EX-13 5 w66596exv13.txt PAGES 13 TO 51 OF THE 2002 ANNUAL REPORT UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- FINANCIAL REVIEW BUSINESS OVERVIEW UGI Corporation ("UGI") is a holding company that, through subsidiaries and joint-venture affiliates, distributes and markets energy products and related services. We are a domestic and international distributor of propane; a provider of natural gas and electricity service through regulated local distribution utilities; a generator of electricity through our ownership interests in electric generation facilities; a regional marketer of energy commodities; and a provider of heating and cooling services. We conduct a national propane distribution business through AmeriGas Partners, L.P. ("AmeriGas Partners") and its principal operating subsidiaries AmeriGas Propane, L.P. ("AmeriGas OLP") and AmeriGas Eagle Propane, L.P. ("Eagle OLP"). At September 30, 2002, UGI, through its wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the "General Partner"), held an approximate 51% effective interest in the Partnership. We refer to AmeriGas Partners and its subsidiaries together as "the Partnership" and the General Partner and its subsidiaries, including the Partnership, as "AmeriGas Propane." Our natural gas and electric distribution utilities and electric generation businesses are conducted through UGI Utilities, Inc. and its subsidiaries ("UGI Utilities"). UGI Utilities owns and operates a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and an electricity distribution utility ("Electric Utility") in northeastern Pennsylvania. UGI Utilities also owns interests in electricity generating facilities in Pennsylvania which, together with Electric Utility, are referred to herein as "Electric Operations." Our wholly owned subsidiary UGI Enterprises, Inc. ("Enterprises") conducts an energy marketing business primarily in the Middle Atlantic region of the United States through its wholly owned subsidiary, UGI Energy Services, Inc. ("Energy Services"). Through other subsidiaries, Enterprises (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 in the Middle Atlantic states ("HVAC"); and (3) participates in propane joint-venture businesses in France ("Antargaz") and in the Nantong region of China. This Financial Review should be read in conjunction with our Consolidated Financial Statements and Notes to Consolidated Financial Statements including the business segment information included in Note 21. RESULTS OF OPERATIONS 2002 COMPARED WITH 2001 CONSOLIDATED RESULTS
Variance- Favorable 2002 2001 (Unfavorable) ------------------- ------------------ ------------------ Diluted Earnings Diluted DILUTED Net (Loss) Net Earnings NET EARNINGS Income Per Income (Loss) INCOME PER SHARE (Loss) Share (Loss) Per Share ========================================================================================= (Millions of dollars, except per share) AmeriGas Propane $ 17.4 $ 0.62 $ 13.5 $ 0.49 $ 3.9 $ 0.13 UGI Utilities 42.5 1.52 46.6 1.70 (4.1) (0.18) Energy Services 6.5 0.23 4.0 0.15 2.5 0.08 International Propane 7.5 0.27 (4.4) (0.16) 11.9 0.43 Corporate & Other (a) 1.6 0.06 (7.7) (0.28) 9.3 0.34 Changes in accounting (b) -- -- 4.5 0.16 (4.5) (0.16) ----------------------------------------------------------------------------------------- Total (c) $ 75.5 $ 2.70 $ 56.5 $ 2.06 $ 19.0 $ 0.64 -----------------------------------------------------------------------------------------
(a) Consists principally of UGI, HVAC, UGI Enterprises' corporate and general expenses and in Fiscal 2001, Hearth USA(TM). Hearth USA(TM) ceased operations in October 2001. Net loss in Fiscal 2001 includes after-tax shut-down costs of $5.5 million or $0.20 per share associated with Hearth USA(TM) (see Note 16 to Consolidated Financial Statements). (b) Fiscal 2001 amounts include cumulative effect of accounting changes associated with (1) the Partnership's changes in accounting for tank fee revenue and tank installation costs and (2) the Company's adoption of SFAS 133 (see Note 3 to Consolidated Financial Statements). (c) Results for Fiscal 2002 reflect the elimination of goodwill amortization resulting from the adoption of Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets." Pro Forma net income and diluted earnings per share for Fiscal 2001 as if the adoption of SFAS 142 had occurred as of October 1, 2000 is $70.5 million and $2.58, respectively. For a detailed discussion of SFAS 142 and its impact on the Company's results, see Note 1 to Consolidated Financial Statements. Although significantly warmer than normal weather negatively affected UGI Utilities' and AmeriGas Propane's Fiscal 2002 operating results, our Fiscal 2002 net income and earnings per share increased more than 30%. The increase in net income reflects the elimination of goodwill amortization as a result of the adoption of SFAS 142, a significant increase in income from our International Propane businesses, and the benefit of higher growth-related earnings from our Energy Services business. In addition, results in Fiscal 2001 were negatively impacted by operating losses and shut-down costs associated with Hearth USA(TM). 13 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) The following table presents certain financial and statistical information by reportable segment for Fiscal 2002 and Fiscal 2001:
Increase 2002 2001 (Decrease) ======================================================================================== (Millions of dollars) AMERIGAS PROPANE: Revenues $ 1,307.9 $ 1,418.4 $ (110.5) (7.8)% Total margin (a) $ 675.8 $ 582.4 $ 93.4 16.0% EBITDA (b) $ 210.7 $ 209.3 $ 1.4 0.7% Operating income $ 144.3 $ 133.8 $ 10.5 7.8% Retail gallons sold (millions) 932.8 820.8 112.0 13.6% Degree days - % colder (warmer) than normal (c) (10.0)% 2.6% -- -- GAS UTILITY: Revenues $ 404.5 $ 500.8 $ (96.3) (19.2)% Total margin (a) $ 162.9 $ 177.9 $ (15.0) (8.4)% Operating income $ 77.1 $ 87.8 $ (10.7) (12.2)% System throughput - billions of cubic feet ("bcf") 70.5 77.3 (6.8) (8.8)% Degree days - % colder (warmer) than normal (17.4)% 2.0% -- -- ELECTRIC OPERATIONS: Revenues $ 86.0 $ 83.9 $ 2.1 2.5% Total margin (a) $ 32.8 $ 28.6 $ 4.2 14.7% Operating income $ 13.2 $ 10.7 $ 2.5 23.4% Distribution sales - millions of kilowatt hours ("gwh") 933.6 945.5 (11.9) (1.3)% ENERGY SERVICES: Revenues $ 332.3 $ 370.7 $ (38.4) (10.4)% Total margin (a) $ 21.4 $ 13.4 $ 8.0 59.7% Operating income $ 11.1 $ 7.3 $ 3.8 52.1% INTERNATIONAL PROPANE: Revenues $ 46.7 $ 50.9 $ (4.2) (8.3)% Total margin (a) $ 24.1 $ 22.5 $ 1.6 7.1% EBITDA (b) $ 7.1 $ 5.1 $ 2.0 39.2% Operating income $ 3.9 $ 0.8 $ 3.1 387.5% Income (loss) from equity investees $ 8.3 $ (1.5) $ 9.8 N.M. ----------------------------------------------------------------------------------------
N.M. - Not meaningful. (a) Total margin represents total revenues less cost of sales and, with respect to Electric Operations, revenue-related taxes, i.e. Electric Utility gross receipts taxes. For financial statement purposes, revenue-related taxes are included in "taxes other than income taxes" on the Consolidated Statements of Income. b) EBITDA (earnings before interest expense, income taxes, depreciation and amortization, minority interests, income (loss) from equity investees, and the cumulative effect of accounting changes) 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 or financial condition under accounting principles generally accepted in the United States. The Company's definition of EBITDA may be different from that used by other companies. (c) 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 United States. AMERIGAS PROPANE. The Partnership's Fiscal 2002 operating results were negatively impacted by significantly warmer than normal heating-season weather. Fiscal 2002 temperatures based upon heating degree day data provided by NOAA were approximately 10.0% warmer than normal and 12.3% warmer than Fiscal 2001. Notwithstanding the impact of the warmer weather on heating-related sales and the effects of a sluggish U.S. economy on commercial sales, retail gallons sold increased 112.0 million gallons principally as a result of the full-year effect of the Partnership's August 21, 2001, acquisition of Columbia Propane (see Note 2 to Consolidated Financial Statements) and, to a much lesser extent, greater volumes from our PPX(R) grill cylinder exchange business. The increase in PPX(R) sales principally reflects the effect on Fiscal 2002 grill cylinder exchanges resulting from recently enacted National Fire Protection Association ("NFPA") guidelines and, to a lesser extent, the full-year effects of Fiscal 2001 increases in the number of PPX(R) distribution outlets. The NFPA guidelines require that propane grill cylinders refilled after April 1, 2002, be fitted with overfill protection devices ("OPDs"). Retail propane revenues were $1,070.6 million in Fiscal 2002, a decrease of $37.8 million from Fiscal 2001, reflecting a $189.0 million decrease as a result of lower average selling prices partially offset by a $151.2 million increase as a result of the greater retail volumes sold. Wholesale propane revenues were $121.1 million in Fiscal 2002, a decrease of $93.5 million, reflecting a $62.0 million decrease due to lower average selling prices and a $31.5 million decrease as a result of lower wholesale volumes sold. The lower Fiscal 2002 retail and wholesale selling prices resulted from lower Fiscal 2002 propane product costs. Revenues from other sales and services increased $20.8 million primarily due to the full-year impact of Columbia Propane. Total cost of sales declined $203.9 million in Fiscal 2002 reflecting lower average propane product costs and the lower wholesale sales partially offset by the higher retail gallons sold. Total margin increased $93.4 million reflecting the full-year volume impact of the Columbia Propane acquisition and a $35.5 million increase in total margin from PPX(R) reflecting higher volumes and unit margins. PPX(R) propane unit margins in Fiscal 2002 were higher than in Fiscal 2001 reflecting increases in sales prices to fund OPD valve replacement capital expenditures on out-of-compliance grill cylinders. The extent to which this greater level of PPX(R) margin is sustainable in the future will depend upon a number of factors, including the continuing rate of OPD valve replacement and competitive market conditions. EBITDA (earnings before interest expense, income taxes, depreciation and amortization, minority interests, income from equity investees, and the cumulative effect of accounting changes) increased $1.4 million in Fiscal 2002 as the significant increase in total margin was substantially offset by an $88.8 million increase in Partnership operating and administrative expenses and a decrease in other income. EBITDA of PPX(R) increased approximately $21 million in Fiscal 2002 partially offsetting the effects of the significantly warmer winter weather on our heating-related volumes. Although EBITDA is not a measure of performance or financial condition under accounting principles generally accepted 14 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- in the United States, it is included in this analysis to provide additional information for evaluating the Partnership's ability to pay and declare the Minimum Quarterly Distribution of $0.55 ("MQD") and for evaluating the Partnership's performance. The Partnership's definition of EBITDA may be different from the definition of EBITDA used by other companies. The greater operating and administrative expenses in Fiscal 2002 resulted primarily from the full-year impact of the Columbia Propane acquisition and higher volume-driven PPX(R) expenses. During Fiscal 2002, the Partnership completed its planned blending of 90 Columbia Propane distribution locations with existing AmeriGas Propane locations. As a result of these district consolidations and other cost reduction activities, management believes that by September 30, 2002 it achieved its anticipated $24 million reduction in annualized operating cost savings subsequent to the acquisition of Columbia Propane. Operating income increased $10.5 million, significantly more than the increase in EBITDA, principally due to the cessation of goodwill amortization in Fiscal 2002 as a result of the adoption of SFAS 142 (see Note 1 to Consolidated Financial Statements) partially offset by higher depreciation and intangible asset amortization associated with Columbia Propane and higher PPX(R) depreciation. Fiscal 2001 operating income includes $23.8 million of goodwill amortization. GAS UTILITY. Weather in Gas Utility's service territory during Fiscal 2002 based upon heating degree days was 17.4% warmer than normal compared to weather that was 2.0% colder than normal in Fiscal 2001. As a result of the significantly warmer weather and the effects of a weak economy on commercial and industrial natural gas usage, distribution system throughput declined 8.8%. The $96.3 million decrease in Fiscal 2002 Gas Utility revenue reflects the impact of lower purchased gas cost ("PGC") rates, resulting from the pass through of lower natural gas costs to firm-residential, commercial and industrial (collectively, "core-market") customers, and the lower distribution system throughput. Gas Utility cost of gas was $241.7 million in Fiscal 2002 compared to $322.9 million in Fiscal 2001 reflecting lower natural gas costs and the decline in core-market throughput in Fiscal 2002. The decline in Gas Utility margin principally reflects a $6.0 million decline in core-market margin due to the lower sales; a $6.6 million decline in interruptible margin due principally to the flowback of certain interruptible customer margin to core-market customers beginning December 1, 2001 pursuant to the Gas Restructuring Order; and lower firm delivery service total margin due to lower sales. Interruptible customers are those who have the ability to switch to alternate fuels. Gas Utility operating income declined $10.7 million in Fiscal 2002 reflecting the previously mentioned decline in total margin and a decrease in pension income partially offset by lower operating expenses. Operating expenses declined $4.1 million primarily as a result of lower charges for uncollectible accounts and lower distribution system expenses. Depreciation expense declined $1.2 million due to a change effective April 1, 2002 in the estimated useful lives of Gas Utility's natural gas distribution assets resulting from an asset life study required by the PUC. ELECTRIC OPERATIONS. The decline in Electric Utility kilowatt-hour sales in Fiscal 2002 reflects the effects on heating-related sales of significantly warmer winter weather partially offset by the beneficial effect on air conditioning sales of warmer summer weather. Notwithstanding the decrease in total kilowatt-hour sales, revenues increased $2.1 million principally due to an increase in state tax surcharge revenue and greater third-party sales of electricity produced by our Pennsylvania-based electric generation facilities. Electric Operations cost of sales was $48.6 million in Fiscal 2002 compared to $51.9 million in Fiscal 2001 principally reflecting the impact of the lower sales and lower purchased power unit costs partially offset by the full-period increase to cost of sales resulting from the transfer of our Hunlock Creek electricity generation assets to Hunlock Creek Energy Ventures ("Energy Ventures") in December 2000. Energy Ventures is an electricity generation joint venture with a subsidiary of Allegheny Energy, Inc. Subsequent to the formation of Energy Ventures, our electric generating business purchases its share of the power produced by Energy Ventures rather than producing this electricity itself. As a result, the cost of this power is reflected in cost of sales whereas prior to the formation of Energy Ventures such costs were reflected as operating and administrative expenses. Electric Operations total margin increased $4.2 million in Fiscal 2002 as a result of lower purchased power unit costs partially offset by the winter weather-driven decline in sales. Operating income increased $2.5 million reflecting the greater total margin and lower operating costs subsequent to the formation of Energy Ventures partially offset by a decline in other income. ENERGY SERVICES. Revenues from Energy Services declined $38.4 million, notwithstanding a 27% increase in natural gas volumes sold, reflecting significantly lower natural gas prices. Total margin increased principally as a result of the acquisition of the energy marketing businesses of PG Energy in July 2001, income from providing winter storage services and higher average unit margins. The increase in total margin was partially offset by higher operating expenses subsequent to the PG Energy acquisition. INTERNATIONAL PROPANE. FLAGA's revenues in Fiscal 2002 were lower than in the prior year as a result of lower average selling prices reflecting lower average propane product costs. Weather based upon heating degree days was approximately 10% warmer than normal in Fiscal 2002 compared to weather that was 12% warmer than normal in Fiscal 2001. The increase in FLAGA's total margin reflects higher average unit margins principally as a result of declining propane product costs. FLAGA's operating results also benefited from lower operating expenses, principally reduced payroll costs, and a $1.2 million decrease in goodwill amortization resulting from the adoption of SFAS 142. The significant increase in income from our international propane joint ventures in Fiscal 2002 principally reflects the full-year benefits from our debt and equity investments in AGZ Holdings ("AGZ"), the parent company of Antargaz, acquired on March 27, 2001. Operating results of Antargaz in Fiscal 2002 benefited from higher than normal unit margins, principally as a 15 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) result of lower propane product costs, and the elimination of goodwill amortization effective April 1, 2002. In addition, income from our debt investments in AGZ in Fiscal 2002 includes $0.9 million of interest income and a currency transaction gain of $1.6 million resulting from AGZ's early redemption of this euro-denominated debt in July 2002. As a result of the redemption of AGZ debt during Fiscal 2002 and an expected decrease in Antargaz unit margins to more normal levels, we anticipate income from our investment in AGZ in Fiscal 2003 to decline significantly from Fiscal 2002. Loss from International Propane joint ventures in Fiscal 2001 includes a loss of $1.1 million from the write-off of our propane joint-venture investment located in Romania. CORPORATE & OTHER. Corporate & Other operating income was $3.0 million in Fiscal 2002 compared to a loss of $11.0 million in Fiscal 2001. The prior-year results include operating losses, and $8.5 million of shut-down costs, associated with Hearth USA(TM), and a $2.0 million loss from the write-down of an investment in a business-to-business e-commerce company. INTEREST EXPENSE AND INCOME TAXES. The increase in interest expense principally reflects higher Partnership long-term debt outstanding resulting from the Columbia Propane acquisition partially offset by lower levels of UGI Utilities and Partnership bank loans outstanding and lower short-term interest rates. The lower effective income tax rate in Fiscal 2002 principally reflects the elimination of nondeductible goodwill amortization resulting from the adoption of SFAS 142 and greater equity income from Antargaz. 2001 COMPARED WITH 2000 CONSOLIDATED RESULTS
Variance- Favorable 2001 2000 (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 $ 13.5 $ 0.49 $ -- $ -- $ 13.5 $ 0.49 UGI Utilities 46.6 1.70 48.9 1.79 (2.3) (0.09) Energy Services 4.0 0.15 1.6 0.06 2.4 0.09 International Propane (4.4) (0.16) (5.6) (0.20) 1.2 0.04 Corporate & Other (7.7) (0.28) (0.2) (0.01) (7.5) (0.27) Changes in accounting 4.5 0.16 -- -- 4.5 0.16 ---------------------------------------------------------------------------------------------------------- Total $ 56.5 $ 2.06 $ 44.7 $ 1.64 $ 11.8 $ 0.42 ----------------------------------------------------------------------------------------------------------
The higher Fiscal 2001 net income and earnings per share reflect a significant increase in the Partnership's and Energy Services' results. Excluding the cumulative effect of accounting changes and one-time costs to close the Hearth USA(TM) retail stores, diluted earnings per share increased 28% to $2.10 in Fiscal 2001. The following table presents certain financial and statistical information by business segment for Fiscal 2001 and Fiscal 2000:
Increase 2001 2000 (Decrease) ================================================================================= (Millions of dollars) AMERIGAS PROPANE: Revenues $ 1,418.4 $ 1,120.1 $ 298.3 26.6% Total margin $ 582.4 $ 491.8 $ 90.6 18.4% EBITDA $ 209.3 $ 158.6 $ 50.7 32.0% Operating income $ 133.8 $ 90.2 $ 43.6 48.3% Retail gallons sold (millions) 820.8 771.2 49.6 6.4% Degree days - % colder (warmer) than normal 2.6% (13.7)% -- -- GAS UTILITY: Revenues $ 500.8 $ 359.0 $ 141.8 39.5% Total margin $ 177.9 $ 170.8 $ 7.1 4.2% Operating income $ 87.8 $ 86.2 $ 1.6 1.9% System throughput - billions of cubic feet ("bcf") 77.3 79.7 (2.4) (3.0)% Degree days - % colder (warmer) than normal 2.0% (9.9)% -- -- ELECTRIC OPERATIONS: Revenues $ 83.9 $ 77.9 $ 6.0 7.7% Total margin $ 28.6 $ 40.8 $ (12.2) (29.9)% Operating income $ 10.7 $ 15.1 $ (4.4) (29.1)% Distribution sales - millions of kilowatt hours ("gwh") 945.5 907.2 38.3 4.2% ENERGY SERVICES: Revenues $ 370.7 $ 146.9 $ 223.8 152.3% Total margin $ 13.4 $ 6.2 $ 7.2 116.1% Operating income $ 7.3 $ 2.8 $ 4.5 160.7% INTERNATIONAL PROPANE: Revenues $ 50.9 $ 50.5 $ 0.4 0.8% Total margin $ 22.5 $ 20.8 $ 1.7 8.2% EBITDA $ 5.1 $ 2.8 $ 2.3 82.1% Operating income (loss) $ 0.8 $ (1.8) $ 2.6 144.4% Loss from equity investees $ (1.5) $ (0.9) $ 0.6 66.7% ---------------------------------------------------------------------------------
AMERIGAS PROPANE. Retail propane gallons sold increased 49.6 million gallons (6.4%) primarily due to the effects of colder weather and the impact of acquisitions, including the August 21, 2001 acquisition of Columbia Propane. Temperatures based upon heating degree days were 2.6% colder than normal in Fiscal 2001 compared to temperatures that were 13.7% warmer than normal in Fiscal 2000. The greater acquisition and weather-related sales were reduced by customer conservation resulting from higher product costs and a slowing U.S. economy. The wholesale price of propane at Mont Belvieu, Texas, a major U.S. supply point, reached a high of 95 cents per gallon in Fiscal 2001 compared to a high of 74 cents per gallon during Fiscal 2000. Total revenues from retail propane sales increased $238.1 million reflecting a $182.1 million increase as a result of higher average selling prices and a $56.0 million increase as a result of the higher 16 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- retail volumes sold. Wholesale propane revenues increased $61.9 million principally reflecting higher average prices and greater sales associated with product cost management activities. Cost of sales increased $207.7 million as a result of higher per unit propane product costs and the greater retail and wholesale volumes sold. Total margin increased $90.6 million due to the impact of higher-than-normal average retail unit margins and, to a lesser extent, the greater retail propane volumes sold. Retail propane unit margins in Fiscal 2001 benefited from gains on derivative hedge instruments and favorably priced supply arrangements. The significant increase in EBITDA in Fiscal 2001 resulted from the increase in margin partially offset by a $37.3 million increase in Partnership operating and administrative expenses. Operating and administrative expenses of the Partnership were $380.0 million in Fiscal 2001 compared to $342.7 million in Fiscal 2000. Adjusting Fiscal 2000 expenses for the impact of the Partnership's change in accounting for tank installation costs, operating and administrative expenses of the Partnership increased $44.3 million. The higher Fiscal 2001 expenses reflect (1) higher employee-related costs, including greater overtime and incentive compensation costs; (2) growth-related expenses, including the impact of Columbia Propane and other acquisitions, and expenses associated with our PPX(R) grill cylinder exchange business; and (3) higher distribution costs, including vehicle fuel and lease expense. Depreciation and amortization expense of the Partnership increased $7.4 million reflecting greater depreciation associated with acquisitions and $4.4 million of depreciation expense resulting from the change in accounting for tank installation costs. GAS UTILITY. Although temperatures based upon heating degree days were colder in Fiscal 2001, total system throughput declined 3.0% as the impact of the colder weather was more than offset by lower interruptible and firm delivery service volumes, the impact of price-induced customer conservation, and the effects of a slowing economy. Natural gas prices were significantly higher in Fiscal 2001 than in the prior year. The higher prices resulted in fuel switching by many of our interruptible customers, who have the ability to switch to alternate fuels, and encouraged price-induced conservation by many of our firm customers. Throughput to our core-market customers increased 3.3 bcf (10.6%) reflecting the impact of the colder Fiscal 2001 weather. The significant increase in Gas Utility revenues is primarily a result of higher core-market revenues reflecting greater PGC rates and higher revenues from sales to customers not on our distribution system ("off-system sales"). Gas Utility's tariffs permit it to pass through prudently incurred gas costs to its core-market customers through higher PGC rates. Gas Utility cost of gas totaled $322.9 million in Fiscal 2001 compared with $184.2 million in Fiscal 2000 principally reflecting the higher average PGC rates and, to a lesser extent, higher core-market and off-system sales. Gas Utility total margin increased $7.1 million reflecting a $12.1 million increase in core-market margin partially offset by lower total margin from interruptible customers. The decline in interruptible margin reflects lower average interruptible unit margins due to a decline in the spread between oil and natural gas prices and the lower interruptible throughput. Gas Utility operating income increased $1.6 million as the previously mentioned increase in total margin and an increase in pension income was partially offset by higher operating and administrative expenses. The increase in operating and administrative expenses includes, among other things, greater allowances for uncollectible accounts, reflecting significantly higher Fiscal 2001 customer bills, and lower income from environmental insurance litigation settlements. Such settlements totaled $0.9 million in Fiscal 2001 compared with $4.5 million in Fiscal 2000. Depreciation expense increased $1.1 million reflecting greater depreciation associated with distribution system capital expenditures. ELECTRIC OPERATIONS. Electric Utility distribution system sales in Fiscal 2001 increased 4.2% on favorable weather. Revenues increased as a result of the higher distribution system sales as well as off-system sales of electricity generated by Energy Ventures. Cost of sales totaled $51.9 million in Fiscal 2001 compared to $34.2 million in the prior year. The increase reflects higher per-unit purchased power costs, the impact on cost of sales resulting from the formation of Energy Ventures, and the higher Fiscal 2001 sales. Electric Operations total margin decreased $12.2 million as a result of the higher purchased power costs. Operating income declined less than the decline in total margin reflecting lower power production and depreciation expenses subsequent to the formation of Energy Ventures and lower utility realty taxes. ENERGY SERVICES. Revenues from Energy Services increased significantly reflecting higher natural gas prices and acquisition-related volume growth. Energy Services acquired the energy marketing businesses of Conectiv in October 2000 and PG Energy in July 2001. Total margin and operating income were also substantially higher in Fiscal 2001 reflecting the greater acquisition-driven sales volumes and higher average unit margins. INTERNATIONAL PROPANE. FLAGA's results in Fiscal 2001 were adversely impacted by weather that was approximately 12% warmer than normal. Propane volumes sold were 8.5% lower than in Fiscal 2000 reflecting the impact of the warm weather and price-induced conservation. The increase in total margin, notwithstanding the decline in sales volumes, reflects higher unit margins partially offset by the impact of a weaker euro in Fiscal 2001. International Propane EBITDA increased in Fiscal 2001 reflecting the greater total margin and a decline in FLAGA operating expenses. International Propane loss from equity investees in Fiscal 2001 includes (1) a loss of $1.1 million from the write-off of our propane joint-venture investment in Romania and (2) $0.5 million of income associated with our investments in AGZ. CORPORATE & OTHER. The increase in Corporate & Other revenues is principally a result of HVAC, which was acquired in late Fiscal 2000. Corporate & Other operating income in Fiscal 2001 declined $10.6 million principally reflecting an $8.5 million provision for shut-down costs of Hearth USA(TM). Corporate & Other operating loss in Fiscal 2001 also includes a $2.0 million loss resulting from the write-down of an investment in a business-to-business e-commerce company, lower interest and investment income, and greater incentive compensation costs. 17 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) INTEREST EXPENSE AND INCOME TAXES. Interest expense increased $6.3 million in Fiscal 2001 primarily as a result of greater amounts of Partnership long-term debt outstanding. The effective income tax rate was 45.9% in Fiscal 2001 compared to a rate of 46.4% in Fiscal 2000. FINANCIAL CONDITION AND LIQUIDITY CAPITALIZATION AND LIQUIDITY Our cash and cash equivalents totaled $194.3 million at September 30, 2002 compared with $87.5 million at September 30, 2001. These amounts include $114.0 million and $31.9 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 principal operating subsidiaries AmeriGas, Inc. and UGI Utilities. AmeriGas, Inc.'s ability to pay dividends to UGI is largely dependent upon distributions on AmeriGas Partners' limited partner units. During Fiscal 2002, 2001 and 2000, AmeriGas, Inc. and UGI Utilities paid cash dividends to UGI as follows:
Year Ended September 30, 2002 2001 2000 ================================================================================ (Millions of dollars) AmeriGas, Inc. $49.4 $41.0 $51.6 UGI Utilities 37.9 35.3 44.0 -------------------------------------------------------------------------------- Total dividends to UGI $87.3 $76.3 $95.6 --------------------------------------------------------------------------------
Dividends received by UGI from AmeriGas, Inc. and UGI Utilities, in addition to dividends from UGI's other operating subsidiaries, are available to pay dividends on UGI Common Stock and for investment purposes. AMERIGAS PARTNERS. The Partnership's debt outstanding at September 30, 2002 totaled $955.8 million. Included in this amount is $10 million outstanding under AmeriGas OLP's Revolving Credit Facility. In December 2001, AmeriGas Partners issued 1,843,047 Common Units to the public through an underwritten public offering. In January 2002, the underwriters exercised a portion of their overallotment option in the amount of 585,000 shares. The net proceeds from these Common Unit offerings of $49.7 million, $6.9 million of proceeds from an October 2001 sale of 350,000 Common Units to the General Partner, and related capital contributions by the General Partner in order to maintain its general partner interests, were contributed to AmeriGas OLP and used to reduce Bank Credit Agreement borrowings and for working capital. The Partnership also completed a number of debt transactions during Fiscal 2002. In November 2001, AmeriGas Partners prepaid $15 million of 10.125% Senior Notes at a redemption price of 103.375%. In April 2002, AmeriGas OLP repaid $60 million of maturing First Mortgage Notes from then-existing cash balances and Revolving Credit Facility borrowings. In May 2002, AmeriGas Partners issued $40 million of Senior Notes due 2011 at an effective interest rate of 8.25%. The proceeds were contributed to AmeriGas OLP and, along with related General Partner capital contributions, used to reduce Revolving Credit Facility borrowings and for working capital and general business purposes. On December 3, 2002, after the end of Fiscal 2002, AmeriGas Partners issued $88 million principal amount of 8.875% Senior Notes due 2011 at an effective interest rate of 8.30%. The net proceeds will be used to redeem in January 2003 the remaining $85 million of 10.125% Senior Notes of AmeriGas Partners at a redemption price of 102.25%. In August 2002, AmeriGas OLP amended and restated its Bank Credit Agreement. AmeriGas OLP's Bank Credit Agreement expires October 1, 2003 and consists of (1) a $100 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. There was $10 million outstanding under this facility at September 30, 2002. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce the amount available for borrowings, totaled $19.8 million at September 30, 2002. AmeriGas OLP's short-term borrowing needs are seasonal and are typically greatest during the fall and winter heating-season months due to the need to fund higher levels of working capital. AmeriGas OLP may borrow under its Acquisition Facility to finance the purchase of propane businesses or propane business assets. In addition to the $100 million available under the Revolving Credit Facility, the Bank Credit Agreement allows up to $30 million of the Acquisition Facility to be used for working capital purposes. There were no loans outstanding under the Acquisition Facility at September 30, 2002. AmeriGas OLP could borrow up to $67.7 million under the Acquisition Facility based upon eligible capital expenditures made through September 30, 2002. AmeriGas OLP also has a credit agreement with the General Partner to borrow up to $20 million on an unsecured, subordinated basis, for working capital and general purposes. UGI has agreed to contribute up to $20 million to the General Partner to fund such borrowings. AmeriGas Partners also has debt and equity shelf registration statements with the U.S. Securities and Exchange Commission ("SEC"). The Partnership must maintain certain financial ratios in order to borrow under the Bank Credit Agreement including a minimum interest coverage ratio and a maximum debt to EBITDA ratio. The Partnership's ratios calculated as of September 30, 2002 permit it to borrow up to the maximum amount available. For a more detailed discussion of the Partnership's credit facilities, see Note 5 to Consolidated Financial Statements. Based upon existing cash balances, cash expected to be generated from operations, borrowings available under its Bank Credit Agreement, and the expected refinancing of its maturing long-term debt, the Partnership's management believes that the Partnership will be able to meet its anticipated contractual commitments and projected cash needs in Fiscal 2003. UGI UTILITIES. UGI Utilities' debt outstanding totaled $285.6 million at September 30, 2002. Included in this amount is $37.2 million under revolving credit agreements. 18 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- UGI Utilities may borrow up to a total of $97 million under its revolving credit agreements. The revolving credit agreements contain financial covenants including interest coverage ratios, debt service, and minimum tangible net worth. In September 2002, UGI Utilities issued $40 million face value of Series C Medium-Term notes under a shelf registration statement with the SEC. The proceeds of the issuance were used after the end of Fiscal 2002 principally to repay debt maturing in October 2002. UGI Utilities may issue up to an additional $85 million of debt securities under the shelf registration statement. Based upon cash expected to be generated from operations, the expected ability to refinance all or a portion of long-term debt maturing in Fiscal 2003, and borrowings available under revolving credit agreements, management believes that UGI Utilities will be able to meet its anticipated contractual and projected cash commitments in Fiscal 2003. For a more detailed discussion of UGI Utilities' debt and credit facilities, see Note 5 to Consolidated Financial Statements. ENERGY SERVICES. Energy Services has a receivables purchase facility ("Receivables Facility") with an issuer of receivables-backed commercial paper expiring November 30, 2004. Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose, bankruptcy-remote subsidiary, Energy Services Funding Corporation ("ESFC") which is consolidated for financial statement purposes. ESFC pays Energy Services for the receivables it purchases as these receivables are collected from customers. In addition, from time to time ESFC may sell an undivided interest in these receivables for up to $50 million in proceeds to a commercial paper conduit of a major bank. The proceeds of these sales are less than the face amount of the accounts receivable sold by an amount that approximates the purchaser's financing cost of issuing its own receivables-backed commercial paper. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. In accordance with a servicing arrangement, Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC. This two-step transaction is accounted for as a sale of receivables following the provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." At September 30, 2002, no receivables had been sold to the commercial paper conduit and removed from the balance sheet. During Fiscal 2002, ESFC sold a total of $34 million of receivables to the commercial paper conduit. Losses on sales of receivables that occurred during Fiscal 2002 were not material. FLAGA. FLAGA has a 15 million euro working capital loan commitment from a European bank. Borrowings under the working capital facility totaled 8.7 million euro ($8.6 million U.S. dollar equivalent) at September 30, 2002. Debt issued under this agreement, as well as $75.1 million of acquisition and special purpose debt of FLAGA, are subject to guarantees of UGI. For a more detailed discussion of FLAGA's debt, see Note 5 to Consolidated Financial Statements. FLAGA's management expects to repay long-term debt maturing in Fiscal 2003 principally through cash generated from operations as well as short-term borrowings and capital contributions from UGI. CASH FLOWS OPERATING ACTIVITIES. Cash flow from operating activities was $247.5 million in Fiscal 2002 compared to $203.5 million in Fiscal 2001. Cash flow from operating activities before considering changes in working capital was $233.7 million in Fiscal 2002 compared to $179.8 million in Fiscal 2001 principally reflecting significantly higher noncash charges for income taxes and the impact of settlement payments in Fiscal 2001 associated with the Energy Services' exchange-traded natural gas derivative hedge contracts. In Fiscal 2002, changes in operating working capital provided $13.8 million of operating cash flow compared to $23.7 million of such cash flow in Fiscal 2001. INVESTING ACTIVITIES. Cash spent for property, plant and equipment totaled $94.7 million in Fiscal 2002, an increase of $15.7 million from Fiscal 2001, reflecting a $15.6 million increase in Partnership capital expenditures principally for PPX(R), including expenditures for grill cylinder OPDs to comply with NFPA guidelines, and to a much lesser extent the full-year effect of capital expenditures associated with the Columbia Propane businesses. Cash flows from investing activities in Fiscal 2002 also include $17.7 million of cash proceeds from the early redemption of AGZ bonds in July 2002. FINANCING ACTIVITIES. During Fiscal 2002, we paid cash dividends on UGI Common Stock of $44.8 million compared to $53.2 million in Fiscal 2001. The higher dividends paid in the prior year reflect the one-time impact of a change in the timing of funding the quarterly dividend from the first day of the quarter to the last day of the previous quarter. During Fiscal 2002, AmeriGas Partners received net proceeds of $49.7 million from its public offering of 2.4 million Common Units. During Fiscal 2002, AmeriGas OLP repaid $20 million of Acquisition Facility borrowings and $60 million of maturing First Mortgage Notes, and AmeriGas Partners redeemed prior to maturity $15 million of its 10.125% Senior Notes. In addition, AmeriGas Partners issued $40 million face amount of 8.875% Senior Notes and contributed the proceeds to AmeriGas OLP to reduce indebtedness under its Revolving Credit Facility and for working capital and general business purposes. In September 2002, UGI Utilities issued $40 million face amount of 19 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) Medium-Term Notes and used the proceeds, after the end of Fiscal 2002, principally to repay maturing long-term debt. DIVIDENDS AND DISTRIBUTIONS In April 2002, our board of directors increased the annual dividend rate on UGI Common Stock to $1.65 a share from $1.60. Dividends declared on our Common Stock in Fiscal 2002 totaled $44.8 million. At September 30, 2002, our approximate 51% effective ownership interest in the Partnership consisted of (1) 14.6 million Common Units; (2) 9.9 million Subordinated Units; and (3) a 2% general partner interest. The remaining approximate 49% effective interest consisted of 24.9 million publicly held Common Units. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Amended and Restated 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 could be made on the Subordinated Units. Because certain cash-based performance and distribution requirements were met in respect of the quarter ended September 30, 2002, effective November 18, 2002 the remaining 9.9 million Subordinated Units held by the General Partner were converted to Common Units (see "Conversion of Subordinated Units" below). 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 Fiscal 2002, 2001 and 2000 was approximately $109 million, $99 million and $94 million, respectively. Based upon the number of Partnership units outstanding on September 30, 2002, the amount of Available Cash needed annually to pay the MQD on all units and the general partner interests is approximately $111 million. A reasonable proxy for the amount of cash available for distribution that is generated by the Partnership can be calculated by subtracting from the Partnership's EBITDA (1) cash interest expense and (2) capital expenditures needed to maintain operating capacity. Partnership distributable cash flow as calculated under this method for Fiscal 2002, 2001 and 2000 is as follows:
Year Ended September 30, 2002 2001 2000 ================================================================================ (Millions of dollars) EBITDA $210.4 $208.6 $157.6 Cash interest expense (a) (88.5) (82.0) (76.7) Maintenance capital expenditures (20.7) (17.8) (11.6) -------------------------------------------------------------------------------- Distributable cash flow $101.2 $108.8 $ 69.3 --------------------------------------------------------------------------------
(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, among other things, the impact of changes in working capital, which can significantly affect cash available for distribution, and is not a measure of performance or financial condition under accounting principles generally accepted in the United States but provides additional information for evaluating the Partnership's ability to declare and pay the MQD. The Partnership's definition of distributable cash flow may be different from the definition used by other companies. Although the levels of distributable cash flow in Fiscal 2002 and 2000 were less than the full MQD, other sources of cash, including cash from equity offerings and borrowings, was more than sufficient to permit the Partnership to pay the full MQD. The ability of the Partnership to 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, the cost of propane and changes in capital market conditions. CONVERSION OF AMERIGAS PARTNERS SUBORDINATED UNITS Pursuant to the Agreement of Limited Partnership of AmeriGas Partners, the 9.9 million AmeriGas Partners Subordinated Units held by the General Partner as of September 30, 2002 were 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 certain cash-based performance and distribution requirements were met. In December 2002, the General Partner determined that the cash-based performance and distribution requirements in respect of the quarter ended September 30, 2002 had been met and, as a result, the remaining 9.9 million Subordinated Units held by the Company were converted to Common Units effective November 18, 2002. Concurrent with the Subordinated Unit conversion, the Company recorded an increase in common stockholders' equity and a decrease in minority interest of approximately $160 million associated with gains from sales of Common Units by AmeriGas Partners in conjunction with, and subsequent to, its April 19, 1995 initial public offering in accordance with the accounting guidance in SEC Staff Accounting Bulletin No. 51, "Accounting for Sales of Common Stock by a Subsidiary." The gains result because the public offering prices of the AmeriGas Partners Common Units at the dates of their sales exceeded the associated carrying amount of our investment in the Partnership. No deferred taxes were recorded related to the gains due to the Company's intent to hold its investment in the Partnership indefinitely. The changes to the Company's balance sheet resulting from the Subordinated Unit conversion had no effect on the Company's net income or cash flow. The conversion of the Subordinated Units did not result in an increase in the number of AmeriGas Partners limited partner units outstanding. REDEMPTION OF AGZ BONDS In July 2002, the Company received $19.3 million in cash from AGZ representing repayment of 18 million euro face value (90%), $17.7 million U.S. dollar equivalent, of redeemable bonds of AGZ ("AGZ Bonds") held by the Company, plus accrued interest. This repayment was funded from the proceeds of an AGZ placement of high-yield debt. The Company purchased the AGZ Bonds on March 27, 2001 in conjunction with its joint-venture investment, through AGZ, in Antargaz, a leading distributor of propane and related gases in France. Concurrent with the repayment, the remaining 2.0 million 20 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- euro (10%) investment in AGZ Bonds was converted to additional shares of AGZ. The Company recorded a pretax currency transaction gain of $1.6 million as a result of the repayment of the AGZ Bonds. After these transactions, the Company continues to hold an approximate 19.5% equity investment in AGZ. UGI UTILITIES PENSION PLAN UGI Utilities sponsors a defined benefit pension plan ("Pension Plan") for employees of UGI, UGI Utilities, and certain of UGI's other subsidiaries. During Fiscal 2002 and 2001, the market value of plan assets was negatively affected by persistent declines in the equity markets. Notwithstanding the significant decline in the market value of plan assets during these years, at September 30, 2002 the Pension Plan's assets exceeded its accumulated benefit obligations by approximately $7.2 million. The Company is in full compliance with regulations governing defined benefit pension plans, including ERISA rules and regulations, and does not anticipate it will be required to make a contribution to the Pension Plan in Fiscal 2003. Pretax pension income reflected in Fiscal 2002, 2001 and 2000 was $4.0 million, $5.9 million, and $3.0 million, respectively. Pension income in Fiscal 2003 is expected to decline to approximately $1.0 million principally as a result of the impact of declines through September 2002 in the market value of Pension Plan assets. CAPITAL EXPENDITURES In the following table, we present capital expenditures (which include expenditures for capital leases but exclude acquisitions) by business segment for Fiscal 2002, 2001 and 2000. We also provide amounts we expect to spend in Fiscal 2003. We expect to finance Fiscal 2003 capital expenditures principally from cash generated by operations and borrowings under our credit facilities.
Year Ended September 30, 2003 2002 2001 2000 ================================================================================ (Millions of dollars) (estimate) AmeriGas Propane $ 52.2 $ 53.5 $ 39.2 $ 30.4 UGI Utilities 44.9 35.9 36.8 36.4 International Propane 5.9 4.0 2.7 1.8 Other 1.8 1.3 0.6 2.4 -------------------------------------------------------------------------------- Total $ 104.8 $ 94.7 $ 79.3 $ 71.0 --------------------------------------------------------------------------------
CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS The following table presents significant contractual cash obligations under agreements existing as of September 30, 2002 (in millions).
Fiscal Fiscal 2003 & 2004 2005 & 2006 Thereafter Total ================================================================================ Long-term debt $207.0 $ 296.8 $771.9 $1,275.7 UGI Utilities preferred - 2.0 18.0 20.0 stock Operating leases 71.7 50.8 63.6 186.1 Energy Services supply contracts 157.5 - - 157.5 Gas and Electric utility supply contracts 202.9 80.2 107.3 390.4 -------------------------------------------------------------------------------- Total $639.1 $ 429.8 $960.8 $2,029.7 --------------------------------------------------------------------------------
UTILITY REGULATORY MATTERS The Pennsylvania Public Utility Commission ("PUC") approved a settlement establishing rules for Electric Utility Provider of Last Resort ("POLR") service on March 28, 2002, and a separate settlement that modified these rules on June 13, 2002 (collectively the "POLR Settlement"). Under the terms of the POLR Settlement, Electric Utility terminated stranded cost recovery through its Competitive Transition Charge ("CTC") from commercial and industrial ("C&I") customers on July 31, 2002, and from residential customers on October 31, 2002, and is no longer subject to the statutory rate caps as of August 1, 2002 for C&I customers and as of November 1, 2002 for residential customers. Stranded costs are electric generation-related costs that traditionally would be recoverable in a regulated environment but may not be recoverable in a competitive electric generation market. Charges for generation service will (1) initially be set at a level equal to the rates paid by Electric Utility customers for POLR service under the statutory rate caps; (2) may be raised at certain designated times up to certain specified caps through December 2004; and (3) may be set at market rates thereafter. Electric Utility may also offer multiple year POLR contracts to its customers. The POLR Settlement provides for annual shopping periods during which customers may elect to remain on POLR service or choose an alternate supplier. Customers who do not select an alternate supplier will be obligated to remain on POLR service until the next shopping period. Residential customers who return to POLR service at a time other than during the annual shopping period must remain on POLR service until the date of the second open shopping period after returning. C&I customers who return to POLR service at a time other than during the annual shopping period must remain on POLR service until the next open shopping period, and may, in certain circumstances, be subject to generation rate surcharges. On June 29, 2000, the PUC issued its order ("Gas Restructuring Order") approving Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's Natural Gas Choice and Competition Act. Among other things, the implementation of the Gas Restructuring Order resulted in an increase in Gas Utility's core-market base rates effective October 1, 2000. This base rate increase was designed to generate approximately $16.7 million in additional net annual revenues. In accordance with the Gas Restructuring Order, Gas Utility reduced its core-market PGC rates by an annualized amount of $16.7 million in the first 14 months following the October 1, 2000 base rate increase. Effective December 1, 2001, Gas Utility was required to reduce its PGC rates by amounts equal to the margin it receives from interruptible customers using pipeline capacity contracted by Gas Utility for core-market customers. As a result, Gas Utility operating results are more sensitive to the effects of heating-season weather and less sensitive to the market prices of alternative fuels. MANUFACTURED GAS PLANTS From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of manufactured gas plants ("MGPs") prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, UGI Utilities divested all of its utility operations other than those which now constitute Gas Utility and Electric Utility. UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. UGI Utilities has been notified of several sites outside 21 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) Pennsylvania on which (1) MGPs were formerly operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or private parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating two claims against it relating to out-of-state sites. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that the subsidiary's separate corporate form should be disregarded. UGI Utilities has filed suit against more than fifty insurance companies alleging that the defendants breached contracts of insurance by failing to indemnify UGI Utilities for certain environmental costs. The suit seeks to recover more than $11 million in such costs. During Fiscal 2002, 2001 and 2000, UGI Utilities entered into settlement agreements with several of the insurers and recorded pretax income of $0.4 million, $0.9 million and $4.5 million, respectively, which amounts are included in operating and administrative expenses in the Consolidated Statements of Income. MARKET RISK DISCLOSURES Our primary market risk exposures are (1) market prices for propane, natural gas and electricity; (2) changes in interest rates; and (3) foreign currency exchange rates. The risk associated with fluctuations in the prices the Partnership and our International Propane operations pay for propane is principally a result of market forces reflecting changes in supply and demand for propane and other energy commodities. The Partnership's profitability is sensitive to changes in propane supply costs, and the Partnership generally attempts to pass on increases in such costs to customers. The Partnership may not, however, always be able to pass through product cost increases fully, particularly when product costs rise rapidly. In order to reduce the volatility of the Partnership's propane market price risk, it uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements, and over-the-counter derivative commodity instruments including price swap and option contracts. International Propane's profitability is also sensitive to changes in propane supply costs. On occasion, FLAGA uses derivative commodity instruments to reduce market risk associated with a portion of its propane purchases. Over-the-counter derivative commodity instruments utilized by the Partnership and FLAGA to hedge forecasted purchases of propane are generally settled at expiration of the contract. In order to minimize credit risk associated with its derivative commodity contracts, the Partnership monitors established credit limits with the contract counterparties. 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. Gas Utility's tariffs contain clauses that permit recovery of substantially all of the prudently incurred cost of natural gas it sells to its customers. The recovery clauses provide for a periodic adjustment for the difference between the total amount actually collected from customers and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. During Fiscal 2002, 2001 and 2000, Electric Utility purchased all of its electric power needs, in excess of the electric power it obtained from its interests in electric generating facilities, under power supply arrangements of various lengths and on the spot market. Beginning September 2002, Electric Utility began purchasing its power needs from electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market, and our electricity generation businesses began selling on the spot market electric power produced from its interests in electricity generating facilities to third parties. Prices for electricity can be volatile especially during periods of high demand or tight supply. Although the generation component of Electric Utility's rates is subject to various rate cap provisions as a result of the Electricity Restructuring Order and the POLR Settlement, Electric Utility's fixed-price contracts with electricity suppliers mitigate most risks associated with offering customers a fixed price during the contract periods. However, should any of the suppliers under these contracts fail to provide electric power under the terms of the power and capacity contracts, increases, if any, in the cost of replacement power or capacity would negatively impact Electric Utility results. In order to reduce this non-performance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. In order to manage market price risk relating to substantially all of Energy Services' forecasted fixed-price sales of natural gas, we purchase exchange-traded natural gas futures contracts or enter into fixed-price supply arrangements. Exchange-traded natural gas futures contracts are guaranteed by the New York Mercantile Exchange ("NYMEX") and have nominal credit risk. The change in market value of these contracts generally requires daily cash deposits in margin accounts with brokers. Although Energy Services' fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the natural gas suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas would adversely impact Energy Services' results. In order to reduce this risk of supplier nonperformance, Energy Services has diversified its purchases across a number of suppliers. We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact its fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows. 22 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- Our variable-rate debt includes borrowings under AmeriGas OLP's Bank Credit Agreement, borrowings under UGI Utilities' revolving credit agreements, and a substantial portion of FLAGA's debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. At September 30, 2002 and 2001, combined borrowings outstanding under these agreements totaled $131.0 million and $162.3 million, respectively. Based upon weighted average borrowings outstanding under these agreements during Fiscal 2002 and Fiscal 2001, an increase in short-term interest rates of 100 basis points (1%) would have increased our interest expense by $1.4 million and $2.4 million, respectively. The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of $52.5 million and $57.9 million at September 30, 2002 and 2001, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $56.4 million and $58.8 million at September 30, 2002 and 2001, respectively. Our long-term debt is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may 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. In order to reduce interest rate risk associated with near-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements. The primary currency for which the Company has exchange rate risk is the U.S. dollar versus the euro. We do not currently use derivative instruments to hedge foreign currency exposure associated with our international propane businesses, principally FLAGA and Antargaz. 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. With respect to FLAGA, the net effect of changes in foreign currency exchange rates on assets and liabilities has been significantly limited because FLAGA's U.S. dollar denominated financial instrument assets and liabilities are substantially equal in amount. With respect to our equity investment in Antargaz, a 10% decline in the value of the euro versus the U.S. dollar would reduce the book value of this investment by approximately $2.0 million, which amount would be reflected in other comprehensive income. The following table summarizes the fair values of unsettled market risk sensitive derivative instruments held at September 30, 2002 and 2001. 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; and (3) interest rates on ten-year U.S. treasury notes of 100 basis points.
Change in Fair Value Fair Value ================================================================================ (Millions of dollars) September 30, 2002: Propane commodity price risk $ 9.8 $(11.1) Natural gas commodity price risk 5.1 (6.0) Interest rate risk (4.0) (6.6) September 30, 2001: Propane commodity price risk $(10.5) $(19.3) Natural gas commodity price risk (1.5) (2.2) Interest rate risk (3.0) (4.2) --------------------------------------------------------------------------------
Because the Company's derivative instruments generally qualify as hedges under SFAS 133, we expect that changes in the fair value of derivative instruments used to manage commodity or interest rate market risk would be substantially offset by gains or losses on the associated anticipated transactions. CRITICAL ACCOUNTING POLICIES AND ESTIMATES In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," the Company has identified the following critical accounting policies that are most important to the portrayal of the Company's financial condition and results of operations. The following policies require management's most subjective or complex judgments, as a result of the need to make estimates regarding matters that are inherently uncertain. LITIGATION ACCRUALS AND ENVIRONMENTAL REMEDIATION LIABILITIES. We are involved in litigation regarding pending claims and legal actions that arise in the normal course of our businesses. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere at which hazardous substances may be present. In accordance with accounting principles generally accepted in the United States, the Company establishes reserves for pending claims and legal actions or environmental remediation obligations when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Reasonable estimates involve management judgments based on a broad range of information and prior experience. These judgments are reviewed quarterly as more information is received and the amounts reserved are updated as necessary. Such estimated reserves may differ materially from the actual liability, and such reserves may change materially as more information becomes available and estimated reserves are adjusted. REGULATORY ASSETS AND LIABILITIES. Gas Utility and Electric Utility are subject to regulation by the Pennsylvania Public Utility Commission ("PUC"). In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and 23 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) public statements issued by the PUC and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations. DEPRECIATION AND AMORTIZATION OF LONG-LIVED ASSETS. We compute depreciation on UGI Utilities property, plant and equipment on a straight-line basis over the average remaining lives of its various classes of depreciable property and on other property, plant and equipment on a straight-line basis over estimated useful lives generally ranging from two to 40 years. We also use amortization methods and determine asset values of intangible assets other than goodwill using reasonable assumptions and projections. Changes in the estimated useful lives of property, plant and equipment and changes in intangible asset amortization methods or values could have a material effect on our results of operations. As of September 30, 2002, our regulatory assets totaled $62.0 million. IMPAIRMENT OF GOODWILL. Certain of the Company's business units have goodwill resulting from purchase business combinations. In accordance with SFAS 142, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, management must determine the reporting unit's fair value using quoted market prices or, in the absence of quoted market prices, valuation techniques which use discounted estimates of future cash flows to be generated by the reporting unit. These cash flow estimates involve management judgments based on a broad range of information and historical results. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill which would adversely impact our results of operations. As of September 30, 2002, our goodwill totaled $644.9 million. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS The Financial Accounting Standards Board ("FASB") recently issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"); SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"); SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" ("SFAS 145"); and SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 143 addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with a corresponding increase in the carrying value of the related asset. Entities shall subsequently charge the retirement cost to expense using a systematic and rational method over the related asset's useful life and adjust the fair value of the liability resulting from the passage of time through charges to operating expense. We adopted SFAS 143 effective October 1, 2002. The adoption of SFAS 143 did not have a material effect on our financial position or results of operations. Our joint venture, AGZ Holdings, is required to adopt SFAS 143 effective April 1, 2003. We are currently in the process of evaluating the impact of SFAS 143 on AGZ Holdings. SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," as it relates to the disposal of a segment of a business. SFAS 144 establishes a single accounting model for long-lived assets to be disposed of based upon the framework of SFAS 121, and resolves significant implementation issues of SFAS 121. We adopted SFAS 144 effective October 1, 2002. The adoption of SFAS 144 did not affect our financial position or results of operations. SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"), effective May 15, 2002. SFAS 4 had required that material gains and losses on extinguishment of debt be classified as an extraordinary item. Under SFAS 145, it is less likely that a gain or loss on extinguishment of debt would be classified as an extraordinary item in our Consolidated Statement of Income. Among other things, SFAS 145 also amends SFAS 13, "Accounting for Leases," to require that certain lease modifications that have economic effects similar to sale-leaseback transactions be accounted for in the same manner as sale-leaseback transactions. The provisions of SFAS 145 relating to leases became effective for transactions occurring after May 15, 2002. The adoption of SFAS 145 did not affect our financial position or results of operations. SFAS 146 addresses accounting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force ("EITF") No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." Generally, SFAS 146 requires that a liability for costs associated with an exit or disposal activity, including contract termination costs, employee termination benefits and other associated costs, be recognized when the liability is incurred. Under EITF No. 94-3, a liability was recognized at the date of an entity's commitment to an exit plan. SFAS 146 will be effective for disposal activities initiated after December 31, 2002. FORWARD-LOOKING STATEMENTS Information contained in this Financial Review and elsewhere in this Annual Report may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as "believe," "plan," "anticipate," "continue," "estimate," "expect," "may," "will," or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future. A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that 24 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability of propane, oil, electricity, and natural gas and the capacity to transport to market areas; (3) changes in laws and regulations, including safety, tax and accounting matters; (4) competitive pressures from the same and alternative energy sources; (5) failure to acquire new customers thereby reducing or limiting any increase in revenues; (6) liability for environmental claims; (7) customer conservation measures and improvements in energy efficiency and technology resulting in reduced demand; (8) adverse labor relations; (9) large customer, counterparty or supplier defaults; (10) liability for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and propane including liability in excess of insurance coverage; (11) political, regulatory and economic conditions in the United States and 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. -------------------------------------------------------------------------------- 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 of America and include amounts that are based on management's best judgments and estimates. The Company maintains a system of internal controls. Management believes the system provides reasonable, but not absolute, 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 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 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 accountants and internal auditors. The independent 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 of America, 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 25 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- REPORT OF INDEPENDENT ACCOUNTANTS TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF UGI CORPORATION: In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, stockholders' equity and cash flows present fairly, in all material respects, the financial position of UGI Corporation and its subsidiaries at September 30, 2002 and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The consolidated financial statements of UGI Corporation and its subsidiaries as of September 30, 2001, and for each of the two years in the period ended September 30, 2001, were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statements in their report dated November 16, 2001. As discussed in Note 1 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, in fiscal 2002. /S/ PRICEWATERHOUSECOOPERS LLP Philadelphia, Pennsylvania November 15, 2002, except for Note 18 as to which the date is December 16, 2002 -------------------------------------------------------------------------------- THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED ACCOUNTANT'S REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF UGI CORPORATION: We have audited the accompanying consolidated balance sheets of UGI Corporation and subsidiaries as of September 30, 2001 and 2000, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended September 30, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of UGI Corporation and subsidiaries as of September 30, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Notes 1 and 3 to the financial statements, effective October 1, 2000, the Partnership changed its methods of accounting for tank installation costs and nonrefundable tank fees and the Company adopted the provisions of SFAS No. 133. /S/ ARTHUR ANDERSEN LLP Philadelphia, Pennsylvania November 16, 2001 26 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF INCOME (Millions of dollars, except per share amounts)
Year Ended September 30, --------------------------------------------------------- 2002 2001 2000 ==================================================================================================================================== REVENUES AmeriGas Propane $ 1,307.9 $ 1,418.4 $ 1,120.1 UGI Utilities 490.5 584.7 436.9 International Propane 46.7 50.9 50.5 Energy Services and other 368.6 414.1 154.2 ------------------------------------------------------------------------------------------------------------------------------------ 2,213.7 2,468.1 1,761.7 ------------------------------------------------------------------------------------------------------------------------------------ COSTS AND EXPENSES AmeriGas Propane cost of sales 632.1 836.0 628.3 UGI Utilities - gas, fuel and purchased power 290.3 374.8 218.1 International Propane cost of sales 22.6 28.4 29.7 Energy Services and other cost of sales 330.6 382.2 145.5 Operating and administrative expenses 597.5 517.8 461.2 Utility taxes other than income taxes 11.9 9.2 17.1 Depreciation and amortization 93.5 105.2 97.5 Provision for shut-down costs - Hearth USA(TM) -- 8.5 -- Other income, net (17.4) (23.0) (27.8) ------------------------------------------------------------------------------------------------------------------------------------ 1,961.1 2,239.1 1,569.6 ------------------------------------------------------------------------------------------------------------------------------------ OPERATING INCOME 252.6 229.0 192.1 Income (loss) from equity investees 8.5 (1.6) (0.9) Interest expense (109.1) (104.8) (98.5) Minority interests in AmeriGas Partners (28.0) (23.6) (6.3) ------------------------------------------------------------------------------------------------------------------------------------ INCOME BEFORE INCOME TAXES, SUBSIDIARY PREFERRED STOCK DIVIDENDS AND ACCOUNTING CHANGES 124.0 99.0 86.4 Income taxes (46.9) (45.4) (40.1) Dividends on UGI Utilities Series Preferred Stock (1.6) (1.6) (1.6) ------------------------------------------------------------------------------------------------------------------------------------ Income before accounting changes 75.5 52.0 44.7 Cumulative effect of accounting changes, net -- 4.5 -- ------------------------------------------------------------------------------------------------------------------------------------ NET INCOME $ 75.5 $ 56.5 $ 44.7 ==================================================================================================================================== EARNINGS PER COMMON SHARE Basic: Income before accounting changes $ 2.74 $ 1.91 $ 1.64 Cumulative effect of accounting changes, net -- 0.17 -- ------------------------------------------------------------------------------------------------------------------------------------ Net income $ 2.74 $ 2.08 $ 1.64 ==================================================================================================================================== Diluted: Income before accounting changes $ 2.70 $ 1.90 $ 1.64 Cumulative effect of accounting changes, net -- 0.16 -- ------------------------------------------------------------------------------------------------------------------------------------ Net income $ 2.70 $ 2.06 $ 1.64 ==================================================================================================================================== AVERAGE COMMON SHARES OUTSTANDING (MILLIONS) Basic 27.550 27.163 27.219 ==================================================================================================================================== Diluted 27.938 27.373 27.255 ====================================================================================================================================
See accompanying notes to consolidated financial statements. 27 -------------------------------------------------------------------------------- CONSOLIDATED BALANCE SHEETS (Millions of dollars)
September 30, ---------------------------- ASSETS 2002 2001 ==================================================================================================================================== CURRENT ASSETS Cash and cash equivalents $ 194.3 $ 87.5 Accounts receivable (less allowances for doubtful accounts of $11.8 and $15.6, respectively) 157.7 180.8 Accrued utility revenues 8.1 11.1 Inventories 109.2 128.6 Deferred income taxes 10.4 25.2 Income taxes recoverable 1.7 -- Utility deferred fuel costs 4.3 -- Prepaid expenses and other current assets 44.3 25.7 ------------------------------------------------------------------------------------------------------------------------------------ Total current assets 530.0 458.9 ------------------------------------------------------------------------------------------------------------------------------------ PROPERTY, PLANT AND EQUIPMENT AmeriGas Propane 1,028.6 984.0 UGI Utilities 883.3 855.2 Other 80.5 74.3 ------------------------------------------------------------------------------------------------------------------------------------ 1,992.4 1,913.5 Accumulated depreciation and amortization (720.5) (645.5) ------------------------------------------------------------------------------------------------------------------------------------ Net property, plant, and equipment 1,271.9 1,268.0 ------------------------------------------------------------------------------------------------------------------------------------ OTHER ASSETS Goodwill and excess reorganization value 644.9 641.1 Intangible assets (less accumulated amortization of $10.3 and $5.8, respectively) 25.8 31.3 Utility regulatory assets 57.7 56.2 Other assets 84.1 94.7 ------------------------------------------------------------------------------------------------------------------------------------ Total assets $2,614.4 $2,550.2 ====================================================================================================================================
See accompanying notes to consolidated financial statements. 28 UGI Corporation 2002 Annual Report --------------------------------------------------------------------------------
September 30, ------------------------------------- LIABILITIES AND STOCKHOLDERS' EQUITY 2002 2001 ============================================================================================================================= CURRENT LIABILITIES Current maturities of long-term debt $ 148.7 $ 98.3 AmeriGas Propane bank loans 10.0 -- UGI Utilities bank loans 37.2 57.8 Other bank loans 8.6 10.0 Accounts payable 166.1 167.0 Employee compensation and benefits accrued 35.4 39.4 Dividends and interest accrued 41.5 38.4 Income taxes accrued -- 11.6 Deposits and advances 63.0 55.6 Other current liabilities 75.9 89.4 ----------------------------------------------------------------------------------------------------------------------------- Total current liabilities 586.4 567.5 ----------------------------------------------------------------------------------------------------------------------------- DEBT AND OTHER LIABILITIES Long-term debt 1,127.0 1,196.9 Deferred income taxes 200.2 182.4 Deferred investment tax credits 8.4 8.8 Other noncurrent liabilities 79.1 72.8 Commitments and contingencies (note 13) MINORITY INTERESTS Minority interests in AmeriGas Partners 276.0 246.2 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) 396.6 395.0 Retained earnings 39.7 9.0 Accumulated other comprehensive income (loss) 6.6 (13.5) ----------------------------------------------------------------------------------------------------------------------------- 442.9 390.5 Treasury stock, at cost (125.6) (134.9) ----------------------------------------------------------------------------------------------------------------------------- Total common stockholders' equity 317.3 255.6 ----------------------------------------------------------------------------------------------------------------------------- Total liabilities and stockholders' equity $2,614.4 $2,550.2 =============================================================================================================================
29 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of dollars)
Year Ended September 30, ---------------------------------------------------- 2002 2001 2000 ==================================================================================================================================== CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 75.5 $ 56.5 $ 44.7 Reconcile to net cash provided by operating activities: Depreciation and amortization 93.5 105.2 97.5 Cumulative effect of accounting changes, net -- (4.5) -- Minority interests in AmeriGas Partners 28.0 23.6 6.3 Deferred income taxes, net 11.0 (5.5) 3.2 Net change in settled accumulated other comprehensive income 13.3 (16.9) -- Other, net 12.4 21.4 15.8 Net change in: Accounts receivable and accrued utility revenues 12.6 (13.6) (63.4) Inventories 19.7 (4.2) (26.1) Deferred fuel costs (7.1) 9.9 (3.8) Accounts payable (0.4) 5.8 52.0 Other current assets and liabilities (11.0) 25.8 6.5 ------------------------------------------------------------------------------------------------------------------------------------ Net cash provided by operating activities 247.5 203.5 132.7 ------------------------------------------------------------------------------------------------------------------------------------ CASH FLOWS FROM INVESTING ACTIVITIES Expenditures for property, plant and equipment (94.7) (78.0) (71.0) Acquisitions of businesses, net of cash acquired (0.7) (209.1) (65.3) Proceeds from redemption of AGZ Bonds 17.7 -- -- Net proceeds from disposals of assets 9.7 4.2 8.4 Investments in equity investees (0.3) (32.6) -- Other, net 1.9 2.2 6.4 ------------------------------------------------------------------------------------------------------------------------------------ Net cash used by investing activities (66.4) (313.3) (121.5) ------------------------------------------------------------------------------------------------------------------------------------ CASH FLOWS FROM FINANCING ACTIVITIES Dividends on UGI Common Stock (44.8) (53.2) (41.2) Distributions on AmeriGas Partners publicly held Common Units (53.5) (44.3) (39.1) Issuance of long-term debt 81.1 308.2 209.7 Repayment of long-term debt (105.0) (137.0) (95.4) AmeriGas Propane bank loans increase (decrease) 10.0 (30.0) 8.0 UGI Utilities bank loans increase (decrease) (20.6) (42.6) 13.0 Other bank loans increase (decrease) (2.2) 6.2 (6.8) Issuance of AmeriGas Partners Common Units 49.7 39.8 -- Proceeds from sale of AmeriGas OLP interest -- 50.0 -- Issuance of UGI Common Stock 11.0 7.6 3.8 Repurchases of UGI Common Stock -- (1.0) (9.6) ------------------------------------------------------------------------------------------------------------------------------------ Net cash provided (used) by financing activities (74.3) 103.7 42.4 ------------------------------------------------------------------------------------------------------------------------------------ EFFECT OF EXCHANGE RATE CHANGES ON CASH -- (0.3) (0.2) ------------------------------------------------------------------------------------------------------------------------------------ Cash and cash equivalents increase (decrease) $106.8 $ (6.4) $ 53.4 ==================================================================================================================================== CASH AND CASH EQUIVALENTS: End of year $194.3 $ 87.5 $ 93.9 Beginning of year 87.5 93.9 40.5 ------------------------------------------------------------------------------------------------------------------------------------ Increase (decrease) $106.8 $ (6.4) $ 53.4 ====================================================================================================================================
See accompanying notes to consolidated financial statements. 30 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Millions of dollars, except per share amounts)
Retained Accumulated Unearned Earnings Other Compensation- Common (Accumulated Comprehensive Restricted Treasury Stock Deficit) Income (Loss) Stock Stock Total ================================================================================================================================= 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 gains 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 reacquired (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 Net income 56.5 56.5 Cumulative effect of change in accounting principle - SFAS No. 133 (net of tax of $4.8) 7.1 7.1 Net loss on derivative instruments (net of tax of $7.9) (10.5) (10.5) Reclassification of net gains on derivative instruments (net of tax of $6.5) (10.3) (10.3) Foreign currency translation adjustments (net of tax of $0.1) 0.2 0.2 --------- --------- --------- Comprehensive income 56.5 (13.5) 43.0 Cash dividends on Common Stock ($1.575 per share) (42.6) (42.6) Common Stock issued: Employee and director plans 0.3 5.5 5.8 Dividend reinvestment plan 0.2 2.3 2.5 Common Stock reacquired (1.0) (1.0) Amortization of unearned compensation- restricted stock awards 0.7 0.7 --------------------------------------------------------------------------------------------------------------------------------- BALANCE SEPTEMBER 30, 2001 395.0 9.0 (13.5) -- (134.9) 255.6 Net income 75.5 75.5 Net loss on derivative instruments (net of tax of $0.4) (1.5) (1.5) Reclassification of net losses on derivative instruments (net of tax of $11.6) 18.3 18.3 Foreign currency translation adjustments (net of tax of $2.2) 4.4 4.4 Reclassification of foreign currency translation gain (net of tax of $0.5) (1.1) (1.1) --------- --------- --------- Comprehensive income 75.5 20.1 95.6 Cash dividends on Common Stock ($1.625 per share) (44.8) (44.8) Common Stock issued: Employee and director plans 1.0 7.4 8.4 Dividend reinvestment plan 0.6 2.0 2.6 Common Stock reacquired (0.1) (0.1) --------------------------------------------------------------------------------------------------------------------------------- BALANCE SEPTEMBER 30, 2002 $ 396.6 $ 39.7 $ 6.6 $ -- $ (125.6) $ 317.3 =================================================================================================================================
See accompanying notes to consolidated financial statements. 31 -------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) NOTE 1 - ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION. UGI Corporation ("UGI") is a holding company that owns and operates natural gas and electric utility, electricity generation, propane distribution, energy marketing and related businesses in the United States. Through foreign subsidiaries and joint-venture affiliates, UGI also distributes propane in Austria, the Czech Republic, Slovakia, France and China. We refer to UGI and its consolidated subsidiaries collectively as "the Company" or "we." Our utility business is conducted through our wholly owned subsidiary, UGI Utilities, Inc. ("UGI Utilities"). UGI Utilities owns and operates (1) a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and (2) an electricity distribution utility ("Electric Utility") and electricity generation business (which together with Electric Utility are referred to herein as "Electric Operations") in northeastern Pennsylvania. We conduct a national propane distribution business through AmeriGas Partners, L.P. ("AmeriGas Partners") and its principal operating subsidiaries AmeriGas Propane, L.P. ("AmeriGas OLP") and AmeriGas Eagle Propane, L.P. ("Eagle OLP"). AmeriGas Partners, AmeriGas OLP and Eagle OLP are Delaware limited partnerships. UGI's wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the "General Partner") serves as the general partner of AmeriGas Partners and AmeriGas OLP. AmeriGas OLP and Eagle OLP (collectively referred to as "the Operating Partnerships") comprise the largest retail propane distribution business in the United States serving residential, commercial, industrial, motor fuel and agricultural customers from locations in 46 states. We refer to AmeriGas Partners and its subsidiaries together as "the Partnership" and the General Partner and its subsidiaries, including the Partnership, as "AmeriGas Propane." At September 30, 2002, the General Partner and its wholly owned subsidiary Petrolane Incorporated ("Petrolane," a predecessor company of AmeriGas OLP) collectively held a 1% general partner interest and a 49.1% limited partner interest in AmeriGas Partners, and effective 50.6% and 50.5% ownership interests in AmeriGas OLP and Eagle OLP, respectively. Our limited partnership interest in AmeriGas Partners comprised 14,633,932 Common Units and 9,891,072 Subordinated Units. The remaining 49.9% interest in AmeriGas Partners comprises 24,907,354 publicly held Common Units representing limited partner interests. Effective November 18, 2002, the remaining 9,891,072 Subordinated Units held by us were converted to Common Units (see Note 18). The Partnership has no employees. Employees of the General Partner conduct, direct and manage the activities of AmeriGas Partners and AmeriGas OLP. The General Partner also provides management and administrative services to AmeriGas Eagle Holdings, Inc., the general partner of Eagle OLP, under a management services agreement. The General Partner is reimbursed monthly for all direct and indirect expenses it incurs 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 the Partnership's significant minority interest; higher relative interest charges; and, prior to 2002, higher effective income taxes associated with the Partnership's pretax income resulting from nondeductible goodwill amortization. Our wholly owned subsidiary UGI Enterprises, Inc. ("Enterprises") conducts an energy marketing business primarily in the Middle Atlantic region of the United States through its wholly owned subsidiary, UGI Energy Services, Inc. ("Energy Services"). Through other subsidiaries, Enterprises (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 in the Middle Atlantic states ("HVAC"); and (3) participates in propane joint-venture businesses in France and China. UGI is exempt from registration as a holding company because it files an annual exemption statement with the U.S. Securities and Exchange Commission ("SEC") 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"). CONSOLIDATION PRINCIPLES. The 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's limited partner interests in the Partnership as minority interests. Entities in which we own 50 percent or less and in which we exercise significant influence over operating and financial policies are accounted for by the equity method (see Note 19). Investments in equity investees are included in other assets in the Consolidated Balance Sheets. 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 (collectively, "Utilities") are subject to regulation by the PUC. We account for Gas Utility and Electric Utility in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71"). SFAS 71 requires us to record the effects of rate regulation in the financial statements. If a separable portion of Gas Utility or Electric Utility no longer meets the provisions of SFAS 71, we are required to eliminate the financial statement effects of regulation for that portion of our operations. On June 29, 2000, the PUC entered its order ("Gas Restructuring Order") in Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's Natural Gas Choice and Competition Act ("Gas Competition Act"). Based upon the provisions of the Gas Restructuring Order and the Gas Competition Act, we believe Gas Utility's regulatory assets continue to satisfy the criteria of SFAS 71. For further information on the impact of 32 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- the Gas Competition Act and Pennsylvania's Electricity Customer Choice and Competition Act ("Electricity Choice Act"), see Note 4. DERIVATIVE INSTRUMENTS. Effective October 1, 2000, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. To the extent a derivative instrument qualifies and is designated as a hedge of the variability of cash flows associated with a forecasted transaction ("cash flow hedge"), the effective portion of the gain or loss on such derivative instrument is generally reported in other comprehensive income and the ineffective portion, if any, is reported in net income. Such amounts reported in other comprehensive income are reclassified into net income when the forecasted transaction affects earnings. If a cash flow hedge is discontinued because it is probable that the forecasted transaction will not occur, the net gain or loss is immediately reclassified into net income. To the extent derivative instruments qualify and are designated as hedges of changes in the fair value of an existing asset, liability or firm commitment ("fair value hedge"), the gain or loss on the hedging instrument is recognized in earnings along with changes in the fair value of the hedged asset, liability or firm commitment attributable to the hedged risk. The adoption of SFAS 133 resulted 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. The increase in accumulated other comprehensive income is attributable to net gains on derivative instruments designated and qualifying as cash flow hedges on October 1, 2000. Prior to the adoption of SFAS 133, gains or losses on derivative instruments associated with forecasted transactions generally were recorded in net income when the forecasted transactions affected earnings. If it became probable that the original forecasted transactions would not occur, we immediately recognized in net income any gains or losses on the derivative instruments. For a detailed description of the derivative instruments we use, our objectives for using them, and related supplemental information required by SFAS 133, see Note 14. 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 $106.2 million in 2002, $103.9 million in 2001, and $96.9 million in 2000. We paid income taxes totaling $48.0 million in 2002, $43.0 million in 2001, and $26.6 million in 2000. REVENUE RECOGNITION. We recognize revenues from the sale of propane principally as product is delivered to customers. Revenue from the sale of appliances and equipment is recognized at the time of sale or installation. We record Utilities' regulated revenues for service provided to the end of each month which includes an accrual for certain unbilled amounts based upon estimated usage. We reflect the impact of Utilities' rate increases or decreases at the time they become effective. Energy Services records revenues when energy products are delivered to customers. Effective October 1, 2000, the Partnership applied the guidance of SEC Staff Accounting Bulletin No. 101 entitled "Revenue Recognition" ("SAB 101") with respect to its annually billed non-refundable tank fees. Under the new accounting method, revenues from such fees are recorded on a straight-line basis over one year. Prior to the change in accounting, such revenues were recorded when billed. For a detailed description of this change in accounting and its impact on our results, see Note 3. INVENTORIES. 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. EARNINGS PER COMMON SHARE. Basic earnings per share reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present the shares used in computing basic and diluted earnings per share for 2002, 2001 and 2000:
2002 2001 2000 ============================================================================== Denominator (millions of shares): Average common shares outstanding for basic computation 27.550 27.163 27.219 Incremental shares issuable for stock options and awards 0.388 0.210 0.036 ------------------------------------------------------------------------------ Average common shares outstanding for diluted computation 27.938 27.373 27.255 --------------------------------------------------------------------------------
INCOME TAXES. AmeriGas Partners and the Operating Partnerships 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 differences between the book and tax bases of the Partnership's assets and liabilities. The Operating Partnerships have subsidiaries which operate in corporate form and are directly subject to federal income taxes. Gas Utility and Electric Utility record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. They also record a deferred tax liability for tax benefits that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse. We are amortizing deferred investment tax credits related to Utilities' plant additions over the service lives of the related property. Utilities reduces its deferred income tax liability for the future tax benefits that will occur when 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. 33 ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Note 1 continued PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION. 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 and equipment, we charge its original cost and the net cost of its removal to accumulated depreciation for financial accounting purposes. We record depreciation expense for Utilities' plant and equipment on a straight-line method over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.5% in 2002 and 2.6% in each of 2001 and 2000. Depreciation expense as a percentage of the related average depreciable base for Electric Operations was 3.0% in each of 2002 and 2001, and 3.5% in 2000. 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 2 to 10 years for vehicles, equipment, and office furniture and fixtures. Depreciation expense was $88.2 million in 2002, $75.7 million in 2001, and $69.3 million in 2000. Effective October 1, 2000, the Partnership changed its method of accounting for costs to install Partnership-owned tanks at customer locations. Under the new accounting method, all costs to install such tanks, net of amounts billed to customers, are capitalized and amortized over the estimated period of benefit not exceeding ten years. For a detailed description of this change in accounting and its impact on our results, see Note 3. INTANGIBLE ASSETS. Intangible assets comprise the following at September 30:
2002 2001 ================================================================= Subject to amortization: Customer relationships, noncompete agreements and other $ 36.1 $ 37.1 Accumulated amortization (10.3) (5.8) ----------------------------------------------------------------- $ 25.8 $ 31.3 ----------------------------------------------------------------- Not subject to amortization: Goodwill (a) $551.6 $547.8 Excess reorganization value 93.3 93.3 ----------------------------------------------------------------- $644.9 $641.1 -----------------------------------------------------------------
(a) The change in the carrying amount of goodwill from September 30, 2001 to September 30, 2002 is principally the result of foreign currency translation. Effective October 1, 2001, we early adopted the provisions of SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 142 addresses the financial accounting and reporting for acquired goodwill and other intangible assets and supersedes Accounting Principles Board ("APB") Opinion No. 17, "Intangible Assets." SFAS 142 addresses the financial accounting and reporting for intangible assets acquired individually or with a group of other assets (excluding those acquired in a business combination) at acquisition and also addresses the financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under SFAS 142, an intangible asset is amortized over its useful life unless that life is determined to be indefinite. Goodwill, including excess reorganization value, and other intangible assets with indefinite lives are not amortized but are subject to tests for impairment at least annually. In accordance with the provisions of SFAS 142, we ceased the amortization of goodwill and excess reorganization value effective October 1, 2001. We amortize customer relationship and noncompete agreement intangibles over their estimated periods of benefit which do not exceed 15 years. Prior to the adoption of SFAS 142, we amortized goodwill resulting from purchase business combinations over 40 years, and excess reorganization value (resulting from Petrolane's July 1993 reorganization under Chapter 11 of the U.S. Bankruptcy Code) on a straight-line basis over 20 years. Amortization expense of intangible assets was $4.6 million in 2002 including amortization expense associated with customer contracts recorded in cost of sales. Amortization expense of intangible assets in 2001 and 2000, which includes amortization of goodwill and excess reorganization value prior to the adoption of SFAS 142, was $27.7 million and $26.5 million, respectively. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2003 - $3.8 million; Fiscal 2004 - $3.4 million; Fiscal 2005 - $2.9 million; Fiscal 2006 - $2.4 million; Fiscal 2007 - $1.8 million. The following table provides reconciliations of reported and adjusted net income and diluted earnings per share as if SFAS 142 had been adopted as of October 1, 2000. Basic earnings per share is not materially different from diluted earnings per share and, therefore, is not presented:
Year Ended September 30, 2002 2001 2000 ================================================================================ NET INCOME: Reported income before accounting changes $75.5 $ 52.0 $ 44.7 Add back goodwill and excess reorganization value amortization - 25.2 24.7 Adjust minority interests in AmeriGas Partners - (10.5) (9.7) Adjust income tax expense - (0.7) (0.3) -------------------------------------------------------------------------------- Adjusted income before accounting changes 75.5 66.0 59.4 Cumulative effect of accounting changes - 4.5 - -------------------------------------------------------------------------------- Adjusted net income $75.5 $ 70.5 $ 59.4 -------------------------------------------------------------------------------- DILUTED EARNINGS PER SHARE: Reported income before accounting changes $2.70 $ 1.90 $ 1.64 Add back goodwill and excess reorganization value amortization - 0.92 0.91 Adjust minority interests in AmeriGas Partners - (0.38) (0.36) Adjust income tax expense - (0.03) (0.01) -------------------------------------------------------------------------------- Adjusted income per share before accounting changes 2.70 2.41 2.18 Cumulative effect of accounting changes - 0.17 - -------------------------------------------------------------------------------- Adjusted net income per share $2.70 $ 2.58 $ 2.18 --------------------------------------------------------------------------------
34 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- In accordance with the provisions of SFAS 142, we were required to perform transitional goodwill impairment tests for each of our reporting units having goodwill by March 31, 2002. In addition, SFAS 142 requires that we perform impairment tests annually or more frequently if events or circumstances indicate that the value of goodwill might be impaired. No goodwill impairments were recorded as a result of our SFAS 142 transitional impairment tests or our annual impairment tests completed during the fourth quarter of fiscal 2002. STOCK-BASED COMPENSATION. As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), we apply the provisions of APB 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. For a description of stock-based compensation and related disclosures, see Note 10. OTHER ASSETS. Included in other assets are net deferred debt issuance costs of $14.8 million at September 30, 2002 and $15.9 million at September 30, 2001. We are amortizing these costs over the term of the related debt. COMPUTER SOFTWARE COSTS. We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding ten years once the installed software is ready for its intended use. DEFERRED FUEL COSTS. Gas Utility's tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost ("PGC") rates. The clauses provide for periodic adjustments to PGC rates for the difference between the total amount of purchased gas costs collected from customers and the recoverable costs incurred. In accordance with SFAS 71, we defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers. ENVIRONMENTAL LIABILITIES. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. We do not discount to present value the costs of future expenditures for environmental liabilities. We intend to pursue recovery of any incurred costs through all appropriate means, including regulatory relief. Gas Utility is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. Gas Utility is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred removal costs. FOREIGN CURRENCY TRANSLATION. Balance sheets of international subsidiaries and investments in international propane joint ventures are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity method results are translated into U.S. dollars using a weighted-average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income. Where the local currency is not the functional currency, translation adjustments are recorded in net income. COMPREHENSIVE INCOME (LOSS). Comprehensive income (loss) comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally results from gains and losses on derivative instruments qualifying as cash flow hedges and foreign currency translation adjustments. The components of accumulated other comprehensive income (loss) at September 30, 2001 and 2002 follows:
Derivative Foreign Instruments Currency Gains Translation (Losses) Adjustments Total ======================================================================================= Balance - September 30, 2001 $(13.7) $0.2 $(13.5) Balance - September 30, 2002 $ 3.1 $3.5 $ 6.6 ---------------------------------------------------------------------------------------
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. The Financial Accounting Standards Board ("FASB") recently issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"); SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"); SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" ("SFAS 145"); and SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 143 addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with a corresponding increase in the carrying value of the related asset. Entities shall subsequently charge the retirement cost to expense using a systematic and rational method over the related asset's useful life and adjust the fair value of the liability resulting from the passage of time through charges to operating expense. We adopted SFAS 143 effective October 1, 2002. The adoption of SFAS 143 did not have a material effect on our financial position or results of operations. Our joint venture, AGZ Holdings, is required to adopt SFAS 143 effective April 1, 2003. We are currently in the process of evaluating the impact of SFAS 143 on AGZ Holdings. SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," as it relates to the disposal of a segment 35 ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Note 1 continued of a business. SFAS 144 establishes a single accounting model for long-lived assets to be disposed of based upon the framework of SFAS 121, and resolves significant implementation issues of SFAS 121. We adopted SFAS 144 effective October 1, 2002. The adoption of SFAS 144 did not affect our financial position or results of operations. SFAS 145 rescinded SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" (an amendment of APB Opinion No. 30) ("SFAS 4"), effective for fiscal years beginning after May 15, 2002. SFAS 4 had required that material gains and losses on extinguishment of debt be classified as an extraordinary item. Under SFAS 145, it is less likely that a gain or loss on extinguishment of debt would be classified as an extraordinary item in the Consolidated Statement of Income. Among other things, SFAS 145 also amends SFAS No. 13, "Accounting for Leases," to require that certain lease modifications that have economic effects similar to sale-leaseback transactions be accounted for in the same manner as sale-leaseback transactions. The provisions of SFAS 145 relating to leases were effective for transactions occurring after May 15, 2002. The application of SFAS 145 did not affect our financial position or results of operations during 2002. SFAS 146 addresses accounting for costs associated with exit or disposal activities and replaces the guidance in Emerging Issues Task Force ("EITF") No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." Generally, SFAS 146 requires that a liability for costs associated with an exit or disposal activity, including contract termination costs, employee termination benefits and other associated costs, be recognized when the liability is incurred. Under EITF No. 94-3, a liability was recognized at the date an entity committed to an exit plan. SFAS 146 will be effective for disposal activities initiated after December 31, 2002. NOTE 2 - ACQUISITIONS On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired the propane distribution businesses of Columbia Energy Group ("Columbia Propane Businesses") in a series of equity and asset purchases pursuant to the terms of the Purchase Agreement dated January 30, 2001, and Amended and Restated August 7, 2001 ("Columbia Purchase Agreement") by and among Columbia Energy Group ("CEG"), Columbia Propane Corporation ("Columbia Propane"), Columbia Propane, L.P. ("CPLP"), CP Holdings, Inc. ("CPH"), AmeriGas Partners, AmeriGas OLP, and the General Partner. The acquired businesses comprised the seventh largest retail marketer of propane in the United States with annual sales of over 300 million gallons from locations in 29 states. The acquired businesses were principally conducted through Columbia Propane and its approximate 99% owned subsidiary, CPLP (referred to after the acquisition as "Eagle OLP"). AmeriGas OLP acquired substantially all of the assets of Columbia Propane, including an indirect 1% general partner interest and an approximate 99% limited partnership interest in Eagle OLP. The purchase price of the Columbia Propane Businesses consisted of $201.8 million in cash. In addition, AmeriGas OLP agreed to pay CEG for the amount of working capital, as defined, in excess of $23 million. In April 2002, the Partnership's management and CEG agreed upon the amount of working capital acquired by AmeriGas OLP and AmeriGas OLP made an additional payment for working capital and other adjustments totaling $0.7 million. The Columbia Purchase Agreement also provided for the purchase by CEG of limited partnership interests in AmeriGas OLP valued at $50 million for $50 million in cash, which interests were exchanged for 2,356,953 Common Units of AmeriGas Partners having an estimated fair value of $54.4 million. Concurrently with the acquisition, AmeriGas Partners issued $200 million of 8.875% Senior Notes due May 2011, the net proceeds of which were contributed to AmeriGas OLP to finance the acquisition of the Columbia Propane Businesses, to fund related fees and expenses, and to repay debt outstanding under AmeriGas OLP's Bank Credit Agreement. The operating results of the Columbia Propane Businesses are included in our consolidated results from August 21, 2001. The following table identifies the components of the purchase price: ================================================================================ Cash paid $ 202.5 Cash received from sale of AmeriGas OLP limited partner interests (50.0) Fair value of AmeriGas Partners' Common Units issued in exchange for the AmeriGas OLP limited partner interests 54.4 Transaction costs and expenses 8.2 Involuntary employee termination benefits and relocation costs 2.6 Other liabilities and obligations incurred 1.0 -------------------------------------------------------------------------------- Total $ 218.7 --------------------------------------------------------------------------------
As of September 30, 2002, substantially all involuntary employee termination benefits and relocation costs had been paid. The purchase price of the Columbia Propane Businesses has been allocated to the assets and liabilities acquired as follows: ================================================================================ Net current assets $ 16.7 Property, plant and equipment 182.8 Customer relationships and noncompete agreement (estimated useful life of 15 and 5 years, respectively) 19.9 Other assets and liabilities (0.7) -------------------------------------------------------------------------------- Total $ 218.7 --------------------------------------------------------------------------------
The following table presents unaudited pro forma income statement and diluted per share data for 2001 and 2000 as if the acquisition of the Columbia Propane Businesses had occurred as of the beginning of those years:
2001 2000 ================================================================================ Revenues $2,838.3 $2,069.8 Income before accounting changes 50.8 39.5 Net income 55.3 39.5 Diluted earnings per share: Income before accounting changes 1.86 1.45 Net income 2.02 1.45 --------------------------------------------------------------------------------
36 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- The pro forma results of operations reflect the Columbia Propane Businesses' historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing impact. They are not adjusted for, among other things, the impact of normal weather conditions, operating synergies and anticipated cost savings. In our opinion, the unaudited pro forma results are not necessarily indicative of the actual results that would have occurred had the acquisition of the Columbia Propane Businesses occurred as of the beginning of the years presented or of future operating results under our management. During 2001, Energy Services acquired two energy marketing businesses and the Partnership acquired several small propane distribution businesses for total cash consideration of $5.4 million. 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 allocated to the net assets acquired for the 2000 acquisitions was approximately $42 million. The operating results of these businesses have been included in the consolidated results from their respective dates of acquisition. The pro forma effect of these transactions was not material to our 2001 and 2000 results of operations. NOTE 3 - CHANGES IN ACCOUNTING TANK FEE REVENUE RECOGNITION. In order to apply the guidance of SAB 101, effective October 1, 2000, the Partnership changed its method of accounting for annually billed nonrefundable tank fees. Prior to the change in accounting, nonrefundable tank fees for installed Partnership-owned tanks were recorded as revenue when billed. Under the new accounting method, revenues from such fees are being recorded on a straight-line basis over one year. As a result of this change in accounting, on October 1, 2000, we recorded an after-tax charge of $2.1 million representing the cumulative effect of the change in accounting on prior years. The change in accounting for nonrefundable tank fees did not have a material impact on reported revenues in 2002 and 2001, and would not have had a material impact on reported revenues in 2000. At September 30, 2002 and 2001, deferred revenues relating to nonrefundable tank fees were $6.8 million and $6.2 million, respectively. ACCOUNTING FOR TANK INSTALLATION COSTS. Effective October 1, 2000, the Partnership changed its method of accounting for tank installation costs which are not billed to customers. Prior to the change in accounting, costs to install Partnership-owned tanks at a customer location were expensed as incurred. Under the new accounting method, all such costs, net of amounts billed to customers, are capitalized in property, plant and equipment and amortized over the estimated period of benefit not exceeding ten years. The Partnership believes that the new accounting method better matches the costs of installing Partnership-owned tanks with the periods benefited. As a result of this change in accounting, on October 1, 2000, we recorded after-tax income of $6.9 million representing the cumulative effect of the change in accounting on prior years. The change in accounting for tank installation costs did not have a material effect on 2001 net income. CUMULATIVE EFFECT OF ACCOUNTING CHANGES AND PRO FORMA DISCLOSURE. The cumulative effect reflected on the 2001 Consolidated Statement of Income and related diluted per share amounts resulting from the above changes in accounting principles, as well as the cumulative effect resulting from the adoption of SFAS 133 (see Note 1), comprise the following:
Diluted Pre-Tax Income Tax After-Tax Earnings Income (Expense) Income (Loss) (Loss) Benefit (Loss) Per Share ================================================================================ Tank fees $(3.5) $ 1.4 $(2.1) $(0.08) Tank installation costs 11.3 (4.4) 6.9 0.25 SFAS 133 (0.4) 0.1 (0.3) (0.01) -------------------------------------------------------------------------------- Total $ 7.4 $(2.9) $ 4.5 $ 0.16 --------------------------------------------------------------------------------
The pro forma impact on 2000 net income and net income per share after applying retroactively the changes in accounting for tank installation costs and nonrefundable tank fees was not materially different from reported amounts. NOTE 4 - UTILITY REGULATORY MATTERS GAS UTILITY GAS COMPETITION ACT. On June 22, 1999, the Gas Competition Act was signed into law. The purpose of the Gas Competition Act is to provide all natural gas consumers in Pennsylvania with the ability to purchase their gas supplies from the supplier of their choice. Under the Gas Competition Act, local gas distribution companies ("LDCs") like Gas Utility may continue to sell gas to customers, and such sales of gas, as well as distribution services provided by LDCs, continue to be subject to price regulation by the PUC. LDCs serve as the supplier of last resort for all residential and small commercial and industrial ("core-market") customers unless the PUC approves another supplier of last resort. The Gas Competition Act requires energy marketers seeking to serve customers of LDCs to accept assignment of a portion of the LDC's pipeline capacity and storage contracts at contract rates, thus avoiding the creation of stranded costs. After July 1, 2002, a natural gas supplier may petition the PUC to avoid such contract release or assignment. However, such petition may be granted only if the LDC fully recovers the cost of contracts. The Gas Competition Act, in conjunction with a companion bill, eliminated the gross receipts tax on sales of gas effective January 1, 2000. On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas Utility's restructuring plan filed by Gas Utility pursuant to the Gas Competition Act. Among other things, the implementation of the Gas Restructuring Order resulted in an increase in Gas Utility's core-market base rates effective October 1, 2000. This base rate increase was designed to generate approximately $16.7 million in additional net annual revenues. In accordance with the Gas Restructuring Order, Gas Utility reduced its core-market PGC rates by an annualized amount of $16.7 million in the first 14 months following the October 1, 2000 base rate increase. 37 ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Note 4 continued Effective December 1, 2001, Gas Utility was required to reduce its core-market PGC rates by amounts equal to the margin it receives from interruptible customers using pipeline capacity contracted by Gas Utility for core-market customers. As a result, Gas Utility operating results are more sensitive to the effects of heating-season weather and less sensitive to the market prices of alternative fuels. ELECTRIC UTILITY ELECTRIC UTILITY RESTRUCTURING ORDER. On June 19, 1998, the PUC entered its Opinion and Order ("Electricity Restructuring Order") in Electric Utility's restructuring proceeding pursuant to the Electricity Choice Act. Under the terms of the Electricity Restructuring Order, Electric Utility was authorized to recover $32.5 million in stranded costs (on a full revenue requirements basis which includes all income and gross receipts taxes) over a four-year period beginning January 1, 1999 through a Competitive Transition Charge ("CTC") (together with carrying charges on unrecovered balances of 7.94%) and to charge unbundled rates for generation, transmission and distribution services. Stranded costs are electric generation-related costs that traditionally would be recoverable in a regulated environment but may not be recoverable in a competitive electric generation market. Electric Utility's recoverable stranded costs included $8.7 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 Choice Act, Electric Utility generally could not increase the generation component of prices during the period that stranded costs were being recovered through the CTC. Since January 1, 1999, all of Electric Utility's customers have been permitted to choose an alternative generation supplier. Customers choosing an alternative supplier during the stranded cost recovery period received a "shopping credit." The PUC approved a settlement establishing rules for Electric Utility Provider of Last Resort ("POLR") service on March 28, 2002, and a separate settlement that modified these rules on June 13, 2002 (collectively the "POLR Settlement") under which Electric Utility terminated stranded cost recovery through its CTC from commercial and industrial ("C&I") customers on July 31, 2002, and from residential customers on October 31, 2002, and is no longer subject to the statutory rate caps as of August 1, 2002 for C&I customers and as of November 1, 2002 for residential customers. Charges for generation service will (1) initially be set at a level equal to the rates paid by Electric Utility customers for POLR service under the statutory rate caps; (2) may be raised at certain designated times up to certain specified caps through December 2004; and (3) may be set at market rates thereafter. Electric Utility may also offer multiple-year POLR contracts to its customers. The POLR Settlement provides for annual shopping periods during which customers may elect to remain on POLR service or choose an alternate supplier. Customers who do not select an alternate supplier will be obligated to remain on POLR service until the next shopping period. Residential customers who return to POLR service at a time other than during the annual shopping period must remain on POLR service until the date of the second open shopping period after returning. C&I customers who return to POLR service at a time other than during the annual shopping period must remain on POLR service until the next open shopping period, and may, in certain circumstances, be subject to generation rate surcharges. FORMATION OF HUNLOCK CREEK ENERGY VENTURES. On December 8, 2000, a subsidiary of UGI Utilities contributed its coal-fired Hunlock Creek generating station ("Hunlock") and certain related assets having a net book value of approximately $4.2 million, and $6 million in cash, to Hunlock Creek Energy Ventures ("Energy Ventures"), a general partnership jointly owned by us and a subsidiary of Allegheny Energy, Inc. ("Allegheny"). The contribution was recorded at carrying value and no gain was recognized by the Company. Also on December 8, 2000, Allegheny contributed a newly constructed, gas-fired combustion turbine generator to be operated at the Hunlock site. Under the terms of our arrangement with Allegheny, each partner is entitled to purchase 50% of the output of the joint venture at cost. Total purchases from Energy Ventures in 2002 and 2001 were $9.8 million and $8.0 million, respectively. REGULATORY ASSETS AND LIABILITIES The following regulatory assets and liabilities are included in our accompanying balance sheets at September 30:
2002 2001 ==================================================================== Regulatory assets: Income taxes recoverable $54.7 $51.8 Power agreement buy-out - 1.3 Other postretirement benefits 2.4 2.6 Deferred fuel costs 4.3 - Other 0.6 0.5 -------------------------------------------------------------------- Total regulatory assets $62.0 $56.2 -------------------------------------------------------------------- Regulatory liabilities: Other postretirement benefits $ 4.3 $ 4.3 Deferred fuel costs - 2.8 -------------------------------------------------------------------- Total regulatory liabilities $ 4.3 $ 7.1 --------------------------------------------------------------------
Utilities' regulatory liabilities are included in "other current liabilities" and "other noncurrent liabilities" on the Consolidated Balance Sheets. The Company's regulatory assets do not earn a return. 38 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- NOTE 5 - DEBT Long-term debt comprises the following at September 30:
2002 2001 =========================================================================================== AMERIGAS PROPANE: AmeriGas Partners Senior Notes: 8.875%, due May 2011 (of which $40 in 2002 includes unamortized premium of $1.5, effective rate - 8.25%) $ 241.6 $ 200.0 10%, due April 2006 (less unamortized discount of $0.2 and $0.3, respectively, effective rate - 10.125%) 59.8 59.7 10.125%, due April 2007 85.0 100.0 AmeriGas OLP First Mortgage Notes: Series A, 9.34% - 11.71%, due April 2001 through April 2009 (including unamortized premium of $7.9 and $9.2, respectively, effective rate - 8.91%) 167.9 189.2 Series B, 10.07%, due April 2001 through April 2005 (including unamortized premium of $2.3 and $3.9, respectively, effective rate - 8.74%) 122.3 163.9 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 $2.2 and $2.4, respectively, effective rate - 6.52%) 72.2 72.4 Series E, 8.50%, due July 2010 (including unamortized premium of $0.1 and $0.2, respectively, effective rate - 8.47%) 80.1 80.2 AmeriGas OLP Acquisition Facility - 20.0 Other 6.9 10.5 ------------------------------------------------------------------------------------------- Total AmeriGas Propane 945.8 1,005.9 ------------------------------------------------------------------------------------------- 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 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 7.14% Notes, due December 2005 (including unamortized premium of $0.4 and $0.5, respectively, effective rate - 6.64%) 30.4 30.5 7.14% Notes, due December 2005 20.0 20.0 5.53% Notes, due September 2012 40.0 - 6.50% Senior Notes, due August 2003 (less unamortized discount of $0.1 in 2001) 50.0 49.9 ------------------------------------------------------------------------------------------- Total UGI Utilities 248.4 208.4 ------------------------------------------------------------------------------------------- OTHER: FLAGA Acquisition Note, due September 2002 through September 2006 64.3 62.7 FLAGA euro special purpose facility 10.8 10.7 Other 6.4 7.5 ------------------------------------------------------------------------------------------- Total long-term debt 1,275.7 1,295.2 Less current maturities (including net unamortized premiums of $2.9 and $3.3, respectively) (148.7) (98.3) ------------------------------------------------------------------------------------------- Total long-term debt due after one year $ 1,127.0 $1,196.9 -------------------------------------------------------------------------------------------
Scheduled principal repayments of long-term debt due in fiscal years 2003 to 2007 follows:
2003 2004 2005 2006 2007 ============================================================================= AmeriGas Propane $ 57.5 $55.1 $54.9 $113.2 $138.7 UGI Utilities 76.0 - 20.0 50.0 20.0 Other 12.3 6.1 11.1 47.6 1.4 ----------------------------------------------------------------------------- Total $145.8 $61.2 $86.0 $210.8 $160.1 -----------------------------------------------------------------------------
AMERIGAS PROPANE AMERIGAS PARTNERS SENIOR NOTES. The 8.875% Senior Notes generally cannot be redeemed at our option prior to May 20, 2006. A redemption premium applies thereafter through May 19, 2009. However, prior to May 20, 2004, AmeriGas Partners may use the proceeds of a public offering of Common Units to redeem up to 33% of the 8.875% Senior Notes at 108.875% plus accrued and unpaid interest. The 10% Senior Notes generally cannot be redeemed at our option prior to their maturity. The 10.125% Senior Notes are redeemable prior to their maturity date. A redemption premium applies until April 15, 2004. In November 2001, AmeriGas Partners prepaid $15 million of 10.125% Senior Notes at a redemption price of 103.375%. 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. AMERIGAS OLP FIRST MORTGAGE NOTES. AmeriGas OLP's First Mortgage Notes are collateralized by substantially all of its assets. The General Partner and 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. AmeriGas OLP 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, AmeriGas OLP may be required to offer to prepay the First Mortgage Notes, in whole or in part. AMERIGAS OLP BANK CREDIT AGREEMENT. AmeriGas OLP's Second Amended and Restated Credit Agreement ("Bank Credit Agreement") consists of (1) a Revolving Credit Facility and (2) an Acquisition Facility. AmeriGas OLP'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, AmeriGas OLP may borrow up to $100 million (including a $35 million sublimit for letters of credit) subject to restrictions in the AmeriGas Partners Senior Notes indentures (see "Restrictive Covenants" below). The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Revolving Credit Facility expires October 1, 2003, but may be extended for additional one-year periods with the consent of the participating banks representing at least 80% of the commitments thereunder. AmeriGas OLP had borrowings under the Revolving Credit Facility totaling $10 million at September 30, 2002, which we classify as bank loans. There were no borrowings outstanding under the Revolving Credit Facility at September 30, 2001. Issued and outstanding letters of 39 ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Note 5 continued credit, which reduce available borrowings under the Revolving Credit Facility, totaled $19.8 million and $9.5 million at September 30, 2002 and 2001, respectively. The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 million to finance the purchase of propane businesses or propane business assets. In addition, up to $30 million of the Acquisition Facility may be used for working capital purposes. The Acquisition Facility operates as a revolving facility through October 1, 2003, at which time amounts then outstanding will be immediately due and payable. The Revolving Credit Facility and the Acquisition Facility permit AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank's prime rate (4.75% at September 30, 2002), or at two-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the Bank Credit Agreement, plus a margin. The margin on Eurodollar Rate borrowings (which ranges from 1.00% to 2.25%), and the Bank Credit Agreement commitment fee rate (which ranges from 0.25% to 0.50%) are dependent upon AmeriGas OLP'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 weighted-average interest rate on Revolving Credit Facility borrowings at September 30, 2002 was 4.75%. The weighted-average interest rate on Acquisition Facility loans outstanding at September 30, 2001 was 4.08%. AmeriGas OLP had the ability to borrow an additional $67.7 million under the Acquisition Facility based upon eligible propane business and asset expenditures made through September 30, 2002. GENERAL PARTNER FACILITY. AmeriGas OLP also has a revolving credit agreement with the General Partner under which it may borrow up to $20 million for working capital and general purposes. This agreement is coterminous with, and generally comparable to, AmeriGas OLP's Revolving Credit Facility except that borrowings under the General Partner Facility are unsecured and subordinated to all senior debt of AmeriGas OLP. Interest rates on borrowings are based upon one-month offshore interbank offering rates. 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 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 indentures, 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. 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, 2002, such ratio was 2.41-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, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The Bank Credit Agreement and First Mortgage Notes 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 4.75-to-1 with respect to the Bank Credit Agreement and 5.25-to-1 with respect to the First Mortgage Notes. In addition, the Bank Credit Agreement requires that AmeriGas OLP 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, AmeriGas OLP 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, 2002, the Partnership was in compliance with its financial covenants. UGI UTILITIES REVOLVING CREDIT AGREEMENTS. At September 30, 2002, UGI Utilities had revolving credit agreements with four banks providing for borrowings of up to $97 million. These agreements expire at various dates through September 2005. UGI Utilities may borrow at various prevailing interest rates, including LIBOR. UGI Utilities pays quarterly commitment fees on these credit lines. UGI Utilities had borrowings under these agreements totaling $37.2 million at September 30, 2002 and $57.8 million at September 30, 2001, which we classify as bank loans. The weighted-average interest rates on UGI Utilities bank loans were 2.35% at September 30, 2002 and 3.75% at September 30, 2001. RESTRICTIVE COVENANTS. UGI Utilities' credit agreements have restrictions on such items as total debt, debt service, and payments for investments. They also require consolidated tangible net worth of at least $125 million. At September 30, 2002, UGI Utilities was in compliance with its financial covenants. OTHER At September 30, 2002, FLAGA's multi-currency acquisition note ("Acquisition Note") consisted of a $14.5 million U.S. dollar denominated obligation and a 50.5 million euro-denominated obligation. During 2002, a portion of the euro-denominated acquisition note was converted to a $16.7 million U.S. dollar denominated obligation. The Acquisition Note bears interest at a rate of 1.25% over one- to twelve-month euribor rates (as chosen by FLAGA from time to time). The effective interest rates on the Acquisition Note at September 30, 2002 and September 30, 2001 were 4.86% and 5.42%, respectively. On or after September 10, 2003, FLAGA may prepay the Acquisition Note, in whole or in part. Prior to March 11, 2005, such prepayments shall be at a premium. 40 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- At September 30, 2002, FLAGA has a 15 million euro working capital loan commitment from a European bank. The working capital facility expires in September 2003, but may be extended with the bank's consent. Loans under the working capital facility, as well as borrowings under FLAGA's special purpose facility, bear interest at market rates. The weighted-average interest rate on FLAGA's working capital facility at September 30, 2002 was 4.40%. Borrowings under the euro working capital facility at September 30, 2002 and 2001 totaled $8.6 million and $10.0 million, respectively, and are classified as bank loans. The FLAGA Acquisition 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. NOTE 6 - INCOME TAXES Income before income taxes comprises the following:
2002 2001 2000 =========================================================================== Domestic $117.2 $103.0 $ 93.4 Foreign 6.8 (4.0) (7.0) --------------------------------------------------------------------------- Total income before income taxes $124.0 $ 99.0 $ 86.4 ---------------------------------------------------------------------------
The provisions for income taxes consist of the following:
2002 2001 2000 ============================================================================= Current expense: Federal $26.5 $39.2 $28.6 State 9.3 11.7 8.3 Foreign 0.1 - - ------------------------------------------------------------------------------ Total current expense 35.9 50.9 36.9 Deferred (benefit) expense: Federal 11.8 (2.9) 5.7 State (0.4) (1.2) (0.2) Foreign - (1.0) (1.9) Investment tax credit amortization (0.4) (0.4) (0.4) ------------------------------------------------------------------------------ Total deferred (benefit) expense 11.0 (5.5) 3.2 ------------------------------------------------------------------------------ Total income tax expense $46.9 $45.4 $40.1 ------------------------------------------------------------------------------
A reconciliation from the statutory federal tax rate to our effective tax rate is as follows:
2002 2001 2000 ============================================================================= Statutory federal tax rate 35.0% 35.0% 35.0% Difference in tax rate due to: State income taxes, net of federal 5.3 7.3 7.5 Goodwill amortization - 4.4 5.8 Other, net (2.5) (0.8) (1.9) ------------------------------------------------------------------------------ Effective tax rate 37.8% 45.9% 46.4% ------------------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September 30:
2002 2001 ================================================================================ Excess book basis over tax basis of property, plant and equipment $199.2 $180.3 Regulatory assets 23.7 23.3 Pension plan asset 10.5 8.9 Other 17.0 12.6 ------------------------------------------------------------------------------ Gross deferred tax liabilities 250.4 225.1 ------------------------------------------------------------------------------ Self-insured property and casualty liability (9.0) (8.2) Employee-related benefits (16.2) (14.5) Premium on long-term debt (2.5) (3.2) Deferred investment tax credits (3.5) (3.6) Hearth USA(TM)shut-down costs - (3.3) Accumulated other comprehensive loss - (9.7) Operating loss carryforwards (13.3) (8.9) Allowance for doubtful accounts (2.4) (3.2) Other (15.6) (15.1) ------------------------------------------------------------------------------ Gross deferred tax assets (62.5) (69.7) ------------------------------------------------------------------------------ Deferred tax assets valuation allowance 1.9 1.8 ------------------------------------------------------------------------------ Net deferred tax liabilities $189.8 $157.2 ------------------------------------------------------------------------------
Deferred income taxes of approximately $1.9 million have not been provided on the excess of book basis over tax basis of our equity investment in AGZ Holdings because the Company has no present intent to dispose of this investment. UGI Utilities had recorded deferred tax liabilities of approximately $35.5 million as of September 30, 2002 and $33.9 million as of September 30, 2001, 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 $3.5 million at September 30, 2002 and $3.6 million at September 30, 2001, pertaining to utility deferred investment tax credits. UGI Utilities had recorded regulatory income tax assets related to these net deferred taxes of $54.7 million as of September 30, 2002 and $51.8 million as of September 30, 2001. These regulatory income tax assets represent future revenues expected to be recovered through the ratemaking process. We will recognize this regulatory income tax asset in deferred tax expense as the corresponding temporary differences reverse and additional income taxes are incurred. Foreign net operating loss carryforwards of FLAGA totaled approximately $33.0 million, $5.1 million of which expires through 2007 and $27.9 million of which has no expiration date. At September 30, 2002, deferred tax assets relating to operating loss carryforwards include those of FLAGA and $2.3 million of deferred tax assets associated with state net operating loss carryforwards expiring through 2022. Substantially all of our deferred tax valuation allowances relate to state operating loss carryforwards. NOTE 7 - 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 41 ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Note 7 continued 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 domestic active and retired employees. The following provides a reconciliation of benefit obligations, plan assets, and funded status of these plans as of September 30:
Pension Other Postretirement Benefits Benefits ----------------- -------------------- 2002 2001 2002 2001 ============================================================================================== CHANGE IN BENEFIT OBLIGATIONS: Benefit obligations - beginning of year $165.2 $150.9 $ 21.3 $ 19.7 Service cost 3.6 3.1 0.1 0.1 Interest cost 12.5 12.1 1.7 1.6 Plan amendments 0.4 - - - Actuarial loss 18.6 7.9 5.8 1.8 Benefits paid (9.4) (8.8) (1.6) (1.9) ---------------------------------------------------------------------------------------------- Benefit obligations - end of year $190.9 $165.2 $ 27.3 $ 21.3 ---------------------------------------------------------------------------------------------- CHANGE IN PLAN ASSETS: Fair value of plan assets - beginning of year $183.7 $223.5 $ 7.0 $ 6.4 Actual return on plan assets (8.3) (31.0) 0.1 0.2 Employer contributions - - 2.3 2.2 Benefits paid (9.3) (8.8) (1.6) (1.8) ---------------------------------------------------------------------------------------------- Fair value of plan assets - end of year $166.1 $183.7 $ 7.8 $ 7.0 ---------------------------------------------------------------------------------------------- Funded status of the plans $(24.8) $ 18.5 $ (19.5) $(14.3) Unrecognized net actuarial (gain) loss 50.2 4.2 4.7 (1.4) Unrecognized prior service cost 3.0 3.3 - - Unrecognized net transition (asset) obligation (3.0) (4.6) 8.7 9.5 ---------------------------------------------------------------------------------------------- Prepaid (accrued) benefit cost - end of year $ 25.4 $ 21.4 $ (6.1) $ (6.2) ---------------------------------------------------------------------------------------------- ASSUMPTIONS AS OF SEPTEMBER 30: Discount rate 6.8% 7.7% 6.8% 7.7% Expected return on plan assets 9.5% 9.5% 6.0% 6.0% Rate of increase in salary levels 4.5% 4.5% 4.5% 4.5% ----------------------------------------------------------------------------------------------
Net periodic pension income and other postretirement benefit costs include the following components:
Pension Other Postretirement Benefits Benefits ----------------------------- -------------------------- 2002 2001 2000 2002 2001 2000 ============================================================================================== Service cost $ 3.6 $ 3.1 $ 3.2 $ 0.1 $ 0.1 $ 0.1 Interest cost 12.5 12.1 11.8 1.7 1.6 1.4 Expected return on assets (19.1) (18.9) (17.0) (0.3) (0.3) (0.3) 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 - (1.2) - (0.1) (0.1) (0.2) ---------------------------------------------------------------------------------------------- Net benefit cost (income) (4.0) (5.9) (3.0) 2.3 2.2 1.9 Change in regulatory assets and liabilities - - - 1.2 1.4 1.4 ---------------------------------------------------------------------------------------------- Net expense (income) $ (4.0) $ (5.9) $ (3.0) $ 3.5 $ 3.6 $ 3.3 ----------------------------------------------------------------------------------------------
UGI Utilities Pension Plan assets are held in trust and consist principally of equity and fixed income mutual funds and a commingled bond fund. UGI Common Stock comprised approximately 6% of trust assets at September 30, 2002. Although the UGI Utilities Pension Plan projected benefit obligation exceeded plan assets at September 30, 2002, plan assets exceeded accumulated benefit obligations by approximately $7.2 million. Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary Employees' Beneficiary Association ("VEBA") trust to pay retiree health care and life insurance benefits and to fund the UGI Utilities' postretirement benefit liability. UGI Utilities is required to fund its postretirement benefit obligations by depositing into the VEBA the annual amount of postretirement benefits costs determined under SFAS No. 106, "Employers Accounting for Postretirement Benefits Other than Pensions." The difference between such amounts and amounts included in UGI Utilities' rates is deferred for future recovery from, or refund to, ratepayers. VEBA investments consist principally of money market funds. The assumed health care cost trend rates are 12.0% for fiscal 2003, decreasing to 5.5% in fiscal 2010. A one percentage point change in the assumed health care cost trend rate would change the 2002 postretirement benefit cost and obligation as follows:
1% Increase 1% Decrease ==================================================================================== Effect on total service and interest costs $0.1 $(0.1) Effect on postretirement benefit obligation $1.5 $(1.3) ------------------------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key employees. At September 30, 2002 and 2001, the projected benefit obligations of these plans were not material. We recorded expense for these plans of $1.4 million in 2002, $1.2 million in 2001, and $0.9 million in 2000. DEFINED CONTRIBUTION PLANS. We sponsor 401(k) savings plans for eligible employees of UGI, UGI Utilities, AmeriGas Propane, HVAC and certain of UGI's other wholly owned domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for either mandatory or discretionary employer matching contributions at various rates. The cost of benefits under the savings plans totaled $4.5 million in 2002, $6.2 million in 2001, and $5.9 million in 2000. NOTE 8 - INVENTORIES Inventories comprise the following at September 30:
2002 2001 ===================================================================== Propane gas $ 40.4 $ 54.8 Utility fuel and gases 36.6 45.6 Materials, supplies and other 32.2 28.2 --------------------------------------------------------------------- Total inventories $109.2 $128.6 ---------------------------------------------------------------------
NOTE 9 - SERIES PREFERRED STOCK The UGI Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, has 5,000,000 42 UGI Corporation 2002 Annual Report -------------------------------------------------------------------------------- shares authorized for issuance. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2002 or 2001. 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, 2002 and 2001, 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 are subject to mandatory redemption on October 1, 2009, at a price of $100 per share. NOTE 10 - COMMON STOCK AND INCENTIVE STOCK AWARD PLANS Common Stock share activity for 2000, 2001 and 2002 follows:
Issued Treasury Outstanding ======================================================================================== Balance at 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 Issued: Employee and director plans - 241,039 241,039 Dividend reinvestment plan - 98,812 98,812 Reacquired - (37,163) (37,163) ---------------------------------------------------------------------------------------- Balance September 30, 2001 33,198,731 (5,902,334) 27,296,397 Issued: Employee and director plans - 321,863 321,863 Dividend reinvestment plan - 87,062 87,062 Reacquired - (3,592) (3,592) ---------------------------------------------------------------------------------------- Balance September 30, 2002 33,198,731 (5,497,001) 27,701,730 ----------------------------------------------------------------------------------------
STOCK OPTION AND INCENTIVE PLANS. Under UGI's current employee stock option and incentive plans, we may grant options to acquire shares of Common Stock, or issue awards of restricted stock, to key employees. The exercise price for options granted under these plans may not be less than the fair market value on the grant date. Grants of stock options or awards of 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"), awards representing up to 1,100,000 shares of Common Stock may be granted in connection with stock options and awards of restricted stock. However, awards representing no more than 500,000 shares of restricted stock may be issued. In addition, the 2000 Incentive Plan provides that both option grants and restricted stock awards 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. Awards of restricted stock may be settled, at the option of the Company, in shares of Common Stock, cash, or a combination of Common Stock and cash. The actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is dependent upon the achievement of objective performance goals. During 2002 and 2001, the Company made restricted stock awards representing 169,500 and 110,675 shares, respectively. At September 30, 2002, awards representing 280,175 shares of restricted stock were outstanding. At September 30, 2002, there remained available for grant options to acquire 111,861 shares of Common Stock under the 1997 Stock Option and Dividend Equivalent Plan ("1997 SODEP Plan"). Certain outstanding option grants under the 1997 SODEP Plan provided for the crediting of dividend equivalents subject to UGI'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. In addition to the 2000 Incentive Plan and the 1997 SODEP Plan, we have non-qualified stock option plans under which we may grant options to acquire shares of Common Stock to key employees other than executive officers of UGI. In addition to these employee incentive plans, UGI may grant options to acquire up to a total of 200,000 shares of Common Stock to each of UGI'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. Stock option transactions under all of our plans for 2000, 2001, and 2002 follow:
Shares Average Option Price ================================================================================ 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 -------------------------------------------------------------------------------- Granted 33,600 25.875 Exercised (202,673) 20.807 Forfeited (12,333) 20.828 -------------------------------------------------------------------------------- Shares under option - September 30, 2001 1,702,238 21.321 -------------------------------------------------------------------------------- Granted 476,250 30.705 Exercised (291,978) 21.028 -------------------------------------------------------------------------------- Shares under option - September 30, 2002 1,886,510 23.786 -------------------------------------------------------------------------------- Options exercisable 2000 947,144 21.696 Options exercisable 2001 1,100,904 21.799 Options exercisable 2002 1,137,926 21.772 --------------------------------------------------------------------------------
43 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Note 10 continued The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2002:
Range of exercise prices ------------------------ $ 20.00 - $ 30.60 - $ 25.875 $ 31.88
Options outstanding at September 30, 2002: Number of options 1,410,260 476,250 Weighted average remaining contractual life (in years) 6.25 9.29 Weighted average exercise price $ 21.379 $ 30.705 Options exercisable at September 30, 2002: Number of options 1,109,926 28,000 Weighted average exercise price $ 21.583 $ 30.600
At September 30, 2002, 1,124,336 shares of Common Stock were available for future option grants or restricted stock awards under all of our stock option and incentive plans. OTHER STOCK-BASED COMPENSATION PLANS AND AWARDS. Under the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan ("2000 Propane Plan"), the General Partner may grant to key employees the right to receive a total of 500,000 AmeriGas Partners Common Units, or cash equivalent to the fair market value of such Common Units, upon the achievement of performance goals. In addition, the 2000 Propane Plan may provide for the crediting of Partnership distribution equivalents to participants' accounts. Distribution equivalents will be paid in cash and such payments may, at the participants' request, be deferred. The actual number of Common Units (or their cash equivalent) ultimately issued, and the actual amount of distribution equivalents paid, is dependent upon the achievement of performance goals. Generally, each grant, unless paid, will terminate when the participant ceases to be employed by the General Partner. We also have a nonexecutive Common Unit plan under which the General Partner may grant awards of up to a total of 200,000 Common Units to key employees who do not participate in the 2000 Propane Plan. Generally, awards under the nonexecutive plan vest at the end of a three-year period and will be paid in Common Units and cash. The General Partner made awards under the 2000 Propane Plan and the nonexecutive plan representing 43,250 and 66,075 Common Units in 2002 and 2001, respectively. At September 30, 2002 and 2001, awards representing 105,825 and 65,325 Common Units, respectively, were outstanding. Under the 1997 UGI Corporation Directors' Equity Compensation Plan ("1997 Directors' Plan"), we make annual awards to our nonemployee 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. Through December 31, 2002, 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 9,449, 11,556, and 12,017 in 2002, 2001 and 2000, respectively. At September 30, 2002 and 2001, there were 63,185 and 53,736 Units, respectively, outstanding. FAIR VALUE INFORMATION. The per share weighted-average fair value of stock options granted under our option plans was $4.91 in 2002, $4.35 in 2001, and $3.76 in 2000. 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 2002, 2001 and 2000 are as follows:
2002 2001 2000 ---- ---- ---- Expected life of option 6 YEARS 6 years 6 years Expected volatility 28.8% 29.1% 26.5% Expected dividend yield 6.7% 6.6% 6.2% Risk free interest rate 4.7% 5.0% 6.6%
We use the intrinsic value method prescribed by APB 25 for our stock-based employee compensation plans. We recognized total stock-based compensation expense (income) of $5.7 million in 2002, $2.7 million in 2001, and $(0.8) million in 2000. 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 2002, 2001 and 2000 would have been as follows:
2002 2001 2000 ---- ---- ---- Net income: As reported $75.5 $56.5 $44.7 Pro forma 74.5 55.7 44.2 Diluted earnings per share: As reported $2.70 $2.06 $1.64 Pro forma 2.67 2.03 1.62
STOCK OWNERSHIP POLICY. Under the terms of our Stock Ownership Policy, executives and certain key employees are required to own UGI Common Stock having a fair value equal to approximately 40% to 450% of their base salaries. Prior to the enactment of the Sarbanes-Oxley Act of 2002, we offered 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, 2002 and 2001, loans outstanding totaled $3.5 million and $4.6 million, respectively. The Company is no longer offering loans under this program. NOTE 11 - 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. The rights expire in 2006. 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 44 UGI Corporation 2002 Annual Report 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: 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 12 - 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 have generally been made 98% to 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 was sufficient Available Cash, the holders of Common Units had 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 all the remaining Subordinated Units have been converted to Common Units pursuant to the terms of the Partnership Agreement. Effective November 18, 2002, the remaining Subordinated Units held by the General Partner as of September 30, 2002 were converted to Common Units (see Note 18). NOTE 13 - 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 $46.5 million in 2002, $38.4 million in 2001, and $34.1 million in 2000. Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows:
After 2003 2004 2005 2006 2007 2007 ---- ---- ---- ---- ---- ---- AmeriGas Propane $ 35.0 $ 29.5 $ 25.4 $ 20.9 $ 16.8 $ 41.2 UGI Utilities 2.8 2.6 2.1 1.8 1.6 4.0 International Propane and other 1.1 0.7 0.4 0.2 -- -- ------- ------- ------- ------- ------- ------- Total $ 38.9 $ 32.8 $ 27.9 $ 22.9 $ 18.4 $ 45.2
Gas Utility has gas supply agreements with producers and marketers with terms of less than one year. Gas Utility also has agreements for firm pipeline transportation and storage capacity, which Gas Utility may terminate at various dates through 2015. Gas Utility's costs associated with transportation and storage capacity agreements are included in its annual PGC filing with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices. Electric Utility purchases its capacity requirements and electric energy needs under contracts with various suppliers and on the spot market. Contracts with producers for capacity and energy needs expire at various dates through December 2006. Energy Services enters into fixed price contracts with suppliers to purchase natural gas to meet its sales commitments. Generally, these contracts have terms of less than two years. The following table presents contractual obligations under Gas Utility, Electric Utility and Energy Services supply contracts existing at September 30, 2002:
After 2003 2004 2005 2006 2007 2007 ---- ---- ---- ---- ---- ---- Gas and electric supply contracts $106.4 $ 96.5 $56.9 $23.3 $14.9 $92.4 Energy Services supply contracts 145.8 11.7 -- -- -- -- ------ ------ ----- ----- ----- ----- Total $252.2 $108.2 $56.9 $23.3 $14.9 $92.4
The Partnership also enters into contracts to purchase propane to meet a portion of its supply requirements. Generally, these contracts are one- or two-year agreements subject to annual review 45 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Note 13 continued 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 relating to Petrolane's divestiture of non-propane operations before its 1989 acquisition by QFB Partners. Future lease payments under these leases total approximately $20 million at September 30, 2002. 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. In December 1999, Texas Eastern filed for dissolution under the Delaware General Corporation Law. In May 2001, Petrolane filed a declaratory judgment action in the Delaware Chancery Court seeking confirmation of Texas Eastern's indemnification obligations and judicial supervision of Texas Eastern's dissolution to ensure that its indemnification obligations to Petrolane are paid or adequately provided for in accordance with law. Those proceedings are pending. In a Liquidation and Winding Up Agreement dated September 17, 2002, PanEnergy Corporation ("PanEnergy"), Texas Eastern's sole stockholder, agreed to assume all of Texas Eastern's liabilities as of December 20, 2002, to the extent of the value of Texas Eastern's assets transferred to PanEnergy as of that date (which is expected to exceed $94 million), and to the extent that such liabilities arise within ten years from Texas Eastern's date of dissolution. Notwithstanding the dissolution proceeding, and based on Texas Eastern previously having satisfied directly defaulted lease obligations without the Partnership's having to honor its guarantee, we believe that the probability that the Partnership will be required to directly satisfy the lease obligations subject to the indemnification agreement is remote. Columbia Propane, CPLP, and CPH (collectively, the "Company Parties") agreed to indemnify the former general partners of National Propane Partners, L.P. and certain of their affiliates (collectively, "National General Partners") against certain income tax and other losses that the National General Partners may sustain as a result of the 1999 acquisition by CPLP of the National Propane business (the "1999 Acquisition") or its operation of the business after the 1999 Acquisition. CEG has agreed to indemnify AmeriGas Partners, AmeriGas OLP, the General Partner (collectively, the "Buyer Parties") and the Company Parties against any losses that they sustain under the 1999 Acquisition Agreement and related agreements ("Losses"), including claims asserted by the National General Partners ("National Claims"), to the extent such claims are based on acts or omissions of CEG or the Company Parties prior to the acquisition of the Columbia Propane Businesses by AmeriGas OLP on August 21, 2001 (the "2001 Acquisition"). The Buyer Parties have agreed to indemnify CEG against Losses, including National Claims, to the extent such claims are based on acts or omissions of the Buyer Parties or the Company Parties after the 2001 Acquisition. The Seller and Buyer Parties have agreed to apportion certain losses resulting from a National Claim to the extent such losses result from the 2001 Acquisition itself. From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of manufactured gas plants ("MGPs") prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, UGI Utilities divested all of its utility operations other than those which now constitute Gas Utility and Electric Utility. UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. UGI Utilities has been notified of several sites outside Pennsylvania on which (1) MGPs were formerly operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or private parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating two claims against it relating to out-of-state sites. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that the subsidiary's separate corporate form should be disregarded. UGI Utilities has filed suit against more than fifty insurance companies alleging that the defendants breached contracts of insurance by failing to indemnify UGI Utilities for certain environmental costs. The suit seeks to recover more than $11 million in such costs. During 2002, 2001 and 2000, UGI Utilities entered into settlement agreements with several of the insurers and recorded pretax income of $0.4 million, $0.9 million and $4.5 million, respectively, which amounts are included in operating and administrative expenses in the Consolidated Statements of Income. 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. We believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position but could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. 46 UGI Corporation 2002 Annual Report NOTE 14 - FINANCIAL INSTRUMENTS In accordance with its propane price risk management policy, the Partnership uses derivative instruments, including price swap and option contracts and contracts for the forward sale of propane, to manage the cost of a portion of its forecasted purchases of propane and to manage market risk associated with propane storage inventories. These derivative instruments have been designated by the Partnership as cash flow or fair value hedges under SFAS 133. The fair values of these derivative instruments are affected by changes in propane product prices. In addition to these derivative instruments, the Partnership may also enter into contracts for the forward purchase of propane as well as fixed-price supply agreements to manage propane market price risk. These contracts generally qualify for the normal purchases and normal sales exception of SFAS 133 and therefore are not adjusted to fair value. FLAGA also uses derivative instruments, principally price swap contracts, to reduce market risk associated with purchases of propane. These contracts may or may not qualify for hedge accounting under SFAS 133. Energy Services uses exchange-traded natural gas futures contracts to manage market risk associated with forecasted purchases of natural gas it sells under firm commitments. These derivative instruments are designated as cash flow hedges. The fair values of these futures contracts are affected by changes in natural gas prices. In addition, we have, on occasion, used 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. These contracts are generally designated as cash flow hedges. Gas Utility and Electric Utility are parties to a number of contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the delivery of natural gas, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts are not subject to the accounting requirements of SFAS 133 because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business or the value of the contract is directly associated with the price or value of a service. On occasion, we enter into interest rate protection agreements ("IRPAs") to reduce market interest rate risk associated with forecasted debt issuances. We designate these IRPAs as cash flow hedges. Gains or losses on IRPAs are included in other comprehensive income and are reclassified to interest expense as the interest expense on the associated debt issue affects earnings. During the year ended September 30, 2002, the net pre-tax loss recognized in earnings representing cash flow hedge ineffectiveness was $2.1 million. During the year ended September 30, 2001, such gain or loss was not material. The amount of cash flow hedge gains reclassified to net income because it became probable that the original forecasted transactions would not occur was $1.0 million in 2001. This amount is included in other income. Gains and losses included in accumulated other comprehensive income at September 30, 2002 relating to cash flow hedges will be reclassified into (1) cost of sales when the forecasted purchase of propane or natural gas subject to the hedges impacts net income and (2) interest expense when interest on anticipated issuances of fixed-rate long-term debt is reflected in net income. Included in accumulated other comprehensive income at September 30, 2002 are net after-tax losses of approximately $3.8 million from IRPAs associated with forecasted issuances of debt generally anticipated to occur during the next two years. The amount of this net loss which is expected to be reclassified into net income during the next twelve months is not material. Also included in accumulated other comprehensive income at September 30, 2002 are net after-tax gains of approximately $7.0 million principally associated with future purchases of natural gas or propane generally anticipated to occur during the next twelve months. The actual amount of gains or losses on unsettled derivative instruments that ultimately is reclassified into net income will depend upon the value of such derivative contracts when settled. The fair value of derivative instruments is included in other current assets, other current liabilities and other noncurrent liabilities in the Consolidated Balance Sheets. The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amounts and estimated fair values of our remaining financial instruments (including unsettled derivative instruments) at September 30 are as follows:
Carrying Estimated Amount Fair Value ------ ---------- 2002: Natural gas futures contracts $ 5.1 $ 5.1 Propane swap and option contracts 9.8 9.8 Interest rate protection agreements (4.0) (4.0) Long-term debt 1,275.7 1,328.1 UGI Utilities Series Preferred Stock 20.0 20.4 2001: Natural gas futures contracts $ (1.5) $ (1.5) Propane swap, option and forward sales (10.5) (10.5) contracts Interest rate protection agreements (3.0) (3.0) Available for sale securities 18.3 18.3 Long-term debt 1,295.2 1,386.5 UGI Utilities Series Preferred Stock 20.0 21.4
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. Fair values of derivative instruments reflect the estimated amounts that we would receive or pay to terminate the contracts at the reporting date based upon quoted market prices of comparable contracts at September 30, 2002 and 2001. 47 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Note 14 continued 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. We attempt to minimize our credit risk associated with our derivative financial instruments through the application of credit policies. NOTE 15 - ENERGY SERVICES ACCOUNTS RECEIVABLE SECURITIZATION FACILITY Energy Services has a receivables purchase facility ("Receivables Facility") with an issuer of receivables-backed commercial paper expiring November 30, 2004. Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose, bankruptcy-remote subsidiary, Energy Services Funding Corporation ("ESFC") which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in these receivables for up to $50 million in proceeds to a commercial paper conduit of a major bank. The proceeds of these sales are less than the face amount of the accounts receivable sold by an amount that approximates the purchaser's financing cost of issuing its own receivables-backed commercial paper. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. In accordance with a servicing arrangement, Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC. This two-step transaction is accounted for as a sale of receivables following the provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." During 2002, Energy Services sold $302.4 million of trade receivables to ESFC of which ESFC sold an aggregate $34.0 million to the commercial paper conduit. At September 30, 2002, no receivables had been sold to the commercial paper conduit and removed from the balance sheet. Losses on sales of receivables to the commercial paper conduit that occurred during the year ended September 30, 2002, which losses are included in other income, net, were $0.1 million. NOTE 16 - PROVISION FOR SHUT-DOWN COSTS - HEARTH USA(TM) In September 2001, after evaluating the prospects for Hearth USA(TM) in light of the weak retail environment and the capital required to expand beyond its two-store pilot phase, we committed to close both of its stores and cease all operations by the end of October 2001. Hearth USA(TM) sold, installed and serviced hearth, grill and spa products and sold related accessories from two superstores located in Rockville, Maryland and Springfield, Virginia. As a result of this action, in September 2001 we recorded a pre-tax charge of $8.5 million. The pre-tax charge reflects $3.7 million associated with the impairment of leasehold improvements; $3.2 million for estimated costs associated with lease guaranty arrangements and the restoration of the leased facilities; $1.1 million associated with the write-down of inventory to net realizable value; and $0.5 million associated with vehicle lease, severance and other costs directly resulting from the decision to close the stores. These charges and accrued costs have been reflected in the 2001 Consolidated Statement of Income as "Provision for shut-down costs - Hearth USA(TM)." As of September 30, 2001, the $3.7 million of costs associated with lease guaranty arrangements, the restoration of the leased facility and the vehicle lease, severance and other costs is included in other current liabilities in the Consolidated Balance Sheet. At September 30, 2002, all amounts had been settled. NOTE 17 - OTHER INCOME, NET Other income, net, comprises the following:
2002 2001 2000 ---- ---- ---- Interest and interest-related income $ (3.1) $ (6.7) $ (9.3) Utility non-tariff service income (5.7) (5.4) (3.2) Gain on sales of fixed assets (1.6) (2.4) (3.6) Pension income (3.9) (5.9) (3.0) Other (3.1) (2.6) (8.7) ------- ------- ------- Total other income, net $ (17.4) $ (23.0) $ (27.8) ------- ------- -------
NOTE 18 - SUBSEQUENT EVENT Pursuant to the Partnership Agreement, the 9,891,072 Subordinated Units outstanding as of September 30, 2002, all of which are held by the General Partner, were 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 (i) each of the two immediately preceding nonoverlapping four-quarter periods and (ii) 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. In December 2002, the General Partner determined that the cash-based performance and distribution requirements had been met in respect of the quarter ended September 30, 2002. As a result, the remaining 9,891,072 Subordinated Units held by the Company were converted to Common Units effective November 48 UGI Corporation 2002 Annual Report 18, 2002. Concurrent with the Subordinated Unit conversion, the Company recorded an increase in common stockholders' equity and a decrease in minority interest of approximately $160 million associated with gains from sales of Common Units by AmeriGas Partners in conjunction with, and subsequent to, the Partnership's April 19, 1995 initial public offering in accordance with the guidance in SEC Staff Accounting Bulletin No. 51, "Accounting for Sales of Common Stock by a Subsidiary." The gains result because the public offering prices of the AmeriGas Partners Common Units at the dates of their sales exceeded the associated carrying amount of our investment in the Partnership. No deferred taxes were recorded relating to this gain due to the Company's intent to hold its investment in the Partnership indefinitely. The changes to the Company's balance sheet resulting from the Subordinated Unit conversion had no effect on the Company's net income or cash flow. The conversion of the Subordinated Units did not result in an increase in the number of AmeriGas Partners limited partner units outstanding. NOTE 19 - INVESTMENTS IN EQUITY INVESTEES Our principal investments accounted for using the equity method and our approximate ownership interest in each at September 30, 2002 and 2001 are as follows:
Company Percentage Ownership ------- -------------------- Atlantic Energy 50.0% AGZ Holdings 19.5% China Gas Partners 50.0% Hunlock Creek Energy Ventures 50.0%
Income (loss) from our equity investees comprises the following:
2002 2001 2000 ---- ---- ---- Equity in income (loss) of equity investees $ 6.0 $ (2.1) $ (0.9) Interest income on AGZ Bonds 0.9 0.5 -- Currency gain from redemption of AGZ Bonds 1.6 -- -- ------- ------- ------- Total $ 8.5 $ (1.6) $ (0.9) ------- ------- -------
Undistributed net earnings (loss) of our equity investees included in consolidated retained earnings were $3.6 million and $(2.3) million at September 30, 2002 and 2001, respectively. On March 27, 2001, UGI France, Inc. ("UGI France"), a wholly owned indirect subsidiary of Enterprises, together with Paribas Affaires Industrielles ("PAI") and Medit Mediterranea GPL, S.r.L. ("Medit"), acquired, through AGZ Holdings ("AGZ"), the stock and certain related assets of Elf Antargaz, S.A., one of the largest distributors of liquefied petroleum gas in France (referred to after the transaction and herein as "Antargaz"). Prior to the transaction, Antargaz was a subsidiary of Total Fina Elf S.A., a French petroleum and chemical company. Under the terms of the Shareholders' Funding Agreement among UGI France, PAI and Medit, we acquired an approximate 19.5% equity interest in Antargaz; PAI an approximate 68.1% interest; Medit an approximate 9.7% interest; and certain members of management of Antargaz an approximate 2.7% interest. PAI is a leading private equity fund manager in Europe and an affiliate of BNP Paribas, 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. Pursuant to the Shareholders' Funding Agreement, on March 27, 2001, UGI France made a 29.8 million euro ($26.6 million U.S. dollar equivalent) investment comprising a 9.8 million euro investment in shares of AGZ and a 20.0 million euro investment in redeemable bonds of AGZ ("AGZ Bonds"). In July 2002, the Company received $19.3 million in cash from AGZ representing repayment of 18 million euro face value (90%), $17.7 million U.S. dollar equivalent, of the AGZ Bonds held by the Company, plus accrued interest. This repayment was funded from the proceeds of an AGZ placement of high-yield debt. Concurrent with the repayment, the remaining 2.0 million euro (10%) investment in AGZ Bonds was redeemed in the form of additional shares of AGZ. After these transactions, the Company continues to hold an approximate 19.5% equity investment in shares of AGZ. As a result of the redemption of AGZ Bonds, we recorded a pretax currency transaction gain of $1.6 million. Because we believe we have significant influence over operating and financial policies of Antargaz due, in part, to our membership on its Board of Directors, our investment in AGZ shares is accounted for by the equity method. Summarized financial information for AGZ follows:
2002 2001(a) ---- ------- STATEMENT OF INCOME DATA: Revenues $ 550.6 $ 243.8 ------- ------- Operating income $ 79.4 $ 22.5 Interest, net (27.9) (13.9) ------- ------- Income before income taxes $ 51.5 $ 8.6 Income taxes $ (20.7) $ (5.1) Net income $ 29.9 $ 2.9 ------- ------- BALANCE SHEET DATA (AT SEPTEMBER 30): Current assets $ 171.5 $ 195.1 Property, plant and equipment, net 259.5 233.8 Goodwill 378.8 355.7 Other assets 116.7 93.3 ------- ------- Total assets $ 926.5 $ 877.9 ------- ------- Current liabilities $ 106.1 $ 123.4 Long-term debt 436.2 458.1 Other liabilities 292.0 248.3 ------- ------- Total liabilities $ 834.3 $ 829.8 ------- ------- Equity $ 92.2 $ 48.1 ------- -------
(a) Statement of income data is for the period March 27, 2001 to September 30, 2001. Summarized financial information for AGZ as of September 30, 2001 and for the period March 27, 2001 to September 30, 2001 was not required to be disclosed previously, but is being presented for comparative purposes only. Summarized financial information for our other equity investments are not presented because they are not material to our Consolidated Balance Sheets or Consolidated Statements of Income. 49 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) NOTE 20 - QUARTERLY DATA (UNAUDITED)
December 31, March 31, June 30, September 30, 2001 2000 2002 2001 2002 2001 2002(A) 2001(b) -------- -------- -------- -------- -------- -------- -------- -------- Revenues $ 619.4 $ 737.1 $ 764.0 $ 943.8 $ 446.3 $ 411.9 $ 384.0 $ 375.3 Operating income (loss) $ 73.8 $ 92.2 $ 150.5 $ 143.9 $ 29.0 $ 8.4 $ (0.7) $ (15.5) Income (loss) from equity investees $ 3.8 $ (0.2) $ 3.7 $ (1.3) $ 0.7 $ -- $ 0.3 $ (0.1) Income (loss) before changes in accounting $ 24.1 $ 27.1 $ 54.0 $ 45.5 $ 4.0 $ (4.3) $ (6.6) $ (16.3) Cumulative effect of accounting changes, net (c) -- 4.5 -- -- -- -- -- -- -------- -------- -------- -------- -------- -------- -------- -------- Net income (loss) $ 24.1 $ 31.6 $ 54.0 $ 45.5 $ 4.0 $ (4.3) $ (6.6) $ (16.3) -------- -------- -------- -------- -------- -------- -------- -------- Earnings (loss) per share: Basic: Income (loss) before accounting changes $ 0.88 $ 1.00 $ 1.96 $ 1.68 $ 0.14 $ (0.16) $ (0.24) $ (0.60) Cumulative effect of accounting changes, net (c) -- 0.17 -- -- -- -- -- -- -------- -------- -------- -------- -------- -------- -------- -------- Net income (loss) $ 0.88 $ 1.17 $ 1.96 $ 1.68 $ 0.14 $ (0.16) $ (0.24) $ (0.60) -------- -------- -------- -------- -------- -------- -------- -------- Diluted: Income (loss) before accounting changes $ 0.87 $ 1.00 $ 1.92 $ 1.67 $ 0.14 $ (0.16) $ (0.24) $ (0.60) Cumulative effect of accounting changes, net (c) -- 0.16 -- -- -- -- -- -- -------- -------- -------- -------- -------- -------- -------- -------- Net income (loss) $ 0.87 $ 1.16 $ 1.92 $ 1.67 $ 0.14 $ (0.16) $ (0.24) $ (0.60) -------- -------- -------- -------- -------- -------- -------- --------
The quarterly data above includes all adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) that we consider necessary for a fair presentation. Our quarterly results fluctuate because of the seasonal nature of our businesses. (a) Includes euro currency transaction gain resulting from the redemption of AGZ Bonds which increased income from equity investees by $1.6 million and decreased net loss by $1.1 million or $0.04 per share. (b) Includes shut-down costs associated with Hearth USA(TM) which increased operating loss by $8.5 million and net loss by $5.5 million or $0.20 per share. (c) Includes the impact of changes in accounting associated with (1) the Partnership's changes in accounting for tank fee revenue and tank installation costs, and (2) the Company's adoption of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." NOTE 21 - SEGMENT INFORMATION We have organized our business units into five reportable segments generally based upon products sold, geographic location (domestic or international) or regulatory environment. Our reportable segments are: (1) AmeriGas Propane; (2) Gas Utility; (3) Electric Operations, comprising Electric Utility and our electricity generation business; (4) Energy Services; and (5) an international propane segment comprising FLAGA and our international propane equity investments ("International Propane"). AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers from locations in 46 states. Gas Utility's revenues are derived principally from the sale and distribution of natural gas to customers in eastern and southeastern Pennsylvania. Electric Operations derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. Energy Services revenues are derived from the sale of natural gas and, to a lesser extent, electricity and fuel oil to customers located primarily in the Middle Atlantic region. Our International Propane segment's revenues are derived principally from the distribution of propane to retail customers in Austria, the Czech Republic and Slovakia. The accounting policies of our reportable segments are 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, minority interests, income from equity investees and cumulative effect of accounting changes ("EBITDA"). Although we use EBITDA to evaluate segment performance, it should not be considered as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States. The Company's definition of EBITDA may be different from that used by other companies. We evaluate the performance of our Gas Utility, Electric Operations 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 United States, and all of our reportable segments' long-lived assets, other than those of our International Propane segment, are located in the United States. 50 UGI Corporation 2002 Annual Report Financial information by reportable business segment follows:
Reportable Segments ------------------------------------------------------ Inter- Elimi- AmeriGas Gas Electric Energy national Corporate & Total nations Propane Utility Operations Services Propane Other -------- -------- -------- -------- ---------- -------- -------- ----------- 2002 Revenues $2,213.7 $ (2.0) $1,307.9 $ 404.5 $ 86.0 $ 332.3 $ 46.7 $ 38.3 EBITDA $ 346.1 $ -- $ 210.7 $ 96.1 $ 16.4 $ 11.9 $ 7.1 $ 3.9 Depreciation and amortization (93.5) -- (66.4) (19.0) (3.2) (0.8) (3.2) (0.9) -------- -------- -------- -------- -------- -------- -------- -------- Operating income 252.6 -- 144.3 77.1 13.2 11.1 3.9 3.0 Income (loss) from equity investees 8.5 -- 0.3 -- -- -- 8.3(a) (0.1) Interest expense (109.1) -- (87.8) (14.2) (2.4) -- (4.2) (0.5) Minority interest (28.0) -- (28.0) -- -- -- -- -- -------- -------- -------- -------- -------- -------- -------- -------- Income before income taxes $ 124.0 $ -- $ 28.8 $ 62.9 $ 10.8 $ 11.1 $ 8.0 $ 2.4 Total assets $2,614.4 $ (34.1) $1,492.2 $ 689.1 $ 109.0 $ 57.2 $ 141.1 $ 159.9 Capital expenditures $ 94.7 $ -- $ 53.5 $ 31.0 $ 4.9 $ 0.9 $ 3.9 $ 0.5 Investments in equity investees $ 35.5 $ -- $ 3.4 $ -- $ 10.0 $ -- $ 22.1 $ -- Goodwill and excess reorganization value $ 644.9 $ -- $ 589.1 $ -- $ -- $ -- $ 53.1 $ 2.7 ======== ======== ======== ======== ======== ======== ======== ======== 2001 Revenues $2,468.1 $ (2.8) $1,418.4 $ 500.8 $ 83.9 $ 370.7 $ 50.9 $ 46.2 EBITDA $ 334.2 $ (0.4) $ 209.3 $ 108.0 $ 14.3 $ 7.6 $ 5.1 $ (9.7)(b) Depreciation and amortization (105.2) -- (75.5) (20.2) (3.6) (0.3) (4.3) (1.3) -------- -------- -------- -------- -------- -------- -------- -------- Operating income (loss) 229.0 (0.4) 133.8 87.8 10.7 7.3 0.8 (11.0) Loss from equity investees (1.6) -- -- -- -- -- (1.5)(a) (0.1) Interest expense (104.8) 0.4 (80.3) (16.3) (2.7) (0.4) (4.9) (0.6) Minority interest (23.6) -- (23.6) -- -- -- -- -- -------- -------- -------- -------- -------- -------- -------- -------- Income (loss) before income taxes $ 99.0 $ -- $ 29.9 $ 71.5 $ 8.0 $ 6.9 $ (5.6) $ (11.7) Total assets $2,550.2 $ (43.3) $1,522.3 $ 678.9 $ 105.5 $ 44.7 $ 141.2 $ 100.9 Capital expenditures $ 79.3 $ -- $ 39.2(c) $ 31.8 $ 5.0 $ 0.2 $ 2.7 $ 0.4 Investments in equity investees $ 44.8 $ -- $ 3.2 $ -- $ 10.8 $ -- $ 30.8(d) $ -- Goodwill and excess reorganization value $ 641.1 $ -- $ 589.0 $ -- $ -- $ -- $ 48.6 $ 3.5 ======== ======== ======== ======== ======== ======== ======== ======== 2000 Revenues $1,761.7 $ (3.1) $1,120.1 $ 359.0 $ 77.9 $ 146.9 $ 50.5 $ 10.4 EBITDA $ 289.6 $ -- $ 158.6 $ 105.3 $ 19.6 $ 3.0 $ 2.8 $ 0.3 Depreciation and amortization (97.5) -- (68.4) (19.1) (4.5) (0.2) (4.6) (0.7) -------- -------- -------- -------- -------- -------- -------- -------- Operating income (loss) 192.1 -- 90.2 86.2 15.1 2.8 (1.8) (0.4) Loss from equity investees (0.9) -- -- -- -- -- (0.9) -- Interest expense (98.5) -- (74.7) (16.2) (2.2) -- (4.8) (0.6) Minority interest (6.3) -- (6.3) -- -- -- -- -- -------- -------- -------- -------- -------- -------- -------- -------- Income (loss) before income taxes $ 86.4 $ -- $ 9.2 $ 70.0 $ 12.9 $ 2.8 $ (7.5) $ (1.0) Total assets $2,275.8 $ (19.0) $1,281.7 $ 653.7 $ 97.4 $ 36.2 $ 113.7 $ 112.1 Capital expenditures $ 71.0 $ -- $ 30.4 $ 31.7 $ 4.7 $ 0.1 $ 1.8 $ 2.3 Investments in equity investees $ 5.5 $ -- $ -- $ -- $ -- $ -- $ 5.5 $ -- Goodwill and excess reorganization value $ 668.1 $ -- $ 615.7 $ -- $ -- $ -- $ 47.6 $ 4.8 ======== ======== ======== ======== ======== ======== ======== ========
(a) In addition to equity income (loss) of international propane equity investees (1) 2002 amount includes a currency transaction gain of $1.6 million from the redemption of AGZ Bonds and $0.9 million of interest income on AGZ Bonds and (2) 2001 amount includes $0.5 million of interest income on AGZ Bonds. (b) Includes Hearth USA(TM) shut-down costs of $8.5 million. (c) Includes capital leases of $1.3 million. (d) Includes investment in AGZ Bonds of $18.2 million. 51