------------------------------------------------------------------------------------------------------------------------------- 10.24 General Security Agreement dated as of AmeriGas Form 10-Q (3/31/95) 10.3 April 19, 1995 among AmeriGas Propane, Partners, L.P. L.P., Bank of America National Trust and Savings Association and Mellon Bank, N.A. - --------------------------------------------------------------------------------------------------------------------------------- 10.25 Subsidiary Security Agreement dated as of AmeriGas Form 10-Q (3/31/95) 10.4 April 19, 1995 among AmeriGas Propane, Partners, L.P. L.P., Bank of America National Trust and Savings Association as Collateral Agent and Mellon Bank, N.A. as Cash Collateral Agent - --------------------------------------------------------------------------------------------------------------------------------- 10.26 Restricted Subsidiary Guarantee dated as of AmeriGas Form 10-Q (3/31/95) 10.5 April 19, 1995 by AmeriGas Propane, L.P. Partners, L.P. for the benefit of Bank of America National Trust and Savings Association, as Collateral Agent - --------------------------------------------------------------------------------------------------------------------------------- 10.27 Trademark License Agreement dated April 19, AmeriGas Form 10-Q (3/31/95) 10.6 1995 among UGI Corporation, AmeriGas, Inc., Partners, L.P. AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. - --------------------------------------------------------------------------------------------------------------------------------- 10.28 Trademark License Agreement, dated April AmeriGas Form 10-Q (3/31/95) 10.7 19, 1995 among AmeriGas Propane, Inc., Partners, L.P. AmeriGas Partners, L.P. and AmeriGas Propane, L.P. - --------------------------------------------------------------------------------------------------------------------------------- 10.29 Agreement dated as of May 1, 1996 between AmeriGas Form 10-K (9/30/97) 10.2 TE Products Pipeline Company, L.P. and Partners, L.P. AmeriGas Propane, L.P. - --------------------------------------------------------------------------------------------------------------------------------- 10.30 Pledge Agreement dated September 1999 UGI Form 10-K (9/30/99) 10.28 between Eastfield International Holdings, Inc. and Reiffeisen Zentralbank Osterreich Aktiengesellschaft ("RZB") - --------------------------------------------------------------------------------------------------------------------------------- 10.31 Pledge Agreement dated September 1999 UGI Form 10-K (9/30/99) 10.29 between EuroGas Holdings, Inc. and RZB - ---------------------------------------------------------------------------------------------------------------------------------
-32- 35
- --------------------------------------------------------------------------------------------------------------------------------- INCORPORATION BY REFERENCE - --------------------------------------------------------------------------------------------------------------------------------- EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT - --------------------------------------------------------------------------------------------------------------------------------- 10.32 Form of Guarantee Agreement dated September UGI Form 10-K (9/30/99) 10.30 1999 between UGI Corporation and RZB relating to loan amount of EURO 74 million - --------------------------------------------------------------------------------------------------------------------------------- *10.33 Form of Guarantee Agreement dated September 2000 between UGI Corporation and RZB relating to loan amount of EURO 14.9 million - --------------------------------------------------------------------------------------------------------------------------------- *10.34 Form of Guarantee Agreement dated September 2000 between UGI Corporation and RZB relating to loan amount of EURO 9 million - --------------------------------------------------------------------------------------------------------------------------------- 10.35** Description of Change of Control UGI Form 10-K (9/30/99) 10.33 arrangements for Messrs. Greenberg, Bovaird and Mendicino - --------------------------------------------------------------------------------------------------------------------------------- 10.36** Description of Change of Control UGI Form 10-K (9/30/99) 10.34 arrangement for Mr. Chaney - --------------------------------------------------------------------------------------------------------------------------------- 10.37** Description of Change of Control AmeriGas Form 10-K (9/30/99) 10.31 arrangement for Mr. Bissell Partners, L.P. - --------------------------------------------------------------------------------------------------------------------------------- *10.38** Consulting Services Agreement dated as of August 1, 2000 between Stephen D. Ban and UGI Corporation - --------------------------------------------------------------------------------------------------------------------------------- *10.39** 1992 Non-Qualified Stock Option Plan, as amended - --------------------------------------------------------------------------------------------------------------------------------- *10.40 Service Agreement for comprehensive delivery service (Rate CDS) dated February 23, 1998 between UGI Utilities, Inc. and Texas Eastern Transmission Corporation - --------------------------------------------------------------------------------------------------------------------------------- *10.41 Service Agreement for comprehensive delivery service (Rate CDS) dated February 23, 1999 between UGI Utilities, Inc. and Texas Eastern Transmission Corporation - --------------------------------------------------------------------------------------------------------------------------------- *13 Pages 13 through 47 of 2000 Annual Report to Shareholders - --------------------------------------------------------------------------------------------------------------------------------- *21 Subsidiaries of the Registrant - --------------------------------------------------------------------------------------------------------------------------------- *23 Consent of Arthur Andersen LLP - --------------------------------------------------------------------------------------------------------------------------------- *27 Financial Data Schedule - ---------------------------------------------------------------------------------------------------------------------------------
* 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 no Current Reports on Form 8-K during the last quarter of fiscal year 2000. -33- 36 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 CORPORATION Date: December 19, 2000 By: Anthony J. Mendicino ------------------------------- Anthony J. Mendicino Vice President - Finance and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 19, 2000, by the following persons on behalf of the Registrant in the capacities indicated. SIGNATURE TITLE - --------- ----- Lon R. Greenberg Chairman, President - ----------------------------- and Chief Executive Officer Lon R. Greenberg (Principal Executive Officer) and Director Anthony J. Mendicino Vice President - Finance - ----------------------------- and Chief Financial Officer Anthony J. Mendicino (Principal Financial Officer and Principal Accounting Officer) Stephen D. Ban Director - ----------------------------- Stephen D. Ban Thomas F. Donovan Director - ----------------------------- Thomas F. Donovan -34- 37 Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 19, 2000, by the following persons on behalf of the Registrant in the capacities indicated. SIGNATURE TITLE - --------- ----- 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 David I. J. Wang Director - --------------------------- David I. J. Wang -35- 38 UGI CORPORATION AND SUBSIDIARIES FINANCIAL INFORMATION FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K YEAR ENDED SEPTEMBER 30, 2000 F-1 39 UGI CORPORATION AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES The consolidated financial statements and supplementary data of UGI Corporation and subsidiaries, together with the report thereon of Arthur Andersen LLP dated November 10, 2000, listed in the following index, are included in UGI's 2000 Annual Report to Shareholders and are incorporated in this Form 10-K Annual Report by reference. With the exception of the pages listed in this index and information incorporated in Items 1, 2, 5, 7 and 8, the 2000 Annual Report to Shareholders is not to be deemed filed as part of this Report.
Reference ------------------------- Annual Report to Form 10-K Shareholders (page) (page) --------- ------------ Reports of Independent Public Accountants: On Consolidated Financial Statements 24 On Financial Statement Schedules F-4 Financial Statements: Consolidated Balance Sheets, September 30, 2000 and 1999 26 and 27 For the years ended September 30, 2000, 1999 and 1998: Consolidated Statements of Income 25 Consolidated Statements of Cash Flows 28 Consolidated Statements of Stockholders' Equity 29
Index F-2 40 UGI CORPORATION AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES (CONTINUED)
Reference ------------------------- Annual Report to Form 10-K Shareholders (page) (page) --------- ------------ Notes to Consolidated Financial Statements 30 to 47 Supplementary Data (unaudited): Quarterly Data for the years ended September 30, 2000 and 1999 46 Financial Statement Schedules: For the years ended September 30, 2000, 1999 and 1998: I - Condensed Financial Information of Registrant (Parent Company) S-1 to S-3 II - Valuation and Qualifying Accounts S-4 to S-5
Annual Reports on Form 10-K/A Annual Reports on Form 10-K/A for the UGI Utilities, Inc. and AmeriGas Propane, Inc. savings plans will be filed by amendment within the time period specified by Rule 15d-21(b). 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) the information required is included elsewhere in the financial statements or related notes. F-3 41 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of UGI Corporation: We have audited, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements included in UGI Corporation's annual report to shareholders for the year ended September 30, 2000, incorporated by reference in this Form 10-K, and have issued our report thereon dated November 10, 2000. Our audits were made for the purpose of forming an opinion on those consolidated financial statements taken as a whole. The schedules listed in the Index on pages F-2 and F-3 are the responsibility of UGI Corporation's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state 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 10, 2000 F-4 42 UGI CORPORATION AND SUBSIDIARIES SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY) BALANCE SHEETS (Millions of dollars)
September 30, 2000 1999 -------------- -------------- ASSETS - ------ Current assets: Cash and cash equivalents $ 1.1 $ 0.4 Accounts receivable 0.1 0.1 Deferred income taxes 0.2 0.2 Prepaid expenses and other current assets 0.3 0.3 -------------- -------------- Total current assets 1.7 1.0 Investments in subsidiaries 315.9 271.3 Other assets 2.4 2.2 -------------- -------------- Total assets $ 320.0 $ 274.5 ============== ============== LIABILITIES AND COMMON STOCKHOLDERS' EQUITY Current liabilities: Accounts and notes payable $ 9.6 $ 11.1 Accrued liabilities 12.4 10.7 -------------- -------------- Total current liabilities 22.0 21.8 Noncurrent liabilities 50.3 3.5 Commitments and contingencies Common stockholders' equity: Common Stock, without par value (authorized - 100,000,000 shares; issued - 33,198,731 shares) 394.5 394.8 Accumulated deficit (4.9) (8.2) Accumulated other comprehensive income - 0.5 Unearned compensation - restricted stock (0.7) (1.7) -------------- -------------- 388.9 385.4 Less treasury stock, at cost (141.2) (136.2) -------------- -------------- Total common stockholders' equity 247.7 249.2 -------------- -------------- Total liabilities and common stockholders' equity $ 320.0 $ 274.5 ============== ==============
Commitments and Contingencies In addition to the guarantees of FLAGA debt described in Note 3 to Consolidated Financial Statements, UGI Corporation is authorized to guarantee up to $30 million of supplier and customer obligations of its wholly owned second-tier subsidiary UGI Energy Services, Inc., and $5 million of lease obligations of its wholly owned second-tier subsidiary Hearth USA, Inc. S-1 43 UGI CORPORATION AND SUBSIDIARIES SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY) STATEMENTS OF INCOME (Millions of dollars, except per share amounts)
Year Ended September 30, ---------------------------------------------------- 2000 1999 1998 ---------- ---------- ---------- Revenues $ - $ - $ - Costs and expenses: Operating and administrative expenses 8.1 10.4 10.7 Other income, net (8.4) (10.5) (10.4) ---------- ---------- ---------- (0.3) (0.1) 0.3 ---------- ---------- ---------- Operating income (loss) 0.3 0.1 (0.3) Interest expense on intercompany debt (2.0) - - ---------- ---------- ---------- Income (loss) before income taxes (1.7) 0.1 (0.3) Income tax expense (benefit) (1.1) 0.3 (0.1) ---------- ---------- ---------- Loss before equity in income of unconsolidated subsidiaries (0.6) (0.2) (0.2) Equity in income of unconsolidated subsidiaries 45.3 55.9 40.5 ---------- ---------- ---------- Net income $ 44.7 $ 55.7 $ 40.3 ========== ========== ========== Earnings per common share: Basic $ 1.64 $ 1.74 $ 1.22 ========== ========== ========== Diluted $ 1.64 $ 1.74 $ 1.22 ========== ========== ========== Average common shares outstanding (millions): Basic 27.219 31.954 32.971 ========== ========== ========== Diluted 27.255 32.016 33.123 ========== ========== ==========
S-2 44 UGI CORPORATION AND SUBSIDIARIES SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY) STATEMENTS OF CASH FLOWS (Millions of dollars)
Year Ended September 30, ---------------------------------------------------- 2000 1999 1998 ---------- ---------- ---------- NET CASH PROVIDED BY OPERATING ACTIVITIES (a) $ 95.5 $ 178.0 $ 77.8 CASH FLOWS FROM INVESTING ACTIVITIES: Investments in unconsolidated subsidiaries (95.8) (16.5) (34.8) Other - - 2.5 ----------- ---------- ---------- Net cash used by investing activities (95.8) (16.5) (32.3) CASH FLOWS FROM FINANCING ACTIVITIES: Payment of dividends on Common Stock (41.2) (47.9) (47.6) Issuance of intercompany long-term debt 47.5 - - Issuance of Common Stock 3.8 4.7 8.5 Repurchases of Common Stock (9.1) (133.1) (11.3) ----------- ---------- ---------- Net cash used by financing activities 1.0 (176.3) (50.4) ----------- ---------- ---------- Cash and cash equivalents increase (decrease) $ 0.7 $ (14.8) $ (4.9) =========== ========== ========== Cash and cash equivalents: End of period $ 1.1 $ 0.4 $ 15.2 Beginning of period 0.4 15.2 20.1 ----------- ---------- ---------- Increase (decrease) $ 0.7 $ (14.8) $ (4.9) =========== ========== ==========
(a) Includes dividends received from unconsolidated subsidiaries of $96.2, $176.7 and $77.6, respectively, for the years ended September 30, 2000, 1999 and 1998. S-3 45 UGI CORPORATION AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Millions of dollars)
Charged Balance at (credited) Balance at beginning to costs and end of of year expenses Other year ---------- ------------ ----------- ---------- YEAR ENDED SEPTEMBER 30, 2000 - ----------------------------- Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 8.0 $ 10.0 $ (8.9)(1) $ 9.3 ========== 0.2 (2) ========== Allowance for amortization of deferred financing costs - AmeriGas Propane $ 7.1 $ 1.7 $ - $ 8.8 ========== ========== Allowance for amortization of other deferred costs - AmeriGas Propane $ 2.1 $ 0.4 $ (1.5)(2) $ 1.0 ========== ========== Other reserves: Self-insured property and casualty liability $ 38.7 $ 14.1 $ (15.8)(3) $ 37.1 ========== 0.1 (2) ========== Insured property and casualty liability $ 5.1 $ (3.0) $ 2.1 ========== ========== Environmental, litigation and other $ 12.5 $ (1.3)(3) $ 11.2 ========== ========== YEAR ENDED SEPTEMBER 30, 1999 - ----------------------------- Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 7.9 $ 7.8 $ (7.9)(1) $ 8.0 ========== 0.2 (2) ========== Allowance for amortization of deferred financing costs - AmeriGas Propane $ 5.4 $ 1.7 $ - $ 7.1 ========== ========== Allowance for amortization of other deferred costs - AmeriGas Propane $ 4.6 $ 1.0 $ (3.5)(2) $ 2.1 ========== ========== Other reserves: Self-insured property and casualty liability $ 48.5 $ 12.9 $ (22.9)(3) $ 38.7 ========== 0.2 (2) ========== Insured property and casualty liability $ 4.3 $ 0.8 $ 5.1 ========== ========== Environmental, litigation and other $ 13.9 $ (1.5)(3) $ 12.5 ========== $ 0.1 (2) ==========
S-4 46 UGI CORPORATION AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (CONTINUED) (Millions of dollars)
Charged Balance at (credited) Balance at beginning to costs and end of of year expenses Other year ---------- ------------ ----------- ---------- YEAR ENDED SEPTEMBER 30, 1998 - ----------------------------- Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 11.3 $ 8.4 $ (11.8)(1) $ 7.9 ========== ========== Allowance for amortization of deferred financing costs - AmeriGas Propane $ 3.8 $ 1.6 $ - $ 5.4 ========== ========== Allowance for amortization of other deferred costs - AmeriGas Propane $ 3.9 $ 0.7 $ - $ 4.6 ========== ========== Other reserves: Self-insured property and casualty liability $ 48.5 $ 11.7 $ (11.7)(3) $ 48.5 ========== ========== Insured property and casualty liability $ 1.8 $ 2.9 $ (0.4)(3) $ 4.3 ========== ========== Environmental, litigation and other $ 22.6 $ (4.0) $ (4.7)(3) $ 13.9 ========== ==========
(1) Uncollectible accounts written off, net of recoveries. (2) Other adjustments. (3) Payments, net. S-5 47 EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION - ----------- ----------- 10.6 UGI Corporation Directors Deferred Compensation Plan Amended and Restated as of January 1, 2000 10.9 UGI Corporation Directors Equity Compensation Plan Amended and Restated as of January 1, 2000 10.33 Form of Guarantee Agreement dated September 2000 between UGI Corporation and RZB relating to loan amount of EURO 14.9 million 10.34 Form of Guarantee Agreement dated September 2000 between UGI Corporation and RZB relating to loan amount of EURO 9 million 10.38 Consulting Services Agreement dated as of August 1, 2000 between Stephen D. Ban and UGI Corporation 10.39 1992 Non-Qualified Stock Option Plan, as amended 10.40 Service Agreement dated February 23, 1998 between UGI Utilities, Inc. and Texas Eastern Transmission Corporation 10.41 Service Agreement dated February 23, 1999 between UGI Utilities, Inc. and Texas Eastern Transmission Corporation 13 Pages 13 to 47 of the 2000 Annual Report 21 Subsidiaries of the Registrant 23 Consent of Arthur Andersen LLP 27 Financial Data Schedule
EX-10.6 2 w43405ex10-6.txt UGI CORP DIRECTORS DEFFERED COMPENSATION PLAN 1 EXHIBIT 10.6 UGI CORPORATION AMENDED AND RESTATED DIRECTORS' DEFERRED COMPENSATION PLAN 1. Background and Purpose 1.1 The Directors' Deferred Compensation Plan (the "Plan") was adopted effective as of June 20, 1984. The Plan was adopted and, until April 10, 1992, maintained by UGI Utilities, Inc., which prior to April 10, 1992 was known as UGI Corporation ("UGI Utilities"). On April 10, 1992, UGI Utilities became a subsidiary of New UGI Corporation which was renamed, as of such date, UGI Corporation. As of April 10, 1992 UGI Corporation assumed sponsorship of the Plan and all obligations of UGI Utilities hereunder. In connection with the transfer of Plan sponsorship, pursuant to the authority granted under Section 6.4, the Plan was amended and restated in its entirety effective as of April 10, 1992. Pursuant to the authority granted under Section 6.4, the Plan is now amended and restated in its entirety effective as of January 1, 2000, to reflect certain changes approved by the Board of Directors on December 14, 1999. 1.2 The Plan is intended to enable each Director of the Company to defer the payment of all or a specified portion of the compensation otherwise payable in cash for services rendered as a Director of the Company, until the cessation of the Director's services on the Board, the Director's attainment of a specified age, or the Director's death. 2. Definitions For case of reference, the following definitions will be used in the Plan: 2.1 "Affiliate" and "Associate" shall have the respective meanings ascribed to such terms in Rule 12b-2 of the General Rules and Regulations under the Exchange Act. 2.2 "Beneficial Owner" means that a person shall be deemed the "Beneficial Owner" of any securities: (i) that such person or any of such person's Affiliates or Associates, directly or indirectly, has the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the exercise of conversion rights, exchange rights, rights, warrants, or options, or otherwise; provided, however, that a person shall not be deemed the "Beneficial Owner" of securities tendered pursuant to a tender or exchange offer made by such person or any of such person's Affiliates or Associates until such tendered securities are accepted for payment, purchase or exchange; (ii) that such person or any of such person's Affiliates or Associates, directly or indirectly, has the right to vote or dispose of or has "beneficial ownership" of (as determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act), including without limitation pursuant to any agreement, arrangement or understanding, whether or not in writing; provided, however, that a person shall not be deemed the "Beneficial Owner" of any security under this clause (ii) as a result of an oral or written agreement, arrangement or understanding to vote such security if such 2 agreement, arrangement or understanding (A) arises solely from a revocable proxy given in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable provisions of the General Rules and Regulations under the Exchange Act, and (B) is not then reportable by such person on Schedule 13D under the Exchange Act (or any comparable or successor report); or (iii) that are beneficially owned, directly or indirectly, by any other person (or any Affiliate or Associate thereof) with which such person (or any of such person's Affiliates or Associates) has any agreement, arrangement or understanding (whether or not in writing) for the purpose of acquiring, holding, voting (except pursuant to a revocable proxy as described in the proviso to clause (ii) above) or disposing of any voting securities of the Company; provided, however, that nothing in this section shall cause a person engaged in business as an underwriter of securities to be the "Beneficial Owner" of any securities acquired through such person's participation in good faith in a firm commitment underwriting until the expiration of forty days after the date of such acquisition. 2.3 "Board of Directors", "Board", "Directors" or "Director" mean, respectively, the Board of Directors, the Directors or a Director of the Company. 2.4 "Change of Control" of the Company means (i) any person (except the Director, his Affiliates and Associates, the Company, any subsidiary of the Company, any employee benefit plan of the Company or of any subsidiary of the Company, or any person or entity organized, appointed or established by the Company for or pursuant to the terms of any such employee benefit plan), together with all Affiliates and Associates of such person, becomes the Beneficial Owner in the aggregate of 20% or more of either (A) the then outstanding shares of Common Stock of the Company (the "Outstanding Company Common Stock") or (B) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Company Voting Securities"); or (ii) individuals who, as of the beginning of any twenty-four month period, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board, provided that any individual becoming a director subsequent to the beginning of such period whose election or nomination for election by the Company's shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the Directors of the Company (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act); or (iii) consummation by the Company of a reorganization, merger or consolidation (a "Business Combination"), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of the Outstanding Company Common Stock and Company Voting Securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of Common Stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business -2- 3 Combination of the Outstanding Company Common Stock and Company Voting Securities, as the case may be; or (iv) (A) Consummation of a complete liquidation or dissolution of the Company or (B) sale or other disposition of all or substantially all of the assets of the Company other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of Common Stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of the Outstanding Company Common Stock and Company Voting Securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of the Outstanding Company Common Stock and Company Voting Securities, as the case may be, immediately prior to such sale or disposition. 2.5 The "Committee" means the Compensation and Management Development Committee of the Board of Directors as constituted from time to time. 2.6 "Common Stock" means the common stock of the Company. 2.7 The "Company" means, prior to April 10, 1992, UGI Utilities. From and after April 10, 1992, the term "Company" shall mean UGI Corporation, a Pennsylvania corporation (formerly named New UGI Corporation). 2.8 "Deferred Compensation Account" or "Accounts" means the separate account established under the Plan for each Participant, as described in Section 4.1. 2.9 "Exchange Act" means Securities Exchange Act of 1934, as amended. 2.10 "Notice" means a written notice given to the Secretary, pursuant to Section 3.2 or a form substantially in the form of Exhibit A attached hereto. 2.11 "Participant" means each Director of the Company who participates in the Plan. 2.12 The "Plan" means the UGI Corporation Directors' Deferred Compensation Plan as set forth herein, or as it may be amended from time to time by the Committee or Board of Directors. 2.13 The "Plan Year" means the calendar year. 2.14 The "Secretary" means the Secretary of the Company who will have responsibility for those functions assigned to the Secretary under the Plan. 3. Participation 3.1 Each Director is eligible to participate in the Plan except a Director who is also an employee of the company or any of its subsidiaries or affiliates. 3.2 The procedure to participate in the Plan is as follows: -3- 4 (a) A Director, or a nominee for that office, may elect to participate in the Plan by giving a written Notice to the Secretary. The effective date for a Director's participation in the Plan will be either (i) the date of election to a first term as a Director; or (ii) the commencement of the earning period in any Plan Year, whichever first occurs following the giving of such Notice. Such election will remain in effect until (i) the termination of the Participant's services as a Director; or (ii) the Participant's further written Notice to the Secretary of the termination or the modification of such election. (b) An election to terminate or modify a prior election to defer compensation will be effective at the start of the Plan Year and must be made by the Participant prior to the Plan Year to which such compensation pertains. 4. Compensation Deferred 4.1 A Participant may elect to defer the receipt of all or a specified portion of the compensation otherwise payable in cash for services rendered as a Director of the Company. Such compensation includes retainer fees for service on the Board and Board committees of the Company and fees for attendance at meetings of the Board and Board committees of the Company, but does not include travel expense allowances, other expense reimbursement, or non-cash compensation. 4.2 An unfunded Deferred Compensation Account will be established for each Participant and the compensation that the Participant elects to defer under the Plan will be credited to that Account. Each such credit will be made to the Account as of the last day of the month during which such compensation would have otherwise been payable to the Participant in cash. 4.3 Compensation deferred under the Plan is assumed to earn interest at a market rate determined by the Committee for each year during the period in which compensation is deferred. Each Participant will be notified of this rate annually. Notwithstanding the foregoing, the Committee may at any time or from time to time change or otherwise modify the basis or the method for calculating and crediting such interest, provided that the change or modification does not adversely affect the balance of any Participant's Account at the time of the change or modification. 4.4 Each Participant will receive a statement of the balance in the Participant's Account at the end of each Plan Year as promptly as practicable thereafter. 5. Payment of Deferred Compensation 5.1 Upon the termination of a Participant's services as a Director, the balance in the Participant's Account will be paid in accordance with the method and at the time or times elected by the Participant by the Notice in effect at the time each portion of the Participant's compensation was deferred and credited to such Account. 5.2 Notwithstanding Section 5.1, a Participant may elect, no later than the end of the Plan Year preceding the Plan Year in which the Participant's services as a Director terminates, periodic payments over a specified period of years or a lump sum -4- 5 distribution, provided that (i) no payment may be made prior to January of the calendar year following the calendar year during which the Participant's services as a Director terminate, unless the payment is made pursuant to Section 5.3, 5.4 or 5.5; (ii) a lump sum payment must be made or installment payments must commence no later than January of the Plan Year following the Participant's attainment of age 70 or January of the Plan Year following the termination of the Participant's services as a Director, whichever is later; and (iii) installment payments must be made at least annually and not more frequently than quarterly for a period not to exceed 20 years. 5.3 Unless otherwise provided by the Committee, in the event of a Change of Control of the Company, the Participant's Account will be paid in cash as soon as practicable. A Participant may elect to defer receipt of such payment until such Participant attains a specified age, not to exceed the age of the Participant in January of the Plan Year following the Participant's attainment of age 70. In addition, a Participant may elect to receive such payment in (i) a single distribution or (ii) annual or quarterly installments over a period not to exceed 20 years. Both such elections made hereunder must be made no later than December 31st of the calendar year preceding the year of the Change of Control. 5.4 Notwithstanding any other provisions of this Plan, if the Committee determines, after consideration of a Participant's application, that the Participant has a financial need of such a substantial nature that a contemporaneous payment of compensation deferred under this Plan is warranted, the Committee may, in its sole and absolute discretion, direct that all or a portion of the balance of the Participant's Account be paid to the Participant. The payment will be made in the manner and at the time specified by the Committee. No Participant who is also a member of the Committee may in any way take part in any decision pertaining to a request for payment made by that Participant under this Section 5.4. 5.5 In the event of a Participant's death before the balance in the Participant's Account is fully paid out: (a) Payment of such balance will be made to the beneficiary or beneficiaries designated by the Participant or, if the Participant has made no such designation or no beneficiary survives, to the Participant's estate. In either case, such payment will be made in the same manner as provided with respect to payments to the Participant; provided, that any lump sum payment must be made and any installment payments must commence no later than January of the calendar year following the Participant's death. (b) If the balance in such Account is to be paid to the estate of the Participant in installments, the Committee may, in its sole and absolute discretion and upon receipt of an application therefor from the duly appointed Administrator or Executor of such estate, direct that the balance in the Participant's Deferred Compensation Account be paid to the estate in a single payment at such time as is specified by the Committee. -5- 6 6. General 6.1 The right of any Participant, beneficiary or estate to receive payment of any unpaid balance in the Participant's Account will be an unsecured claim against the general assets of the Company. 6.2 During a Participant's lifetime, any payment under the Plan will be made only to the Participant. No sum or other interest under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance or charge, and any attempt by a Participant or any beneficiary under the Plan to do so shall be void. No interest under the Plan shall in any manner be liable for or subject to the debts, contracts, liabilities, engagements or torts of a Participant or beneficiary entitled thereto. 6.3 Except as otherwise provided herein, the Plan will be administered by the Committee which will have the authority, subject to the express provisions of the Plan, to adopt, amend and rescind rules and regulations relating to the Plan, and to interpret, construe and implement the provisions of the Plan. 6.4 The Plan may at any time or from time to time be amended, modified, or terminated by the Committee, provided that no amendment, modification or termination may (i) adversely affect the balance in a Participant's Account without the Participant's consent or (ii) permit payment of such balance prior to the date specified pursuant to Section 5.2 (except for payments provided for in Section 5.3, 5.4 or 5.5). IN WITNESS WHEREOF, and as evidence of its adoption of this Amended and Restated Plan, the Company has caused the same to be executed by its duly authorized officer and its corporate seal to be affixed hereto as of the 1st day of January, 2000. [Corporate Seal} UGI CORPORATION By:___________________________ Title: -6- 7 Exhibit A NOTICE TO DEFER UNDER UGI CORPORATION AMENDED AND RESTATED DIRECTORS' DEFERRED COMPENSATION PLAN CALENDAR YEAR: 2001 I hereby elect to defer, under the terms and conditions of the UGI Corporation Directors' Deferred Compensation Plan (the "Plan"), the payment of compensation (excluding travel expense allowances, other expense reimbursement, or non-cash compensation) otherwise due to me on account of my future services as a Director of UGI corporation as set forth below: 1. AMOUNT OF DEFERRAL: ______ All ______ % $ ______ 2. METHOD OF PAYMENT: (CHOOSE ONE) ______ Lump Sum; or ______ Installments Payable: ______ Quarterly ______ Annually over ______ Years (not more than 20) 3. TIME OF PAYMENT (IF LUMP SUM), OR START OF PAYMENT (IF INSTALLMENTS): ______ January following the termination of my services as a Director, or ______ January following my attainment of age ______ (no later than 70), whichever is later. 4. TIME OF PAYMENT UPON A CHANGE OF CONTROL OF COMPANY: IN THE EVENT OF A CHANGE CONTROL OF THE COMPANY, UNLESS OTHERWISE PROVIDED BY THE COMMITTEE, YOUR ACCOUNT WILL BE PAID IN CASH AS SOON AS PRACTICABLE. HOWEVER, YOU MAY ELECT TO DEFER RECEIPT OF PAYMENT AS FOLLOWS: ______ January following my attainment of age ______ (no later than 70). Method of Payment upon Change of Control: (Choose one) ______ Lump Sum; or ______ Installments Payable: ______ Quarterly ______ Annually over ______ Years (not more than 20) 8 5. BENEFICIARY OR BENEFICIARIES TO WHOM PAYMENT IS TO BE MADE (AS ABOVE SPECIFIED) IN THE EVENT OF MY DEATH BEFORE RECEIVING PAYMENT OF THE ENTIRE BALANCE IN MY DEFERRED COMPENSATION ACCOUNT. IF MORE THAN ONE BENEFICIARY IS NAMED, PLEASE INDICATE THE PERCENTAGE TO BE PAID TO EACH. % - ---------------------- ------------------------------- -------- Name ------------------------------- Address % - ---------------------- ------------------------------- -------- Name ------------------------------- Address This election supersedes any prior election I have made under the Plan, and is effective as to compensation otherwise due to me for my services as a Director after (i) the date of my election to my first term in that office, or (ii) the Commencement of the next Plan Year, whichever first occurs after the date hereof. The beneficiary election is effective immediately. ---------------------------------- ---------------------------------- Date Signature ---------------------------------- Name [please print] EX-10.9 3 w43405ex10-9.txt UGI CORP DIRECTORS EQUITY COMPENSATION PLAN 1 EXHIBIT 10.9 UGI CORPORATION AMENDED AND RESTATED DIRECTORS' EQUITY COMPENSATION PLAN 1. PURPOSE The purpose of the UGI Corporation Directors' Equity Compensation Plan is to provide a means whereby UGI Corporation (the "Company") may, through the grant of common stock of the Company ("Common Stock") or deferred units ("Units") relating to such stock, offer a reward and an incentive to the members of the board of directors of the Company, motivate such directors to exert their best efforts on behalf of the Company and further to align the economic interest of such individuals with those of the Company's shareholders. This Plan is intended to constitute, in part, a non-qualified deferred compensation plan. Pursuant to the authority granted under Section 8.06, the Plan is amended in its entirety effective as of January 1, 2000, to reflect certain changes approved by the Board of Directors on December 14, 1999. 2. DEFINITIONS Whenever used in this Plan, the following terms will have the respective meanings set forth below: 2.01 "Account" means the Company's record established pursuant to Section 5 which reflects the number of Units and the amount of Dividend Equivalents standing to the credit of a Participant under the Plan. 2.02 "Affiliate" and "Associate" shall have the respective meanings ascribed to such terms in Rule 12b-2 of the General Rules and Regulations under the Exchange Act. 2.03 "Beneficial Owner" means that a person shall be deemed the "Beneficial Owner" of any securities: (i) that such person or any of such person's Affiliates or Associates, directly or indirectly, has the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the exercise of conversion rights, exchange rights, rights, warrants or options, or otherwise; provided, however, that a person shall not be deemed the "Beneficial Owner" of securities tendered pursuant to a tender or exchange offer made by such person or any of such person's Affiliates or Associates until such tendered securities are accepted for payment, purchase or exchange; (ii) that such person or any of such person's Affiliates or Associates, directly or indirectly, has the right to vote or dispose of or has "beneficial ownership" of (as determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act), including without limitation pursuant to any agreement, arrangement or understanding, whether or not in writing; provided, however, that a person shall not be deemed the "Beneficial Owner" of any security under this clause (ii) as a result of an oral or written agreement, arrangement or understanding to vote such security if such agreement, arrangement or understanding (A) arises solely from a revocable proxy given in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable provisions of the 2 General Rules and Regulations under the Exchange Act, and (B) is not then reportable by such person on Schedule 13D under the Exchange Act (or any comparable or successor report); or (iii) that are beneficially owned, directly or indirectly, by any other person (or any Affiliate or Associate thereof) with which such person (or any of such person's Affiliates or Associates) has any agreement, arrangement or understanding (whether or not in writing) for the purpose of acquiring, holding, voting (except pursuant to a revocable proxy as described in the proviso to clause (ii) above) or disposing of any voting securities of the Company; provided, however, that nothing in this section shall cause a person engaged in business as an underwriter of securities to be the "Beneficial Owner" of any securities acquired through such person's participation in good faith in a firm commitment underwriting until the expiration of forty days after the date of such acquisition. 2.04 "Beneficiary" means the person(s) designated by a Participant to receive any benefits payable under this Plan subsequent to the Participant's death. The Committee shall provide a form for this purpose. In the event a Participant has not filed a Beneficiary designation with the Company, the Beneficiary shall be the Participant's estate. 2.05 "Board" means the Board of Directors of the Company. 2.06 "Change of Control" of the Company means (i) any person (except the Director, his Affiliates and Associates, the Company, any subsidiary of the Company, any employee benefit plan of the Company or of any subsidiary of the Company, or any person or entity organized, appointed or established by the Company for or pursuant to the terms of any such employee benefit plan), together with all Affiliates and Associates of such person, becomes the Beneficial Owner in the aggregate of 20% or more of either (A) the then outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or (B) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Company Voting Securities"); or (ii) individuals who, as of the beginning of any twenty-four month period, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board, provided that any individual becoming a director subsequent to the beginning of such period whose election or nomination for election by the Company's shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the Directors of the Company (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act); or (iii) consummation by the Company of a reorganization, merger or consolidation (a "Business Combination"), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of the Outstanding Company Common Stock and Company Voting Securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of the 2 3 Outstanding Company Common Stock and Company Voting Securities, as the case may be; or (iv)(A) Consummation of a complete liquidation or dissolution of the Company or (B) sale or other disposition of all or substantially all of the assets of the Company other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of the Outstanding Company Common Stock and Company Voting Securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of the Outstanding Company Common Stock and Company Voting Securities, as the case may be, immediately prior to such sale or disposition. 2.07 "Committee" means the Compensation and Management Development Committee of the Board and any successor thereto. 2.08 "Common Stock" means the common stock of the Company. 2.09 "Company" means UGI Corporation and any successor thereto. 2.10 "Director" means a member of the Board who is not an employee of the Company or any of its Affiliates. 2.11 "Dividend Equivalent" means an amount determined by multiplying the number of Units credited to a Participant's Account by the per share cash dividend, or the per share fair market value (as determined by the Committee) of any dividend in consideration other than cash, paid by the Company on its stock on a dividend payment date. 2.12 "Effective Date" means January 1, 1997. 2.13 "Exchange Act" means Securities Exchange Act of 1934, as amended. 2.14 "Fair Market Value" of Common Stock means the average, rounded to the next highest one-eighth of a point (.125), of the highest and lowest sales prices thereof on the New York Stock Exchange on the day on which Fair Market Value is being determined, as reported on the Composite Tape for transactions on the New York Stock Exchange. In the event that there are no Common Stock transactions on the New York Stock Exchange on such day, the Fair Market Value will be determined as of the immediately preceding day on which there were Common Stock transactions on that exchange. 2.15 "Participant" means any Director who is eligible to participate in the Plan under Section 4. In the event of the death or incompetency of a Participant, the term shall mean his personal representative or guardian. An individual shall remain a Participant until that individual has received full distribution of any amount credited to the Participant's Account. 2.16 "Plan" means the UGI Corporation Directors' Equity Compensation Plan as the same is set forth herein, and as it may be amended from time to time. 3 4 2.17 "Plan Year" means the calendar year. 2.18 "Separates from Service" means the Director's termination of service as a member of the Board for any reason other than death. Except as otherwise provided herein, a Separation from Service shall be deemed to have occurred on the last day of the month during which the Director's service to the Company ceases and shall be determined without reference to any compensation continuation arrangement that may be applicable. 2.19 "Unit" means a single unit granted to a Participant which represents a phantom interest equivalent to one share of Common Stock. 2.20 "Unit Value" means, at any time, unless otherwise specified in the Plan, the value of each Unit issued under the Plan, which value shall be equal to the Fair Market Value of the Common Stock on such date. 3. ADMINISTRATION The Plan shall be administered by the Committee which shall have full power and authority to interpret the Plan, to prescribe, amend and rescind any rules, forms and procedures as it deems necessary or appropriate for the proper administration of the Plan and to make any other determinations, including factual determinations, and take such other actions as it deems necessary or advisable in carrying out its duties under the Plan. All decisions and determinations by the Committee shall be final and binding on the Company, Participants, Directors, Beneficiaries and any other persons having or claiming an interest hereunder. Any other provisions of the Plan notwithstanding, the Board may perform any function of the Committee under the Plan, including without limitation for the purpose of ensuring that transactions under the Plan by Participants who are subject to Section 16 of the Exchange Act in respect of the Company are exempt under Rule 16b-3. In any case in which the Board is performing a function of the Committee under the Plan, each reference to the Committee herein shall be deemed to refer to the Board (unless the context shall otherwise require). 4. PARTICIPATION Each Director of the Company shall become a Participant of the Plan on the later of (i) the Effective Date or (ii) the date such individual first becomes a Director. 5. AWARD OF UNITS 5.01 Initial Award of Units. On the Effective Date, each Director who is a Participant on January 1, 1997 shall be awarded the number of Units equal to the present value of benefits accrued by that Director through December 31, 1996 under the UGI Corporation Retirement Plan for Outside Directors, as determined by an actuary appointed by the Committee. The value of each Unit to be credited to a Participant's Account pursuant to this section shall be equal to the average of the closing sales prices for the Common Stock as reported on the New 4 5 York Stock Exchange Composite Tape for each trading day in the period October 1, 1996 through December 31, 1996. 5.02 Annual Award of Units. On the first day of each Plan Year, each Participant shall receive an award of 630 Units. Such awarded Units shall be credited to each Participant's Account as specified in Section 5.04 below. Any Participant who was not a Participant on the first day of the Plan Year shall receive, on the date such individual becomes a Participant, a pro-rata share of the annual award of Units determined based on the number of calendar quarters during the Plan Year that such Participant is expected to serve as a Director. A Director will be deemed to serve the entire quarter during which he is a Director at least one day. 5.03 Dividend Equivalents (a) Dividend Equivalent to be Credited. From the date of grant of each Unit to a Participant until the Participant's Account has been fully distributed, the Company shall credit to each Participant's Account on each record date for the payment of a dividend by the Company on its Common Stock, an amount equal to the Dividend Equivalent associated with the Units in the Account. (b) Conversion to Units. On the last day of each Plan Year, the amount of the Dividend Equivalents credited to the Participant's Account during that Plan Year shall be converted to a number of Units, based on the Unit Value on that day. Notwithstanding the foregoing, in the event of a Change of Control or in the event the Participant dies or Separates from Service prior to the last day of the Plan Year, as soon as practicable following such event and in no event later that the date on which Units are redeemed in accordance with Section 6, the Company shall convert the amount of the Dividend Equivalents credited to the Participant's Account as of the date of the Change of Control, death or Separation from Service (the "Conversion Date") to the number of Units based on the Unit Value on the Conversion Date. 5.04 Accounts. The Company shall keep records to reflect the number of Units and Dividend Equivalents credited to each Participant hereunder; provided, however, that no Participant or any other person shall under any circumstances acquire any property interest in any specific assets of the Company. Fractional Units shall accumulate in the Participant's Account and shall be added to fractional Units held in such Account to create whole Units. Nothing contained in this Plan and no action taken pursuant hereto shall create or be construed to create a fiduciary relationship between the Company and any Participant or any other person. To the extent that any person acquires a right to receive payment from the Company hereunder, such right shall be no greater than the right of any unsecured general creditor of the Company. 6. EVENTS REQUIRING REDEMPTION OF UNITS The Company shall redeem Units credited to a Participant's Account only at the times and in the manner prescribed by the further terms of this Section 6. To determine the total amount to be paid, all redemptions shall be made by providing a number of shares of Common Stock equal to the number of Units being redeemed; provided, however, that any fractional Units credited to 5 6 a Participant's Account shall be paid in cash in an amount equal to the Unit Value of such fractional Unit. 6.01 Death. In the event a Participant dies, the Company shall redeem all of the Units then credited to the Participant's Account. Any such redemption shall be paid to the Participant's Beneficiary in the form of Common Stock. 6.02 Separation from Service. In the event a Participant Separates from Service, the Company shall redeem all of the Units then credited to the Participant's Account as soon as practicable following such Separation from Service. Any such redemption shall be paid in the form of Common Stock. A Participant may elect to defer receipt of such payment until such Participant attains a specific age, not to exceed the age of the Participant in January of the Plan Year following the Participant's attainment of age seventy (70). In addition, a Participant may elect to receive such payment in (i) a single distribution or (ii) annual or quarterly installments over a period not to exceed twenty (20) years. Both such elections made hereunder must be made no later than December 31st of the Plan Year preceding the Plan Year of Separation from Service. Dividend Equivalents will be credited to such Participant's Account in accordance with Section 5 until the full amount of the Participant's Account has been distributed. Each installment payment shall be calculated by dividing the Participant's total Account balance as of such payment date by the number of payments remaining in the installment period. 6.03 Change of Control. Unless otherwise provided by the Committee, in the event of a Change of Control of the Company, the Company shall redeem all of the Units then credited to the Participant's Account. Any such redemption shall be made in the form of cash. The amount paid shall equal the product of the number of Units being redeemed multiplied by the then Unit Value. A Participant may elect to defer receipt of such payment until such Participant attains a specified age, not to exceed the age of the Participant in January of the Plan Year following the Participant's attainment of age seventy (70). In addition, a Participant may elect to receive such payment in (i) a single distribution or (ii) annual or quarterly installments over a period not to exceed twenty (20) years. Both such elections made hereunder must be made no later than December 31st of the calendar year preceding the year of the Change of Control. 7. RETAINER AWARDS 7.01 Annual Grants. The Committee is authorized, subject to limitations under applicable law, to grant to any Participant awards of Common Stock in lieu of a portion of their annual retainer. Unless otherwise determined by the Committee, the number of shares of Common Stock to be paid to Directors annually under this Section 7.01 will be equal to (i) the amount by which the annual retainer at the rates then in effect exceeds $18,500 divided by (ii) the Fair Market Value of the Common Stock as of the first day of the Plan Year. The shares of Common Stock to be paid pursuant to this section will become due on the date of the first meeting of the Board of Directors during the Plan Year. No fractional shares of Common Stock will be granted; instead, the amount remaining will be paid to the Participant in cash. As promptly as practicable, the Company will issue to the Participant shares of Common Stock registered in the name of the Participant (or, if directed by the Participant, in joint names of the Participant and his or her spouse). Any Participant who commences service during the Plan Year 6 7 shall receive a pro-rata share of the annual retainer, the same proportion of which will be paid in Common Stock as was paid to a Director serving a full Plan Year, determined based on the number of calendar quarters during the Plan Year that the Participant is expected to serve as a Director. 7.02 Deferral of Retainers and Meeting Attendance Fees. A Participant may elect, no later than the end of the calendar year preceding the calendar year of payment to convert all or any part of (i) the cash portion of the annual retainer, (ii) Committee Chair annual retainer, and (iii) meeting attendance fees, into Units under this Plan, payable in accordance with the terms of the Plan. Dividend Equivalents will be credited and Units will be awarded to such Participant's Account in accordance with the provisions of Section 5.03 during such deferral period. 8. MISCELLANEOUS 8.01 Transferability. No Unit awarded under this Plan shall be transferred, assigned, pledged or encumbered by the Participant, and a Unit may be redeemed during the lifetime of a Participant only from such Participant. 8.02 No Rights as Shareholder. No Participant shall have any rights as a shareholder of the Company, including the right to any cash dividends, or the right to vote, as a result of the grant to the Participant, or the Participant's holding of, any Units. 8.03 Adjustment Upon Acquisitions, Dispositions or other Events not in the Ordinary Course of Business. Notwithstanding anything herein to the contrary, if the Company's financial performance is affected by any event that is of a non-recurring nature including an acquisition or disposition of the assets or stock of a business, the Committee, in its sole discretion, may make such adjustments in the number of Units or the Unit Value of each Unit for the then current Plan Year as it shall determine to be equitable and appropriate in order to make the value of each Unit, as nearly as may be practicable, equivalent to the value of the Unit immediately prior to such event. 8.04 No Rights to Service. Nothing in this Plan, and no action taken pursuant hereto, shall affect the Participant's term of service as a Director. 8.05 Notices. Any notice hereunder to be given to the Company shall be in writing and shall be delivered in person to the Secretary of the Company, or shall be sent by registered mail, return receipt requested, to the Secretary of the Company at the Company's executive offices, and any notice hereunder to be given to the Participant shall be in writing and shall be delivered in person to the Participant, or shall be sent by registered mail, return receipt requested, to the Participant at his last address as shown in the employment records of the Company. Any notice duly mailed in accordance with the preceding sentence shall be deemed given on the date postmarked. 8.06 Termination and Amendment of the Plan/Modification of Units. The Plan may be terminated, modified or amended by the Committee at any time, except with respect to any Units then outstanding under the Plan; provided, however, that the Committee may accelerate the 7 8 redemption of any Units then outstanding as if a redemption were then being made under Section 6. 8.07 Miscellaneous. (a) If the Company shall find that any person to whom any payment is payable under this Plan is unable to care for his affairs because of illness or accident, or is a minor, any payment due (unless a prior claim therefor shall have been made by a duly appointed guardian, committee or other legal representative) may be paid to the spouse, a child, a parent, or a brother or sister, or to any person deemed by the Company to have incurred expense for such person otherwise entitled to payment, in such manner and proportions as the Company may determine. Any such payment shall be a complete discharge of the liabilities of the Company under this Plan. (b) This Plan shall be binding upon and inure to the benefit of the Company, its successors and assigns and the Participant and his heirs, executors, administrators and legal representatives. (c) This Plan shall be construed in accordance with, and governed by, the law of the Commonwealth of Pennsylvania. 8.08 Shareholder Approval. This Plan shall be effective on the Effective Date, subject to the approval by a majority of the shareholders of the Company at the next annual meeting following the Effective Date. IN WITNESS WHEREOF, and as evidence of its adoption of this Amended and Restated Plan, the Company has caused the same to be executed by its duly authorized officer and its corporate seal to be affixed hereto as of the 1st day of January, 2000. UGI CORPORATION [Corporate Seal] By: ------------------------------- Title 8 9 Exhibit A NOTICE UNDER UGI CORPORATION AMENDED AND RESTATED DIRECTORS' EQUITY COMPENSATION PLAN CALENDAR YEAR: 2001 I. ELECTION TO DEFER DISTRIBUTION OF COMMON STOCK UNDERLYING UNITS BEYOND SEPARATION FROM SERVICE: The Plan automatically defers receipt of the Units credited to your account until your Separation from Service. Please complete Section III below to make your initial election or to change any prior elections with respect to method and timing of payment of such Units as well as the designation of your beneficiary. II. ELECTION TO DEFER CASH COMPENSATION INTO UNITS UNDER THE AMENDED AND RESTATED DIRECTORS' EQUITY PLAN: The Plan allows you to elect to defer receipt of cash compensation (including annual cash retainer, Board meeting fees, Committee meeting fees and Committee Chair fees, but excluding expense reimbursements and non-cash compensation) and to convert such cash deferrals into Units. Those Units will be included in your total account of Units under the Plan and paid in accordance with your elections in Section III below. I hereby elect to defer receipt of cash compensation payable in calendar year 2001 into Units in my account under the Plan in the following manner: AMOUNT OF CASH COMPENSATION TO BE DEFERRED IN THE FORM OF UNITS: _________ All __________% $_________ * * * * * * III. 1. METHOD OF PAYMENT OF ALL SHARES OF COMMON STOCK UNDERLYING DEFERRED UNITS: (CHOOSE ONE) _____ Lump Sum; or _____ Installments Payable: _____ Quarterly _____ Annually over: _____ Years (not more than 20) 2. TIME OF RECEIPT OF SHARES OF COMMON STOCK UNDERLYING ALL DEFERRED UNITS (IF LUMP SUM), OR START OF PAYMENT (IF INSTALLMENTS): _____ January following the termination of my services as a Director, or _____ January following my attainment of age _____ (no later than 70), whichever is later. 10 3. TIME OF PAYMENT UPON A CHANGE OF CONTROL OF COMPANY: IN THE EVENT OF A CHANGE CONTROL OF THE COMPANY, UNLESS OTHERWISE PROVIDED BY THE COMMITTEE, ALL DEFERRED UNITS IN YOUR ACCOUNT WILL BE PAID IN CASH AS SOON AS PRACTICABLE. HOWEVER, YOU MAY ELECT TO DEFER RECEIPT OF PAYMENT AS FOLLOWS: ____ January following my attainment of age _____ (no later than 70). METHOD OF PAYMENT UPON A CHANGE OF CONTROL: (CHOOSE ONE) ____ Lump Sum, or ____ Installments Payable: _____ Quarterly _____ Annually over _____ Years (not more than 20) 4. DESIGNATION OF BENEFICIARY: Beneficiary or Beneficiaries to whom Payment is to be made (as above specified) in the event of my death before receiving payment of the entire balance in my Account. If more than one beneficiary is named, please indicate the percentage to be paid to each. _______________________________ ______________________________ ________% Name _______________________________ ________% Address _______________________________ ______________________________ ________% Name _______________________________ ________% Address These elections supersede any prior elections I have made under the Plan, and are effective as to compensation otherwise due to me for my services as a Director after (i) the date of my election to my first term in that office, or (ii) the Commencement of the next Plan Year, whichever first occurs after the date hereof. The beneficiary election is effective immediately. __________________________ ___________________________________________ Date Signature ___________________________________________ Name [please print] EX-10.33 4 w43405ex10-33.txt GUARANTEE AGREEMENT BETWEEN UGI & RZB 14.9MIL EURO 1 Exhibit 10.33 UGI Corporation 460 North Gulph Road King of Prussia Pennsylvania 19406 USA Raiffeisen Zentralbank Osterreich Aktiengesellschaft Am Stadtpark 9 1030 Wien Austria Statement regarding Guarantee Agreement (B) dated 21 September 1999 - ------------------------------------------------------------------- Ladies and Gentlemen, We have taken note of the attached amendment offer of Flaga GmbH (the "Offer"). We hereby irrevocably and unconditionally agree that the Offer be accepted by your bank. Moreover, we hereby irrevocably and unconditionally agree and confirm that the Guarantee Agreement (B) as executed and concluded in Bratislava on 21 September 1999 by and between your bank as beneficiary and our company as guarantor shall remain in full force and effect and fully applicable in accordance with its terms in the event that you accept the Offer (such Guarantee Agreement (B) shall of course also remain in full force and effect and fully applicable in accordance with its terms in the event that you do not accept the Offer). ..........., dated 21.09.2000 UGI Corporation 1 Attachment: Offer of Flaga GmbH dated 21.09.2000 We hereby accept the above statement of UGI Corporation: Bratislava, dated 21.09.2000 Raiffeisen Zentralbank Osterreich Aktiengesellschaft page 1 2 FLAGA GmbH An der Bundesstrasse 6 2100 Leobendorf Austria Raiffeisen Zentralbank Osterreich Aktiengesellschaft Am Stadtpark 9 1030 Vienna Austria ............, 21 September 2000 RE.: OFFER (B) Dear Sirs, we, FLAGA GmbH, An der Bundesstrasse 6, 2100 Leobendorf, Austria, herewith refer to our previous Offer (B) (hereinafter the "Offer (B)") and propose to amend the terms of Offer (B) as follows (Clauses referred to herein are Clauses of Offer (B)): The amount in Clause 1.1 shall be replaced by EURO 14,959,285.00 (fourteenmillionninehundredandfiftyninethousand-twohundredeightyfive). The amounts in Clauses 1.2 (a), (b) and (c) shall be added up to one Tranche ("Tranche I") and reduced to the aggregate of EURO 6,959,285.00. The amounts in Clause 1.2 (d) and (e) shall be added up to one Tranche ("Tranche II") in the aggregate of EURO 8,000,000.00. Up to EURO 1,500,000.00, Tranche II can be used for the issuance of guarantees. Provisions of the Offer (B) applying to Tranches I, II and III shall now apply to Tranche I, and provisions of the Offer (B) applying to Tranches IV and V shall now apply to Tranche II. The date in Clause 2.1.(b) shall be replaced by 30 August 2003. In Clause 4.1 (a) and (d), "clause 4.1 (e), (f), (g) and (h) shall be replaced by: "clause 4.1 (e) and (f)". Clause 4.1 (e) shall be replaced by the following: "The Final Maturity of Tranche I shall be 31 August 2007" Clause 4.1 (f) shall be replaced by the following: "The Final Maturity of Tranche II shall be 30 September 2003; in August 2003, the parties shall enter into negotiations for an extension of the Final Maturity of Tranche II for an additional period of one year." Clauses 4.1 (g) and (h) shall be deleted. Clause 6.1 (a) and (b) shall be replaced by the following: page 1 3 "6.1 Subject to clause 4.1 (e) and (f) as applicable to the respective Tranche, repayments shall be made as follows: (a) in respect of Tranche I, repayments have to be made on the date and in amounts as follows:
Date Amount in ATS Amount in EUR - ---------------------------------------------------------- 01.02.2001 11.320.500 822.693 01.08.2001 11.320.500 822.693 01.02.2002 11.320.500 822.693 01.08.2002 11.320.500 822.693 31.12.2002 10.789.250 784.085 01.02.2003 6.083.000 442.069 30.06.2003 6.087.000 442.360 01.02.2004 3.440.075 250.000 01.08.2004 3.440.075 250.000 01.02.2005 3.440.075 250.000 01.08.2005 3.440.075 250.000 01.02.2006 3.440.075 250.000 01.08.2006 3.440.075 250.000 01.02.2007 3.440.075 250.000 01.08.2007 3.440.075 250.000
(b) in respect of Tranche II, repayment shall be made on the respective Final Maturity." All other clauses of Offer (B) shall remain unchanged. You can accept the present proposal by debiting our account no. 1-00.640.763 with an account fee in the amount of ATS 400.00, not later than 21 September 2001. You are hereby irrevocably authorized to make such debit. If you accept the present proposal, the respective amendments shall also apply to any agreement resulting from Offer (B). With kind regards, FLAGA GmbH page 2 EX-10.34 5 w43405ex10-34.txt GUARANTEE AGREEMENT BETWEEN UGI & RZB 9MILL EURO 1 Exhibit 10.34 UGI Corporation 460 North Gulph Road King of Prussia Pennsylvania 19406 USA Raiffeisen Zentralbank Osterreich Aktiengesellschaft Am Stadtpark 9 1030 Wien Austria Statement regarding Guarantee Agreement (C) dated 21 September 1999 - ------------------------------------------------------------------- Ladies and Gentlemen, We have taken note of the attached amendment offer of Flaga GmbH (the "Offer"). We hereby irrevocably and unconditionally agree that the Offer be accepted by your bank. Moreover, we hereby irrevocably and unconditionally agree and confirm that the Guarantee Agreement (C) as executed and concluded in Bratislava on 21 September 1999 by and between your bank as beneficiary and our company as guarantor shall remain in full force and effect and fully applicable in accordance with its terms in the event that you accept the Offer (such Guarantee Agreement (C) shall of course also remain in full force and effect and fully applicable in accordance with its terms in the event that you do not accept the Offer). ............., dated 21.09.2000 UGI Corporation 1 Attachment: Offer of Flaga GmbH dated 21.09.2000 We hereby accept the above statement of UGI Corporation: Bratislava, dated 21.09.2000 Raiffeisen Zentralbank Osterreich Aktiengesellschaft page 1 2 FLAGA GmbH An der Bundesstrasse 6 2100 Leobendorf Austria Raiffeisen Zentralbank Osterreich Aktiengesellschaft Am Stadtpark 9 1030 Vienna Austria .........., 21 September 2000 RE.: OFFER (C) Dear Sirs, we, FLAGA GmbH, An der Bundesstrasse 6, 2100 Leobendorf, Austria, herewith refer to our previous Offer (C) (hereinafter the "Offer (C)") and propose to amend the terms of Offer (C) as follows (Clauses referred to herein are Clauses of Offer (C)): The amount in Clause 1.1. shall be replaced by EURO 9,000,000.00 (ninemillion). The date in Clause 2.1. shall be replaced by 28 August 2001. In Clause 4.1.(d) the first date shall be replaced by 28 September 2001, and "spring 2000" shall be replaced by August 2001. All other clauses of the afore mentioned offer shall remain unchanged. You can accept the present proposal by debiting our account no. 1-00.640.763 with an account fee in the amount of ATS 300.00, not later than 21 September 2001. You are hereby irrevocably authorized to make such debit. If you accept the present proposal, the respective amendments shall also apply to any agreement resulting from Offer (C). With kind regards, FLAGA GmbH page 1 EX-10.38 6 w43405ex10-38.txt CONSULTING SERVICES AGREEMENT DATED AUGUST 1, 2000 1 Exhibit 10.38 CONSULTING SERVICES AGREEMENT THIS CONSULTING SERVICES AGREEMENT (the "Agreement"), is entered into as of August 1, 2000, by and between UGI Corporation, a Pennsylvania corporation, ("UGI") and Stephen D. Ban, an individual, ("Consultant"). WHEREAS, UGI wishes to obtain the consulting services of Consultant, and Consultant wishes to provide consulting services according to the terms and conditions of this Agreement. NOW, THEREFORE, in consideration of the mutual promises hereinafter set forth, and intending to be legally bound, UGI and Consultant agree as follows: 1. Services to be Provided. During the term of this Agreement, Consultant shall perform for UGI such consulting services as UGI may from time to time request in connection with identifying, evaluating and providing advice relating to growth opportunities in distributed generation ("Services"). 2. Term. The term of this Agreement is one year, beginning August 1, 2000 and ending July 31, 2001. 3. Time Commitment and Compensation. (a) Consultant shall provide up to four (4) days of Services per month at the request of the Chairman of UGI and shall receive an annual fee of $50,000, payable semiannually in arrears, commencing February 1, 2001. In addition, if the Chairman of UGI and the Consultant agree that more than four (4) days of Services shall be performed in any month, Consultant shall be paid $1,000 per day for each such additional day. (b) Consultant will be reimbursed promptly for all reasonable and necessary out-of-pocket expenses incurred in carrying out the Services outlined above. Consultant will submit to UGI on a monthly basis a written request for reimbursement together with supporting documentation including, where practicable, receipts for travel, lodging and meals. 4. No Benefits. Consultant is not an employee of UGI and will not be entitled to participate in or receive any benefit or right under any of UGI's employee benefit and welfare plans, including, without limitation, insurance, pension and savings plans, provided however, that the payments due hereunder shall be in addition to and not in lieu of any payments or benefits to which Consultant is entitled as a result of Consultant's service as an outside director of UGI and its subsidiary, UGI Utilities, Inc. 5. Independent Contract. For purposes of this Agreement and all Services to be provided hereunder, Consultant shall not be considered a partner, co-venturer, agent, employee, or representative of UGI, but shall remain in all respects an independent contractor, and neither 2 party shall have any right or authority to make or undertake any promise, warranty or representation, to execute any contract, or otherwise to assume any obligation or responsibility in the name of or on behalf of the other party. 6. Confidentiality. (a) Services and Company Information. Consultant agrees not to disclose to third parties during the term of this Agreement or at any time thereafter any information concerning the Services. Consultant also agrees at all times during the term of this Agreement and thereafter, to hold in strictest confidence, and not to use, except in connection with Consultant's performance of the Services, and not to disclose to any person or entity any Confidential Information of UGI without the prior written authorization of UGI. As used herein, "Confidential Information" means any proprietary or confidential information, technical data, trade secrets or know-how, including, but not limited to, research, sales and/or marketing plans and products, services, business plans, acquisitions or strategies (past, present and/or prospective), customer lists and customers, credit information, markets, software, developments, inventions, processes, formulas, technology, designs, drawings, engineering, distribution and sales methods and systems, sales and profit figures, finances and other business information disclosed to Consultant or otherwise learned, discovered or developed by Consultant, either directly or indirectly in writing, orally or by drawings or inspection of documents or other tangible property. Confidential Information does not include any of the foregoing items which has become publicly known and made generally available through no wrongful act of Consultant. (b) Third Party Information. Consultant recognizes that UGI has received and in the future may continue to receive from third parties their confidential or proprietary information subject to a duty on UGI's part to maintain the confidentiality of such information and to use it only for certain limited purposes. Consultant agrees at all times during the term of this Agreement and thereafter, to hold in strictest confidence and not to use or disclose such third-party information, except in connection with Consultant's performance of the Services and in a manner consistent with UGI's agreement with any such third party. UGI shall provide Consultant with a copy of any applicable confidentiality agreements. (c) Survival. The provisions of this Section shall survive the expiration of the term of this Agreement for a period of three (3) years. 7. No Conflicting Agreements. Consultant represents that Consultant is not a party to any existing agreement which would prevent Consultant from entering into and performing this Agreement. Consultant will not enter into any other agreement that is in conflict with Consultant's obligations under this Agreement without the prior written approval of UGI. 8. Entire Agreement, Amendment and Assignment. This Agreement is the sole agreement between Consultant and UGI with respect to the Services to be performed hereunder and it supersedes all prior agreements and understandings with respect thereto, whether oral or written. No modification to any provision of this Agreement shall be binding unless in writing and signed by both the Consultant and UGI. No waiver of any rights under this agreement, will be effective unless in writing signed by the party to be charged. All of the terms and provisions -2- 3 of this Agreement shall be binding upon and inure to the benefit of and be enforceable by the respective heirs, executors, administrators, legal representatives, successors and assigns of the parties hereto, except that the duties and responsibilities of Consultant hereunder are of a personal nature and shall not be assignable or delegable in whole or in part by Consultant. 9. Governing Law. This Agreement shall be governed by and interpreted under the laws of the Commonwealth of Pennsylvania without regard to its choice of law provisions. 10. Notices. All notices and other communications required or permitted hereunder or necessary or convenient in connection herewith shall be in writing and shall be deemed to have been given when hand delivered, sent by facsimile or mailed by registered or certified mail, as follows (provided that notice of change of address shall be deemed given only when received): If to UGI, to: UGI Corporation Attention: Lon R. Greenberg, President P.O. Box 858 Valley Forge, PA 19482 Facsimile No.: (610) 992-3254 If to Consultant, to: Dr. Stephen D. Ban 50 Woodland Drive Barrington, IL 60010 or to such other names or addresses as UGI or Consultant, as the case may be, shall designate by notice to each other person entitled to receive notices in the manner specified in this paragraph. IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have duly executed this Agreement as of the date first above written. UGI CORPORATION By: ---------------------------- Lon R. Greenberg, President CONSULTANT ---------------------------- Stephen D. Ban -3- EX-10.39 7 w43405ex10-39.txt 1992 NON-QUALIFIED STOCK OPTION PLAN, AS AMENDED 1 Exhibit 10.39 UGI CORPORATION AMENDMENT NO. 1 TO 1992 NON-QUALIFIED STOCK OPTION PLAN This Amendment No. 1 dated as of December 10, 1996 amends that certain UGI Corporation 1992 Non-Qualified Stock Option Plan ("the Plan"). BACKGROUND The Board of Directors of UGI Corporation approved a 1997 Stock Option and Dividend Equivalent Plan (the "1997 SODEP") and also approved certain amendments to the Plan to make its vesting provisions and its definition of "Fair Market Value" conform to the corresponding provisions of the 1997 SODEP. The purpose of this Amendment is to make those changes in the Plan. NOW THEREFORE, the Plan is amended as follows: Section 1. Amendment and Restatement. Sections 2(e), 7.3 and 7.4 of the Plan are hereby amended and restated in their entirety as follows: 2(e) "Fair Market Value" of Stock means the average, rounded to the next highest one-eighth of a point (.125), of the highest and lowest sales prices thereof on the New York Stock Exchange on the day on which Fair Market Value is being determined, as reported on the Composite Tape for transactions on the New York Stock Exchange; provided, however, in the case of a cashless exercise pursuant to Section 7.4, the Fair Market Value shall be the actual sale price of the shares issued upon exercise of the Option. In the event that there are no Stock transactions on the New York Stock Exchange on such day, the Fair Market Value will be determined as of the immediately preceding day on which there were Stock transactions on that exchange. 7.3 Exercise and Vesting. (a) Except as otherwise specified by the Committee, an Option shall be fully and immediately exercisable on the date of grant. Notwithstanding the foregoing, in the event that any such Options are not by their terms immediately exercisable, the Committee may accelerate the exercisability of any or all outstanding Options at any time for any reason. No Option shall be exercisable on or after the tenth anniversary of the date of grant. (b) If a Participant holding an Option ceases to be an Employee, the Option held by such Participant shall be exercisable only with respect to that number of shares of Stock with respect to which it is already exercisable on the date such Participant -1- 2 ceases to be an Employee. However, if a Participant holding an Option ceases to be an Employee by reason of a retirement under the Company's or a Subsidiary's retirement plan, the Option held by any such participant shall thereafter become exercisable with respect to that additional number of shares of Stock with respect to which it becomes exercisable on any anniversary of the date on which the Participant was granted the Option which occurs within thirteen (13) months after the date of such retirement and such Option shall be exercisable during such thirteen-month period. Notwithstanding the foregoing, the Committee shall have the power, in the event of any merger or consolidation of any other corporation with or into the Company, or the sale of all or substantially all of the assets of the Company or an offer to purchase made by a party other than the Company to all shareholders of the Company for all or any substantial portion of the outstanding Stock, to amend any or all outstanding Options to permit the exercise of all such Options prior to the effectiveness of any such merger, consolidation or sale or the expiration of any such offer to purchase, and to terminate such Options as of such effectiveness or expiration. Notwithstanding anything contained in this Section 7.3 with respect to the number of shares with respect to which an Option is or is to become exercisable, no Option, to the extent that it has not previously been exercised, shall be exercisable after it has terminated, including without limitation, after any termination of such Option pursuant to Section 10 hereof. 7.4 Payment of Option Price. The Option Price upon exercise of any Option shall be payable to the Company in full (i) in cash or its equivalent, (ii) by tendering shares of previously acquired Stock already beneficially owned by the Participant for more than one year and having a Fair Market Value at the time of exercise equal to the total Option Price, (iii) by payment through a broker in accordance with procedures permitted by Regulation T of the Federal Reserve Board, or (iv) by a combination of (i) (ii) and/or (iii). The cash proceeds from such payment will be added to the general funds of the Company and shall be used for its general corporate purposes. Any shares of previously acquired Stock tendered to the Company in payment of the Option Price will be added by the Company to its treasury stock to be used for its general corporate purposes. Section 2. Effect of Amendment. All other terms and conditions of the Plan shall remain unaffected by this Amendment No. 1 and are ratified and confirmed. Section 3. Definitions. Capitalized terms used in this Amendment No. 1, but not defined shall have the meanings ascribed to those terms in the Plan. -2- 3 IN WITNESS WHEREOF, and as evidence of the adoption of this Amendment, an appropriate officer of the Company has caused this Amendment to be executed as of December 10, 1996. Attest: UGI CORPORATION By: /s/ Barton D. Whitman By /s/ Brendan P. Bovaird ------------------------- -------------------------------- Secretary Name: Brendan P. Bovaird Title: Vice President and General Counsel -3- EX-10.40 8 w43405ex10-40.txt 1998 AGREEMENT BETWEEN UGI AND TEXAS EASTERN TRAN 1 EXHIBIT 10.40 Contract #: 800239R SERVICE AGREEMENT FOR RATE SCHEDULE CDS This Service Agreement, made and entered into this 23rd day of February 1998, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware Corporation (herein called "Pipeline") and UGI UTILITIES, INC. (herein called "Customer", whether one or more), WITNESSETH: 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. 800239); and WHEREAS, Pipeline and Customer desire to enter into this Service Agreement to supersede Pipeline's currently effective Contract No. 800239; 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 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. 2 SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) 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, 2002 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, 2002 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. -2- 3 SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) 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. 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. -3- 4 SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) 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 (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. -4- 5 SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) 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. 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 December 8, 1995, between Pipeline and Customer under Pipeline's Rate Schedule CDS (Pipeline's Contract No. 800239). -5- 6 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: ----------------------------------------- ATTEST: - ------------------------ Name: Title: UGI UTILITIES, INC. By: ----------------------------------------- Robert J. Chaney Executive Vice President ATTEST: - ------------------------ Brendan P. Bovaird Secretary -6- 7 Contract #: 800239R 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, INC. ("Customer"), DATED 2/23/99: (1) Customer's firm Point(s) of Receipt:
Maximum Daily Point Receipt Obligation of (plus Applicable Measurement Receipt Description Shrinkage) dth Responsibilities Owner Operator* - ------- ----------- -------------- ---------------- ----- --------- 70011 COLUMBIA GAS 0 TX EAST TX EAST COLUMBIA - EAGLE, PA, TRAN TRAN GAS CHESTER CO., PA 75577 COLUMBIA GAS- 0 TX EAST TX EAST COLUMBIA PENNSBURG, PA TRAN TRAN GAS BUCKS CO., PA
*-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.
Transportation Transportation Path Path Quantity (Dth/D) ------------------- --------------------- M1 to M3 25,000
SIGNED FOR IDENTIFICATION PIPELINE: ----------------------------------- CUSTOMER: --------------------------------- SUPERSEDES EXHIBIT A DATED: --------------- A-1 8 Contract #: 800239R EXHIBIT B, POINT(S) OF DELIVERY, DATED 2/23/99 TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND UGI UTILITIES, INC. ("Customer"), DATED 2/23/99:
Maximum Daily Delivery Point of Delivery Pressure Measurement Delivery Description Obligation (dth) Obligation Responsibilities Owner Operator* -------- ----------- ---------------- ---------- ---------------- ----- --------- 1. 70069 UGI UTILITIES - COLUMBIA, PA 5,190 AS PROVIDED TX EAST TRAN TX EAST TRAN UGI UTILITIES LANCASTER CO., PA IN SECTION 6 OF THE GENERAL TERMS AND CONDITIONS OF PIPELINE'S FERC GAS TARIFF 2. 70070 UGI UTILITIES - LANCASTER, PA 25,000 AS PROVIDED TX EAST TRAN TX EAST TRAN UGI UTILITIES LANCASTER CO., PA IN SECTION 6 OF THE GENERAL TERMS AND CONDITIONS OF PIPELINE'S FERC GAS TARIFF 3. 71528 UGI UTILITIES - LANCASTER, PA 7,200 300 POUNDS TX EAST TRAN TX EAST TRAN UGI UTILITIES LANCASTER CO., PA PER SQUARE INCH GAUGE 4. 70519 UGI UTILITIES - DAUPHIN CO., 25,000 400 POUNDS TX EAST TRAN TX EAST TRAN UGI UTILITIES PA DAUPHIN CO., PA PER SQUARE INCH GAUGE 5. 70321 UGI UTILITIES - LEBANON, PA 17,000 400 POUNDS TX EAST TRAN TX EAST TRAN UGI UTILITIES LEBANON CO., PA PER SQUARE INCH GAUGE 6. 70486 UGI UTILITIES - WOMELSDORF, PA 6,500 400 POUNDS TX EAST TRAN TX EAST TRAN UGI UTILITIES BERKS CO., PA PER SQUARE INCH GAUGE
B-1 9 Contract #: 800239R EXHIBIT B, POINT(S) OF DELIVERY (Continued) UGI UTILITIES, INC.
Maximum Daily Delivery Point of Delivery Pressure Measurement Delivery Description Obligation (dth) Obligation Responsibilities Owner Operator* -------- ----------- ---------------- ---------- ---------------- ----- --------- 7. 70322 UGI UTILITIES - READING, PA 25,000 400 POUNDS TX EAST TRAN TX EAST TRAN UGI UTILITIES BERKS CO., PA PER SQUARE INCH GAUGE 8. 72571 COLUMBIA GAS - BALLY, PA 5,190 400 POUNDS TX EAST TRAN COLUMBIA GAS UGI UTILITIES BERKS CO., PA PER SQUARE INCH GAUGE 9. 71461 COLUMBIA GAS - RICH HILL, PA 5,190 SUCH PRESSURE TX EAST TRAN COLUMBIA GAS UGI UTILITIES BUCKS CO., PA AS MAY BE AVAILABLE BY PIPELINE AT THE POINT OF DELIVERY 10. 70011 COLUMBIA GAS - EAGLE, PA 0 AS PROVIDED TX EAST TRAN TX EAST TRAN COLUMBIA GAS CHESTER CO., PA IN SECTION 6 OF THE GENERAL TERMS AND CONDITIONS OF PIPELINE'S FERC GAS TARIFF 11. 75577 COLUMBIA GAS- PENNSBURG, PA, 0 AS PROVIDED TX EAST TRAN TX EAST TRAN COLUMBIA GAS BUCKS CO., PA IN SECTION 6 OF THE GENERAL TERMS AND CONDITIONS OF PIPELINE'S FERC GAS TARIFF
B-2 10 Contract #: 800239R EXHIBIT B, POINT(S) OF DELIVERY (Continued) UGI UTILITIES, INC. * 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; 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 Service Agreements existing between Pipeline and Customer shall in no event exceed the following:
Point of Aggregate Maximum Daily Delivery Delivery Obligation -------- ------------------- No. 1 5,190 dth No. 2 49,000 dth No. 3 17,200 dth No. 4 53,000 dth No. 5 17,000 dth No. 6 6,500 dth No. 7 65,880 dth No. 8 7,186 dth No. 9 5,190 dth No. 10 68,785 dth
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: B-3 11 Contract #: 800239R EXHIBIT B, POINT(S) OF DELIVERY (Continued) UGI UTILITIES, INC.
Section 14.9 Firm Point of Capacity Measurement Delivery Description (dth/d) Responsibilities Owner Operator -------- ----------- ------- ---------------- ----- -------- 1. 70011 COLUMBIA GAS (MFGRS.) - 85,635 TX EAST TRAN TX EAST TRAN COLUMBIA GAS EAGLE, PA CHESTER CO., PA 4/1/97- 10/31/97 49,635 11/l/97-10/31/98 2. 70069 UGI UTILITIES - COLUMBIA, 12,700 TX EAST TRAN TX EAST TRAN UGI UTILITIES PA LANCASTER CO. PA 3. 70070 UGI UTILITIES - COLUMBIA, 31,328 TX EAST TRAN TX EAST TRAN UGI UTILITIES PA LANCASTER, PA LANCASTER CO., PA 4. 70321 UGI UTILITIES - LEBANON, 1,253 TX EAST TRAN TX EAST TRAN UGI UTILITIES 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 - RICH HILL, 840 TX EAST TRAN COLUMBIA GAS COLUMBIA GAS BUCKS CO., PA 8. 72571 UGI UTILITIES - BERKS, 13,984 TX EAST TRAN COLUMBIA GAS COLUMBIA GA CO., PA 9 75577 UGI UTILITIES - PENNSBURG, 75,440 TX EAST TRAN COLUMBIA GAS COLUMBIA GAS PA BUCKS CO., PA
B-4 12 Contract #: 800239R EXHIBIT B, POINT(S) OF DELIVERY (Continued) UGI UTILITIES, INC. SIGNED FOR IDENTIFICATION PIPELINE: --------------------------------- CUSTOMER: --------------------------------- SUPERSEDES EXHIBIT B DATED: --------------- B-5 13 Contract #: 800239R EXHIBIT C ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY, DATED 2/23/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS BETWEEN 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 709 - ---------------------------------------------------------------------------------------------------------------------------- ETX 3013 1073 - ---------------------------------------------------------------------------------------------------------------------------- WLA 326 709 - ---------------------------------------------------------------------------------------------------------------------------- ELA 19576 - ---------------------------------------------------------------------------------------------------------------------------- M1-24 3013 - ---------------------------------------------------------------------------------------------------------------------------- M1-30 19576 - ---------------------------------------------------------------------------------------------------------------------------- M1-TXG 1399 - ---------------------------------------------------------------------------------------------------------------------------- M1-TGC 1418 - ---------------------------------------------------------------------------------------------------------------------------- M2-24 - ---------------------------------------------------------------------------------------------------------------------------- M2-30 - ---------------------------------------------------------------------------------------------------------------------------- M2-TXG - ---------------------------------------------------------------------------------------------------------------------------- M2-TGC - ---------------------------------------------------------------------------------------------------------------------------- M2 25000 - ---------------------------------------------------------------------------------------------------------------------------- M3 ============================================================================================================================
C-1 14 Contract #: 800239R EXHIBIT C (Continued) UGI UTILITIES, INC. ZONE BOUNDARY EXIT 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 - ---------------------------------------------------------------------------------------------------------------------------- ETX - ---------------------------------------------------------------------------------------------------------------------------- WLA - ---------------------------------------------------------------------------------------------------------------------------- ELA - ---------------------------------------------------------------------------------------------------------------------------- M1-24 3013 - ---------------------------------------------------------------------------------------------------------------------------- M1-30 19576 - ---------------------------------------------------------------------------------------------------------------------------- M1-TXG 1399 - ---------------------------------------------------------------------------------------------------------------------------- M1-TGC 1418 - ---------------------------------------------------------------------------------------------------------------------------- M2-24 - ---------------------------------------------------------------------------------------------------------------------------- M2-30 - ---------------------------------------------------------------------------------------------------------------------------- M2-TXG - ---------------------------------------------------------------------------------------------------------------------------- M2-TGC - ---------------------------------------------------------------------------------------------------------------------------- M2 25000 - ---------------------------------------------------------------------------------------------------------------------------- M3 ============================================================================================================================
SIGNED FOR IDENTIFICATION: PIPELINE: --------------------------------- CUSTOMER: --------------------------------- SUPERCEDES EXHIBIT C DATED ---------------- C-2 EX-10.41 9 w43405ex10-41.txt 1999 AGREEMENT BETWEEN UGI AND TEXAS EASTERN TRAN 1 EXHIBIT 10.41 Contract #: 800397R SERVICE AGREEMENT FOR RATE SCHEDULE CDS TMT Service Agreement made and entered into this, 23rd day of February, 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), WITNESSETH: 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. 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. 2 Contract #: 800397R SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) 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 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. -2- 3 Contract #: 800397R SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) 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. 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. -3- 4 Contract #: 800397R SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) 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 (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 -4- 5 Contract #: 800397R SERVICE AGREEMENT FOR RATE SCHEDULE CDS (Continued) 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. 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 December 8, 1995, between Pipeline and Customer under Pipeline's Rate Schedule CDS (Pipeline's Contract No. 800397). 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 -5- 6 Contract #: 800397R SERVICE AGREEMENT FOR RATE SCHEDULE CDS (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: -------------------------------------- ATTEST: - -------------------------- Assistant Secretary UGI UTILITIES, INC. By: -------------------------------------- Robert J. Chaney Executive Vice President ATTEST: - -------------------------- Brendan P. Bovaird Secretary -6- 7 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 UGI UTILITIES, INC. ("Customer"), DATED 2/23/99: (1) Customer's firm Point(s) of Receipt:
Maximum Daily Receipt Obligation (plus Point of Applicable Measurement Receipt Description Shrinkage) (dth) Responsibilities Owner Operator * - ------- ----------- ---------------- ---------------- ----- ---------- 71200 CHEVRON - VENICE, LA PLAQUEMINES 16,475 CHEVRON CHEVRON CHEVRON USA 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 8 Contract #: 800397R EXHIBIT A, TRANSPORTATION PATHS, continued UGI UTILITIES, INC.
Transportation Transportation Path Path Quantity-(Dth/D) - ------------------- --------------------- Ml to M3 41,000
SIGNED FOR IDENTIFICATION PIPELINE: --------------------------------- CUSTOMER: --------------------------------- SUPERSEDES EXHIBIT A DATED: --------------- A-2 9 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 Point of Delivery Delivery Pressure Measurement Delivery Description Obligation Obligation Responsibilities Owner Operator * - -------- ----------- ---------- ---------- ---------------- ----- ---------- (dth) 1. 70011 COLUMBIA GAS - EAGLE, 41,000 dth AS PROVIDED IN SECTION 6 TX EAST TX EAST COLUMBIA PA CHESTER CO., PA during the OF THE GENERAL TERMS AND TRAN TRAN GAS period CONDITIONS OF PIPELINE'S April 16 FERC GAS TARIFF through November 15 of each year - otherwise 35,593 dth 2. 70069 UGI UTILITIES - 5,190 AS PROVIDED IN SECTION 6 TX EAST TX EAST UGI COLUMBIA, PA LANCASTER OF THE GENERAL TERMS AND TRAN TRAN UTILITIES CO., PA CONDITIONS OF PIPELINE'S FERC GAS TARIFF 3. 70070 UGI UTILITIES-LANCASTER, 41,000 AS PROVIDED IN SECTION 6 TX EAST TX EAST UGI PA LANCASTER CO., PA OF THE GENERAL TERMS AND TRAN TRAN UTILITIES CONDITIONS OF PIPELINE'S FERC GAS TARIFF 4. 70321 UGI UTILITIES - LEBANON, 17,000 TX EAST TX EAST UGI PA LEBANON CO., PA TRAN TRAN UTILITIES 5. 70322 UGI UTILITIES - READING, 41,000 400 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 41,000 400 POUNDS PER SQUARE TX EAST TX EAST UGI CO., PA DAUPHIN CO., INCH GAUGE TRAN TRAN UTILITIES
B-1 10 Contract #: 800397R EXHIBIT B POINT(S) OF DELIVERY (Continued) UGI UTILITIES, INC.
Maximum Daily Point of Delivery Delivery Pressure Measurement Delivery Description Obligation Obligation Responsibilities Owner Operator * - -------- ----------- ---------- ---------- ---------------- ----- ---------- (dth) 8. 71461 COLUMBIA GAS - RICH 5,190 SUCH PRESSURE AS MAY BE TX EAST COLUMBIA UGI HILL, BUCKS CO., PA AVAILABLE BY PIPELINE AT TRAN GAS UTILITIES 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 SECTION 6 TX EAST TX EAST COLUMBIA PENNSBURG, PA, BUCKS OF THE GENERAL TERMS AND TRAN TRAN GAS CO., PA 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: B-2 11 Contract #: 800397R EXHIBIT B POINT(S) OF DELIVERY (Continued) UGI UTILITIES, INC.
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 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 Firm Point of Capacity Measurement Delivery Description (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/l/97-0/31/97 PA 49,635 11/l/97-0/31/98 2. 70069 UGI UTILITIES - 12,700 TX EAST TRAN TX EAST TRAN UGI UTILITIES COLUMBIA PA LANCASTER CO., PA
B-3 12 Contract #: 800397R EXHIBIT B POINT(S) OF DELIVERY (Continued) UGI UTILITIES, INC.
Section 14.9 Firm Point of Capacity Measurement Delivery Description (dth/d) Responsibilities Owner Operator - -------- ----------- ------- ---------------- ----- -------- 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 5. 70486 UGI UTILITIES - 3,670 TX EAST TRAN TX EAST TRAN UGI WOMELSDORF, PA BERKS UTILITIES 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: ------------------------------------- CUSTOMER: ------------------------------------- SUPERSEDES EXHIBIT B EFFECTIVE ---------------- B-4 13 Contract #: 800397R EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY, DATED 2/23/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS BETWEEN 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 - -------------------------------------------------------------------------------------------------------------------------- WLA 684 1487 - -------------------------------------------------------------------------------------------------------------------------- ELA 34899 - -------------------------------------------------------------------------------------------------------------------------- M1-24 194 - -------------------------------------------------------------------------------------------------------------------------- M1-30 34899 - -------------------------------------------------------------------------------------------------------------------------- M1-TXG 2933 - -------------------------------------------------------------------------------------------------------------------------- M1-TGC 2974 - -------------------------------------------------------------------------------------------------------------------------- M2-24 - -------------------------------------------------------------------------------------------------------------------------- M2-30 - -------------------------------------------------------------------------------------------------------------------------- M2-TXG - -------------------------------------------------------------------------------------------------------------------------- M2-TGC - -------------------------------------------------------------------------------------------------------------------------- M2 41000 - -------------------------------------------------------------------------------------------------------------------------- M3 ==========================================================================================================================
C-1 14 Contract #: 800397R EXHIBIT C (Continued) UGI UTILITIES, INC. ZONE BOUNDARY EXIT 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 - -------------------------------------------------------------------------------------------------------------------------- ETX - -------------------------------------------------------------------------------------------------------------------------- WLA - -------------------------------------------------------------------------------------------------------------------------- ELA - -------------------------------------------------------------------------------------------------------------------------- M1-24 194 - -------------------------------------------------------------------------------------------------------------------------- M1-30 34899 - -------------------------------------------------------------------------------------------------------------------------- M1-TXG 2933 - -------------------------------------------------------------------------------------------------------------------------- M1-TGC 2974 - -------------------------------------------------------------------------------------------------------------------------- M2-24 - -------------------------------------------------------------------------------------------------------------------------- M2-30 - -------------------------------------------------------------------------------------------------------------------------- M2-TXG - -------------------------------------------------------------------------------------------------------------------------- M2-TGC - -------------------------------------------------------------------------------------------------------------------------- M2 41000 - -------------------------------------------------------------------------------------------------------------------------- M3 ==========================================================================================================================
SIGNED FOR IDENTIFICATION: PIPELINE: --------------------------------- CUSTOMER: --------------------------------- SUPERCEDES EXHIBIT C DATED ---------------- C-2 EX-13 10 w43405ex13.txt FINANCIAL REVIEW OF ANNUAL REPORT 1 Exhibit 13 UGI Corporation 2000 Annual Report - -------------------------------------------------------------------------------- FINANCIAL REVIEW BUSINESS OVERVIEW Our domestic propane business is conducted through AmeriGas Partners, L.P. ("AmeriGas Partners") and its operating subsidiary, AmeriGas Propane, L.P. (the "Operating Partnership"). We refer to AmeriGas Partners and the Operating Partnership together as "the Partnership." At September 30, 2000, we held an effective 58.4% interest in the Operating Partnership. UGI Utilities, Inc. ("UGI Utilities") operates a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and an electric distribution utility and electricity generation business ("Electric Utility") in northeastern Pennsylvania. Gas Utility and Electric Utility are together referred to as "Utilities." UGI Enterprises, Inc. ("Enterprises"), our "new business" arm, conducts an energy marketing business ("Energy Services") and through other subsidiaries (1) owns and operates a propane distribution business in Austria, the Czech Republic and Slovakia ("FLAGA"); (2) owns and operates a heating, ventilation and air-conditioning service business ("HVAC") and a retail hearth, spa and grill products business in the Middle Atlantic states ("Hearth USA(TM)"); and (3) participates in international propane joint-venture projects. This Financial Review should be read in conjunction with our Consolidated Financial Statements and Notes to Consolidated Financial Statements including the business segment information in Note 17. RESULTS OF OPERATIONS 2000 COMPARED WITH 1999 CONSOLIDATED RESULTS. Our 2000 results reflect improved earnings from Utilities partially offset by a decline in net income from AmeriGas Propane and International Propane losses. Excluding the effect of merger termination fee income in 1999, earnings per share increased 22% in 2000 reflecting a 15% decline in average shares outstanding and higher net income.
Variance- Favorable 2000 1999 (Unfavorable) --------------------------------------------------------------------------- DILUTED Diluted Diluted NET EARNINGS Net Earnings Net Earnings INCOME (LOSS) Income (Loss) Income (Loss) (LOSS) PER SHARE (Loss) Per Share (Loss) Per Share - -------------------------------------------------------------------------------------------------------------------------- (Millions of dollars, except per share) AmeriGas Propane $ -- $ -- $ 4.5 $ 0.14 $ (4.5) $ (0.14) Utilities 48.9 1.79 37.4 1.17 11.5 0.62 Energy Services 1.6 0.06 1.5 0.05 0.1 0.01 International Propane (5.6) (0.20) (0.1) -- (5.5) (0.20) Other Enterprises (a) (3.8) (0.14) (3.6) (0.11) (0.2) (0.03) Corporate & Other 3.6 0.13 3.1 0.09 0.5 0.04 Merger termination fee, net (b) -- -- 12.9 0.40 (12.9) (0.40) - -------------------------------------------------------------------------------------------------------------------------- Total $ 44.7 $ 1.64 $ 55.7 $ 1.74 $ (11.0) $ (0.10) - --------------------------------------------------------------------------------------------------------------------------
(a) Comprised principally of Hearth USA(TM), HVAC, and Enterprises' corporate and general expenses. (b) Represents after-tax merger termination fee income, net of related expenses, associated with the Company's terminated Merger Agreement with Unisource Worldwide, Inc. See Note 14 to Consolidated Financial Statements. SEGMENT RESULTS. The following table presents certain financial and statistical information by business segment for 2000 and 1999:
Increase 2000 1999 (Decrease) - ------------------------------------------------------------------------------------------- (Millions of dollars) AMERIGAS PROPANE Revenues $1,120.1 $872.5 $247.6 28.4% Total margin $ 491.8 $481.7 $ 10.1 2.1% EBITDA (a) $ 158.6 $158.8 $ (0.2) (0.1)% Operating income $ 90.2 $ 92.5 $ (2.3) (2.5)% Retail gallons sold (millions) 771.2 783.2 (12.0) (1.5)% Degree days - % warmer than normal (b) 13.7% 9.9% - - GAS UTILITY Revenues $ 359.0 $345.6 $ 13.4 3.9% Total margin $ 170.8 $160.6 $ 10.2 6.4% EBITDA (a) $ 105.3 $ 87.0 $ 18.3 21.0% Operating income $ 86.2 $ 68.0 $ 18.2 26.8% System throughput - billions of cubic feet ("bcf") 79.7 76.1 3.6 4.7% Degree days - % warmer than normal 9.9% 12.8% - - ELECTRIC UTILITY (c) Revenues $ 77.9 $ 75.0 $ 2.9 3.9% Total margin $ 40.5 $ 38.6 $ 1.9 4.9% EBITDA (a) $ 19.6 $ 16.7 $ 2.9 17.4% Operating income $ 15.1 $ 12.7 $ 2.4 18.9% Sales - millions of kilowatt hours ("gwh") 907.2 900.4 6.8 0.8% ENERGY SERVICES Revenues $ 146.9 $ 90.4 $ 56.5 62.5% Total margin $ 6.2 $ 6.0 $ 0.2 3.3% EBITDA (a) $ 3.0 $ 2.7 $ 0.3 11.1% Operating income $ 2.8 $ 2.6 $ 0.2 7.7% INTERNATIONAL PROPANE Revenues $ 50.5 $ - $ 50.5 N.M. Total margin $ 20.8 $ - $ 20.8 N.M. EBITDA (a) $ 1.9 $ (0.1) $ 2.0 N.M. Operating loss $ (2.7) $ (0.1) $ 2.6 N.M. - -------------------------------------------------------------------------------------------
N.M. - Not Meaningful (a) EBITDA (earnings before interest expense, income taxes, depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance under generally accepted accounting principles. (b) Deviation from average heating degree days during the 30-year period from 1961 to 1990, based upon national weather statistics provided by the National Oceanic and Atmospheric Administration ("NOAA") for 335 airports in the continental U.S. (c) Electric Utility comprises the Company's regulated electric utility distribution business and its nonutility electric generation operations. 13 2 - -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) AMERIGAS PROPANE. Based upon national heating degree day information, temperatures in 2000 were 13.7% warmer than normal and 3.8% warmer than in 1999. Retail volumes of propane sold were 12 million gallons lower, primarily a result of the warmer weather's effect on residential heating gallons and a decline in agricultural gallons as a result of a poor crop drying season. Partially offsetting these decreases were higher motor fuel sales, reflecting the continuing effects of our expanding National Accounts program, the volume impact of our growing grill cylinder exchange business, PPX Prefilled Propane Xchange ("PPX(R)"), and acquisition-related volume increases. Total revenues from retail propane sales increased $160.5 million in 2000 due to higher average selling prices. The higher average selling prices resulted from significantly higher propane product costs. Wholesale propane revenues increased $77.4 million reflecting (1) a $50.7 million increase as a result of higher average wholesale prices and (2) a $26.7 million increase as a result of higher wholesale volumes sold. Nonpropane revenues increased $9.7 million in 2000 reflecting higher customer fees, hauling, and PPX(R) cylinder sales revenue. Cost of sales increased $237.5 million primarily as a result of the higher propane product costs and greater wholesale volumes sold. Total margin increased $10.1 million in 2000 due to (1) greater volumes sold to higher margin PPX(R) customers; (2) slightly higher average retail unit margins; and (3) an increase in total margin from customer fees, and ancillary sales and services. EBITDA in 2000 was comparable to 1999 as the increases in total margin and higher other income were offset by higher operating expenses. Other income increased $3.1 million due to, among other things, higher income from sales of assets and higher finance charge income. Operating expenses of the Partnership were $342.7 million in 2000 compared with $329.6 million in 1999 reflecting incremental expenses from growth and operational initiatives and higher vehicle fuel costs. Our growth and operational initiatives in 2000 included significantly expanding PPX(R), acquiring retail propane businesses, and developing and implementing more efficient methods of operating the business. Although EBITDA in 2000 was about equal to 1999, operating income declined $2.3 million reflecting higher PPX(R) and acquisition-related charges for depreciation and amortization. GAS UTILITY. Weather in Gas Utility's service territory was 9.9% warmer than normal in 2000 but 3.8% colder than in 1999. The increase in system throughput during 2000 resulted from higher interruptible delivery service volumes and higher sales to our firm retail ("core market") customers. The increase in Gas Utility's revenues during 2000 principally resulted from (1) a $13.1 million increase in core market revenues reflecting higher sales and higher average purchased gas cost ("PGC") rates partially offset by the impact of the elimination of gross receipts tax revenue effective January 1, 2000 pursuant to Pennsylvania's Gas Competition Act and (2) a $5.9 million increase in revenues from interruptible customers. These increases in revenue were partially offset by lower off-system sales and firm delivery service revenues. Gas Utility cost of gas was $184.2 million in 2000 compared with $172.0 million in 1999. The increase reflects higher average PGC rates and higher core market sales partially offset by lower costs associated with the decline in off-system sales. Gas Utility total margin increased $10.2 million reflecting (1) a $4.2 million increase in total interruptible retail and interruptible delivery service margin; (2) a $4.9 million increase in core market margin; and (3) slightly higher firm delivery service total margin. Gas Utility EBITDA and operating income increased $18.3 million and $18.2 million, respectively, as a result of (1) the higher total margin; (2) a $5.0 million increase in other income; and (3) a decrease in net operating expenses. Other income in 2000 includes, among other things, (1) income from the refund of revenue-related tax overpayments made in prior years (including associated interest); (2) interest income from PGC undercollections; and (3) higher income from a construction project and other activities. Gas Utility's net operating expenses declined $3.1 million, despite an increase in distribution system maintenance expenses, principally reflecting (1) $4.5 million in income from insurance litigation settlements and (2) $0.9 million from adjustments to incentive compensation accruals. ELECTRIC UTILITY. Electric sales for 2000 increased 0.8% on weather that was slightly colder than in the prior year. Revenues increased as a result of the higher sales as well as an increase in transmission revenues from wholesale transmission services which have been unbundled as a result of electric customer choice. Cost of sales increased to $33.9 million in 2000 from $33.2 million in 1999 reflecting the higher sales and higher costs associated with wholesale transmission services. Electric Utility total margin increased $1.9 million principally reflecting the impact of lower average power costs and higher sales. EBITDA and operating income also increased reflecting higher total margin and a $2.5 million increase in other income principally from the sale of pollution credits. These increases were partially offset by higher utility realty taxes and greater power production maintenance expenses. ENERGY SERVICES. Revenues increased $56.5 million during 2000 primarily as a result of higher natural gas prices and to a lesser extent higher volumes sold. Total margin, EBITDA and operating income in 2000 were slightly higher than in 1999 due to the impact of the higher sales on total margin. 14 3 UGI Corporation 2000 Annual Report - -------------------------------------------------------------------------------- INTERNATIONAL PROPANE. International Propane results include equity in our joint venture projects in Romania and China and, in 2000, the results of FLAGA. The results of FLAGA during 2000 were adversely affected by weather that was 9.6% warmer than normal and by higher propane supply costs. The higher propane supply costs resulted in lower than normal unit margins and price-induced conservation. Equity income in 2000 from our China propane joint venture partnership was also negatively impacted by higher propane product costs and customer conservation. CORPORATE & OTHER AND OTHER ENTERPRISES. Corporate and other operating income in 2000 was $5.1 million, a decrease of $0.8 million from 1999, primarily reflecting lower interest income on cash investments. Other Enterprises' results in 2000 primarily reflect start-up costs and initial operating losses of Hearth USA(TM). Results in 1999 include due diligence expenses associated with Enterprises' domestic and international new business activities and start-up expenses associated with Hearth USA(TM). INTEREST EXPENSE AND INCOME TAXES. The higher interest expense in 2000 is a result of an increase in the Partnership's long-term debt, higher interest under the Partnership's and UGI Utilities' bank credit agreements, and interest on FLAGA debt in 2000. The effective income tax rate was 46.4% in 2000 compared to 43.0% in 1999 which rate reflected a lower tax rate on merger termination fee income. 1999 COMPARED WITH 1998 CONSOLIDATED RESULTS. Our consolidated net income in 1999 increased $15.4 million compared to 1998. The improvement in net income was due to one-time net merger termination fee income of $12.9 million and higher net income from UGI Utilities and AmeriGas Partners, offset in part by costs associated with Enterprises' new business activities.
Variance- Favorable 1999 1998 (Unfavorable) --------------------------------------------------------------------------- DILUTED Diluted Diluted NET EARNINGS Net Earnings Net Earnings INCOME (LOSS) Income (Loss) Income (Loss) (LOSS) PER SHARE (Loss) Per Share (Loss) Per Share - -------------------------------------------------------------------------------------------------------------------------- (Millions of dollars, except per share) AmeriGas Propane $ 4.5 $ 0.14 $ 1.9 $ 0.06 $ 2.6 $ 0.08 Utilities 37.4 1.17 33.0 1.00 4.4 0.17 Energy Services 1.5 0.05 1.1 0.03 0.4 0.02 International Propane (0.1) - (0.5) (0.01) 0.4 0.01 Other Enterprises (3.6) (0.11) (1.3) (0.04) (2.3) (0.07) Corporate & Other 3.1 0.09 6.1 0.18 (3.0) (0.09) Merger termination fee, net 12.9 0.40 - - 12.9 0.40 - -------------------------------------------------------------------------------------------------------------------------- Total $ 55.7 $ 1.74 $ 40.3 $ 1.22 $ 15.4 $ 0.52 - --------------------------------------------------------------------------------------------------------------------------
SEGMENT RESULTS. The following table presents certain financial and statistical information by business segment for 1999 and 1998:
Increase 1999 1998 (Decrease) - ------------------------------------------------------------------------------------------- (Millions of dollars) AMERIGAS PROPANE Revenues $872.5 $914.4 $(41.9) (4.6)% Total margin $481.7 $470.6 $ 11.1 2.4% EBITDA $158.8 $153.3 $ 5.5 3.6% Operating income $ 92.5 $ 87.9 $ 4.6 5.2% Retail gallons sold (millions) 783.2 785.3 (2.1) (0.3)% Degree days - % warmer than normal 9.9% 8.7% - - GAS UTILITY Revenues $345.6 $350.2 $ (4.6) (1.3)% Total margin $160.6 $157.2 $ 3.4 2.2% EBITDA $ 87.0 $ 83.0 $ 4.0 4.8% Operating income $ 68.0 $ 64.8 $ 3.2 4.9% System throughput - bcf 76.1 74.9 1.2 1.6% Degree days - % warmer than normal 12.8% 16.3% - - ELECTRIC UTILITY Revenues $ 75.0 $ 72.1 $ 2.9 4.0% Total margin $ 38.6 $ 34.0 $ 4.6 13.5% EBITDA $ 16.7 $ 13.6 $ 3.1 22.8% Operating income $ 12.7 $ 9.7 $ 3.0 30.9% Sales - gwh 900.4 876.4 24.0 2.7% ENERGY SERVICES Revenues $ 90.4 $103.0 $(12.6) (12.2)% Total margin $ 6.0 $ 4.7 $ 1.3 27.7% EBITDA $ 2.7 $ 2.1 $ 0.6 28.6% Operating income $ 2.6 $ 2.0 $ 0.6 30.0% INTERNATIONAL PROPANE EBITDA $ (0.1) $ (1.0) $ 0.9 90.0% Operating loss $ (0.1) $ (1.0) $ (0.9) (90.0)%
AMERIGAS PROPANE. Based upon national weather data, temperatures in 1999 were 9.9% warmer than normal and 1.3% warmer than in 1998. Retail volumes of propane sold were slightly lower in 1999 primarily as a result of a 7.3 million decline in agricultural gallons as a dry autumn reduced demand for crop drying. Partially offsetting the decrease in agricultural gallons were higher motor fuel sales, increased gallons sold through PPX(R), and, notwithstanding the warmer weather, higher sales to our targeted residential customer market. Total revenues from retail propane sales declined $36.3 million in 1999 primarily due to lower average selling prices. The lower 15 4 - -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) average selling prices resulted from lower propane product costs. Wholesale propane revenues declined $13.2 million reflecting (1) a $6.9 million decrease as a result of lower average wholesale prices and (2) a $6.3 million decrease as a result of lower wholesale volumes sold. Nonpropane revenues increased $7.6 million in 1999 reflecting higher appliance and cylinder sales, increased terminal and hauling revenues, and greater customer fee revenues. Cost of sales declined $53.0 million primarily as a result of lower propane product costs. Total margin increased $11.1 million in 1999 due to (1) slightly higher average retail unit margin per gallon; (2) greater total margin from PPX; and (3) an increase in total margin from appliance sales, customer fees and hauling and terminal revenue. EBITDA and operating income were higher in 1999 as a result of (1) the higher total margin and (2) higher other income. These increases were partially offset by an increase in operating expenses. Other income, net, in 1998 included a $4.0 million loss from two interest rate protection agreements. Operating expenses of the Partnership were $329.6 million in 1999 compared with $320.2 million in 1998. Operating expenses in 1998 are net of (1) $2.7 million of income from lower required accruals for environmental matters and (2) $2.0 million of income from lower required accruals for property taxes. Excluding the impact of these items in the prior year, operating expenses of the Partnership increased $4.7 million in 1999 principally due to expenses associated with new business initiatives. GAS UTILITY. Weather in Gas Utility's service territory was 12.8% warmer than normal in 1999 but 4.2% colder than in 1998. Total system throughput increased 1.6% as a result of the slightly colder weather as well as an increase in total customers. The decrease in Gas Utility revenues in 1999 is principally due to several of our core market industrial customers switching from retail to delivery service. Under retail service, we bill our customers for the transportation of gas through our distribution system as well as the cost of the gas, for which we get dollar-for-dollar recovery. Under delivery service, we bill customers for the transportation of the gas but not for the gas itself. Our revenues from customers who switch to delivery service are therefore lower, but there is little impact on our total margin. Partially offsetting the decline in revenues from our core market industrial customers was an increase in revenues from sales to our core market residential and commercial customers. Gas Utility cost of gas was $172.0 million in 1999, a decrease of $7.6 million from 1998, reflecting the impact of core market industrial customers switching to delivery service. The increase in Gas Utility total margin in 1999 includes a $3.6 million increase from sales to our core market residential and commercial customers. Total margin from interruptible customers (who have the ability to switch to alternate fuels, principally oil) was slightly lower in 1999. The decline in total margin from our interruptible customers reflects lower interruptible rates due to a decline in the spread between oil and natural gas prices during most of 1999. Gas Utility operating income was higher in 1999 reflecting the increase in total margin and higher other income partially offset by slightly higher operating and administrative expenses and increased charges for depreciation. Operating expenses in 1998 are net of $1.6 million of income from an insurance recovery. Excluding the impact of the insurance recovery in 1998, total Gas Utility operating and administrative expenses in 1999 were essentially unchanged. ELECTRIC UTILITY. The increase in 1999 sales of electricity reflects slightly colder heating season weather and warmer weather during the summer air conditioning season. Electric Utility revenues increased $2.9 million in 1999 principally as a result of the higher sales. Although Electric Utility's Restructuring Order filed pursuant to Pennsylvania's Electricity Customer Choice Act gives all of our customers the ability to choose their electricity generation supplier effective January 1, 1999, only approximately 5% of our sales during 1999 represented electricity we distributed for alternate suppliers. Notwithstanding the increase in Electric Utility sales in 1999, cost of sales decreased $1.8 million to $33.2 million. The impact of the higher 1999 sales on purchased power costs was more than offset by (1) the benefit of a power supply agreement settlement and (2) lower average purchased power costs Electric Utility's total margin increased $4.6 million as a result of (1) the power supply agreement settlement; (2) lower average purchased power costs; and (3) the higher sales. EBITDA and operating income were also higher as the greater total margin was partially offset by higher maintenance costs associated with our generation assets, higher customer service and information expenses, and lower other income. ENERGY SERVICES. Total revenues from energy marketing in 1999 declined $12.6 million as a result of lower average gas prices and, to a lesser extent, a decrease in billed volumes. Total margin increased $1.3 million reflecting higher average margins from gas marketing and greater income from power marketing and other services. EBITDA and operating income increased $0.6 million in 1999 as a result of the higher margin offset by slightly higher operating expenses. INTERNATIONAL PROPANE. Results for 1999 and 1998 principally reflect the equity results in our international propane joint venture projects. CORPORATE & OTHER AND OTHER ENTERPRISES. Corporate and other operating income was $5.9 million in 1999 compared with $8.6 million in 1998. Income in both years principally comprises inter- 16 5 UGI Corporation 2000 Annual Report - -------------------------------------------------------------------------------- est income on short-term investments and, in 1998, income from the sale of certain equity securities. The decrease in operating income from Other Enterprises in 1999 resulted from start-up costs associated with Hearth USA(TM) retail and due diligence expenses associated with international propane business opportunities. INTEREST EXPENSE AND INCOME TAXES. The Company's interest expense in 1999 was $84.6 million, comparable to the $84.4 million recorded in 1998. The effective income tax rate in 1999 was 43.0% compared to an effective tax rate of 44.7% in 1998. The lower effective tax rate in 1999 is principally a result of a lower tax rate on the merger termination fee income. FINANCIAL CONDITION AND LIQUIDITY CAPITALIZATION AND LIQUIDITY Our cash and short-term investments totaled $101.7 million at September 30, 2000 compared with $55.6 million at September 30, 1999. Included in these amounts are $56.3 million and $23.3 million, respectively, of cash and short-term investments held by UGI. The primary sources of UGI's cash and short-term investments are the cash dividends it receives from its wholly owned subsidiaries, AmeriGas, Inc. and UGI Utilities. AmeriGas, Inc.'s ability to pay dividends to UGI is dependent upon the receipt of distributions on the Common and Subordinated units of AmeriGas Partners that we own. During 2000, 1999 and 1998, AmeriGas, Inc. and UGI Utilities paid cash dividends to UGI as follows:
Year Ended September 30, 2000 1999 1998 - --------------------------------------------------------------- (Millions of dollars) AmeriGas $51.6 $47.6 $55.2 UGI Utilities 44.0 29.0 22.6 - --------------------------------------------------------------- Total dividends to UGI $95.6 $76.6 $77.8 - ---------------------------------------------------------------
THE PARTNERSHIP. The Operating Partnership's primary sources of cash since its formation in 1995 have been (1) cash generated by operations; (2) borrowings under its Bank Credit Agreement; and (3) the issuance of $80 million of long-term debt in 2000 and $70 million of long-term debt in 1999. On September 22, 2000, a shelf registration statement for the issuance of 9 million AmeriGas Common Units was declared effective by the Securities and Exchange Commission. In October 2000, the Partnership issued 2.3 million of its registered Common Units in an underwritten public offering and received $40.6 million in cash proceeds, including related capital contributions from our wholly owned, second-tier subsidiary, AmeriGas Propane, Inc. (the "General Partner"). These proceeds were used to reduce Bank Credit Agreement indebtedness and for working capital purposes. The Operating Partnership's Bank Credit Agreement, as amended, consists of (1) a $100 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for (1) working capital; (2) capital expenditures; and (3) interest and Partnership distribution payments. Revolving Credit Facility loans were $30 million at September 30, 2000 and $22 million at September 30, 1999. The Operating Partnership may borrow under its Acquisition Facility to finance the purchase of propane businesses or propane business assets. Loans outstanding under the Acquisition Facility at September 30, 2000 and 1999 were $70 million and $23 million, respectively. During 2000, the Bank Credit Agreement was amended to, among other changes, extend the Acquisition Facility termination date to September 15, 2002. Then-outstanding borrowings under the Acquisition Facility will be due in their entirety on such date. The Operating Partnership also has a credit agreement with the General Partner to borrow up to $20 million on an unsecured, subordinated basis, to fund (1) working capital; (2) capital expenditures; and (3) interest and Partnership distribution payments. UGI has agreed to contribute up to $20 million to the General Partner to fund such borrowings. During 2000, the Operating Partnership issued $80 million of Series E First Mortgage Notes at an effective interest rate of 8.47%. The proceeds were used principally to reduce Acquisition Facility borrowings and $10 million of maturing First Mortgage Note debt. The Partnership's management believes that cash flow from operations and Bank Credit Agreement borrowings will be sufficient to satisfy its liquidity needs in fiscal 2001. For a more detailed discussion of the Partnership's credit facilities, including financial covenant ratios, see Note 3. UGI UTILITIES. UGI Utilities' primary sources of cash have been (1) cash generated by operations; (2) borrowings under its revolving credit agreements; and (3) debt issued under its Medium-Term Note program. UGI Utilities can issue up to an additional $52 million under its Medium-Term Note program. UGI Utilities may borrow up to a total of $122 million under its revolving credit agreements. Borrowings under revolving credit agreements totaled $100.4 million at September 30, 2000 and $87.4 million at September 30, 1999. Management believes that UGI Utilities' cash flow from operations and borrowings under its Medium-Term Note program and 17 6 - -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) bank credit facilities will satisfy UGI Utilities' cash needs in fiscal 2001. For a more detailed discussion of UGI Utilities' debt and credit facilities, including financial covenants and ratios, see Note 3. FLAGA. FLAGA has a 9 million EURO working capital loan commitment and a 15 million EURO special purpose commitment from a foreign bank. Borrowings under these commitments totaled 4.9 million EUROs and 13.5 million EUROs, respectively, at September 30, 2000. Management believes that cash flow from operations and borrowings under its special purpose facility, working capital facility and a short-term credit facility from UGI will satisfy FLAGA's cash needs in fiscal 2001. CASH FLOWS OPERATING ACTIVITIES. Cash flow from operating activities was $132.7 million in 2000 compared to $141.9 million in 1999 which included $12.9 million of after-tax proceeds from the merger termination fee. As a result of significantly higher propane and natural gas costs, cash flows from operating activities in 2000 reflect significantly higher accounts receivable, inventories and accounts payable. Cash flow from operating activities before changes in operating working capital declined modestly from $170.3 million in 1999 to $167.5 million in 2000. INVESTING ACTIVITIES. We spent $71.0 million for property, plant and equipment in 2000 compared with $70.2 million in 1999. The increase in 2000 resulted from expenditures of FLAGA. Net cash paid for acquisitions, principally comprising Partnership propane and HVAC business acquisitions, totaled $65.3 million in 2000 compared to $77.6 million in 1999 including $73.7 million for the purchase of FLAGA. FINANCING ACTIVITIES. We paid cash dividends on our Common Stock of $41.2 million in 2000 compared to $47.9 million in 1999 on fewer shares outstanding. In 2000 and 1999, the Partnership paid (1) distributions to its public unitholders totaling approximately $39 million; (2) the full minimum quarterly distribution of $0.55 ("MQD") on all units we hold totaling $53.2 million; and (3) $1.1 million to the General Partner. During 2000, the Operating Partnership borrowed $116 million under the Acquisition Facility, and made Acquisition Facility repayments totaling $69 million. In 2000, we used $9.6 million to repurchase 0.5 million shares of UGI Common Stock. In 1999, we spent $133.1 million (including transaction costs) for the repurchase of 5.9 million shares of UGI Common Stock, including 4.5 million shares repurchased through our Dutch auction tender offer. DIVIDENDS AND DISTRIBUTIONS In April 2000, our board of directors increased the annual dividend rate to $1.55 a share from $1.50. Dividends declared in 2000 totaled $41.4 million. At September 30, 2000, our 58.4% effective interest in the Partnership consisted of (1) 14.3 million Common Units; (2) 9.9 million Subordinated Units; and (3) a 2% general partner interest. The remaining 41.6% effective interest consists of 17.8 million publicly held Common Units. As a result of the Partnership's October 2000 issue of 2.3 million Common Units pursuant to a public offering, our effective interest in the Partnership declined to 55.5%. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Agreement of Limited Partnership of AmeriGas Partners, the "Partnership Agreement") relating to such fiscal quarter. Common Unitholders receive the MQD, plus any arrearages, before a distribution of Available Cash can be made on the Subordinated Units. Since its formation in 1995, the Partnership has paid the MQD on all limited partner units outstanding. The amount of Available Cash needed annually to pay the MQD on all units and the general partner interests in 2000, 1999 and 1998 was approximately $94 million. In fiscal 2001, as a result of the additional Common Units issued in October 2000, this amount will increase to approximately $99 million. One measure of the amount of cash available for distribution that is generated by the Partnership can be determined by subtracting (1) cash interest expense and (2) capital expenditures needed to maintain operating capacity, from the Partnership's EBITDA. Partnership distributable cash flow as calculated for 2000, 1999 and 1998 is as follows:
Year Ended September 30, 2000 1999 1998 - ------------------------------------------------------------------ (Millions of dollars) EBITDA $157.6 $157.5 $151.1 Cash interest expense (a) (76.7) (68.3) (67.6) Maintenance capital expenditures (11.6) (11.1) (10.3) - ------------------------------------------------------------------ Distributable cash flow $ 69.3 $ 78.1 $ 73.2 - ------------------------------------------------------------------
(a) Interest expense adjusted for noncash items. Although distributable cash flow is a reasonable estimate of the amount of cash generated by the Partnership, it does not reflect the impact of changes in working capital which can significantly affect cash available for distribution and it is not a measure of performance or financial condition under generally accepted accounting principles but provides additional information for evaluating the Partnership's ability to declare and pay the MQD. Although the 18 7 UGI Corporation 2000 Annual Report - -------------------------------------------------------------------------------- levels of distributable cash flow in these years were less than the full MQD, borrowings in 2000 and 1999, and cash generated from changes in working capital in 1998, were more than sufficient to permit the Partnership to declare and pay the full MQD. The ability of the Partnership to declare and pay the MQD on all units depends upon a number of factors. These factors include (1) the level of Partnership earnings; (2) the cash needs of the Partnership's operations (including cash needed for maintaining and increasing operating capacity); (3) changes in operating working capital; and (4) the Partnership's ability to borrow under its Bank Credit Agreement, to refinance maturing debt, and to increase its long-term debt. Some of these factors are affected by conditions beyond our control including weather, competition in markets we serve, and the cost of propane. CONVERSION OF SUBORDINATED UNITS Pursuant to the Partnership Agreement, a total of 9,891,074 Subordinated Units held by the General Partner were converted to Common Units on May 18, 1999 because certain historical and projected cash generation-based requirements were achieved as of March 31, 1999. The Partnership's ability to attain the cash-based performance and distribution requirements necessary to convert the remaining 9,891,072 Subordinated Units depends upon a number of factors, including highly seasonal operating results, changes in working capital, asset sales and debt refinancings. Due to significantly warmer-than-normal weather and the impact of higher propane product costs on working capital, we did not achieve the cash-based performance requirements as of any relevant quarter through September 30, 2000. Due to the historical "look-back" provisions of the conversion test, the possibility is remote that the Partnership will satisfy the cash-based performance requirements for conversion any earlier than in respect of the quarter ending March 31, 2002. CAPITAL EXPENDITURES In the following table, we present capital expenditures of our consolidated operations (which include expenditures for capital leases but exclude acquisitions) for 2000, 1999 and 1998. We also provide amounts we expect to spend in fiscal 2001. We expect to finance a substantial portion of fiscal 2001 capital expenditures from cash generated by operations and the remainder from borrowings under our credit facilities.
Year Ended September 30, 2001 2000 1999 1998 - ---------------------------------------------------------------------- (Millions of dollars) (estimate) AmeriGas Propane $28.9 $30.4 $34.6 $31.9 Utilities 40.9 36.4 36.4 37.2 International Propane 2.9 1.8 - - Other 2.2 2.4 2.7 0.1 - ---------------------------------------------------------------------- Total $74.9 $71.0 $73.7 $69.2 - ----------------------------------------------------------------------
UTILITY MATTERS 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 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 Pennsylvania Public Utility Commission ("PUC"). As of January 1, 2000, the Gas Competition Act, in conjunction with a companion bill, eliminated the gross receipts tax on sales of gas. Generally, 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. LDCs are generally precluded from increasing rates for the recovery of costs, other than gas costs, until January 1, 2001. 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 assignment. The PUC, however, may only grant the petition if certain findings are made and the LDC fully recovers the cost of contracts. On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas Utility's restructuring plan substantially as filed. Among other things, the restructuring plan (1) provides for recovery of costs associated with existing pipeline capacity and gas supply contracts; (2) increases Gas Utility's base rates for firm customers; and (3) changes the calculation of the PGC rates. The effect of (2) and (3) above is to reduce the financial impact of volatility in revenues from customers who have the ability to switch to an alternate fuel under interruptible rates and increase our sensitivity to changes in weather. Because the Gas Competition Act requires alternate suppliers to accept assignment of a portion of the LDC's pipeline capacity and storage contracts, we do not believe the Gas Competition Act and the Gas Restructuring Order will have a material adverse impact on our financial condition or results of operations. In September 2000, UGI Development Company ("UGIDC"), a subsidiary of UGI Utilities, agreed to joint venture with a subsidiary of Allegheny Energy, Inc. ("Allegheny") to own and operate electric generation facilities, including Electric Utility's coal-fired Hunlock Creek generating station ("Hunlock"). Initially, UGIDC will contribute to the joint venture Hunlock, certain related assets, and approximately $6 million in cash. Allegheny will contribute a newly-constructed gas-fired combustion turbine generator to be operated at the existing Hunlock site. Each partner will be entitled 19 8 - -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) to purchase 50% of the output of the joint venture at cost. The joint venture is expected to become operational in December 2000. MANUFACTURED GAS PLANTS Prior to the general availability of natural gas, in the 1800s through the mid-1900s, most gas for lighting and heating nationwide was manufactured from combustibles such as coal, oil and coke. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the federal "Comprehensive Environmental Response, Compensation and Liability Act," or "Superfund Law," and may be present on the sites of former manufactured gas plants ("MGPs"). UGI Utilities and its former subsidiaries owned and operated a number of 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. By the mid-1930s, UGI Utilities was one of the largest public utility holding companies in the country. 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 has been notified of several sites outside Pennsylvania on which (1) gas plants 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 UGI Utilities should not have significant liability in those instances in which a former subsidiary operated an MGP because UGI Utilities generally is not legally liable for the obligations of its subsidiaries. Under certain circumstances, however, a court could find a parent company liable for environmental damage caused by a subsidiary company when the parent company either (1) itself operated the facility causing the environmental damage or (2) otherwise so controlled the subsidiary that the subsidiary's separate corporate form should be disregarded. There could be, therefore, significant future costs of an uncertain amount associated with environmental damage caused by MGPs that UGI Utilities owned or 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 identified 40 sites in Pennsylvania where either (1) UGI Utilities formerly conducted some MGP operations or (2) UGI Utilities owns or at one time owned the site. Because Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with Pennsylvania sites, the Company does not expect its costs for Pennsylvania sites to be material to future results of operations. 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 million in such costs. During 2000, UGI Utilities entered into settlement agreements with several of the insurers and recorded pre-tax income of $4.5 million. MARKET RISK DISCLOSURES Our primary market risk exposures are (1) fluctuations in market prices for propane, natural gas and electricity; (2) changes in interest rates; and (3) foreign currency exchange rates. The Partnership's profitability is sensitive to changes in propane supply costs, and the Partnership generally attempts to pass on promptly increases in such costs to customers. There is no assurance, however, that the Partnership will be able to do so. In order to manage a portion of the Partnership's propane market price risk, it uses contracts for the forward purchase of propane, propane fixed-price supply agreements, and derivative commodity instruments such as price swap and option contracts. Due to competitive and business conditions in the markets it serves, FLAGA is less able than the Partnership to recover promptly increases in product costs. FLAGA does not currently use derivative commodity instruments to hedge propane market risk. In order to manage market price risk relating to substantially all of Energy Services' forecasted sales of natural gas, we purchase exchange-traded natural gas futures contracts. In addition, we occasionally utilize a managed program of derivative instruments including natural gas and oil futures contracts to preserve gross margin associated with certain of our natural gas customers. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The current regulatory framework allows Gas Utility to recover prudently incurred gas costs from its customers. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Electric Utility purchases electricity it does not otherwise pro- 20 9 UGI Corporation 2000 Annual Report - -------------------------------------------------------------------------------- duce, representing approximately 50% of its electric power needs in 2000, under power supply arrangements of varying length terms with other producers and on the spot market. Spot market prices for electricity and, to a lesser extent, monthly market-based contracts can be volatile, especially during periods of high demand. Because Electric Utility's generation rates are capped through approximately December 2002 under its Restructuring Order, any increases in costs to produce or purchase electricity will negatively impact Electric Utility's results. We have market risk exposure from changes in interest rates on floating rate borrowings under the Operating Partnership's Bank Credit Agreement, UGI Utilities' revolving credit agreements and substantially all of FLAGA's debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. At September 30, 2000 and 1999, combined borrowings outstanding under these facilities totaled $282.1 million and $221.0 million, respectively. Based upon average borrowings under these agreements during 2000 and 1999, an increase in short-term interest rates of 100 basis points (1%) would have increased interest expense by $2.5 million and $1.2 million, respectively. We also use fixed-rate long-term debt as a source of capital. As these fixed-rate long-term debt issues mature, we intend to refinance such debt with new debt having interest rates reflecting then-current market conditions. This debt may have an interest rate that is more or less than the refinanced debt. On occasion, we enter into interest rate protection agreements to reduce interest rate risk associated with a forecasted issuance of debt. We do not currently use derivative instruments to hedge foreign currency exposure associated with our investments in international propane operations, principally FLAGA. As a result, the U.S. dollar value of our foreign denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. Our exposure to changes in foreign currency exchange rates has been significantly limited, however, because our net investment in FLAGA, our principal international propane operation, was financed with EURO denominated debt. The following table summarizes the fair values of unsettled market risk sensitive derivative instruments held at September 30, 2000 and 1999. It also includes the changes in fair value that would result if there were an adverse change in (1) the market price of propane of 10 cents a gallon; (2) the market price of natural gas of 50 cents a dekatherm; (3) interest rates on ten-year U.S. treasury notes of 100 basis points; and (4) the market price of oil of 10 cents a gallon:
Change in Fair Value Fair Value - ------------------------------------------------------------------------ (Millions of dollars) September 30, 2000: Propane commodity price risk $6.5 $(10.5) Natural gas commodity price risk 4.2 (3.5) Interest rate risk 2.5 (3.9) September 30, 1999: Propane commodity price risk $2.9 $(2.5) Natural gas commodity price risk 2.6 (5.2) Interest rate risk 3.2 (3.8) Oil commodity price risk (0.2) (0.5) - ------------------------------------------------------------------------
We expect that adverse changes in the fair value of derivative instruments used to manage commodity or interest rate market risk would be substantially offset by gains on the associated underlying transactions. ACCOUNTING PRINCIPLES NOT YET ADOPTED In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 was amended in June 2000 by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" ("SFAS 138"), which addressed a limited number of issues causing implementation difficulties. SFAS 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that an entity recognize all derivative instruments as either assets or liabilities and measure them 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 derivative instruments qualify and are designated as hedges of the variability in cash flows associated with forecasted transactions, the effective portion of the gain or loss on such derivative instruments will generally be reported in other comprehensive income and the ineffective portion, if any, will be reported in net income. Such amounts recorded in accumulated other comprehensive income will be reclassified into net income when the forecasted transaction affects earnings. 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, the gain or loss on the hedging instrument will be recognized currently in earnings along with changes in the fair value of the hedged asset, liability or firm commitment attributable to the hedged risk. 21 10 - -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) The Company was required to adopt the provisions of SFAS 133 effective October 1, 2000. Virtually all of the Company's derivative instruments outstanding as of October 1, 2000 qualify and have been designated as hedging the variability in cash flows associated with forecasted transactions. The adoption of SFAS 133 will result in an after-tax cumulative effect charge to net income of $0.3 million, and an after-tax cumulative effect increase to accumulated other comprehensive income of $7.1 million. Because the Company's derivative instruments historically have been highly effective in hedging the exposure to changes in cash flows associated with forecasted purchases or sales of natural gas and propane, changes in the fair value of propane inventories, and changes in the risk-free rate of interest on anticipated issuances of long-term debt, we do not expect the adoption of SFAS 133 to have a material impact on our future results of operations. Although the Company expects the derivative instruments it currently uses to hedge to continue to be highly effective, if they are determined not to be highly effective in the future, or if the Company uses derivative instruments that do not meet the stringent requirements for hedge accounting under SFAS 133, our future earnings could reflect greater volatility. Additionally, if a cash flow hedge is discontinued because the forecasted transaction is no longer expected to occur, any gain or loss in accumulated comprehensive income associated with the hedged transaction will be immediately recognized in net income. In order to comply with the provisions of the Securities and Exchange Commission Staff Accounting Bulletin No. 101 ("SAB 101") entitled "Revenue Recognition", which is effective for the Company on October 1, 2000, the Company will record a cumulative effect charge to net income of approximately $2.3 million related to the Partnership's method of recognizing revenue associated with nonrefundable tank fees largely for residential customers. Consistent with a number of its competitors in the propane industry, the Partnership receives nonrefundable fees for installed Partnership-owned tanks. Historically, such fees, which are generally received annually, were recorded as revenue when billed. In accordance with SAB 101, effective October 1, 2000, the Partnership will record such nonrefundable fees on a straight-line basis over one year. The adoption of SAB 101 is not expected to have a material impact on the Company's future financial condition or results of operations. Also, during fiscal 2001, the Partnership plans to change its method of accounting for tank installation costs which are not billed to customers. Currently, all direct costs to install Partnership-owned tanks at a customer location are expensed as incurred. The Partnership believes that these costs should now be capitalized and amortized over the period benefited. On date of adoption, this change in accounting method will result in a cumulative effect increase to net income. The Company is in the process of evaluating the impact of such change on its financial condition and results of operations. PROPOSED FOREIGN EQUITY INVESTMENT On October 30, 2000, the Company, together with Paribas Affaires Industrielles ("PAI") and Medit Mediterranea GPL, S.r.L. ("Medit"), submitted to Total Fina Elf S. A. ("TFE"), a large French petroleum and chemical company, a bid to acquire the stock and certain related assets of Elf AntarGaz S.A. ("EAZ"). EAZ, a subsidiary of TFE, is one of the largest distributors of liquefied petroleum gas in France with an approximate 24% market share. Under the terms of the bid, the Company would acquire a 20% interest in EAZ; PAI a 70% interest; and Medit a 10% interest. PAI is a leading private equity fund manager in Europe and an affiliate of BNP Partners. BNP Partners is one of Europe's largest commercial and investment banks. Medit is a supplier of logistics services to the liquefied petroleum gas industry in Europe, primarily Italy. The amount of the Company's investment in EAZ is not expected to exceed $30 million. The bid is subject to approval by the Commission of the European Communities. There can be no assurance, however, that the bid will be approved or that other requirements for consummation of the transaction will be met. FORWARD-LOOKING STATEMENTS Information contained in this Financial Review and elsewhere in this Annual Report with respect to expected financial results and future events is forward-looking, based on our estimates and assumptions and subject to risks and uncertainties. For those statements, we claim the protection of the safe harbor for forward looking statements contained in the Private Securities Litigation Reform Act of 1995. The following important factors could affect our future results and could cause actual 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 propane, oil, electricity, and natural gas and the capacity to transport product 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) 22 11 liability for environmental claims; (6) improvements in energy efficiency and technology resulting in reduced demand; (7) labor relations; (8) large customer or supplier defaults; (9) operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and propane including the risk of explosions and fires resulting in personal injury and property damage; (10) regional economic conditions; (11) political, regulatory and economic conditions in foreign countries; (12) interest rate fluctuations and other capital market conditions, including foreign currency rate fluctuations; (13) reduced distributions from subsidiaries; and (14) the timing and success of the Company's efforts to develop new business opportunities. 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. 23 12 UGI Corporation 2000 Annual Report - -------------------------------------------------------------------------------- REPORT OF MANAGEMENT The Company's consolidated financial statements and other financial information contained in this Annual Report are prepared by management, which is responsible for their fairness, integrity and objectivity. The consolidated financial statements and related information were prepared in accordance with accounting principles generally accepted in the United States and include amounts that are based on management's best judgements and estimates. The Company maintains a system of internal controls. Management believes the system provides reasonable assurance that assets are safeguarded and that transactions are executed in accordance with management's authorization and are properly recorded to permit the preparation of reliable financial information. There are limits in all systems of internal control, based on the recognition that the cost of the system should not exceed the benefits to be derived. We believe that the Company's internal control system is cost effective and provides reasonable assurance that material errors or irregularities will be prevented or detected within a timely period. The internal control system and compliance therewith are monitored by the Company's internal audit staff. The Audit Committee of the Board of Directors is composed of three members, none of whom is an employee of the Company. This Committee is responsible for overseeing the financial reporting process and the adequacy of controls, and for monitoring the independence of the Company's independent public accountants and the performance of the independent accountants and internal audit staff. The Committee recommends to the Board of Directors the engagement of the independent public accountants to conduct the annual audit of the Company's consolidated financial statements. The Committee is also responsible for maintaining direct channels of communication between the Board of Directors and both the independent public accountants and internal auditors. The independent public accountants, who are appointed by the Board of Directors and ratified by the shareholders, perform certain procedures, including an evaluation of internal controls to the extent required by auditing standards generally accepted in the United States, in order to express an opinion on the consolidated financial statements and to obtain reasonable assurance that such financial statements are free of material misstatement. /s/ Lon. R. Greenberg Lon. R. Greenberg Chief Executive Officer /s/ Anthony J. Mendicino Anthony J. Mendicino Chief Financial Officer - -------------------------------------------------------------------------------- Report of Independent Public Accountants TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF UGI CORPORATION: We have audited the accompanying consolidated balance sheets of UGI Corporation and subsidiaries as of September 30, 2000 and 1999, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended September 30, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based upon our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. These 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 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 Corporation and subsidiaries as of September 30, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2000, in conformity with accounting principles generally accepted in the United States. /s/ Arthur Andersen LLP Philadelphia, Pennsylvania November 10, 2000 24 13 UGI Corporation 2000 Annual Report CONSOLIDATED STATEMENTS OF INCOME (MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
Year Ended September 30, ---------------------------------------------- 2000 1999 1998 ---------- ---------- ---------- REVENUES AmeriGas Propane $ 1,120.1 $ 872.5 $ 914.4 UGI Utilities 436.9 420.6 422.3 International Propane 50.5 -- -- Energy Services and other 154.2 90.5 103.0 ---------- ---------- ---------- 1,761.7 1,383.6 1,439.7 ---------- ---------- ---------- COSTS AND EXPENSES AmeriGas Propane cost of sales 628.3 390.8 443.8 UGI Utilities - gas, fuel and purchased power 218.1 205.2 214.6 International Propane cost of sales 29.7 -- -- Energy Services and other cost of sales 145.5 84.4 98.3 Operating and administrative expenses 461.2 429.2 412.5 Utility taxes other than income taxes 17.1 25.2 25.2 Depreciation and amortization 97.5 89.7 87.8 Other income, net (26.9) (16.8) (12.7) ---------- ---------- ---------- 1,570.5 1,207.7 1,269.5 ---------- ---------- ---------- OPERATING INCOME 191.2 175.9 170.2 Merger fee income and expenses, net -- 19.9 -- Interest expense (98.5) (84.6) (84.4) Minority interest in AmeriGas Partners (6.3) (10.7) (8.9) ---------- ---------- ---------- INCOME BEFORE INCOME TAXES AND SUBSIDIARY PREFERRED STOCK DIVIDENDS 86.4 100.5 76.9 Income taxes (40.1) (43.2) (34.4) Dividends on UGI Utilities Series Preferred Stock (1.6) (1.6) (2.2) ---------- ---------- ---------- NET INCOME $ 44.7 $ 55.7 $ 40.3 ---------- ---------- ---------- EARNINGS PER COMMON SHARE Basic $ 1.64 $ 1.74 $ 1.22 Diluted $ 1.64 $ 1.74 $ 1.22 AVERAGE COMMON SHARES OUTSTANDING (MILLIONS) Basic 27.219 31.954 32.971 Diluted 27.255 32.016 33.123 ========== ========== ==========
See accompanying notes to consolidated financial statements. 25 14 UGI Corporation 2000 Annual Report CONSOLIDATED BALANCE SHEETS (Millions of dollars)
September 30, ------------------------ ASSETS 2000 1999 -------- -------- CURRENT ASSETS Cash and cash equivalents $ 93.9 $ 40.5 Short-term investments, at cost which approximates market value 7.8 15.1 Accounts receivable (less allowances for doubtful accounts of $9.3 and $8.0, respectively) 165.7 107.5 Accrued utility revenues 10.5 6.9 Inventories 117.4 87.1 Deferred income taxes 11.8 13.7 Prepaid expenses and other current assets 19.0 24.7 -------- -------- Total current assets 426.1 295.5 -------- -------- PROPERTY, PLANT AND EQUIPMENT AmeriGas Propane 722.1 680.7 UGI Utilities 857.8 826.8 Other 72.2 91.5 -------- -------- 1,652.1 1,599.0 Accumulated depreciation and amortization (578.9) (514.9) -------- -------- Net property, plant and equipment 1,073.2 1,084.1 -------- -------- OTHER ASSETS Intangible assets (less accumulated amortization of $190.2 and $165.9, respectively) 675.5 653.1 Utility regulatory assets 62.3 61.1 Other assets 41.7 46.7 -------- -------- TOTAL ASSETS $2,278.8 $2,140.5 ======== ========
See accompanying notes to consolidated financial statements. 26 15 UGI Corporation 2000 Annual Report
September 30, ------------------------- LIABILITIES AND STOCKHOLDERS' EQUITY 2000 1999 -------- -------- CURRENT LIABILITIES Current maturities of long-term debt $ 85.9 $ 26.7 Operating Partnership bank loans 30.0 22.0 UGI Utilities bank loans 100.4 87.4 Other bank loans 4.3 11.6 Accounts payable 156.7 100.6 Employee compensation and benefits accrued 26.5 34.4 Dividends and interest accrued 47.3 44.1 Income taxes accrued 10.3 0.6 Deposits and refunds 39.0 40.2 Other current liabilities 39.0 39.3 -------- -------- Total current liabilities 539.4 406.9 -------- -------- DEBT AND OTHER LIABILITIES Long-term debt 1,029.7 989.6 Deferred income taxes 172.9 174.3 Deferred investment tax credits 9.2 9.6 Other noncurrent liabilities 83.3 81.0 Commitments and contingencies (note 11) -------- -------- MINORITY INTEREST Minority interest in AmeriGas Partners 177.1 209.9 -------- -------- PREFERRED AND PREFERENCE STOCK UGI Utilities Series Preferred Stock Subject to Mandatory Redemption, without par value 20.0 20.0 Preference Stock, without par value (authorized-5,000,000 shares) -- -- COMMON STOCKHOLDERS' EQUITY Common Stock, without par value (authorized-100,000,000 shares; issued-33,198,731 shares) 394.5 394.8 Accumulated deficit (4.9) (8.2) Accumulated other comprehensive income -- 0.5 Unearned compensation-restricted stock (0.7) (1.7) -------- -------- 388.9 385.4 Treasury stock, at cost (141.7) (136.2) -------- -------- Total common stockholders' equity 247.2 249.2 -------- -------- Total liabilities and stockholders' equity $2,278.8 $2,140.5 ======== ========
27 16 UGI Corporation 2000 Annual Report CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of dollars)
Year Ended September 30, ----------------------------------- 2000 1999 1998 ------ ------ ------ CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 44.7 $ 55.7 $ 40.3 Reconcile to net cash provided by operating activities: Depreciation and amortization 97.5 89.7 87.8 Minority interest in AmeriGas Partners 6.3 10.7 8.9 Deferred income taxes, net 3.2 7.7 10.1 Other, net 15.8 6.5 4.9 ------ ------ ------ 167.5 170.3 152.0 Net change in: Receivables and accrued utility revenues (63.4) (25.1) 22.0 Inventories and prepaid propane purchases (26.1) (5.0) 39.0 Deferred fuel costs (3.8) (5.1) (5.8) Accounts payable 52.0 17.4 (23.5) Other current assets and liabilities 6.5 (10.6) (5.2) ------ ------ ------ Net cash provided by operating activities 132.7 141.9 178.5 ------ ------ ------ CASH FLOWS FROM INVESTING ACTIVITIES Expenditures for property, plant and equipment (71.0) (70.2) (69.2) Acquisitions of businesses, net of cash acquired (65.3) (77.6) (8.1) Short-term investments (increase) decrease 7.3 66.7 (16.4) Net proceeds from disposals of assets 8.4 4.9 7.9 Investments in joint venture partnerships -- (4.9) (2.0) Other, net (0.9) (5.4) (2.3) ------ ------ ------ Net cash used by investing activities (121.5) (86.5) (90.1) ------ ------ ------ CASH FLOWS FROM FINANCING ACTIVITIES Dividends on Common Stock (41.2) (47.9) (47.6) Distributions on Partnership public Common Units (39.1) (39.0) (39.0) Issuance of long-term debt 209.7 173.7 58.0 Repayment of long-term debt (95.4) (70.9) (22.3) AmeriGas Propane bank loans increase (decrease) 8.0 12.0 (18.0) UGI Utilities bank loans increase 13.0 19.0 1.4 Other bank loans decrease (6.8) -- -- Issuance of Common Stock 3.8 4.7 8.5 Repurchases of Common Stock (9.6) (133.1) (11.3) Redemption of UGI Utilities Series Preferred Stock -- -- (15.5) ------ ------ ------ Net cash provided (used) by financing activities 42.4 (81.5) (85.8) ------ ------ ------ Effect of exchange rate changes on cash (0.2) -- -- ------ ------ ------ Cash and cash equivalents increase (decrease) $ 53.4 $(26.1) $ 2.6 ====== ====== ====== CASH AND CASH EQUIVALENTS End of period $ 93.9 $ 40.5 $ 66.6 Beginning of period 40.5 66.6 64.0 ------ ------ ------ Increase (decrease) $ 53.4 $(26.1) $ 2.6 ====== ====== ======
See accompanying notes to consolidated financial statements. 28 17 UGI Corporation 2000 Annual Report CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Millions of dollars, except per share amounts)
Accumulated Unearned Other Compensation- Common Accumulated Comprehensive Restricted Treasury Stock Deficit Income Stock Stock Total ------ ----------- ------------- ------------- --------- ------ BALANCE SEPTEMBER 30, 1997 $393.7 $ (9.2) $ -- $ -- $ (8.4) $376.1 Net income 40.3 40.3 Cash dividends on Common Stock ($1.45 per share) (47.8) (47.8) Common Stock issued: Employee and director plans 0.5 (0.7) 6.3 6.1 Dividend reinvestment plan 2.8 2.8 Acquisition 0.1 1.1 1.2 Redemption of UGI Utilities Series Preferred Stock (0.3) (0.3) Common Stock repurchased (11.3) (11.3) ------ ------ ----- ------ ------- ------ BALANCE SEPTEMBER 30, 1998 394.3 (17.7) -- -- (9.5) 367.1 Net income 55.7 55.7 Net unrealized gain on available for sale securities 0.5 0.5 ------ ----- ------ Comprehensive income 55.7 0.5 56.2 Cash dividends on Common Stock ($1.47 per share) (45.8) (45.8) Common Stock issued: Employee and director plans 0.4 (0.1) 3.4 3.7 Dividend reinvestment plan 0.1 (0.3) 3.0 2.8 Common Stock repurchased (133.1) (133.1) Issuance of restricted stock awards (2.1) (2.1) Amortization of unearned compensation- restricted stock awards 0.4 0.4 ------ ------ ----- ------ ------- ------ BALANCE SEPTEMBER 30, 1999 394.8 (8.2) 0.5 (1.7) (136.2) 249.2 Net income 44.7 44.7 Reclassification of unrealized gain on available for sale securities (0.5) (0.5) ------ ----- ------ Comprehensive income 44.7 (0.5) 44.2 Cash dividends on Common Stock ($1.525 per share) (41.4) (41.4) Common Stock issued: Employee and director plans (0.1) 1.5 1.4 Dividend reinvestment plan (0.2) 2.6 2.4 Common Stock repurchased (9.6) (9.6) Amortization of unearned compensation- restricted stock awards 1.0 1.0 ------ ------ ----- ------ ------- ------ BALANCE SEPTEMBER 30, 2000 $394.5 $ (4.9) $ -- $ (0.7) $(141.7) $247.2 ====== ====== ===== ====== ======= ======
See accompanying notes to consolidated financial statements. 29 18 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise)
NOTE PAGE - ---- ---- 1. Organization and Significant Accounting Policies 30 2. Utility Regulatory Matters 34 3. Debt 35 4. Income Taxes 37 5. Employee Retirement Plans 38 6. Inventories 39 7. Series Preferred Stock 39 8. Common Stock and Incentive Stock Award Plans 40 9. Preference Stock Purchase Rights 41 10. Partnership Distributions 42 11. Commitments and Contingencies 43 12. Financial Instruments 44 13. Acquisitions 45 14. Terminated Merger-Unisource Worldwide, Inc. 45 15. Other Income, Net 45 16. Quarterly Data (Unaudited) 46 17. Segment Information 46
NOTE 1 -- ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION. UGI Corporation ("UGI") is a holding company that operates gas and electric utility, propane distribution, energy marketing and related businesses through subsidiaries. Our utility business is conducted through a wholly owned subsidiary, UGI Utilities, Inc. ("UGI Utilities"). UGI Utilities owns and operates a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and an electric distribution utility and electricity generation business ("Electric Utility") in northeastern Pennsylvania (together we refer to them as "Utilities"). We conduct a national propane distribution business through AmeriGas Partners, L.P. ("AmeriGas Partners") and its operating subsidiary, AmeriGas Propane, L.P. (the "Operating Partnership"), both of which are Delaware limited partnerships. Our wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the "General Partner"), serves as the general partner of AmeriGas Partners and the Operating Partnership. At September 30, 2000, the General Partner and its wholly owned subsidiary Petrolane Incorporated ("Petrolane") held an effective 2% general partner interest and a 56.4% limited partner interest in the Operating Partnership. We refer to AmeriGas Partners and the Operating Partnership together as "the Partnership," and the General Partner and its subsidiaries, including the Partnership, as "AmeriGas Propane." The Operating Partnership is one of the largest retail propane distributors in the United States serving residential, commercial, industrial, motor fuel and agricultural customers from locations in 45 states, including Alaska and Hawaii. At September 30, 2000, our limited partner interest in AmeriGas Partners consisted of 14,283,932 Common Units and 9,891,072 Subordinated Units. The remaining 41.6% effective interest in the Partnership comprises 17,794,361 publicly held Common Units representing limited partner interests. In October 2000, AmeriGas Partners issued 2,300,000 Common Units in a public offering for net cash proceeds of approximately $40 million. After this transaction, the General Partner and Petrolane held an effective 2% general partner interest and 53.5% limited partner interest in the Operating Partnership. AmeriGas Partners and the Operating Partnership have no employees. Employees of the General Partner conduct, direct and manage the activities of the Partnership. The General Partner does not receive management fees or other compensation in connection with managing the Partnership, but is reimbursed for direct and indirect expenses incurred on behalf of the Partnership, including all General Partner employee compensation costs and a portion of UGI employee compensation and administrative costs. Although the Partnership's operating income represents a significant portion of our consolidated operating income, the Partnership's impact on our consolidated net income is considerably less due to (1) the Partnership's significant minority interest; (2) higher relative interest charges; and (3) a higher effective income tax rate associated with the Partnership's pre-tax income. Our wholly owned subsidiary, UGI Enterprises, Inc. ("Enterprises"), conducts an energy marketing business through its wholly owned subsidiary, UGI Energy Services, Inc. ("Energy Services"). Through other subsidiaries, Enterprises (1) owns and operates a propane distribution business, FLAGA GmbH ("FLAGA") in Austria, the Czech Republic and Slovakia; (2) owns and operates a heating, ventilation and air-conditioning service business ("HVAC") and a retail hearth, spa and grill products business in the Middle Atlantic region of the U.S.; and (3) participates in propane joint-venture projects in Romania and China. UGI is exempt from registration as a holding company and is not otherwise subject to regulation under the Public Utility Holding Company Act of 1935 except for acquisitions under Section 9(a)(2). UGI is not subject to regulation by the Pennsylvania Public Utility Commission ("PUC"). 30 19 CONSOLIDATION PRINCIPLES. Our consolidated financial statements include the accounts of UGI and its majority-owned subsidiaries. We eliminate all significant intercompany accounts and transactions when we consolidate. We report the public unitholders' interest in AmeriGas Partners as minority interest in the consolidated financial statements. The Company's investments in international propane joint-venture projects are accounted for by the equity method. Such investments did not materially impact the Company's results of operations for the periods presented. RECLASSIFICATIONS. We have reclassified certain prior-period balances to conform with the current period presentation. 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 are subject to regulation by the PUC. We account for all of our regulated Gas Utility and Electric Utility operations 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 the Company to record the financial statement effects of the rate regulation to which such operations are currently subject. 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. In June 1998, the PUC approved Electric Utility's restructuring plan which we submitted pursuant to Pennsylvania's Electricity Customer Choice Act ("Electricity Customer Choice Act"). In accordance with the Financial Accounting Standards Board's ("FASB's") Emerging Issues Task Force ("EITF") Statement No. 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements 71 and 101" ("EITF 97-4"), we discontinued the application of SFAS 71 as it related to the electric generation portion of Electric Utility's business in June 1998. This discontinuance of SFAS 71 did not have a material effect on our financial position or results of 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 Electricity Customer Choice Act and the Gas Competition Act, see Note 2. DERIVATIVE INSTRUMENTS. We use derivative instruments, including futures contracts, price swap agreements and option contracts, to hedge exposure to market risk associated with (1) fluctuations in the price of forecasted purchases of natural gas Energy Services sells under firm commitments and (2) fluctuations in propane prices associated with a portion of our anticipated propane purchases. On occasion we enter into interest rate protection agreements to reduce interest rate risk associated with anticipated issuances of debt. In addition, we occasionally utilize a managed program of derivative instruments including natural gas and oil futures contracts to preserve gross margin associated with certain of the Company's natural gas customers, which margin otherwise could be affected by major energy commodity price movements. We defer gains or losses on futures contracts associated with forecasted purchases of natural gas and record them in cost of sales when such purchases affect earnings. We recognize gains or losses on derivative instruments associated with forecasted purchases of propane or issuances of debt when such transactions affect earnings. When it is probable that the original forecasted transaction will not occur, we immediately recognize in earnings any gain or loss on the related derivative instrument. If such derivative instrument is terminated early for other economic reasons, we defer any gain or loss as of the termination date until such time as the forecasted transaction affects earnings. 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 $96.9 million in 2000, $84.6 million in 1999, and $83.5 million in 1998. We paid income taxes totaling $26.6 million in 2000, $36.2 million in 1999, and $29.8 million in 1998. REVENUE RECOGNITION. We recognize revenues from the sale of propane and related equipment and supplies principally when shipped or delivered to customers. We record Utilities' revenues for service provided to the end of each month. We reflect Utilities' rate increases or decreases in revenues from effective dates permitted by the PUC. Energy Services records revenues when product is delivered to customers. See "Accounting Principles Not Yet Adopted" below. INVENTORIES AND PREPAID PROPANE PURCHASES. Our inventories are stated at the lower of cost or market. We determine cost principally on an average or first-in, first-out ("FIFO") method except for appliances for which we use the specific identification method. From time to time the Partnership enters into contracts with certain suppliers requiring it to prepay all or a portion of the purchase price of a fixed volume of propane for future delivery. These prepayments are included in prepaid expenses and other current assets in the Consolidated Balance Sheets. 31 20 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) EARNINGS PER COMMON SHARE. Basic earnings per share are based on the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and awards. In the following table, we present the shares used in computing basic and diluted earnings per share for 2000, 1999 and 1998:
2000 1999 1998 ------ ------ ------ Denominator (millions of shares): Average common shares outstanding for basic computation 27.219 31.954 32.971 Incremental shares issuable for stock options and awards .036 .062 .152 ------ ------ ------ Average common shares outstanding for diluted computation 27.255 32.016 33.123 ------ ------ ------
INCOME TAXES. AmeriGas Partners and the Operating Partnership are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on our share of (1) the Partnership's current taxable income or loss and (2) the difference between the book and tax basis of the Partnership's assets and liabilities. The Operating Partnership does, however, have subsidiaries which operate in corporate form and are directly subject to federal income taxes. UGI Utilities' regulated operations 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. UGI Utilities also records a deferred tax liability for tax benefits that are flowed through to ratepayers when temporary differences originate and establishes 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 UGI Utilities' plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION. We record property, plant and equipment at cost. The amounts we assign to property, plant and equipment of businesses we acquire are based upon estimated fair value at date of acquisition. When we retire Utilities' plant, we charge its original cost and the net cost of its removal to accumulated depreciation for financial accounting purposes. When we retire or dispose of other plant and equipment, we remove from the accounts the cost and accumulated depreciation and include in income any gains or losses. We record depreciation expense for Utilities' plant 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 2.6% in 2000, and 2.7% in 1999 and 1998. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 3.5% in 2000, and 3.2% in 1999 and 1998. We compute depreciation expense on plant and equipment associated with our propane operations using the straight-line method over estimated service lives generally ranging from 15 to 40 years for buildings and improvements; 7 to 30 years for storage and customer tanks and cylinders; and 5 to 10 years for vehicles, equipment and office furniture and fixtures. Depreciation expense was $69.3 million in 2000, $63.6 million in 1999, and $61.4 million in 1998. INTANGIBLE ASSETS. Intangible assets comprise the following at September 30:
2000 1999 ------ ------ Goodwill (less accumulated amortization of $126.6 million and $109.8 million, respectively) $566.8 $538.4 Excess reorganization value (less accumulated amortization of $60.2 million and $52.3 million, respectively) 101.3 109.2 Other (less accumulated amortization of $3.4 million and $3.8 million, respectively) 7.4 5.5 ------ ------ Total intangible assets $675.5 $653.1 ====== ======
Substantially all of our goodwill is a result of propane purchase business combinations. This goodwill is amortized on a straight-line basis over 40 years. We amortize excess reorganization value (resulting from Petrolane's July 15, 1993 reorganization under Chapter 11 of the U.S. Bankruptcy Code) on a straight-line basis over 20 years. We amortize other intangible assets over the estimated periods of benefit which do not exceed ten years. Amortization expense of intangible assets was $26.5 million in 2000, $24.3 million in 1999, and $24.9 million in 1998. We evaluate the impairment of long-lived assets, including intangibles, 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. STOCK-BASED COMPENSATION. As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), we apply the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"), in recording compensation expense for grants of stock, stock options, and other equity instruments to employees. 32 21 UGI Corporation 2000 Annual Report OTHER ASSETS. Included in other assets are net deferred debt issuance costs of $10.8 million at September 30, 2000 and $10.9 million at September 30, 1999. We are amortizing these costs over the term of the related debt. COMPUTER SOFTWARE COSTS. Prior to October 1, 1999, we included in property, plant and equipment external and incremental internal costs associated with computer software we developed or obtained for use in our businesses. Effective October 1, 1999, we adopted Statement of Position No. 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use" ("SOP 98-1"), which requires companies to capitalize the cost of computer software, including nonincremental internal costs, once certain criteria have been met. We amortize computer software costs on a straight-line basis over periods of three to seven years once the installed software is ready for its intended use. The adoption of SOP 98-1 did not have a material effect on our financial position or results of operations. DEFERRED FUEL COSTS. Gas Utility's tariffs contain clauses which permit recovery of certain purchased gas costs ("PGCs") in excess of the level of such costs included in base rates. The clauses provide for a periodic adjustment for the difference between the total amount collected from customers under each clause and the recoverable costs incurred. 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. FOREIGN CURRENCY TRANSLATION. Financial statements of international subsidiaries are translated into U.S. dollars using the exchange rate at each balance sheet date for assets and liabilities and a weighted-average exchange rate for each period for revenues and expenses. Where the local currency is the functional currency, translation adjustments are recorded in accumulated other comprehensive income. Where the local currency is not the functional currency, translation adjustments are recorded in net income. Currency adjustments did not materially impact the Company's results of operations or accumulated comprehensive income in 2000, 1999 or 1998. COMPREHENSIVE INCOME. Our comprehensive income principally includes net earnings or loss and unrealized gains or losses on available for sale securities. In 1998, our comprehensive income was the same as our net income. The net changes in accumulated comprehensive income in 1999 and 2000, which resulted principally from changes in unrealized gains on securities, is reflected net of income taxes of $0.3 million. ACCOUNTING PRINCIPLES NOT YET ADOPTED. In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 was amended in June 2000 by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" ("SFAS 138") which addressed a limited number of issues causing implementation difficulties. SFAS 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that an entity recognize all derivative instruments as either assets or liabilities and measure them 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 derivative instruments qualify and are designated as hedges of the variability in cash flows associated with forecasted transactions, the effective portion of the gain or loss on such derivative instruments will generally be reported in other comprehensive income and the ineffective portion, if any, will be reported in net income. Such amounts recorded in accumulated other comprehensive income will be reclassified into net income when the forecasted transaction affects earnings. 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, the gain or loss on the hedging instrument will be recognized currently in earnings along with changes in the fair value of the hedged asset, liability or firm commitment attributable to the hedged risk. The Company was required to adopt the provisions of SFAS 133 effective October 1, 2000. Virtually all of the Company's derivative instruments outstanding as of October 1, 2000 qualify and have been designated as hedging the variability in cash flows associated with forecasted transactions. The adoption of SFAS 133 will result in an after-tax cumulative effect charge to net income of $0.3 million and an after-tax cumulative effect increase to accumulated other comprehensive income of $7.1 million. Because the Company's derivative instruments historically have been highly effective in hedging the exposure to changes in cash flows associated with forecasted purchases or sales of natural gas and propane, changes in the fair value of propane inventories, and changes in the risk-free rate of interest on anticipated issuances of long-term debt, we do not expect the adoption of SFAS 133 to have a material impact on our future results of operations. Although the Company expects the derivative instruments it currently uses to hedge to continue to be highly effective, if they are deemed not highly effective in the future, or if the Company uses 33 22 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) derivative instruments that do not meet the stringent requirements for hedge accounting under SFAS 133, our future earnings could reflect greater volatility. Additionally, if a cash flow hedge is discontinued because the original forecasted transaction is no longer expected to occur, any gain or loss in accumulated comprehensive income associated with the hedged transaction will be immediately recognized in net income. In order to comply with the provisions of the Securities and Exchange Commission Staff Accounting Bulletin No. 101 entitled "Revenue Recognition" ("SAB 101"), which is effective for the Company on October 1, 2000, the Company will record a cumulative effect charge to net income of approximately $2.3 million related to the Partnership's method of recognizing revenue associated with nonrefundable tank fees largely for residential customers. Consistent with a number of its competitors in the propane industry, the Partnership receives nonrefundable fees for installed Partnership-owned tanks. Historically, such fees, which are generally received annually, were recorded as revenue when billed. In accordance with SAB 101, effective October 1, 2000, the Partnership will record such nonrefundable fees on a straight-line basis over one year. The adoption of SAB 101 is not expected to have a material impact on the Company's future financial condition or results of operations. Also, during fiscal 2001, the Partnership plans to change its method of accounting for tank installation costs which are not billed to customers. Currently, all direct costs to install Partnership-owned tanks at a customer location are expensed as incurred. The Partnership believes that these costs should now be capitalized and amortized over the period benefited. On date of adoption, this change in accounting method will result in a cumulative effect increase to net income. The Company is in the process of evaluating the impact of such change on its financial condition and results of operations. NOTE 2 -UTILITY REGULATORY MATTERS 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 Customer Choice Act. Under the terms of the Electricity Restructuring Order, commencing January 1, 1999, Electric Utility is authorized to recover $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 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 include $8.7 million 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 Customer Choice Act, Electric Utility's rates for transmission and distribution services are capped through July 1, 2001. In addition, Electric Utility generally may not increase the generation component of prices as long as stranded costs are being recovered through the CTC. This generation rate cap is expected to extend through December 31, 2002. Since January 1, 1999, all of Electric Utility's customers have been permitted to select an alternative generation supplier. Customers choosing an alternative supplier receive a "shopping credit." As permitted by the Electricity Restructuring Order, on October 1, 1999, Electric Utility transferred its electric generation assets to its wholly owned nonregulated subsidiary, UGI Development Company ("UGIDC"). In June 1998, Electric Utility discontinued the application of SFAS 71 as it relates to the electric generation portion of its business, which assets comprise less than 15% of Electric Utility's total assets. The discontinuance of SFAS 71 did not have a material effect on our financial position or results of operations. NATURAL 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") 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. As of January 1, 2000, the Gas Competition Act, in conjunction with a companion bill, eliminated the gross receipts tax on sales of gas. Generally, 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. LDCs are generally precluded from increasing rates for the recovery of costs, other than gas costs, until January 1, 2001. 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 assignment. The PUC, however, may only grant the petition if certain findings are made and the LDC fully recovers the cost of contracts. On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas Utility's restructuring plan substantially as filed. Among other things, the restructuring plan (1) provides for the recovery of costs associated with existing pipeline capacity and supply contracts; (2) increases Gas Utility's base rates for firm customers; and (3) changes the calculation of PGC rates. The effect of (2) and 34 23 UGI Corporation 2000 Annual Report (3) above is to reduce the financial impact of volatility in revenues from customers who have the ability to switch to an alternate fuel under interruptible rates and increase our sensitivity to changes in weather. Because the Gas Competition Act requires alternate suppliers to accept assignment of a portion of the LDC's pipeline capacity and storage contracts, we do not believe the Gas Competition Act and the Gas Restructuring Order will have a material adverse impact on our financial condition or results of operations. REGULATORY ASSETS AND LIABILITIES. The following regulatory assets and liabilities are included in our accompanying balance sheets at September 30:
2000 1999 - --------------------------------------------------------------- Regulatory assets: Income taxes recoverable $47.7 $46.9 Power agreement buy-out 3.5 6.8 Other postretirement benefits 2.9 3.1 Deferred fuel costs 7.2 3.4 Other 1.0 0.9 - --------------------------------------------------------------- Total regulatory assets $62.3 $61.1 - --------------------------------------------------------------- Regulatory liabilities: Other postretirement benefits $ 4.0 $2.8 Refundable state taxes -- 1.0 - --------------------------------------------------------------- Total regulatory liabilities $ 4.0 $3.8 - ---------------------------------------------------------------
NOTE 3 - DEBT Long-term debt comprises the following at September 30:
2000 1999 - ----------------------------------------------------------------------------------- AmeriGas Propane: AmeriGas Partners Senior Notes, 10.125%, due April 2007 $ 100.0 $ 100.0 Operating Partnership First Mortgage Notes: Series A, 9.34%-11.71%, due April 2000 through April 2009 (including unamortized premium of $10.6 and $12.1, respectively, calculated at an 8.91% effective rate) 208.6 220.1 Series B, 10.07%, due April 2001 through April 2005 (including unamortized premium of $5.9 and $8.0, respectively, calculated at an 8.74% effective rate) 205.9 208.0 Series C, 8.83%, due April 2003 through April 2010 110.0 110.0 Series D, 7.11%, due March 2009 (including unamortized premium of $2.7 and $2.9, respectively, calculated at a 6.52% effective rate) 72.7 72.9 Series E, 8.50%, due July 2010 (including unamortized premium of $0.2 calculated at an 8.47% effective rate) 80.2 -- Operating Partnership Acquisition Facility 70.0 23.0 Other 9.8 10.7 - ----------------------------------------------------------------------------------- Total AmeriGas Propane 857.2 744.7 - ----------------------------------------------------------------------------------- UGI Utilities: Medium-Term Notes: 7.25% Notes, due November 2017 20.0 20.0 7.17% Notes, due June 2007 20.0 20.0 6.17% Notes, due March 2001 15.0 15.0 7.37% Notes, due October 2015 22.0 22.0 6.73% Notes, due October 2002 26.0 26.0 6.62% Notes, due May 2005 20.0 20.0 6.50% Senior Notes, due August 2003 (less unamortized discount of $0.1) 49.9 49.9 9.71% Notes, due September 2000 -- 7.1 - ----------------------------------------------------------------------------------- Total UGI Utilities 172.9 180.0 - ----------------------------------------------------------------------------------- Other: FLAGA EURO note, due September 2001 through September 2006 65.5 77.0 FLAGA Austrian shilling debt -- 6.8 FLAGA EURO special purpose facility 11.9 -- Other 8.1 7.8 - ----------------------------------------------------------------------------------- Total long-term debt 1,115.6 1,016.3 Less current maturities (85.9) (26.7) - ----------------------------------------------------------------------------------- Total long-term debt due after one year $1,029.7 $ 989.6 - -----------------------------------------------------------------------------------
35 24 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Long-term debt due in fiscal years 2001 to 2005 follows:
2001 2002 2003 2004 2005 - --------------------------------------------------------------- AmeriGas Propane $64.5 $66.5 $60.0 $56.7 $56.2 UGI Utilities 15.0 -- 76.0 -- 20.0 Other 6.4 10.8 16.6 9.9 15.7 - --------------------------------------------------------------- Total $85.9 $77.3 $152.6 $66.6 $91.9 - ---------------------------------------------------------------
AMERIGAS PROPANE AMERIGAS PARTNERS SENIOR NOTES. The 10.125% Senior Notes of AmeriGas Partners are redeemable prior to their maturity date. A redemption premium applies until April 15, 2004. In addition, AmeriGas Partners may, under certain circumstances following the disposition of assets or a change of control, be required to offer to prepay the Senior Notes. OPERATING PARTNERSHIP FIRST MORTGAGE NOTES. The Operating Partnership's First Mortgage Notes are collateralized by substantially all of its assets. The General Partner and its wholly owned subsidiary Petrolane are co-obligors of the Series A, B, and C First Mortgage Notes, and the General Partner is co-obligor of the Series D and E First Mortgage Notes. The Operating Partnership may prepay the First Mortgage Notes, in whole or in part. These prepayments include a make whole premium. Following the disposition of assets or a change of control, the Operating Partnership may be required to offer to prepay the First Mortgage Notes, in whole or in part. OPERATING PARTNERSHIP BANK CREDIT AGREEMENT. The Operating Partnership's Bank Credit Agreement consists of a Revolving Credit Facility and an Acquisition Facility. The Operating Partnership's obligations under the Bank Credit Agreement are collateralized by substantially all of its assets. The General Partner and Petrolane are co-obligors of amounts outstanding under the Bank Credit Agreement. Under the Revolving Credit Facility, the Operating Partnership may borrow up to $100 million (including a $35 million sublimit for letters of credit) subject to restrictions in the 10.125% Senior Notes of AmeriGas Partners (see "Restrictive Covenants" below). The Revolving Credit Facility expires September 15, 2002, but may be extended for additional one-year periods with the consent of the participating banks representing at least 80% of the commitments thereunder. The Revolving Credit Facility permits the Operating Partnership to borrow at various prevailing interest rates, including the Base Rate, defined as the higher of the Federal Funds Rate plus 0.50% or the agent bank's reference rate (9.50% at September 30, 2000), or at two-week, one-, two-, three-, or six-month offshore interbank offering rates ("IBOR"), plus a margin. The margin on IBOR borrowings (which ranges from 0.50% to 1.75%) and the Revolving Credit Facility commitment fee rate are dependent upon the Operating Partnership's ratio of funded debt to earnings before interest expense, income taxes, depreciation and amortization ("EBITDA"), each as defined in the Bank Credit Agreement. The Operating Partnership had borrowings under the Revolving Credit Facility totaling $30 million at September 30, 2000 and $22 million at September 30, 1999, which we classify as bank loans. The weighted-average interest rates on the bank loans outstanding were 8.11% as of September 30, 2000 and 6.26% as of September 30, 1999. Issued outstanding letters of credit under the Revolving Credit Facility totaled $1.5 million at September 30, 2000 and $5.9 million at September 30, 1999. The Acquisition Facility provides the Operating Partnership with the ability to borrow up to $75 million to finance the purchase of propane businesses or propane business assets. The Acquisition Facility operates as a revolving facility through September 15, 2002, at which time amounts then outstanding will be immediately due and payable. The Acquisition Facility permits the Operating Partnership to borrow at the Base Rate or at two-week, one-, two-, three-, or six-month IBOR, plus a margin. The margin on IBOR borrowings and the Acquisition Facility commitment fee rate are dependent upon the Operating Partnership's ratio of funded debt to EBITDA, as defined. The weighted-average interest rates on Acquisition Facility loans outstanding were 8.12% as of September 30, 2000 and 6.02% as of September 30, 1999. GENERAL PARTNER FACILITY. The Operating Partnership also has a revolving credit agreement with the General Partner under which it may borrow up to $20 million to fund working capital, capital expenditures, and interest and Partnership distribution payments. This agreement is coterminous with, and generally comparable to, the Operating Partnership's Revolving Credit Facility except that borrowings under the General Partner Facility are unsecured and subordinated to all senior debt of the Partnership. Interest rates on borrowings are based upon one-month IBOR. Commitment fees are determined in the same manner as fees under the Revolving Credit Facility. UGI has agreed to contribute up to $20 million to the General Partner to fund such borrowings. RESTRICTIVE COVENANTS. The 10.125% Senior Notes of AmeriGas Partners restrict the ability of the Partnership to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets. Under the Senior Notes Indenture, AmeriGas Partners is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. These conditions include: 1. no event of default exists or would exist upon making such distributions and 2. the Partnership's consolidated fixed charge coverage ratio, as defined, is greater than 1.75-to-1. 36 25 UGI Corporation 2000 Annual Report If the ratio in item 2 above is less than or equal to 1.75-to-1, the Partnership may make cash distributions in a total amount not to exceed $24 million less the total amount of distributions made during the immediately preceding 16 fiscal quarters. At September 30, 2000, such ratio was 2.14-to-1. The Bank Credit Agreement and the First Mortgage Notes restrict the incurrence of additional indebtedness and also restrict certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, sales of assets and other transactions. They also require the ratio of total indebtedness, as defined, to EBITDA, as defined (calculated on a rolling four-quarter basis or eight-quarter basis divided by two), to be less than or equal to 5.25-to-1. In addition, the Bank Credit Agreement requires that the Operating Partnership maintain a ratio of EBITDA to interest expense, as defined, of at least 2.25-to-1 on a rolling four-quarter basis. Generally, as long as no default exists or would result, the Operating Partnership is permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter. At September 30, 2000, the Partnership was in compliance with its financial covenants. UGI UTILITIES REVOLVING CREDIT AGREEMENTS. At September 30, 2000, UGI Utilities had revolving credit agreements with four banks providing for borrowings of up to $122 million through June 2003. 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 $100.4 million at September 30, 2000 and $87.4 million at September 30, 1999, which we classify as bank loans. The weighted-average interest rates on UGI Utilities bank loans were 7.12% at September 30, 2000 and 5.90% at September 30, 1999. RESTRICTIVE COVENANTS. UGI Utilities' credit agreements have restrictions on such items as total debt, working capital, debt service, and payments for investments. They also require consolidated tangible net worth of at least $125 million. At September 30, 2000, UGI Utilities was in compliance with its financial covenants. OTHER FLAGA's EURO note bears interest at a rate of 1.25% over one- to twelve-month EURIBOR rates (as chosen by the Company from time to time). The effective interest rates on the EURO note at September 30, 2000 and September 30, 1999 were 5.71% and 5.00%, respectively. On or after September 10, 2003, the Company may prepay the EURO note, in whole or in part. Prior to March 11, 2005, such prepayments shall be at a premium. FLAGA has EURO loan commitments from a foreign bank in the form of (1) a 15 million EURO special purpose facility and (2) a 9 million EURO working capital facility. Borrowings under the FLAGA special purpose facility can be used to repay certain debt obligations of FLAGA existing at the acquisition date and for general business purposes. The working capital facility expires September 28, 2001, but may be extended for an additional three-year period with the bank's consent. Loans under the special purpose facility and the working capital facility bear interest at market rates. The weighted-average interest rates on FLAGA's working capital facility and special purpose facility at September 30, 2000 were 5.78% and 5.25%, respectively. Borrowings under the EURO working capital facility at September 30, 2000, and FLAGA's now terminated Swiss franc denominated bank loan facility at September 30, 1999, totaled $4.3 million and $11.6 million, respectively. The FLAGA EURO note, special purpose facility and the working capital facility are subject to guarantees of UGI. In addition, under certain conditions regarding changes in the credit rating of UGI Utilities' long-term debt, the lending bank may require UGI to grant additional security or may accelerate repayment of the debt prior to its scheduled maturity. NOTE 4 -- INCOME TAXES Income before income taxes comprises the following:
2000 1999 1998 - ---------------------------------------------------------------- Domestic $93.4 $100.5 $76.9 Foreign (7.0) -- -- - ---------------------------------------------------------------- Total income before income taxes $86.4 $100.5 $76.9 - ----------------------------------------------------------------
The provisions for income taxes consist of the following:
2000 1999 1998 - ---------------------------------------------------------------- Current: Federal $28.6 $29.2 $19.6 State 8.3 6.3 4.7 - ---------------------------------------------------------------- Total current 36.9 35.5 24.3 Deferred: Federal 5.7 6.8 10.0 State (0.2) 1.3 0.5 Foreign (1.9) -- -- Investment tax credit amortization (0.4) (0.4) (0.4) - ---------------------------------------------------------------- Total deferred 3.2 7.7 10.1 - ---------------------------------------------------------------- Total income tax expense $40.1 $43.2 $34.4 - ----------------------------------------------------------------
37 26 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) A reconciliation from the statutory federal tax rate to our effective tax rate is as follows:
2000 1999 1998 - ----------------------------------------------------------------------------------- Statutory federal tax rate 35.0% 35.0% 35.0% Difference in tax rate due to: State income taxes, net of federal benefit 7.5 5.2 6.1 Nondeductible amortization of goodwill 5.8 4.6 6.2 Other, net (1.9) (1.8) (2.6) - ----------------------------------------------------------------------------------- Effective tax rate 46.4% 43.0% 44.7% - -----------------------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September 30:
2000 1999 - ------------------------------------------------------------------------------------------ Excess book basis over tax basis of property, plant and equipment $ 172.5 $ 177.0 Regulatory assets 25.6 25.3 Other 13.7 10.1 - ------------------------------------------------------------------------------------------ Gross deferred tax liabilities 211.8 212.4 - ------------------------------------------------------------------------------------------ Self-insured property and casualty liability (8.2) (8.6) Employee-related benefits (12.0) (12.3) Premium on long-term debt (4.4) (5.2) Deferred investment tax credits (3.8) (4.0) Power purchase agreement liability (2.2) (3.2) Operating loss carryforwards (8.3) (4.2) Allowance for doubtful accounts (2.6) (2.5) Other (11.1) (13.8) - ------------------------------------------------------------------------------------------ Gross deferred tax assets (52.6) (53.8) - ------------------------------------------------------------------------------------------ Deferred tax assets valuation allowance 1.9 2.0 - ------------------------------------------------------------------------------------------ Net deferred tax liabilities $ 161.1 $ 160.6 - ------------------------------------------------------------------------------------------
UGI Utilities had recorded deferred tax liabilities of approximately $31.7 million as of September 30, 2000 and $31.4 million as of September 30, 1999 pertaining to utility temporary differences, principally 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 $3.8 million at September 30, 2000 and $4.0 million at September 30, 1999, pertaining to utility deferred investment tax credits. UGI Utilities had recorded a regulatory income tax asset related to these net deferred taxes of $47.7 million as of September 30, 2000 and $46.9 million as of September 30, 1999. This regulatory income tax asset represents 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. At September 30, 2000, the amount of federal operating loss carryforwards which were generated by a domestic subsidiary prior to its acquisition totaled $5.2 million. These operating loss carryforwards expire through the year 2010. The use of pre-acquisition operating loss carryforwards is subject to Internal Revenue Code limitations. We do not believe these limitations will affect our ability to utilize these carryforwards prior to their expiration. Foreign operating loss carryforwards of FLAGA totaled approximately $19.0 million at September 30, 2000. Approximately $3.0 million of these operating loss carryforwards expire through 2005. The remaining approximately $16.0 million have no expiration date. The tax benefit of these foreign operating loss carryforwards of $6.4 million has been reduced by a valuation allowance of $1.7 million due to the uncertainty of realizing certain of these operating loss carryforwards. NOTE 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. The following provides a reconciliation of benefit obligations, plan assets, and funded status of the plans as of September 30:
Other Pension Postretirement Benefits Benefits --------------------- --------------------- 2000 1999 2000 1999 - ---------------------------------------------------------------------------------------------------- CHANGE IN BENEFIT OBLIGATIONS: Benefit obligations - beginning of year $ 149.5 $ 164.8 $ 16.8 $ 16.9 Service cost 3.2 3.8 0.1 0.1 Interest cost 11.8 11.2 1.4 1.2 Actuarial (gain) loss (4.4) (21.4) 3.0 (0.2) Benefits paid (9.2) (8.9) (1.6) (1.2) - ---------------------------------------------------------------------------------------------------- Benefit obligations - end of year $ 150.9 $ 149.5 $ 19.7 $ 16.8 - ---------------------------------------------------------------------------------------------------- CHANGE IN PLAN ASSETS: Fair value of plan assets - beginning of year $ 202.1 $ 183.3 $ 4.9 $ 4.9 Actual return on plan assets 30.6 27.7 0.3 0.2 Employer contributions -- -- 2.2 1.0 Benefits paid (9.2) (8.9) (1.0) (1.2) - ---------------------------------------------------------------------------------------------------- Fair value of plan assets - end of year $ 223.5 $ 202.1 $ 6.4 $ 4.9 - ---------------------------------------------------------------------------------------------------- Funded status of the plans $ 72.6 $ 52.6 $ (13.3) $ (11.9) Unrecognized net actuarial gain (54.8) (36.8) (3.0) (5.8) Unrecognized prior service cost 4.0 4.7 -- -- Unrecognized net transition (asset) obligation (6.3) (7.9) 10.5 11.4 - ---------------------------------------------------------------------------------------------------- Prepaid (accrued) benefit cost - end of year $ 15.5 $ 12.6 $ (5.8) $ (6.3) - ---------------------------------------------------------------------------------------------------- ASSUMPTIONS AS OF SEPTEMBER 30: Discount rate 8.2% 7.8% 8.2% 7.8% 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 - ----------------------------------------------------------------------------------------------------
38 27 UGI Corporation 2000 Annual Report Net periodic pension income and other postretirement benefit costs include the following components:
Pension Other Benefits Postretirement Benefits --------------------------------- --------------------------------- 2000 1999 1998 2000 1999 1998 - ------------------------------------------------------------------------------------------------------ Service cost $ 3.2 $ 3.8 $ 3.4 $ 0.1 $ 0.1 $ 0.1 Interest cost 11.8 11.2 10.9 1.4 1.2 1.2 Expected return on assets (17.0) (16.3) (15.2) (0.3) (0.2) (0.2) Amortization of: Transition (asset) obligation (1.6) (1.6) (1.6) 0.9 0.9 0.9 Prior service cost 0.6 0.6 0.6 -- -- -- Actuarial (gain) loss -- -- -- (0.2) (0.2) (0.3) - ------------------------------------------------------------------------------------------------------ Net postretirement cost (income) (3.0) (2.3) (1.9) 1.9 1.8 1.7 Change in regulatory assets & liabilities -- -- -- 1.4 1.7 1.9 - ------------------------------------------------------------------------------------------------------ Net expense (income) $ (3.0) $ (2.3) $ (1.9) $ 3.3 $ 3.5 $ 3.6 - ------------------------------------------------------------------------------------------------------
Pension plan assets are held in trust and consist principally of equity and fixed income mutual funds and investment grade corporate and U.S. government obligations. UGI Common Stock comprises less than 2% of trust assets at September 30, 2000. Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary Employee Benefit Trust ("VEBA") 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 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 10% for fiscal 2001, decreasing to 5.5% in fiscal 2005. A one percentage point change in the assumed health care cost trend rate would change the 2000 postretirement benefit cost and obligation as follows:
1% 1% Increase Decrease - ---------------------------------------------------------------------- Effect on total service and interest costs $0.1 $(0.1) Effect on postretirement benefit obligation $1.1 $(1.1) - ----------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key employees. At September 30, 2000 and 1999, the projected benefit obligations of these plans were not material. We recorded expense for these plans of $0.9 million in 2000, $1.6 million in 1999, and $2.4 million in 1998. DEFINED CONTRIBUTION PLANS We sponsor a 401(k) savings plan for eligible employees of UGI, UGI Utilities, and certain of UGI's other wholly owned subsidiaries ("UGI Utilities Savings Plan"). Generally, participants in the UGI Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. We may, at our discretion, match a portion of participants' contributions. We also sponsor a 401(k) savings plan for eligible employees of the General Partner ("AmeriGas Propane Savings Plan"). Participants in the AmeriGas Propane Savings Plan may contribute a portion of their compensation on a before-tax basis. We match employee contributions to the AmeriGas Propane Savings Plan on a dollar-for-dollar basis up to 5% of eligible compensation. The cost of benefits under the savings plans totaled $5.9 million in 2000, $4.8 million in 1999, and $5.1 million in 1998. NOTE 6 -- INVENTORIES Inventories comprise the following at September 30:
2000 1999 - ---------------------------------------------------------------- Propane gas $ 47.3 $38.1 Utility fuel and gases 33.6 24.5 Materials, supplies and other 36.5 24.5 - ---------------------------------------------------------------- Total inventories $117.4 $87.1 - ----------------------------------------------------------------
NOTE 7 -- SERIES PREFERRED STOCK The UGI Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, has 5,000,000 shares authorized for issuance. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2000 or 1999. UGI Utilities 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 UGI Utilities Series Preferred Stock have the right to elect a majority of UGI Utilities' 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 UGI Utilities Series Preferred Stock. At September 30, 2000 and 1999, UGI Utilities had outstanding 200,000 shares of $7.75 Series cumulative preferred stock. UGI Utilities is required to establish a sinking fund to redeem on October 1 in each year, commencing October 1, 2004, 10,000 shares of its $7.75 Series at a price of $100 per share. The $7.75 Series is redeemable, in whole or in part, at the option of UGI Utilities on or after October 1, 2004, at a price of $100 per share. All outstanding shares of $7.75 Series Preferred Stock are subject to mandatory redemption on October 1, 2009, at a price of $100 per share. 39 28 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) NOTE 8 -- COMMON STOCK AND INCENTIVE STOCK AWARD PLANS On September 7, 1999, pursuant to strategic and financial initiatives announced on July 28, 1999, we repurchased 4.5 million shares of Common Stock through a "Dutch auction" tender offer for $109.1 million, or $24.25 per share. The repurchased shares are held in treasury. In addition, during 1999, in conjunction with the Company's proposed merger with Unisource (see Note 14), we purchased 1.4 million shares of Common Stock for $23.2 million. Common Stock share activity for 1998, 1999 and 2000 follows:
Issued Treasury Outstanding ====================================================================================== Balance September 30, 1997 33,198,731 (336,715) 32,862,016 Issued: Employee and director plans -- 243,915 243,915 Dividend reinvestment plan -- 108,353 108,353 Acquisitions -- 42,078 42,078 Reacquired -- (433,100) (433,100) - ------------------------------------------------------------------------------------- Balance September 30, 1998 33,198,731 (375,469) 32,823,262 Issued: Employee and director plans -- 175,040 175,040 Dividend reinvestment plan -- 136,587 136,587 Reacquired -- (5,864,496) (5,864,496) - ------------------------------------------------------------------------------------- Balance September 30, 1999 33,198,731 (5,928,338) 27,270,393 Issued: Employee and director plans -- 62,525 62,525 Dividend reinvestment plan -- 114,430 114,430 Reacquired -- (453,639) (453,639) - ------------------------------------------------------------------------------------- Balance September 30, 2000 33,198,731 (6,205,022) 26,993,709 - -------------------------------------------------------------------------------------
STOCK OPTION PLANS Under UGI's current employee stock option and incentive plans, we may grant options to acquire shares of Common Stock, or issue shares of restricted stock, to key employees. The exercise price for options granted under all plans may not be less than the fair market value on the grant date. Grants of stock options or restricted stock under these plans may vest immediately, or ratably over a period of years, and stock options generally can be exercised no later than ten years from the grant date. Under the 2000 Stock Incentive Plan ("2000 Incentive Plan"), up to 1,100,000 shares of Common Stock may be issued in connection with stock options and grants of restricted stock. However, no more than 500,000 shares of restricted stock may be granted. In addition, the 2000 Incentive Plan provides that both option grants and restricted stock grants may provide for the crediting of Common Stock dividend equivalents to participants' accounts. Dividend equivalents will be paid in cash, and such payments may, at the participants' request, be deferred. Grants of restricted stock will be contingent upon the achievement of objective performance goals. At September 30, 2000, no grants have been made under the 2000 Incentive Plan. Under the 1997 Stock Option and Dividend Equivalent Plan ("1997 SODEP Plan"), we may grant options to acquire a total of 1,500,000 shares of Common Stock. Certain option grants under the 1997 SODEP Plan provided for the crediting of dividend equivalents subject to the Company's total shareholder return relative to a peer group of companies during the three-year period ended December 31, 1999. Based upon such performance, no dividend equivalent payments were made. Under the 1992 Non-Qualified Stock Option Plan, we may grant options to acquire a total of 500,000 shares of Common Stock to key employees who do not participate in the 2000 Incentive Plan or the 1997 SODEP Plan. In addition to these employee incentive plans, the Company may grant options to acquire up to a total of 200,000 shares of Common Stock to each of the Company's nonemployee Directors. No Director may be granted options to acquire more than 10,000 shares of Common Stock in any calendar year, and the exercise price may not be less than the fair market value of the Common Stock on the grant date. Generally all options will be fully vested on the grant date and exercisable only while the participant is a Director. Stock option transactions under all of our plans for 1998, 1999 and 2000 follow:
Shares Average Option Price ================================================================================ Shares under option - September 30, 1997 1,175,001 $21.670 - ------------------------------------------------------------------------- Granted 54,583 22.469 Exercised (198,121) 20.650 Forfeited (1,708) 23.962 - ------------------------------------------------------------------------- Shares under option - September 30, 1998 1,029,755 21.905 - ------------------------------------------------------------------------- Granted 231,806 20.406 Exercised (27,250) 21.978 Forfeited (18,750) 21.152 - ------------------------------------------------------------------------- Shares under option - September 30, 1999 1,215,561 21.632 - ------------------------------------------------------------------------- Granted 794,750 20.683 Exercised (30,000) 22.625 Forfeited (96,667) 22.302 - ------------------------------------------------------------------------- Shares under option - September 30, 2000 1,883,644 21.181 - ------------------------------------------------------------------------- Options exercisable 1998 1,014,755 21.921 Options exercisable 1999 984,061 21.725 Options exercisable 2000 947,144 21.696 - -------------------------------------------------------------------------
For options outstanding as of September 30, 2000, the exercise prices range from $18.625 to $26.25. The weighted-average remaining contractual life of these options is 7.1 years. At September 30, 2000, 1,453,103 shares of Common Stock were available for future option grants under all of our stock option plans. OTHER STOCK-BASED COMPENSATION PLANS AND AWARDS On December 13, 1999, the General Partner adopted the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan ("2000 Propane Plan"). Under the 2000 Propane Plan, the General Partner may 40 29 UGI Corporation 2000 Annual Report grant to key employees the right to receive a total of 500,000 AmeriGas Partners Common Units, or cash generally equivalent to the fair market value of such Common Units, upon the achievement of objective performance goals. In addition, the 2000 Propane Plan provides that grants may provide for the crediting of Partnership distribution equivalents to participants' accounts. Distribution equivalents will be paid in cash, and such payment may, at the participant's request, be deferred. Generally, each grant, unless paid, will terminate when the participant ceases to be employed by the General Partner. At September 30, 2000, no grants have been made under the 2000 Propane Plan. Under the 1997 AmeriGas Propane, Inc. Long-Term Incentive Plan ("1997 Propane Plan"), the General Partner granted to key employees the right to receive AmeriGas Partners Common Units, or cash generally equivalent to their fair market value, on the payment date. The 1997 Propane Plan also provided for the crediting of dividend equivalents to participant's accounts. The actual number of Common Units (or their cash equivalent) awarded, and the amount of the distribution equivalent, depended upon the date when the cash generation-based requirements for early conversion of AmeriGas Partners Subordinated Units were met. Because such requirements were achieved at March 31, 1999, 81,226 Common Units were issued, and $1.1 million in cash payments were made, in May 1999. Under the 1997 UGI Corporation Directors' Equity Compensation Plan ("1997 Directors' Plan"), we make annual awards to our nonemployee Board Directors of (1) "Units," each representing an interest equivalent to one share of Common Stock, and (2) Common Stock for a portion of their annual retainer. Board Directors may also elect to receive the cash portion of their retainer fee and all or a portion of their meeting fees in the form of Units. The 1997 Directors' Plan also provides for the crediting of dividend equivalents in the form of additional Units. Units and dividend equivalents are fully vested when credited to a Director's account and will be converted to shares of Common Stock and paid upon retirement or termination of service. Units issued relating to annual awards and deferred compensation totaled 12,017, 9,137 and 7,043 in 2000, 1999 and 1998, respectively. At September 30, 2000 and 1999, there were 53,294 and 41,277 Units, respectively, outstanding. In June 1999, we awarded 103,000 shares of restricted stock to key executives. These awards vest four years from date of issuance but may vest earlier if certain Common Stock performance goals are met. Recipients have the right to vote the shares and to receive dividends during the restriction period. FAIR VALUE INFORMATION The per share weighted-average fair value of stock options granted under our option plans was $3.76 in 2000, $2.58 in 1999, and $1.98 in 1998. These amounts were determined using the Black-Scholes option pricing model, which values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments, and the risk-free interest rate over the expected life of the option. The assumptions we used for option grants during 2000, 1999 and 1998 are as follows:
2000 1999 1998 - --------------------------------------------------------------- Expected life of option 6 years 6 years 6 years Expected volatility 26.5% 19.3% 16.2% Expected dividend yield 6.2% 6.2% 6.0% Risk free interest rate 6.6% 5.9% 4.6% - ---------------------------------------------------------------
We use the intrinsic value method prescribed by APB 25 for our stock-based employee compensation plans. We recognized, under the provisions of APB 25, total stock-based compensation expense (income) of $(0.8) million in 2000, $1.9 million in 1999, and $1.0 million in 1998. Stock-based compensation income in 2000 reflects the reversal of $2.1 million of accrued dividend equivalent payments relating to the 1997 SODEP Plan. If we had determined compensation expense under the fair value method prescribed by SFAS 123, net income and diluted earnings per share for 2000, 1999 and 1998 would have been as follows:
2000 1999 1998 - --------------------------------------------------------------- Net earnings: As reported $44.7 $55.7 $40.3 Pro forma 44.2 55.3 40.2 Diluted earnings per share: As reported $1.64 $1.74 $1.22 Pro forma 1.62 1.73 1.21 - ---------------------------------------------------------------
STOCK OWNERSHIP POLICY The Company has a stock ownership policy ("Stock Ownership Policy") for executives and key employees. Under the terms of the Stock Ownership Policy, executives and certain key employees are required to own UGI Common Stock having a fair value equal to 40% to 450% of their base salaries. Participants have from three months to three years to comply with the Stock Ownership Policy. We offer full recourse, interest-bearing loans to employees in order to assist them in meeting the ownership requirements. Each loan may not exceed ten years and is collateralized by the Common Stock purchased. At September 30, 2000 and 1999, loans outstanding totaled $5.2 million and $4.1 million, respectively. NOTE 9 - PREFERENCE STOCK PURCHASE RIGHTS Holders of our Common Stock own one-half of one right (as described below) for each outstanding share of Common Stock. Each right entitles the holder to purchase one one-hundredth of a share of First Series Preference Stock, without par value, at an exercise price of $120 per one one-hundredth of a share or, under the circumstances summarized below, to purchase the common stock described in the following paragraph. The rights are exercisable only if a person or group, other than certain underwriters: 41 30 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) 1. acquires 20% or more of our Common Stock ("Acquiring Person") or 2. announces or commences a tender offer for 30% or more of our Common Stock. We are entitled to redeem the rights at five cents per right at any time before the earlier of: 1. the expiration of the rights in April 2006 or 2. ten days after a person or group has acquired 20% of our Common Stock if a majority of continuing Directors concur and, in certain circumstances, thereafter. Each holder of a right, other than an Acquiring Person, is entitled to purchase, at the exercise price of the right, Common Stock having a market value of twice the exercise price of the right if: 1. an Acquiring Person merges with UGI or engages in certain other transactions with us or 2. a person acquires 40% or more of our Common Stock. In addition, if, after UGI (or an Acquiring Person) publicly announces that an Acquiring Person has become such, UGI engages in a merger or other business combination transaction in which: 1. we are not the surviving corporation, or 2. we are the surviving corporation, but our Common Stock is changed or exchanged, or 3. 50% or more of our assets or earning power is sold or transferred, then each holder of a right is entitled to purchase, at the exercise price of the right, common stock of the acquiring company having a market value of twice the exercise price of the right. The rights have no voting or dividend rights and, until exercisable, have no dilutive effect on our earnings. NOTE 10 - PARTNERSHIP DISTRIBUTIONS The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash for such quarter. Available Cash generally means: 1. all cash on hand at the end of such quarter, 2. plus all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter, 3. less the amount of cash reserves established by the General Partner in its reasonable discretion. The General Partner may establish reserves for the proper conduct of the Partnership's business and for distributions during the next four quarters. In addition, certain of the Partnership's debt agreements require reserves be established for the payment of debt principal and interest. Distributions of Available Cash will generally be made 98% to the Common and Subordinated unitholders and 2% to the General Partner. The Partnership may pay an incentive distribution if Available Cash exceeds the Minimum Quarterly Distribution of $0.55 ("MQD") on all units. If there is sufficient Available Cash, the holders of Common Units have the right to receive the MQD, plus any arrearages, before the distribution of Available Cash to holders of Subordinated Units. Common Units will not accrue arrearages for any quarter after the Subordination Period (as defined below), and Subordinated Units will not accrue arrearages for any quarter. Pursuant to the Agreement of Limited Partnership of AmeriGas Partners ("Partnership Agreement"), because the required cash generation-based objectives were achieved as of March 31, 1999, a total of 9,891,074 Subordinated Units held by the General Partner and its wholly owned subsidiary, Petrolane, were converted into Common Units on May 18, 1999. The remaining outstanding 9,891,072 Subordinated Units, all of which are held by the General Partner, are eligible to convert to Common Units on the first day after the record date for any quarter ending on or after March 31, 2000 in respect of which: 1. distributions of Available Cash from Operating Surplus (as defined in the Partnership Agreement) equal or exceed the MQD on each of the outstanding Common and Subordinated units for each of the four consecutive nonoverlapping four-quarter periods immediately preceding such date, 2. the Adjusted Operating Surplus (as defined in the Partnership Agreement) generated during both (1) each of the two immediately preceding nonoverlapping four-quarter periods and (2) the immediately preceding sixteen-quarter period, equals or exceeds the MQD on each of the Common and Subordinated units outstanding during those periods, and 3. there are no arrearages on the Common Units. The ability of the Partnership to attain the cash-based performance and distribution requirements will depend upon a number of factors including highly seasonal operating results, changes in working capital, asset sales and debt refinancings. Due to the historical "look-back" provisions of the conversion test, the possibility is remote that the Partnership will satisfy the cash-based performance requirements for conversion any earlier than in respect of the quarter ending March 31, 2002. 42 31 UGI Corporation 2000 Annual Report NOTE 11 - 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 $34.1 million in 2000, $35.3 million in 1999, and $33.5 million in 1998. Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows:
After 2001 2002 2003 2004 2005 2005 - --------------------------------------------------------------------------------------------- AmeriGas Propane $ 27.2 $ 22.0 $ 16.8 $ 13.7 $ 11.3 $ 24.7 UGI Utilities 3.6 3.1 2.5 1.7 0.9 0.7 International Propane 0.1 0.1 0.1 -- -- -- Other 2.4 2.3 2.1 1.8 1.7 6.7 - --------------------------------------------------------------------------------------------- Total $ 33.3 $ 27.5 $ 21.5 $ 17.2 $ 13.9 $ 32.1 - ---------------------------------------------------------------------------------------------
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. 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. Prior to August 1, 1999, Pennsylvania Power & Light Company ("PP&L"), pursuant to a 1992 power supply agreement for bundled energy and capacity, supplied all of Electric Utility's electric power requirements above that provided by other sources. As part of a settlement of all disputes concerning the 1992 power supply agreement, during 1999 Electric Utility and PP&L entered into a new power supply agreement under which PP&L will supply all of Electric Utility's capacity requirements in excess of its capacity resources acquired from other sources through February 2001, and 32 megawatts of energy in each hour of the day through December 2000. Electric Utility has a number of other power supply agreements with PP&L and other power producers having various length terms expiring through December 2001. In high usage months, Electric Utility meets its additional electric power needs, above those provided by these contracts and its own generation facilities, through monthly market-based contracts and through spot purchases at market prices as delivered. In September 2000, UGIDC agreed to joint venture with a subsidiary of Allegheny Energy, Inc. ("Allegheny") to own and operate electric generation facilities, including Electric Utility's coal-fired Hunlock Creek generating station ("Hunlock"). Initially, UGIDC will contribute to the joint venture Hunlock, certain related assets, and approximately $6 million in cash. Allegheny will contribute a newly-constructed gas-fired combustion turbine generator to be operated at Hunlock's site. Each partner will be entitled to purchase 50% of the output of the joint venture at cost. The joint venture is expected to become operational in December 2000. The Partnership enters into contracts to purchase propane and Energy Services enters into contracts to purchase natural gas to meet a portion of their supply requirements. Generally, such contracts have terms of less than one year and call for payment based on either fixed prices or market prices at date of delivery. The Partnership has succeeded to certain lease guarantee obligations of Petrolane, a predecessor company of the Partnership, relating to Petrolane's divestiture of nonpropane operations before its 1989 acquisition by QFB Partners. Future lease payments under these leases total approximately $32 million at September 30, 2000. The leases expire through 2010, and some of them are currently in default. The Partnership has succeeded to the indemnity agreement of Petrolane by which Texas Eastern Corporation ("Texas Eastern"), a prior owner of Petrolane, agreed to indemnify Petrolane against any liabilities arising out of the conduct of businesses that do not relate to, and are not a part of, the propane business, including lease guarantees. To date, Texas Eastern has directly satisfied defaulted lease obligations without the Partnership's having to honor its guarantee. In addition, the Partnership has succeeded to Petrolane's agreement to indemnify Shell Petroleum N.V. ("Shell") for various scheduled claims, including claims related to antitrust actions, that were pending against Tropigas de Puerto Rico ("Tropigas"). Petrolane had entered into this indemnification agreement in conjunction with its sale of the international operations of Tropigas to Shell in 1989. The Partnership also succeeded to Petrolane's right to seek indemnity on these claims first from International Controls Corp., which sold Tropigas to Petrolane, and then from Texas Eastern. To date, neither the Partnership nor Petrolane has paid any sums under this indemnity. In 1999, a case brought by an unsuccessful entrant into the Puerto Rican propane market was dismissed by the Supreme Court of Puerto Rico for lack of subject matter jurisdiction, with the Court concluding that the Public Service Commission of Puerto Rico has exclusive jurisdiction over the matter. In the only pending litigation, the Supreme Court of Puerto Rico denied the motion of the defendants to dismiss, remanding the matter to the trial court for proceedings consistent with its ruling. In this case the plaintiff seeks treble damages in excess of $11.7 million. We believe that the probability the Partnership will be required to directly satisfy the above lease obligations and the remaining claim subject to the indemnification agreements is remote. We, along with other companies, have been named as a potentially responsible party ("PRP") in several administrative proceedings and private party recovery actions for the cleanup, or recovery of costs associated with cleanup, of various waste sites, including some Superfund sites. In addition, we have identified environmental contamination at several of our properties and have voluntarily undertaken investigation and, as appropriate, remediation of these sites in cooperation with appropriate environmental agencies or private parties. 43 32 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Prior to the general availability of natural gas, in the 1800s through the mid-1900s, most gas for lighting and heating nationwide was manufactured from combustibles such as coal, oil and coke. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the federal "Comprehensive Environmental Response, Compensation and Liability Act," or "Superfund Law," and may be present on the sites of former manufactured gas plants ("MGPs"). UGI Utilities and its former subsidiaries owned and operated a number of 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. By the mid-1930s, UGI Utilities was one of the largest public utility holding companies in the country. 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 has been notified of several sites outside Pennsylvania on which (1) gas plants 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 UGI Utilities should not have significant liability in those instances in which a former subsidiary operated an MGP because UGI Utilities generally is not legally liable for the obligations of its subsidiaries. Under certain circumstances, however, a court could find a parent company liable for environmental damage caused by a subsidiary company when the parent company either (1) itself operated the facility causing the environmental damage or (2) otherwise so controlled the subsidiary that the subsidiary's separate corporate form should be disregarded. There could be, therefore, significant future costs of an uncertain amount associated with environmental damage caused by MGPs that UGI Utilities owned or 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 identified 40 sites in Pennsylvania where either (1) UGI Utilities formerly conducted some MGP operations or (2) UGI Utilities owns or at one time owned the site. Because Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with Pennsylvania sites, the Company does not expect its costs for Pennsylvania sites to be material to future results of operations. 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 million in such costs. During 2000, UGI Utilities entered into settlement agreements with several of the insurers and recorded pre-tax income of $4.5 million which amount is included in operating and administrative expenses in the 2000 Consolidated Statement of Income. In addition to these 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. Management believes, 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. NOTE 12 -- 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 carrying amounts and estimated fair values of our long-term debt and UGI Utilities Series Preferred Stock at September 30 are as follows:
Carrying Estimated Amount Fair Value - ------------------------------------------------------------------ 2000: Long-term debt: AmeriGas Propane $857.2 $882.5 UGI Utilities 172.9 167.8 Other 85.5 85.6 UGI Utilities Series Preferred Stock 20.0 21.0 1999: Long-term debt: AmeriGas Propane $744.7 $761.3 UGI Utilities 180.0 174.8 Other 91.6 91.1 UGI Utilities Series Preferred Stock 20.0 20.9 - -----------------------------------------------------------------
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 UGI Utilities Series Preferred Stock is based on the fair value of redeemable preferred stock with similar credit ratings and redemption features. We have financial instruments such as short-term investments and trade accounts receivable which could expose us to concentrations of credit risk. We limit our credit risk from short-term investments by investing only in investment-grade commercial paper and in U.S. Government securities. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different U.S. markets. 44 33 UGI Corporation 2000 Annual Report We utilize derivative instruments to hedge market risk resulting from changes in the price of natural gas and propane, and changes in interest rates. We attempt to minimize our credit risk with our counterparties through the application of credit policies. At September 30, 2000 and 1999, the Partnership was a party to an interest rate protection agreement covering $50 million of long-term debt to be issued in fiscal 2001. The counterparty to this agreement is a large financial institution. The estimated fair value of this agreement was $2.5 million at September 30, 2000 and $3.2 million at September 30, 1999. At September 30, 2000 and 1999, Energy Services held exchange traded natural gas futures contracts with total notional amounts of $30.2 million and $26.6 million, respectively. Net deferred gains on settled and unsettled contracts totaled $6.6 million at September 30, 2000 and $3.3 million at September 30, 1999. At September 30, 1999, Energy Services also held exchange traded heating oil futures and option contracts with a total notional amount of $6.5 million and an estimated fair value of $(0.2) million. At September 30, 2000 and 1999, the Partnership was a party to propane price swap and option agreements with private counterparties with total notional amounts of $74.8 million and $12.9 million, respectively. Agreements outstanding at September 30, 2000 mature through March 2001. The estimated fair values of these swap and option agreements were $6.5 million and $2.9 million at September 30, 2000 and 1999, respectively. NOTE 13 - ACQUISITIONS During 2000, the Partnership acquired several propane distribution businesses, and Enterprises acquired an HVAC business, for net cash consideration of $65.3 million. The excess of the purchase price over the amount preliminarily allocated to the net assets acquired was approximately $42 million. During 1999 and 1998, the Partnership acquired several retail propane distribution businesses for net cash consideration of $3.9 million and $8.1 million, respectively. These acquisitions were recorded using the purchase method of accounting. Under the purchase method, the purchase price has been allocated to assets acquired and liabilities assumed based upon estimated fair values. The operating results of these businesses have been included in the consolidated results from their respective dates of acquisition. In addition to these acquisitions, during 1999 the Company paid $4.9 million for a 25% equity interest in a propane distribution business in Nantong, China, which is being accounted for on the equity method of accounting. On September 21, 1999, Enterprises, through subsidiaries, acquired all of the outstanding stock of FLAGA for net cash consideration of $73.7 million and the assumption of approximately $18 million of debt. The cash purchase price was financed through the issuance of EURO denominated debt. The acquisition of FLAGA has been accounted for using the purchase method of accounting. The excess of the purchase price over the amount allocated to the net assets acquired totaled $57.5 million. For accounting convenience only, September 30, 1999 was deemed to be the acquisition date. As a result, the acquisition of FLAGA did not impact the Company's 1999 results of operations. The unaudited pro forma revenues, net income and diluted earnings per share of the Company for 1999, as if the acquisition of FLAGA had occurred as of October 1, 1998, are $1,434.0 million, $52.0 million, and $1.62, respectively. The pro forma results of operations give effect to FLAGA's historical operating results in accordance with U.S. generally accepted accounting principles and adjustments for interest expense, goodwill amortization and depreciation expense, and income taxes, but do not adjust for normal weather conditions and anticipated operating efficiencies. In management's opinion, the unaudited pro forma results are not indicative of the actual results that would have occurred had the acquisition of FLAGA occurred as of October 1, 1998, or of future operating results under the ownership and management of the Company. The pro forma effect of the other businesses acquired during 2000, 1999 and 1998 was not material to our results of operations. NOTE 14 - TERMINATED MERGER - UNISOURCE WORLDWIDE, INC. On May 25, 1999, the Company announced that Unisource Worldwide, Inc. ("Unisource") had entered into a merger agreement with Georgia-Pacific Corp. ("GP") and that it would allow Unisource to terminate the previously announced Agreement and Plan of Merger (the "Merger Agreement") among Unisource, UGI and Vulcan Acquisition Corp. (a wholly owned subsidiary of UGI) which would have provided for the merger of the Company and Unisource. Because the board of directors of Unisource decided to enter into a merger agreement with GP, Unisource was required to pay the Company a $25 million merger termination fee pursuant to the terms of the Merger Agreement. The Company received the termination fee on May 28, 1999. The fee, net of related merger expenses, is classified as merger fee income and expenses, net, in the 1999 Consolidated Statement of Income. NOTE 15 - OTHER INCOME, NET Other income, net, comprises the following:
2000 1999 1998 - --------------------------------------------------------------------------- Interest and interest-related income $ (9.3) $ (8.5) $ (8.6) Loss on Partnership's interest rate protection agreements -- -- 4.0 Gain on sales of investments (1.8) -- (2.3) Gain on sales of fixed assets (3.6) (2.2) (2.0) Pension income (3.0) (2.3) (1.9) Other (9.2) (3.8) (1.9) - --------------------------------------------------------------------------- Total other income, net $ (26.9) $ (16.8) $ (12.7) - ---------------------------------------------------------------------------
45 34 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) NOTE 16-- QUARTERLY DATA (UNAUDITED)
December 31, March 31, June 30, September 30, 1999 1998 2000(a) 1999(b) 2000 1999(c) 2000(d) 1999 - ---------------------------------------------------------------------------------------------------------------------------------- Revenues $ 466.6 $ 373.7 $ 610.4 $ 499.2 $ 335.9 $ 259.3 $ 348.8 $ 251.4 Operating income (loss) 70.7 61.5 117.9 115.6 8.7 9.4 (6.1) (10.6) Net income (loss) 21.1 18.0 38.8 37.5 (4.7) 11.4 (10.5) (11.2) Net income (loss) per share- Basic 0.77 0.55 1.42 1.15 (0.17) 0.36 (0.39) (0.37) Diluted 0.77 0.55 1.42 1.14 (0.17) 0.36 (0.39) (0.37) - ----------------------------------------------------------------------------------------------------------------------------------
The quarterly data above includes all adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) which we consider necessary for a fair presentation. Our quarterly results fluctuate because of the seasonal nature of our businesses. (a) Includes income from a litigation settlement which increased operating income by $2.4 million and net income by $1.4 million or $0.05 per share. (b) Includes merger expenses of $1.6 million which decreased net income by $1.1 million or $0.03 per share. (c) Includes merger termination fee income of $25 million, less $3.5 million of merger related expenses, which increased net income by $14.0 million or $0.44 per share. (d) Includes income from a litigation settlement which decreased operating loss by $2.1 million and net loss by $1.2 million or $0.04 per share. NOTE 17 -- SEGMENT INFORMATION SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131"), defines operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. We have determined that the Company has five such business segments: (1) AmeriGas Propane; (2) Gas Utility; (3) Electric Utility; (4) Energy Services; and (5) an international propane segment comprising FLAGA and our equity investments in China and Romania. AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies principally to retail customers from locations in 45 states. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern and southeastern Pennsylvania. Electric Utility derives its revenues from the sale and distribution of electricity in two northeastern Pennsylvania counties. Although the Electricity Customer Choice Act unbundled the pricing for Electric Utility's electric generation, transmission and distribution services, we currently manage and evaluate these business components on a combined basis. Energy Services revenues are derived from the sale of natural gas and, to a lesser extent, electricity to customers located primarily in the Middle Atlantic and New England states. Our International Propane segment revenues result principally from the distribution of propane to retail customers in Austria, the Czech Republic and Slovakia. The accounting policies of our reportable segments are substantially the same as those described in Note 1. We evaluate our AmeriGas Propane and International Propane segments' performance principally based upon earnings before interest expense, income taxes, depreciation and amortization ("EBITDA"). We evaluate the performance of our Gas Utility, Electric Utility and Energy Services 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, other than those of our International Propane segment, are derived from sources within the U.S., and all of our reportable segments' long-lived assets, other than those of our International Propane segment, are located in the U.S. Financial information by business segment follows: 46 35
AmeriGas Gas Electric Energy Total Eliminations Propane Utility Utility Services - ---------------------------------------------------------------------------------------------------------------------------------- 2000 Revenues $1,761.7 $ (3.1) $1,120.1 $ 359.0 $ 77.9 $ 146.9 EBITDA $ 288.7 $ -- $ 158.6 $ 105.3 $ 19.6 $ 3.0 Depreciation and amortization (97.5) -- (68.4) (19.1) (4.5) (0.2) - ---------------------------------------------------------------------------------------------------------------------------------- Operating income (loss) 191.2 -- 90.2 86.2 15.1 2.8 Interest expense (98.5) -- (74.7) (16.2) (2.2) -- Minority interest (6.3) -- (6.3) -- -- -- - ---------------------------------------------------------------------------------------------------------------------------------- Income (loss) before income taxes $ 86.4 $ -- $ 9.2 $ 70.0 $ 12.9 $ 2.8 Total assets $2,278.8 $ (19.0) $1,281.7 $ 656.7 $ 97.4 $ 36.2 Capital expenditures $ 71.0 $ -- $ 30.4 $ 31.7 $ 4.7 $ 0.1 Investments in foreign equity investees $ 5.5 $ -- $ -- $ -- $ -- $ -- ================================================================================================================================== 1999 Revenues $1,383.6 $ (2.3) $ 872.5 $ 345.6 $ 75.0 $ 90.4 EBITDA $ 265.6 $ -- $ 158.8 $ 87.0 $ 16.7 $ 2.7 Depreciation and amortization (89.7) -- (66.3) (19.0) (4.0) (0.1) - ---------------------------------------------------------------------------------------------------------------------------------- Operating income (loss) 175.9 -- 92.5 68.0 12.7 2.6 Merger fee income, net 19.9 -- -- -- -- -- Interest expense (84.6) -- (66.5) (15.2) (2.3) -- Minority interest (10.7) -- (10.7) -- -- -- - ---------------------------------------------------------------------------------------------------------------------------------- Income (loss) before income taxes $ 100.5 $ -- $ 15.3 $ 52.8 $ 10.4 $ 2.6 Total assets $2,140.5 $ (15.6) $1,221.9 $ 620.4 $ 95.3 $ 17.4 Capital expenditures $ 73.7 $ -- $ 34.6(a) $ 31.9 $ 4.5 $ 0.2 Investments in foreign equity investees $ 6.3 $ -- $ -- $ -- $ -- $ -- ================================================================================================================================== 1998 Revenues $1,439.7 $ (3.0) $ 914.4 $ 350.2 $ 72.1 $ 103.0 EBITDA $ 258.0 $ -- $ 153.3 $ 83.0 $ 13.6 $ 2.1 Depreciation and amortization (87.8) -- (65.4) (18.2) (3.9) (0.1) - ---------------------------------------------------------------------------------------------------------------------------------- Operating income (loss) 170.2 -- 87.9 64.8 9.7 2.0 Interest expense (84.4) -- (66.1) (15.3) (2.3) -- Minority interest (8.9) -- (8.9) -- -- -- - ---------------------------------------------------------------------------------------------------------------------------------- Income (loss) before income taxes $ 76.9 $ -- $ 12.9 $ 49.5 $ 7.4 $ 2.0 Total assets $2,074.6 $ (17.1) $1,238.2 $ 594.4 $ 95.6 $ 14.3 Capital expenditures $ 69.2 $ -- $ 31.9 $ 32.0 $ 5.2 $ 0.1 Investments in foreign equity investees $ 2.1 $ -- $ -- $ -- $ -- $ -- ==================================================================================================================================
International Other Corporate & Propane Enterprises Other - ------------------------------------------------------------------------------------ 2000 Revenues $ 50.5 $ 7.3 $ 3.1 EBITDA $ 1.9 $ (5.0) $ 5.3 Depreciation and amortization (4.6) (0.5) (0.2) - ------------------------------------------------------------------------------------ Operating income (loss) (2.7) (5.5) 5.1 Interest expense (4.8) -- (0.6) Minority interest -- -- -- - ------------------------------------------------------------------------------------ Income (loss) before income taxes $ (7.5) $ (5.5) $ 4.5 Total assets $ 113.7 $ 28.2 $ 83.9 Capital expenditures $ 1.8 $ 2.3 $ -- Investments in foreign equity investees $ 5.5 $ -- $ -- ================================================================================== 1999 Revenues $ -- $ 0.1 $ 2.3 EBITDA $ (0.1) $ (5.7) $ 6.2 Depreciation and amortization -- -- (0.3) - ------------------------------------------------------------------------------------ Operating income (loss) (0.1) (5.7) 5.9 Merger fee income, net -- -- 19.9 Interest expense -- -- (0.6) Minority interest -- -- -- - ------------------------------------------------------------------------------------ Income (loss) before income taxes $ (0.1) $ (5.7) $ 25.2 Total assets $ 143.2 $ 3.7 $ 54.2 Capital expenditures $ -- $ 2.5 $ -- Investments in foreign equity investees $ 6.3 $ -- $ -- ================================================================================== 1998 Revenues $ -- $ -- $ 3.0 EBITDA $ (1.0) $ (1.8) $ 8.8 Depreciation and amortization -- -- (0.2) - ------------------------------------------------------------------------------------ Operating income (loss) (1.0) (1.8) 8.6 Interest expense -- -- (0.7) Minority interest -- -- -- - ------------------------------------------------------------------------------------ Income (loss) before income taxes $ (1.0) $ (1.8) $ 7.9 Total assets $ 2.3 $ 0.1 $ 146.8 Capital expenditures $ -- $ -- $ -- Investments in foreign equity investees $ 2.1 $ -- $ -- ==================================================================================
(a) Includes capital leases of $3.5 million. 47 EX-21 11 w43405ex21.txt UGI CORPORATION SUSIDIARIES 1 Exhibit 21 UGI CORPORATION SUBSIDIARIES
SUBSIDIARY OWNERSHIP STATE OF INCORPORATION - ---------- -------- ---------------------- AMERIGAS, INC. 100% PA FOUR FLAGS DRILLING COMPANY, INC. 100% PA Four Flags Holding Company 100% DE AMERIGAS PROPANE, INC. * 100% PA AmeriGas Partners, L.P. (1) DE AmeriGas Finance Corp. 100% DE AmeriGas Propane L.P. 98.9899% DE AmeriGas Propane Parts & Service, Inc. 100% PA Petrolane Offshore Limited 100% BERMUDA AmeriGas Technology Group, Inc. 100% PA Petrolane Incorporated 100% PA ASHTOLA PRODUCTION COMPANY 100% PA UGI ETHANOL DEVELOPMENT CORPORATION 100% PA NORTHFIELD HOLDING COMPANY 100% DE UGI ENTERPRISES, INC. 100% PA CFN ENTERPRISES, INC. 100% DE CF Networks LLC 60% DE EASTFIELD INTERNATIONAL HOLDINGS, INC. 100% DE Flaga GmbH 100% AUSTRIA Flaga Energievorsorgung 100% GERMANY Flaga Plyn, spol. s r.o. 100% CZECH REPUBLIC Flaga Slovplyn, spol. s r.o. 100% SLOVAKIA Flaga Tech Trade GmbH 100% AUSTRIA Osterreichische Flussiggas-Gesellschaft m.b.H. 40% AUSTRIA T.S.G.- Transport - und Speditionsgesellschaft m.b.H. 50% AUSTRIA G.T.P. Gas Trans Praha spol. s r.o. 60% CZECH REPUBLIC GTE Gastrans-Erfurt-GmbH 90% GERMANY EUROGAS HOLDINGS, INC. 100% DE UGI ENERGY SERVICES, INC. 100% PA Energy Services Holding Company 100% DE UGI POWER SUPPLY, INC. 100% PA UGI INTERNATIONAL ENTERPRISES, INC. 100% PA UGI BLACK SEA ENTERPRISES, INC. 100% PA UGI INTERNATIONAL (ROMANIA), INC. 100% PA UGI ROMANIA, INC. 100% PA UGI INTERNATIONAL (CHINA), INC. 100% DE UGI CHINA, INC. 100% DE UGI SOUTHWEST CHINA DEVELOPMENT COMPANY, LLC 100% DE HEARTH USA, INC. 100% DE UGI HVAC ENTERPRISES, INC. 100% DE UGI PROPERTIES, INC. 100% PA UGI UTILITIES, INC. 100% PA UGI DEVELOPMENT COMPANY 100% PA UGID Holding Company 100% DE UGI Hunlock Development Company 100% PA UNITED VALLEY INSURANCE COMPANY 100% VT VULCAN ACQUISITION CORP. 100% DE
2 (1) AmeriGas Propane, Inc. and its subsidiary, Petrolane Incorporated, hold a combined 55% interest in AmeriGas Partners, L.P. and its subsidiary AmeriGas Propane, L.P. * Sole General Partner of each of AmeriGas Partners, L.P. and AmeriGas Propane, L.P. EX-23 12 w43405ex23.txt CONSENT OF ARTHUR ANDERSEN LLP 1 Exhibit (23) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS To UGI Corporation: As independent public accountants, we hereby consent to the incorporation of our reports included or incorporated by reference in this Form 10-K, into this Company's previously filed S-8 Registration Statement Nos. 33-47319, 33-61722, 333-22305, 333-37093, 333-49080 and Form S-3 Registration Statement Nos. 33-78776 and 333-42296. Arthur Andersen LLP Philadelphia, Pennsylvania December 22, 2000 EX-27 13 w43405ex27.txt FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONDENSED CONSOLIDATED BALANCE SHEET AND INCOME STATEMENT OF UGI CORPORATION AND SUBSIDIARIES AS OF AND FOR THE YEAR ENDED SEPTEMBER 30, 2000 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS IN UGI CORPORATION'S ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED SEPTEMBER 30,2000 0000884614 UGI CORPORATION 1,000 YEAR SEP-30-2000 OCT-01-1999 SEP-30-2000 93,900 7,800 185,500 9,300 117,400 426,100 1,652,100 578,900 2,278,800 539,400 1,029,700 20,000 0 394,500 (147,300) 2,278,800 1,761,700 1,761,700 1,021,600 1,021,600 0 0 98,500 86,400 40,100 44,700 0 0 0 44,700 1.64 1.64
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