EX-13 10 w43405ex13.txt FINANCIAL REVIEW OF ANNUAL REPORT 1 Exhibit 13 UGI Corporation 2000 Annual Report -------------------------------------------------------------------------------- FINANCIAL REVIEW BUSINESS OVERVIEW Our domestic propane business is conducted through AmeriGas Partners, L.P. ("AmeriGas Partners") and its operating subsidiary, AmeriGas Propane, L.P. (the "Operating Partnership"). We refer to AmeriGas Partners and the Operating Partnership together as "the Partnership." At September 30, 2000, we held an effective 58.4% interest in the Operating Partnership. UGI Utilities, Inc. ("UGI Utilities") operates a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and an electric distribution utility and electricity generation business ("Electric Utility") in northeastern Pennsylvania. Gas Utility and Electric Utility are together referred to as "Utilities." UGI Enterprises, Inc. ("Enterprises"), our "new business" arm, conducts an energy marketing business ("Energy Services") and through other subsidiaries (1) owns and operates a propane distribution business in Austria, the Czech Republic and Slovakia ("FLAGA"); (2) owns and operates a heating, ventilation and air-conditioning service business ("HVAC") and a retail hearth, spa and grill products business in the Middle Atlantic states ("Hearth USA(TM)"); and (3) participates in international propane joint-venture projects. This Financial Review should be read in conjunction with our Consolidated Financial Statements and Notes to Consolidated Financial Statements including the business segment information in Note 17. RESULTS OF OPERATIONS 2000 COMPARED WITH 1999 CONSOLIDATED RESULTS. Our 2000 results reflect improved earnings from Utilities partially offset by a decline in net income from AmeriGas Propane and International Propane losses. Excluding the effect of merger termination fee income in 1999, earnings per share increased 22% in 2000 reflecting a 15% decline in average shares outstanding and higher net income.
Variance- Favorable 2000 1999 (Unfavorable) --------------------------------------------------------------------------- DILUTED Diluted Diluted NET EARNINGS Net Earnings Net Earnings INCOME (LOSS) Income (Loss) Income (Loss) (LOSS) PER SHARE (Loss) Per Share (Loss) Per Share -------------------------------------------------------------------------------------------------------------------------- (Millions of dollars, except per share) AmeriGas Propane $ -- $ -- $ 4.5 $ 0.14 $ (4.5) $ (0.14) Utilities 48.9 1.79 37.4 1.17 11.5 0.62 Energy Services 1.6 0.06 1.5 0.05 0.1 0.01 International Propane (5.6) (0.20) (0.1) -- (5.5) (0.20) Other Enterprises (a) (3.8) (0.14) (3.6) (0.11) (0.2) (0.03) Corporate & Other 3.6 0.13 3.1 0.09 0.5 0.04 Merger termination fee, net (b) -- -- 12.9 0.40 (12.9) (0.40) -------------------------------------------------------------------------------------------------------------------------- Total $ 44.7 $ 1.64 $ 55.7 $ 1.74 $ (11.0) $ (0.10) --------------------------------------------------------------------------------------------------------------------------
(a) Comprised principally of Hearth USA(TM), HVAC, and Enterprises' corporate and general expenses. (b) Represents after-tax merger termination fee income, net of related expenses, associated with the Company's terminated Merger Agreement with Unisource Worldwide, Inc. See Note 14 to Consolidated Financial Statements. SEGMENT RESULTS. The following table presents certain financial and statistical information by business segment for 2000 and 1999:
Increase 2000 1999 (Decrease) ------------------------------------------------------------------------------------------- (Millions of dollars) AMERIGAS PROPANE Revenues $1,120.1 $872.5 $247.6 28.4% Total margin $ 491.8 $481.7 $ 10.1 2.1% EBITDA (a) $ 158.6 $158.8 $ (0.2) (0.1)% Operating income $ 90.2 $ 92.5 $ (2.3) (2.5)% Retail gallons sold (millions) 771.2 783.2 (12.0) (1.5)% Degree days - % warmer than normal (b) 13.7% 9.9% - - GAS UTILITY Revenues $ 359.0 $345.6 $ 13.4 3.9% Total margin $ 170.8 $160.6 $ 10.2 6.4% EBITDA (a) $ 105.3 $ 87.0 $ 18.3 21.0% Operating income $ 86.2 $ 68.0 $ 18.2 26.8% System throughput - billions of cubic feet ("bcf") 79.7 76.1 3.6 4.7% Degree days - % warmer than normal 9.9% 12.8% - - ELECTRIC UTILITY (c) Revenues $ 77.9 $ 75.0 $ 2.9 3.9% Total margin $ 40.5 $ 38.6 $ 1.9 4.9% EBITDA (a) $ 19.6 $ 16.7 $ 2.9 17.4% Operating income $ 15.1 $ 12.7 $ 2.4 18.9% Sales - millions of kilowatt hours ("gwh") 907.2 900.4 6.8 0.8% ENERGY SERVICES Revenues $ 146.9 $ 90.4 $ 56.5 62.5% Total margin $ 6.2 $ 6.0 $ 0.2 3.3% EBITDA (a) $ 3.0 $ 2.7 $ 0.3 11.1% Operating income $ 2.8 $ 2.6 $ 0.2 7.7% INTERNATIONAL PROPANE Revenues $ 50.5 $ - $ 50.5 N.M. Total margin $ 20.8 $ - $ 20.8 N.M. EBITDA (a) $ 1.9 $ (0.1) $ 2.0 N.M. Operating loss $ (2.7) $ (0.1) $ 2.6 N.M. -------------------------------------------------------------------------------------------
N.M. - Not Meaningful (a) EBITDA (earnings before interest expense, income taxes, depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance under generally accepted accounting principles. (b) Deviation from average heating degree days during the 30-year period from 1961 to 1990, based upon national weather statistics provided by the National Oceanic and Atmospheric Administration ("NOAA") for 335 airports in the continental U.S. (c) Electric Utility comprises the Company's regulated electric utility distribution business and its nonutility electric generation operations. 13 2 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) AMERIGAS PROPANE. Based upon national heating degree day information, temperatures in 2000 were 13.7% warmer than normal and 3.8% warmer than in 1999. Retail volumes of propane sold were 12 million gallons lower, primarily a result of the warmer weather's effect on residential heating gallons and a decline in agricultural gallons as a result of a poor crop drying season. Partially offsetting these decreases were higher motor fuel sales, reflecting the continuing effects of our expanding National Accounts program, the volume impact of our growing grill cylinder exchange business, PPX Prefilled Propane Xchange ("PPX(R)"), and acquisition-related volume increases. Total revenues from retail propane sales increased $160.5 million in 2000 due to higher average selling prices. The higher average selling prices resulted from significantly higher propane product costs. Wholesale propane revenues increased $77.4 million reflecting (1) a $50.7 million increase as a result of higher average wholesale prices and (2) a $26.7 million increase as a result of higher wholesale volumes sold. Nonpropane revenues increased $9.7 million in 2000 reflecting higher customer fees, hauling, and PPX(R) cylinder sales revenue. Cost of sales increased $237.5 million primarily as a result of the higher propane product costs and greater wholesale volumes sold. Total margin increased $10.1 million in 2000 due to (1) greater volumes sold to higher margin PPX(R) customers; (2) slightly higher average retail unit margins; and (3) an increase in total margin from customer fees, and ancillary sales and services. EBITDA in 2000 was comparable to 1999 as the increases in total margin and higher other income were offset by higher operating expenses. Other income increased $3.1 million due to, among other things, higher income from sales of assets and higher finance charge income. Operating expenses of the Partnership were $342.7 million in 2000 compared with $329.6 million in 1999 reflecting incremental expenses from growth and operational initiatives and higher vehicle fuel costs. Our growth and operational initiatives in 2000 included significantly expanding PPX(R), acquiring retail propane businesses, and developing and implementing more efficient methods of operating the business. Although EBITDA in 2000 was about equal to 1999, operating income declined $2.3 million reflecting higher PPX(R) and acquisition-related charges for depreciation and amortization. GAS UTILITY. Weather in Gas Utility's service territory was 9.9% warmer than normal in 2000 but 3.8% colder than in 1999. The increase in system throughput during 2000 resulted from higher interruptible delivery service volumes and higher sales to our firm retail ("core market") customers. The increase in Gas Utility's revenues during 2000 principally resulted from (1) a $13.1 million increase in core market revenues reflecting higher sales and higher average purchased gas cost ("PGC") rates partially offset by the impact of the elimination of gross receipts tax revenue effective January 1, 2000 pursuant to Pennsylvania's Gas Competition Act and (2) a $5.9 million increase in revenues from interruptible customers. These increases in revenue were partially offset by lower off-system sales and firm delivery service revenues. Gas Utility cost of gas was $184.2 million in 2000 compared with $172.0 million in 1999. The increase reflects higher average PGC rates and higher core market sales partially offset by lower costs associated with the decline in off-system sales. Gas Utility total margin increased $10.2 million reflecting (1) a $4.2 million increase in total interruptible retail and interruptible delivery service margin; (2) a $4.9 million increase in core market margin; and (3) slightly higher firm delivery service total margin. Gas Utility EBITDA and operating income increased $18.3 million and $18.2 million, respectively, as a result of (1) the higher total margin; (2) a $5.0 million increase in other income; and (3) a decrease in net operating expenses. Other income in 2000 includes, among other things, (1) income from the refund of revenue-related tax overpayments made in prior years (including associated interest); (2) interest income from PGC undercollections; and (3) higher income from a construction project and other activities. Gas Utility's net operating expenses declined $3.1 million, despite an increase in distribution system maintenance expenses, principally reflecting (1) $4.5 million in income from insurance litigation settlements and (2) $0.9 million from adjustments to incentive compensation accruals. ELECTRIC UTILITY. Electric sales for 2000 increased 0.8% on weather that was slightly colder than in the prior year. Revenues increased as a result of the higher sales as well as an increase in transmission revenues from wholesale transmission services which have been unbundled as a result of electric customer choice. Cost of sales increased to $33.9 million in 2000 from $33.2 million in 1999 reflecting the higher sales and higher costs associated with wholesale transmission services. Electric Utility total margin increased $1.9 million principally reflecting the impact of lower average power costs and higher sales. EBITDA and operating income also increased reflecting higher total margin and a $2.5 million increase in other income principally from the sale of pollution credits. These increases were partially offset by higher utility realty taxes and greater power production maintenance expenses. ENERGY SERVICES. Revenues increased $56.5 million during 2000 primarily as a result of higher natural gas prices and to a lesser extent higher volumes sold. Total margin, EBITDA and operating income in 2000 were slightly higher than in 1999 due to the impact of the higher sales on total margin. 14 3 UGI Corporation 2000 Annual Report -------------------------------------------------------------------------------- INTERNATIONAL PROPANE. International Propane results include equity in our joint venture projects in Romania and China and, in 2000, the results of FLAGA. The results of FLAGA during 2000 were adversely affected by weather that was 9.6% warmer than normal and by higher propane supply costs. The higher propane supply costs resulted in lower than normal unit margins and price-induced conservation. Equity income in 2000 from our China propane joint venture partnership was also negatively impacted by higher propane product costs and customer conservation. CORPORATE & OTHER AND OTHER ENTERPRISES. Corporate and other operating income in 2000 was $5.1 million, a decrease of $0.8 million from 1999, primarily reflecting lower interest income on cash investments. Other Enterprises' results in 2000 primarily reflect start-up costs and initial operating losses of Hearth USA(TM). Results in 1999 include due diligence expenses associated with Enterprises' domestic and international new business activities and start-up expenses associated with Hearth USA(TM). INTEREST EXPENSE AND INCOME TAXES. The higher interest expense in 2000 is a result of an increase in the Partnership's long-term debt, higher interest under the Partnership's and UGI Utilities' bank credit agreements, and interest on FLAGA debt in 2000. The effective income tax rate was 46.4% in 2000 compared to 43.0% in 1999 which rate reflected a lower tax rate on merger termination fee income. 1999 COMPARED WITH 1998 CONSOLIDATED RESULTS. Our consolidated net income in 1999 increased $15.4 million compared to 1998. The improvement in net income was due to one-time net merger termination fee income of $12.9 million and higher net income from UGI Utilities and AmeriGas Partners, offset in part by costs associated with Enterprises' new business activities.
Variance- Favorable 1999 1998 (Unfavorable) --------------------------------------------------------------------------- DILUTED Diluted Diluted NET EARNINGS Net Earnings Net Earnings INCOME (LOSS) Income (Loss) Income (Loss) (LOSS) PER SHARE (Loss) Per Share (Loss) Per Share -------------------------------------------------------------------------------------------------------------------------- (Millions of dollars, except per share) AmeriGas Propane $ 4.5 $ 0.14 $ 1.9 $ 0.06 $ 2.6 $ 0.08 Utilities 37.4 1.17 33.0 1.00 4.4 0.17 Energy Services 1.5 0.05 1.1 0.03 0.4 0.02 International Propane (0.1) - (0.5) (0.01) 0.4 0.01 Other Enterprises (3.6) (0.11) (1.3) (0.04) (2.3) (0.07) Corporate & Other 3.1 0.09 6.1 0.18 (3.0) (0.09) Merger termination fee, net 12.9 0.40 - - 12.9 0.40 -------------------------------------------------------------------------------------------------------------------------- Total $ 55.7 $ 1.74 $ 40.3 $ 1.22 $ 15.4 $ 0.52 --------------------------------------------------------------------------------------------------------------------------
SEGMENT RESULTS. The following table presents certain financial and statistical information by business segment for 1999 and 1998:
Increase 1999 1998 (Decrease) ------------------------------------------------------------------------------------------- (Millions of dollars) AMERIGAS PROPANE Revenues $872.5 $914.4 $(41.9) (4.6)% Total margin $481.7 $470.6 $ 11.1 2.4% EBITDA $158.8 $153.3 $ 5.5 3.6% Operating income $ 92.5 $ 87.9 $ 4.6 5.2% Retail gallons sold (millions) 783.2 785.3 (2.1) (0.3)% Degree days - % warmer than normal 9.9% 8.7% - - GAS UTILITY Revenues $345.6 $350.2 $ (4.6) (1.3)% Total margin $160.6 $157.2 $ 3.4 2.2% EBITDA $ 87.0 $ 83.0 $ 4.0 4.8% Operating income $ 68.0 $ 64.8 $ 3.2 4.9% System throughput - bcf 76.1 74.9 1.2 1.6% Degree days - % warmer than normal 12.8% 16.3% - - ELECTRIC UTILITY Revenues $ 75.0 $ 72.1 $ 2.9 4.0% Total margin $ 38.6 $ 34.0 $ 4.6 13.5% EBITDA $ 16.7 $ 13.6 $ 3.1 22.8% Operating income $ 12.7 $ 9.7 $ 3.0 30.9% Sales - gwh 900.4 876.4 24.0 2.7% ENERGY SERVICES Revenues $ 90.4 $103.0 $(12.6) (12.2)% Total margin $ 6.0 $ 4.7 $ 1.3 27.7% EBITDA $ 2.7 $ 2.1 $ 0.6 28.6% Operating income $ 2.6 $ 2.0 $ 0.6 30.0% INTERNATIONAL PROPANE EBITDA $ (0.1) $ (1.0) $ 0.9 90.0% Operating loss $ (0.1) $ (1.0) $ (0.9) (90.0)%
AMERIGAS PROPANE. Based upon national weather data, temperatures in 1999 were 9.9% warmer than normal and 1.3% warmer than in 1998. Retail volumes of propane sold were slightly lower in 1999 primarily as a result of a 7.3 million decline in agricultural gallons as a dry autumn reduced demand for crop drying. Partially offsetting the decrease in agricultural gallons were higher motor fuel sales, increased gallons sold through PPX(R), and, notwithstanding the warmer weather, higher sales to our targeted residential customer market. Total revenues from retail propane sales declined $36.3 million in 1999 primarily due to lower average selling prices. The lower 15 4 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) average selling prices resulted from lower propane product costs. Wholesale propane revenues declined $13.2 million reflecting (1) a $6.9 million decrease as a result of lower average wholesale prices and (2) a $6.3 million decrease as a result of lower wholesale volumes sold. Nonpropane revenues increased $7.6 million in 1999 reflecting higher appliance and cylinder sales, increased terminal and hauling revenues, and greater customer fee revenues. Cost of sales declined $53.0 million primarily as a result of lower propane product costs. Total margin increased $11.1 million in 1999 due to (1) slightly higher average retail unit margin per gallon; (2) greater total margin from PPX; and (3) an increase in total margin from appliance sales, customer fees and hauling and terminal revenue. EBITDA and operating income were higher in 1999 as a result of (1) the higher total margin and (2) higher other income. These increases were partially offset by an increase in operating expenses. Other income, net, in 1998 included a $4.0 million loss from two interest rate protection agreements. Operating expenses of the Partnership were $329.6 million in 1999 compared with $320.2 million in 1998. Operating expenses in 1998 are net of (1) $2.7 million of income from lower required accruals for environmental matters and (2) $2.0 million of income from lower required accruals for property taxes. Excluding the impact of these items in the prior year, operating expenses of the Partnership increased $4.7 million in 1999 principally due to expenses associated with new business initiatives. GAS UTILITY. Weather in Gas Utility's service territory was 12.8% warmer than normal in 1999 but 4.2% colder than in 1998. Total system throughput increased 1.6% as a result of the slightly colder weather as well as an increase in total customers. The decrease in Gas Utility revenues in 1999 is principally due to several of our core market industrial customers switching from retail to delivery service. Under retail service, we bill our customers for the transportation of gas through our distribution system as well as the cost of the gas, for which we get dollar-for-dollar recovery. Under delivery service, we bill customers for the transportation of the gas but not for the gas itself. Our revenues from customers who switch to delivery service are therefore lower, but there is little impact on our total margin. Partially offsetting the decline in revenues from our core market industrial customers was an increase in revenues from sales to our core market residential and commercial customers. Gas Utility cost of gas was $172.0 million in 1999, a decrease of $7.6 million from 1998, reflecting the impact of core market industrial customers switching to delivery service. The increase in Gas Utility total margin in 1999 includes a $3.6 million increase from sales to our core market residential and commercial customers. Total margin from interruptible customers (who have the ability to switch to alternate fuels, principally oil) was slightly lower in 1999. The decline in total margin from our interruptible customers reflects lower interruptible rates due to a decline in the spread between oil and natural gas prices during most of 1999. Gas Utility operating income was higher in 1999 reflecting the increase in total margin and higher other income partially offset by slightly higher operating and administrative expenses and increased charges for depreciation. Operating expenses in 1998 are net of $1.6 million of income from an insurance recovery. Excluding the impact of the insurance recovery in 1998, total Gas Utility operating and administrative expenses in 1999 were essentially unchanged. ELECTRIC UTILITY. The increase in 1999 sales of electricity reflects slightly colder heating season weather and warmer weather during the summer air conditioning season. Electric Utility revenues increased $2.9 million in 1999 principally as a result of the higher sales. Although Electric Utility's Restructuring Order filed pursuant to Pennsylvania's Electricity Customer Choice Act gives all of our customers the ability to choose their electricity generation supplier effective January 1, 1999, only approximately 5% of our sales during 1999 represented electricity we distributed for alternate suppliers. Notwithstanding the increase in Electric Utility sales in 1999, cost of sales decreased $1.8 million to $33.2 million. The impact of the higher 1999 sales on purchased power costs was more than offset by (1) the benefit of a power supply agreement settlement and (2) lower average purchased power costs Electric Utility's total margin increased $4.6 million as a result of (1) the power supply agreement settlement; (2) lower average purchased power costs; and (3) the higher sales. EBITDA and operating income were also higher as the greater total margin was partially offset by higher maintenance costs associated with our generation assets, higher customer service and information expenses, and lower other income. ENERGY SERVICES. Total revenues from energy marketing in 1999 declined $12.6 million as a result of lower average gas prices and, to a lesser extent, a decrease in billed volumes. Total margin increased $1.3 million reflecting higher average margins from gas marketing and greater income from power marketing and other services. EBITDA and operating income increased $0.6 million in 1999 as a result of the higher margin offset by slightly higher operating expenses. INTERNATIONAL PROPANE. Results for 1999 and 1998 principally reflect the equity results in our international propane joint venture projects. CORPORATE & OTHER AND OTHER ENTERPRISES. Corporate and other operating income was $5.9 million in 1999 compared with $8.6 million in 1998. Income in both years principally comprises inter- 16 5 UGI Corporation 2000 Annual Report -------------------------------------------------------------------------------- est income on short-term investments and, in 1998, income from the sale of certain equity securities. The decrease in operating income from Other Enterprises in 1999 resulted from start-up costs associated with Hearth USA(TM) retail and due diligence expenses associated with international propane business opportunities. INTEREST EXPENSE AND INCOME TAXES. The Company's interest expense in 1999 was $84.6 million, comparable to the $84.4 million recorded in 1998. The effective income tax rate in 1999 was 43.0% compared to an effective tax rate of 44.7% in 1998. The lower effective tax rate in 1999 is principally a result of a lower tax rate on the merger termination fee income. FINANCIAL CONDITION AND LIQUIDITY CAPITALIZATION AND LIQUIDITY Our cash and short-term investments totaled $101.7 million at September 30, 2000 compared with $55.6 million at September 30, 1999. Included in these amounts are $56.3 million and $23.3 million, respectively, of cash and short-term investments held by UGI. The primary sources of UGI's cash and short-term investments are the cash dividends it receives from its wholly owned subsidiaries, AmeriGas, Inc. and UGI Utilities. AmeriGas, Inc.'s ability to pay dividends to UGI is dependent upon the receipt of distributions on the Common and Subordinated units of AmeriGas Partners that we own. During 2000, 1999 and 1998, AmeriGas, Inc. and UGI Utilities paid cash dividends to UGI as follows:
Year Ended September 30, 2000 1999 1998 --------------------------------------------------------------- (Millions of dollars) AmeriGas $51.6 $47.6 $55.2 UGI Utilities 44.0 29.0 22.6 --------------------------------------------------------------- Total dividends to UGI $95.6 $76.6 $77.8 ---------------------------------------------------------------
THE PARTNERSHIP. The Operating Partnership's primary sources of cash since its formation in 1995 have been (1) cash generated by operations; (2) borrowings under its Bank Credit Agreement; and (3) the issuance of $80 million of long-term debt in 2000 and $70 million of long-term debt in 1999. On September 22, 2000, a shelf registration statement for the issuance of 9 million AmeriGas Common Units was declared effective by the Securities and Exchange Commission. In October 2000, the Partnership issued 2.3 million of its registered Common Units in an underwritten public offering and received $40.6 million in cash proceeds, including related capital contributions from our wholly owned, second-tier subsidiary, AmeriGas Propane, Inc. (the "General Partner"). These proceeds were used to reduce Bank Credit Agreement indebtedness and for working capital purposes. The Operating Partnership's Bank Credit Agreement, as amended, consists of (1) a $100 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for (1) working capital; (2) capital expenditures; and (3) interest and Partnership distribution payments. Revolving Credit Facility loans were $30 million at September 30, 2000 and $22 million at September 30, 1999. The Operating Partnership may borrow under its Acquisition Facility to finance the purchase of propane businesses or propane business assets. Loans outstanding under the Acquisition Facility at September 30, 2000 and 1999 were $70 million and $23 million, respectively. During 2000, the Bank Credit Agreement was amended to, among other changes, extend the Acquisition Facility termination date to September 15, 2002. Then-outstanding borrowings under the Acquisition Facility will be due in their entirety on such date. The Operating Partnership also has a credit agreement with the General Partner to borrow up to $20 million on an unsecured, subordinated basis, to fund (1) working capital; (2) capital expenditures; and (3) interest and Partnership distribution payments. UGI has agreed to contribute up to $20 million to the General Partner to fund such borrowings. During 2000, the Operating Partnership issued $80 million of Series E First Mortgage Notes at an effective interest rate of 8.47%. The proceeds were used principally to reduce Acquisition Facility borrowings and $10 million of maturing First Mortgage Note debt. The Partnership's management believes that cash flow from operations and Bank Credit Agreement borrowings will be sufficient to satisfy its liquidity needs in fiscal 2001. For a more detailed discussion of the Partnership's credit facilities, including financial covenant ratios, see Note 3. UGI UTILITIES. UGI Utilities' primary sources of cash have been (1) cash generated by operations; (2) borrowings under its revolving credit agreements; and (3) debt issued under its Medium-Term Note program. UGI Utilities can issue up to an additional $52 million under its Medium-Term Note program. UGI Utilities may borrow up to a total of $122 million under its revolving credit agreements. Borrowings under revolving credit agreements totaled $100.4 million at September 30, 2000 and $87.4 million at September 30, 1999. Management believes that UGI Utilities' cash flow from operations and borrowings under its Medium-Term Note program and 17 6 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) bank credit facilities will satisfy UGI Utilities' cash needs in fiscal 2001. For a more detailed discussion of UGI Utilities' debt and credit facilities, including financial covenants and ratios, see Note 3. FLAGA. FLAGA has a 9 million EURO working capital loan commitment and a 15 million EURO special purpose commitment from a foreign bank. Borrowings under these commitments totaled 4.9 million EUROs and 13.5 million EUROs, respectively, at September 30, 2000. Management believes that cash flow from operations and borrowings under its special purpose facility, working capital facility and a short-term credit facility from UGI will satisfy FLAGA's cash needs in fiscal 2001. CASH FLOWS OPERATING ACTIVITIES. Cash flow from operating activities was $132.7 million in 2000 compared to $141.9 million in 1999 which included $12.9 million of after-tax proceeds from the merger termination fee. As a result of significantly higher propane and natural gas costs, cash flows from operating activities in 2000 reflect significantly higher accounts receivable, inventories and accounts payable. Cash flow from operating activities before changes in operating working capital declined modestly from $170.3 million in 1999 to $167.5 million in 2000. INVESTING ACTIVITIES. We spent $71.0 million for property, plant and equipment in 2000 compared with $70.2 million in 1999. The increase in 2000 resulted from expenditures of FLAGA. Net cash paid for acquisitions, principally comprising Partnership propane and HVAC business acquisitions, totaled $65.3 million in 2000 compared to $77.6 million in 1999 including $73.7 million for the purchase of FLAGA. FINANCING ACTIVITIES. We paid cash dividends on our Common Stock of $41.2 million in 2000 compared to $47.9 million in 1999 on fewer shares outstanding. In 2000 and 1999, the Partnership paid (1) distributions to its public unitholders totaling approximately $39 million; (2) the full minimum quarterly distribution of $0.55 ("MQD") on all units we hold totaling $53.2 million; and (3) $1.1 million to the General Partner. During 2000, the Operating Partnership borrowed $116 million under the Acquisition Facility, and made Acquisition Facility repayments totaling $69 million. In 2000, we used $9.6 million to repurchase 0.5 million shares of UGI Common Stock. In 1999, we spent $133.1 million (including transaction costs) for the repurchase of 5.9 million shares of UGI Common Stock, including 4.5 million shares repurchased through our Dutch auction tender offer. DIVIDENDS AND DISTRIBUTIONS In April 2000, our board of directors increased the annual dividend rate to $1.55 a share from $1.50. Dividends declared in 2000 totaled $41.4 million. At September 30, 2000, our 58.4% effective interest in the Partnership consisted of (1) 14.3 million Common Units; (2) 9.9 million Subordinated Units; and (3) a 2% general partner interest. The remaining 41.6% effective interest consists of 17.8 million publicly held Common Units. As a result of the Partnership's October 2000 issue of 2.3 million Common Units pursuant to a public offering, our effective interest in the Partnership declined to 55.5%. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Agreement of Limited Partnership of AmeriGas Partners, the "Partnership Agreement") relating to such fiscal quarter. Common Unitholders receive the MQD, plus any arrearages, before a distribution of Available Cash can be made on the Subordinated Units. Since its formation in 1995, the Partnership has paid the MQD on all limited partner units outstanding. The amount of Available Cash needed annually to pay the MQD on all units and the general partner interests in 2000, 1999 and 1998 was approximately $94 million. In fiscal 2001, as a result of the additional Common Units issued in October 2000, this amount will increase to approximately $99 million. One measure of the amount of cash available for distribution that is generated by the Partnership can be determined by subtracting (1) cash interest expense and (2) capital expenditures needed to maintain operating capacity, from the Partnership's EBITDA. Partnership distributable cash flow as calculated for 2000, 1999 and 1998 is as follows:
Year Ended September 30, 2000 1999 1998 ------------------------------------------------------------------ (Millions of dollars) EBITDA $157.6 $157.5 $151.1 Cash interest expense (a) (76.7) (68.3) (67.6) Maintenance capital expenditures (11.6) (11.1) (10.3) ------------------------------------------------------------------ Distributable cash flow $ 69.3 $ 78.1 $ 73.2 ------------------------------------------------------------------
(a) Interest expense adjusted for noncash items. Although distributable cash flow is a reasonable estimate of the amount of cash generated by the Partnership, it does not reflect the impact of changes in working capital which can significantly affect cash available for distribution and it is not a measure of performance or financial condition under generally accepted accounting principles but provides additional information for evaluating the Partnership's ability to declare and pay the MQD. Although the 18 7 UGI Corporation 2000 Annual Report -------------------------------------------------------------------------------- levels of distributable cash flow in these years were less than the full MQD, borrowings in 2000 and 1999, and cash generated from changes in working capital in 1998, were more than sufficient to permit the Partnership to declare and pay the full MQD. The ability of the Partnership to declare and pay the MQD on all units depends upon a number of factors. These factors include (1) the level of Partnership earnings; (2) the cash needs of the Partnership's operations (including cash needed for maintaining and increasing operating capacity); (3) changes in operating working capital; and (4) the Partnership's ability to borrow under its Bank Credit Agreement, to refinance maturing debt, and to increase its long-term debt. Some of these factors are affected by conditions beyond our control including weather, competition in markets we serve, and the cost of propane. CONVERSION OF SUBORDINATED UNITS Pursuant to the Partnership Agreement, a total of 9,891,074 Subordinated Units held by the General Partner were converted to Common Units on May 18, 1999 because certain historical and projected cash generation-based requirements were achieved as of March 31, 1999. The Partnership's ability to attain the cash-based performance and distribution requirements necessary to convert the remaining 9,891,072 Subordinated Units depends upon a number of factors, including highly seasonal operating results, changes in working capital, asset sales and debt refinancings. Due to significantly warmer-than-normal weather and the impact of higher propane product costs on working capital, we did not achieve the cash-based performance requirements as of any relevant quarter through September 30, 2000. Due to the historical "look-back" provisions of the conversion test, the possibility is remote that the Partnership will satisfy the cash-based performance requirements for conversion any earlier than in respect of the quarter ending March 31, 2002. CAPITAL EXPENDITURES In the following table, we present capital expenditures of our consolidated operations (which include expenditures for capital leases but exclude acquisitions) for 2000, 1999 and 1998. We also provide amounts we expect to spend in fiscal 2001. We expect to finance a substantial portion of fiscal 2001 capital expenditures from cash generated by operations and the remainder from borrowings under our credit facilities.
Year Ended September 30, 2001 2000 1999 1998 ---------------------------------------------------------------------- (Millions of dollars) (estimate) AmeriGas Propane $28.9 $30.4 $34.6 $31.9 Utilities 40.9 36.4 36.4 37.2 International Propane 2.9 1.8 - - Other 2.2 2.4 2.7 0.1 ---------------------------------------------------------------------- Total $74.9 $71.0 $73.7 $69.2 ----------------------------------------------------------------------
UTILITY MATTERS On June 22, 1999, Pennsylvania's Natural Gas Choice and Competition Act ("Gas Competition Act") was signed into law. The purpose of the Gas Competition Act is to provide all natural gas consumers in Pennsylvania with the ability to purchase their gas supplies from the supplier of their choice. Under the Gas Competition Act, local gas distribution companies ("LDCs") like Gas Utility may continue to sell gas to customers, and such sales of gas, as well as distribution services provided by LDCs, continue to be subject to price regulation by the Pennsylvania Public Utility Commission ("PUC"). As of January 1, 2000, the Gas Competition Act, in conjunction with a companion bill, eliminated the gross receipts tax on sales of gas. Generally, LDCs will serve as the supplier of last resort for all residential and small commercial and industrial customers unless the PUC approves another supplier of last resort. LDCs are generally precluded from increasing rates for the recovery of costs, other than gas costs, until January 1, 2001. The Gas Competition Act requires energy marketers seeking to serve customers of LDCs to accept assignment of a portion of the LDC's pipeline capacity and storage contracts at contract rates, thus avoiding the creation of stranded costs. After July 1, 2002, a natural gas supplier may petition the PUC to avoid such contract release or assignment. The PUC, however, may only grant the petition if certain findings are made and the LDC fully recovers the cost of contracts. On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas Utility's restructuring plan substantially as filed. Among other things, the restructuring plan (1) provides for recovery of costs associated with existing pipeline capacity and gas supply contracts; (2) increases Gas Utility's base rates for firm customers; and (3) changes the calculation of the PGC rates. The effect of (2) and (3) above is to reduce the financial impact of volatility in revenues from customers who have the ability to switch to an alternate fuel under interruptible rates and increase our sensitivity to changes in weather. Because the Gas Competition Act requires alternate suppliers to accept assignment of a portion of the LDC's pipeline capacity and storage contracts, we do not believe the Gas Competition Act and the Gas Restructuring Order will have a material adverse impact on our financial condition or results of operations. In September 2000, UGI Development Company ("UGIDC"), a subsidiary of UGI Utilities, agreed to joint venture with a subsidiary of Allegheny Energy, Inc. ("Allegheny") to own and operate electric generation facilities, including Electric Utility's coal-fired Hunlock Creek generating station ("Hunlock"). Initially, UGIDC will contribute to the joint venture Hunlock, certain related assets, and approximately $6 million in cash. Allegheny will contribute a newly-constructed gas-fired combustion turbine generator to be operated at the existing Hunlock site. Each partner will be entitled 19 8 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) to purchase 50% of the output of the joint venture at cost. The joint venture is expected to become operational in December 2000. MANUFACTURED GAS PLANTS Prior to the general availability of natural gas, in the 1800s through the mid-1900s, most gas for lighting and heating nationwide was manufactured from combustibles such as coal, oil and coke. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the federal "Comprehensive Environmental Response, Compensation and Liability Act," or "Superfund Law," and may be present on the sites of former manufactured gas plants ("MGPs"). UGI Utilities and its former subsidiaries owned and operated a number of MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the mid-1930s, UGI Utilities was one of the largest public utility holding companies in the country. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, UGI Utilities divested all of its utility operations other than those which now constitute Gas Utility and Electric Utility. UGI Utilities has been notified of several sites outside Pennsylvania on which (1) gas plants were formerly operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or private parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating two claims against it relating to out-of state sites. Management believes that UGI Utilities should not have significant liability in those instances in which a former subsidiary operated an MGP because UGI Utilities generally is not legally liable for the obligations of its subsidiaries. Under certain circumstances, however, a court could find a parent company liable for environmental damage caused by a subsidiary company when the parent company either (1) itself operated the facility causing the environmental damage or (2) otherwise so controlled the subsidiary that the subsidiary's separate corporate form should be disregarded. There could be, therefore, significant future costs of an uncertain amount associated with environmental damage caused by MGPs that UGI Utilities owned or directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that the subsidiary's separate corporate form should be disregarded. UGI Utilities has identified 40 sites in Pennsylvania where either (1) UGI Utilities formerly conducted some MGP operations or (2) UGI Utilities owns or at one time owned the site. Because Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with Pennsylvania sites, the Company does not expect its costs for Pennsylvania sites to be material to future results of operations. UGI Utilities has filed suit against more than fifty insurance companies alleging that the defendants breached contracts of insurance by failing to indemnify UGI Utilities for certain environmental costs. The suit seeks to recover more than $11 million in such costs. During 2000, UGI Utilities entered into settlement agreements with several of the insurers and recorded pre-tax income of $4.5 million. MARKET RISK DISCLOSURES Our primary market risk exposures are (1) fluctuations in market prices for propane, natural gas and electricity; (2) changes in interest rates; and (3) foreign currency exchange rates. The Partnership's profitability is sensitive to changes in propane supply costs, and the Partnership generally attempts to pass on promptly increases in such costs to customers. There is no assurance, however, that the Partnership will be able to do so. In order to manage a portion of the Partnership's propane market price risk, it uses contracts for the forward purchase of propane, propane fixed-price supply agreements, and derivative commodity instruments such as price swap and option contracts. Due to competitive and business conditions in the markets it serves, FLAGA is less able than the Partnership to recover promptly increases in product costs. FLAGA does not currently use derivative commodity instruments to hedge propane market risk. In order to manage market price risk relating to substantially all of Energy Services' forecasted sales of natural gas, we purchase exchange-traded natural gas futures contracts. In addition, we occasionally utilize a managed program of derivative instruments including natural gas and oil futures contracts to preserve gross margin associated with certain of our natural gas customers. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The current regulatory framework allows Gas Utility to recover prudently incurred gas costs from its customers. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Electric Utility purchases electricity it does not otherwise pro- 20 9 UGI Corporation 2000 Annual Report -------------------------------------------------------------------------------- duce, representing approximately 50% of its electric power needs in 2000, under power supply arrangements of varying length terms with other producers and on the spot market. Spot market prices for electricity and, to a lesser extent, monthly market-based contracts can be volatile, especially during periods of high demand. Because Electric Utility's generation rates are capped through approximately December 2002 under its Restructuring Order, any increases in costs to produce or purchase electricity will negatively impact Electric Utility's results. We have market risk exposure from changes in interest rates on floating rate borrowings under the Operating Partnership's Bank Credit Agreement, UGI Utilities' revolving credit agreements and substantially all of FLAGA's debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. At September 30, 2000 and 1999, combined borrowings outstanding under these facilities totaled $282.1 million and $221.0 million, respectively. Based upon average borrowings under these agreements during 2000 and 1999, an increase in short-term interest rates of 100 basis points (1%) would have increased interest expense by $2.5 million and $1.2 million, respectively. We also use fixed-rate long-term debt as a source of capital. As these fixed-rate long-term debt issues mature, we intend to refinance such debt with new debt having interest rates reflecting then-current market conditions. This debt may have an interest rate that is more or less than the refinanced debt. On occasion, we enter into interest rate protection agreements to reduce interest rate risk associated with a forecasted issuance of debt. We do not currently use derivative instruments to hedge foreign currency exposure associated with our investments in international propane operations, principally FLAGA. As a result, the U.S. dollar value of our foreign denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. Our exposure to changes in foreign currency exchange rates has been significantly limited, however, because our net investment in FLAGA, our principal international propane operation, was financed with EURO denominated debt. The following table summarizes the fair values of unsettled market risk sensitive derivative instruments held at September 30, 2000 and 1999. It also includes the changes in fair value that would result if there were an adverse change in (1) the market price of propane of 10 cents a gallon; (2) the market price of natural gas of 50 cents a dekatherm; (3) interest rates on ten-year U.S. treasury notes of 100 basis points; and (4) the market price of oil of 10 cents a gallon:
Change in Fair Value Fair Value ------------------------------------------------------------------------ (Millions of dollars) September 30, 2000: Propane commodity price risk $6.5 $(10.5) Natural gas commodity price risk 4.2 (3.5) Interest rate risk 2.5 (3.9) September 30, 1999: Propane commodity price risk $2.9 $(2.5) Natural gas commodity price risk 2.6 (5.2) Interest rate risk 3.2 (3.8) Oil commodity price risk (0.2) (0.5) ------------------------------------------------------------------------
We expect that adverse changes in the fair value of derivative instruments used to manage commodity or interest rate market risk would be substantially offset by gains on the associated underlying transactions. ACCOUNTING PRINCIPLES NOT YET ADOPTED In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 was amended in June 2000 by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" ("SFAS 138"), which addressed a limited number of issues causing implementation difficulties. SFAS 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that an entity recognize all derivative instruments as either assets or liabilities and measure them at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. To the extent derivative instruments qualify and are designated as hedges of the variability in cash flows associated with forecasted transactions, the effective portion of the gain or loss on such derivative instruments will generally be reported in other comprehensive income and the ineffective portion, if any, will be reported in net income. Such amounts recorded in accumulated other comprehensive income will be reclassified into net income when the forecasted transaction affects earnings. To the extent derivative instruments qualify and are designated as hedges of changes in the fair value of an existing asset, liability or firm commitment, the gain or loss on the hedging instrument will be recognized currently in earnings along with changes in the fair value of the hedged asset, liability or firm commitment attributable to the hedged risk. 21 10 -------------------------------------------------------------------------------- FINANCIAL REVIEW (continued) The Company was required to adopt the provisions of SFAS 133 effective October 1, 2000. Virtually all of the Company's derivative instruments outstanding as of October 1, 2000 qualify and have been designated as hedging the variability in cash flows associated with forecasted transactions. The adoption of SFAS 133 will result in an after-tax cumulative effect charge to net income of $0.3 million, and an after-tax cumulative effect increase to accumulated other comprehensive income of $7.1 million. Because the Company's derivative instruments historically have been highly effective in hedging the exposure to changes in cash flows associated with forecasted purchases or sales of natural gas and propane, changes in the fair value of propane inventories, and changes in the risk-free rate of interest on anticipated issuances of long-term debt, we do not expect the adoption of SFAS 133 to have a material impact on our future results of operations. Although the Company expects the derivative instruments it currently uses to hedge to continue to be highly effective, if they are determined not to be highly effective in the future, or if the Company uses derivative instruments that do not meet the stringent requirements for hedge accounting under SFAS 133, our future earnings could reflect greater volatility. Additionally, if a cash flow hedge is discontinued because the forecasted transaction is no longer expected to occur, any gain or loss in accumulated comprehensive income associated with the hedged transaction will be immediately recognized in net income. In order to comply with the provisions of the Securities and Exchange Commission Staff Accounting Bulletin No. 101 ("SAB 101") entitled "Revenue Recognition", which is effective for the Company on October 1, 2000, the Company will record a cumulative effect charge to net income of approximately $2.3 million related to the Partnership's method of recognizing revenue associated with nonrefundable tank fees largely for residential customers. Consistent with a number of its competitors in the propane industry, the Partnership receives nonrefundable fees for installed Partnership-owned tanks. Historically, such fees, which are generally received annually, were recorded as revenue when billed. In accordance with SAB 101, effective October 1, 2000, the Partnership will record such nonrefundable fees on a straight-line basis over one year. The adoption of SAB 101 is not expected to have a material impact on the Company's future financial condition or results of operations. Also, during fiscal 2001, the Partnership plans to change its method of accounting for tank installation costs which are not billed to customers. Currently, all direct costs to install Partnership-owned tanks at a customer location are expensed as incurred. The Partnership believes that these costs should now be capitalized and amortized over the period benefited. On date of adoption, this change in accounting method will result in a cumulative effect increase to net income. The Company is in the process of evaluating the impact of such change on its financial condition and results of operations. PROPOSED FOREIGN EQUITY INVESTMENT On October 30, 2000, the Company, together with Paribas Affaires Industrielles ("PAI") and Medit Mediterranea GPL, S.r.L. ("Medit"), submitted to Total Fina Elf S. A. ("TFE"), a large French petroleum and chemical company, a bid to acquire the stock and certain related assets of Elf AntarGaz S.A. ("EAZ"). EAZ, a subsidiary of TFE, is one of the largest distributors of liquefied petroleum gas in France with an approximate 24% market share. Under the terms of the bid, the Company would acquire a 20% interest in EAZ; PAI a 70% interest; and Medit a 10% interest. PAI is a leading private equity fund manager in Europe and an affiliate of BNP Partners. BNP Partners is one of Europe's largest commercial and investment banks. Medit is a supplier of logistics services to the liquefied petroleum gas industry in Europe, primarily Italy. The amount of the Company's investment in EAZ is not expected to exceed $30 million. The bid is subject to approval by the Commission of the European Communities. There can be no assurance, however, that the bid will be approved or that other requirements for consummation of the transaction will be met. FORWARD-LOOKING STATEMENTS Information contained in this Financial Review and elsewhere in this Annual Report with respect to expected financial results and future events is forward-looking, based on our estimates and assumptions and subject to risks and uncertainties. For those statements, we claim the protection of the safe harbor for forward looking statements contained in the Private Securities Litigation Reform Act of 1995. The following important factors could affect our future results and could cause actual results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability of propane, oil, electricity, and natural gas and the capacity to transport product to market areas; (3) changes in laws and regulations, including safety, tax and accounting matters; (4) competitive pressures from the same and alternative energy sources; (5) 22 11 liability for environmental claims; (6) improvements in energy efficiency and technology resulting in reduced demand; (7) labor relations; (8) large customer or supplier defaults; (9) operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and propane including the risk of explosions and fires resulting in personal injury and property damage; (10) regional economic conditions; (11) political, regulatory and economic conditions in foreign countries; (12) interest rate fluctuations and other capital market conditions, including foreign currency rate fluctuations; (13) reduced distributions from subsidiaries; and (14) the timing and success of the Company's efforts to develop new business opportunities. These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events. 23 12 UGI Corporation 2000 Annual Report -------------------------------------------------------------------------------- REPORT OF MANAGEMENT The Company's consolidated financial statements and other financial information contained in this Annual Report are prepared by management, which is responsible for their fairness, integrity and objectivity. The consolidated financial statements and related information were prepared in accordance with accounting principles generally accepted in the United States and include amounts that are based on management's best judgements and estimates. The Company maintains a system of internal controls. Management believes the system provides reasonable assurance that assets are safeguarded and that transactions are executed in accordance with management's authorization and are properly recorded to permit the preparation of reliable financial information. There are limits in all systems of internal control, based on the recognition that the cost of the system should not exceed the benefits to be derived. We believe that the Company's internal control system is cost effective and provides reasonable assurance that material errors or irregularities will be prevented or detected within a timely period. The internal control system and compliance therewith are monitored by the Company's internal audit staff. The Audit Committee of the Board of Directors is composed of three members, none of whom is an employee of the Company. This Committee is responsible for overseeing the financial reporting process and the adequacy of controls, and for monitoring the independence of the Company's independent public accountants and the performance of the independent accountants and internal audit staff. The Committee recommends to the Board of Directors the engagement of the independent public accountants to conduct the annual audit of the Company's consolidated financial statements. The Committee is also responsible for maintaining direct channels of communication between the Board of Directors and both the independent public accountants and internal auditors. The independent public accountants, who are appointed by the Board of Directors and ratified by the shareholders, perform certain procedures, including an evaluation of internal controls to the extent required by auditing standards generally accepted in the United States, in order to express an opinion on the consolidated financial statements and to obtain reasonable assurance that such financial statements are free of material misstatement. /s/ Lon. R. Greenberg Lon. R. Greenberg Chief Executive Officer /s/ Anthony J. Mendicino Anthony J. Mendicino Chief Financial Officer -------------------------------------------------------------------------------- Report of Independent Public Accountants TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF UGI CORPORATION: We have audited the accompanying consolidated balance sheets of UGI Corporation and subsidiaries as of September 30, 2000 and 1999, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended September 30, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based upon our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of UGI Corporation and subsidiaries as of September 30, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2000, in conformity with accounting principles generally accepted in the United States. /s/ Arthur Andersen LLP Philadelphia, Pennsylvania November 10, 2000 24 13 UGI Corporation 2000 Annual Report CONSOLIDATED STATEMENTS OF INCOME (MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
Year Ended September 30, ---------------------------------------------- 2000 1999 1998 ---------- ---------- ---------- REVENUES AmeriGas Propane $ 1,120.1 $ 872.5 $ 914.4 UGI Utilities 436.9 420.6 422.3 International Propane 50.5 -- -- Energy Services and other 154.2 90.5 103.0 ---------- ---------- ---------- 1,761.7 1,383.6 1,439.7 ---------- ---------- ---------- COSTS AND EXPENSES AmeriGas Propane cost of sales 628.3 390.8 443.8 UGI Utilities - gas, fuel and purchased power 218.1 205.2 214.6 International Propane cost of sales 29.7 -- -- Energy Services and other cost of sales 145.5 84.4 98.3 Operating and administrative expenses 461.2 429.2 412.5 Utility taxes other than income taxes 17.1 25.2 25.2 Depreciation and amortization 97.5 89.7 87.8 Other income, net (26.9) (16.8) (12.7) ---------- ---------- ---------- 1,570.5 1,207.7 1,269.5 ---------- ---------- ---------- OPERATING INCOME 191.2 175.9 170.2 Merger fee income and expenses, net -- 19.9 -- Interest expense (98.5) (84.6) (84.4) Minority interest in AmeriGas Partners (6.3) (10.7) (8.9) ---------- ---------- ---------- INCOME BEFORE INCOME TAXES AND SUBSIDIARY PREFERRED STOCK DIVIDENDS 86.4 100.5 76.9 Income taxes (40.1) (43.2) (34.4) Dividends on UGI Utilities Series Preferred Stock (1.6) (1.6) (2.2) ---------- ---------- ---------- NET INCOME $ 44.7 $ 55.7 $ 40.3 ---------- ---------- ---------- EARNINGS PER COMMON SHARE Basic $ 1.64 $ 1.74 $ 1.22 Diluted $ 1.64 $ 1.74 $ 1.22 AVERAGE COMMON SHARES OUTSTANDING (MILLIONS) Basic 27.219 31.954 32.971 Diluted 27.255 32.016 33.123 ========== ========== ==========
See accompanying notes to consolidated financial statements. 25 14 UGI Corporation 2000 Annual Report CONSOLIDATED BALANCE SHEETS (Millions of dollars)
September 30, ------------------------ ASSETS 2000 1999 -------- -------- CURRENT ASSETS Cash and cash equivalents $ 93.9 $ 40.5 Short-term investments, at cost which approximates market value 7.8 15.1 Accounts receivable (less allowances for doubtful accounts of $9.3 and $8.0, respectively) 165.7 107.5 Accrued utility revenues 10.5 6.9 Inventories 117.4 87.1 Deferred income taxes 11.8 13.7 Prepaid expenses and other current assets 19.0 24.7 -------- -------- Total current assets 426.1 295.5 -------- -------- PROPERTY, PLANT AND EQUIPMENT AmeriGas Propane 722.1 680.7 UGI Utilities 857.8 826.8 Other 72.2 91.5 -------- -------- 1,652.1 1,599.0 Accumulated depreciation and amortization (578.9) (514.9) -------- -------- Net property, plant and equipment 1,073.2 1,084.1 -------- -------- OTHER ASSETS Intangible assets (less accumulated amortization of $190.2 and $165.9, respectively) 675.5 653.1 Utility regulatory assets 62.3 61.1 Other assets 41.7 46.7 -------- -------- TOTAL ASSETS $2,278.8 $2,140.5 ======== ========
See accompanying notes to consolidated financial statements. 26 15 UGI Corporation 2000 Annual Report
September 30, ------------------------- LIABILITIES AND STOCKHOLDERS' EQUITY 2000 1999 -------- -------- CURRENT LIABILITIES Current maturities of long-term debt $ 85.9 $ 26.7 Operating Partnership bank loans 30.0 22.0 UGI Utilities bank loans 100.4 87.4 Other bank loans 4.3 11.6 Accounts payable 156.7 100.6 Employee compensation and benefits accrued 26.5 34.4 Dividends and interest accrued 47.3 44.1 Income taxes accrued 10.3 0.6 Deposits and refunds 39.0 40.2 Other current liabilities 39.0 39.3 -------- -------- Total current liabilities 539.4 406.9 -------- -------- DEBT AND OTHER LIABILITIES Long-term debt 1,029.7 989.6 Deferred income taxes 172.9 174.3 Deferred investment tax credits 9.2 9.6 Other noncurrent liabilities 83.3 81.0 Commitments and contingencies (note 11) -------- -------- MINORITY INTEREST Minority interest in AmeriGas Partners 177.1 209.9 -------- -------- PREFERRED AND PREFERENCE STOCK UGI Utilities Series Preferred Stock Subject to Mandatory Redemption, without par value 20.0 20.0 Preference Stock, without par value (authorized-5,000,000 shares) -- -- COMMON STOCKHOLDERS' EQUITY Common Stock, without par value (authorized-100,000,000 shares; issued-33,198,731 shares) 394.5 394.8 Accumulated deficit (4.9) (8.2) Accumulated other comprehensive income -- 0.5 Unearned compensation-restricted stock (0.7) (1.7) -------- -------- 388.9 385.4 Treasury stock, at cost (141.7) (136.2) -------- -------- Total common stockholders' equity 247.2 249.2 -------- -------- Total liabilities and stockholders' equity $2,278.8 $2,140.5 ======== ========
27 16 UGI Corporation 2000 Annual Report CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of dollars)
Year Ended September 30, ----------------------------------- 2000 1999 1998 ------ ------ ------ CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 44.7 $ 55.7 $ 40.3 Reconcile to net cash provided by operating activities: Depreciation and amortization 97.5 89.7 87.8 Minority interest in AmeriGas Partners 6.3 10.7 8.9 Deferred income taxes, net 3.2 7.7 10.1 Other, net 15.8 6.5 4.9 ------ ------ ------ 167.5 170.3 152.0 Net change in: Receivables and accrued utility revenues (63.4) (25.1) 22.0 Inventories and prepaid propane purchases (26.1) (5.0) 39.0 Deferred fuel costs (3.8) (5.1) (5.8) Accounts payable 52.0 17.4 (23.5) Other current assets and liabilities 6.5 (10.6) (5.2) ------ ------ ------ Net cash provided by operating activities 132.7 141.9 178.5 ------ ------ ------ CASH FLOWS FROM INVESTING ACTIVITIES Expenditures for property, plant and equipment (71.0) (70.2) (69.2) Acquisitions of businesses, net of cash acquired (65.3) (77.6) (8.1) Short-term investments (increase) decrease 7.3 66.7 (16.4) Net proceeds from disposals of assets 8.4 4.9 7.9 Investments in joint venture partnerships -- (4.9) (2.0) Other, net (0.9) (5.4) (2.3) ------ ------ ------ Net cash used by investing activities (121.5) (86.5) (90.1) ------ ------ ------ CASH FLOWS FROM FINANCING ACTIVITIES Dividends on Common Stock (41.2) (47.9) (47.6) Distributions on Partnership public Common Units (39.1) (39.0) (39.0) Issuance of long-term debt 209.7 173.7 58.0 Repayment of long-term debt (95.4) (70.9) (22.3) AmeriGas Propane bank loans increase (decrease) 8.0 12.0 (18.0) UGI Utilities bank loans increase 13.0 19.0 1.4 Other bank loans decrease (6.8) -- -- Issuance of Common Stock 3.8 4.7 8.5 Repurchases of Common Stock (9.6) (133.1) (11.3) Redemption of UGI Utilities Series Preferred Stock -- -- (15.5) ------ ------ ------ Net cash provided (used) by financing activities 42.4 (81.5) (85.8) ------ ------ ------ Effect of exchange rate changes on cash (0.2) -- -- ------ ------ ------ Cash and cash equivalents increase (decrease) $ 53.4 $(26.1) $ 2.6 ====== ====== ====== CASH AND CASH EQUIVALENTS End of period $ 93.9 $ 40.5 $ 66.6 Beginning of period 40.5 66.6 64.0 ------ ------ ------ Increase (decrease) $ 53.4 $(26.1) $ 2.6 ====== ====== ======
See accompanying notes to consolidated financial statements. 28 17 UGI Corporation 2000 Annual Report CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Millions of dollars, except per share amounts)
Accumulated Unearned Other Compensation- Common Accumulated Comprehensive Restricted Treasury Stock Deficit Income Stock Stock Total ------ ----------- ------------- ------------- --------- ------ BALANCE SEPTEMBER 30, 1997 $393.7 $ (9.2) $ -- $ -- $ (8.4) $376.1 Net income 40.3 40.3 Cash dividends on Common Stock ($1.45 per share) (47.8) (47.8) Common Stock issued: Employee and director plans 0.5 (0.7) 6.3 6.1 Dividend reinvestment plan 2.8 2.8 Acquisition 0.1 1.1 1.2 Redemption of UGI Utilities Series Preferred Stock (0.3) (0.3) Common Stock repurchased (11.3) (11.3) ------ ------ ----- ------ ------- ------ BALANCE SEPTEMBER 30, 1998 394.3 (17.7) -- -- (9.5) 367.1 Net income 55.7 55.7 Net unrealized gain on available for sale securities 0.5 0.5 ------ ----- ------ Comprehensive income 55.7 0.5 56.2 Cash dividends on Common Stock ($1.47 per share) (45.8) (45.8) Common Stock issued: Employee and director plans 0.4 (0.1) 3.4 3.7 Dividend reinvestment plan 0.1 (0.3) 3.0 2.8 Common Stock repurchased (133.1) (133.1) Issuance of restricted stock awards (2.1) (2.1) Amortization of unearned compensation- restricted stock awards 0.4 0.4 ------ ------ ----- ------ ------- ------ BALANCE SEPTEMBER 30, 1999 394.8 (8.2) 0.5 (1.7) (136.2) 249.2 Net income 44.7 44.7 Reclassification of unrealized gain on available for sale securities (0.5) (0.5) ------ ----- ------ Comprehensive income 44.7 (0.5) 44.2 Cash dividends on Common Stock ($1.525 per share) (41.4) (41.4) Common Stock issued: Employee and director plans (0.1) 1.5 1.4 Dividend reinvestment plan (0.2) 2.6 2.4 Common Stock repurchased (9.6) (9.6) Amortization of unearned compensation- restricted stock awards 1.0 1.0 ------ ------ ----- ------ ------- ------ BALANCE SEPTEMBER 30, 2000 $394.5 $ (4.9) $ -- $ (0.7) $(141.7) $247.2 ====== ====== ===== ====== ======= ======
See accompanying notes to consolidated financial statements. 29 18 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise)
NOTE PAGE ---- ---- 1. Organization and Significant Accounting Policies 30 2. Utility Regulatory Matters 34 3. Debt 35 4. Income Taxes 37 5. Employee Retirement Plans 38 6. Inventories 39 7. Series Preferred Stock 39 8. Common Stock and Incentive Stock Award Plans 40 9. Preference Stock Purchase Rights 41 10. Partnership Distributions 42 11. Commitments and Contingencies 43 12. Financial Instruments 44 13. Acquisitions 45 14. Terminated Merger-Unisource Worldwide, Inc. 45 15. Other Income, Net 45 16. Quarterly Data (Unaudited) 46 17. Segment Information 46
NOTE 1 -- ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION. UGI Corporation ("UGI") is a holding company that operates gas and electric utility, propane distribution, energy marketing and related businesses through subsidiaries. Our utility business is conducted through a wholly owned subsidiary, UGI Utilities, Inc. ("UGI Utilities"). UGI Utilities owns and operates a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and an electric distribution utility and electricity generation business ("Electric Utility") in northeastern Pennsylvania (together we refer to them as "Utilities"). We conduct a national propane distribution business through AmeriGas Partners, L.P. ("AmeriGas Partners") and its operating subsidiary, AmeriGas Propane, L.P. (the "Operating Partnership"), both of which are Delaware limited partnerships. Our wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the "General Partner"), serves as the general partner of AmeriGas Partners and the Operating Partnership. At September 30, 2000, the General Partner and its wholly owned subsidiary Petrolane Incorporated ("Petrolane") held an effective 2% general partner interest and a 56.4% limited partner interest in the Operating Partnership. We refer to AmeriGas Partners and the Operating Partnership together as "the Partnership," and the General Partner and its subsidiaries, including the Partnership, as "AmeriGas Propane." The Operating Partnership is one of the largest retail propane distributors in the United States serving residential, commercial, industrial, motor fuel and agricultural customers from locations in 45 states, including Alaska and Hawaii. At September 30, 2000, our limited partner interest in AmeriGas Partners consisted of 14,283,932 Common Units and 9,891,072 Subordinated Units. The remaining 41.6% effective interest in the Partnership comprises 17,794,361 publicly held Common Units representing limited partner interests. In October 2000, AmeriGas Partners issued 2,300,000 Common Units in a public offering for net cash proceeds of approximately $40 million. After this transaction, the General Partner and Petrolane held an effective 2% general partner interest and 53.5% limited partner interest in the Operating Partnership. AmeriGas Partners and the Operating Partnership have no employees. Employees of the General Partner conduct, direct and manage the activities of the Partnership. The General Partner does not receive management fees or other compensation in connection with managing the Partnership, but is reimbursed for direct and indirect expenses incurred on behalf of the Partnership, including all General Partner employee compensation costs and a portion of UGI employee compensation and administrative costs. Although the Partnership's operating income represents a significant portion of our consolidated operating income, the Partnership's impact on our consolidated net income is considerably less due to (1) the Partnership's significant minority interest; (2) higher relative interest charges; and (3) a higher effective income tax rate associated with the Partnership's pre-tax income. Our wholly owned subsidiary, UGI Enterprises, Inc. ("Enterprises"), conducts an energy marketing business through its wholly owned subsidiary, UGI Energy Services, Inc. ("Energy Services"). Through other subsidiaries, Enterprises (1) owns and operates a propane distribution business, FLAGA GmbH ("FLAGA") in Austria, the Czech Republic and Slovakia; (2) owns and operates a heating, ventilation and air-conditioning service business ("HVAC") and a retail hearth, spa and grill products business in the Middle Atlantic region of the U.S.; and (3) participates in propane joint-venture projects in Romania and China. UGI is exempt from registration as a holding company and is not otherwise subject to regulation under the Public Utility Holding Company Act of 1935 except for acquisitions under Section 9(a)(2). UGI is not subject to regulation by the Pennsylvania Public Utility Commission ("PUC"). 30 19 CONSOLIDATION PRINCIPLES. Our consolidated financial statements include the accounts of UGI and its majority-owned subsidiaries. We eliminate all significant intercompany accounts and transactions when we consolidate. We report the public unitholders' interest in AmeriGas Partners as minority interest in the consolidated financial statements. The Company's investments in international propane joint-venture projects are accounted for by the equity method. Such investments did not materially impact the Company's results of operations for the periods presented. RECLASSIFICATIONS. We have reclassified certain prior-period balances to conform with the current period presentation. USE OF ESTIMATES. We make estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States. These estimates and assumptions affect the reported amounts of assets and liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. REGULATED UTILITY OPERATIONS. Gas Utility and Electric Utility are subject to regulation by the PUC. We account for all of our regulated Gas Utility and Electric Utility operations in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71"). SFAS 71 requires the Company to record the financial statement effects of the rate regulation to which such operations are currently subject. If a separable portion of Gas Utility or Electric Utility no longer meets the provisions of SFAS 71, we are required to eliminate the financial statement effects of regulation for that portion of our operations. In June 1998, the PUC approved Electric Utility's restructuring plan which we submitted pursuant to Pennsylvania's Electricity Customer Choice Act ("Electricity Customer Choice Act"). In accordance with the Financial Accounting Standards Board's ("FASB's") Emerging Issues Task Force ("EITF") Statement No. 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements 71 and 101" ("EITF 97-4"), we discontinued the application of SFAS 71 as it related to the electric generation portion of Electric Utility's business in June 1998. This discontinuance of SFAS 71 did not have a material effect on our financial position or results of operations. On June 29, 2000, the PUC entered its order ("Gas Restructuring Order") in Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's Natural Gas Choice and Competition Act ("Gas Competition Act"). Based upon the provisions of the Gas Restructuring Order and the Gas Competition Act, we believe Gas Utility's regulatory assets continue to satisfy the criteria of SFAS 71. For further information on the impact of the Electricity Customer Choice Act and the Gas Competition Act, see Note 2. DERIVATIVE INSTRUMENTS. We use derivative instruments, including futures contracts, price swap agreements and option contracts, to hedge exposure to market risk associated with (1) fluctuations in the price of forecasted purchases of natural gas Energy Services sells under firm commitments and (2) fluctuations in propane prices associated with a portion of our anticipated propane purchases. On occasion we enter into interest rate protection agreements to reduce interest rate risk associated with anticipated issuances of debt. In addition, we occasionally utilize a managed program of derivative instruments including natural gas and oil futures contracts to preserve gross margin associated with certain of the Company's natural gas customers, which margin otherwise could be affected by major energy commodity price movements. We defer gains or losses on futures contracts associated with forecasted purchases of natural gas and record them in cost of sales when such purchases affect earnings. We recognize gains or losses on derivative instruments associated with forecasted purchases of propane or issuances of debt when such transactions affect earnings. When it is probable that the original forecasted transaction will not occur, we immediately recognize in earnings any gain or loss on the related derivative instrument. If such derivative instrument is terminated early for other economic reasons, we defer any gain or loss as of the termination date until such time as the forecasted transaction affects earnings. CONSOLIDATED STATEMENTS OF CASH FLOWS. We define cash equivalents as all highly liquid investments with maturities of three months or less when purchased. We record cash equivalents at cost plus accrued interest, which approximates market value. We paid interest totaling $96.9 million in 2000, $84.6 million in 1999, and $83.5 million in 1998. We paid income taxes totaling $26.6 million in 2000, $36.2 million in 1999, and $29.8 million in 1998. REVENUE RECOGNITION. We recognize revenues from the sale of propane and related equipment and supplies principally when shipped or delivered to customers. We record Utilities' revenues for service provided to the end of each month. We reflect Utilities' rate increases or decreases in revenues from effective dates permitted by the PUC. Energy Services records revenues when product is delivered to customers. See "Accounting Principles Not Yet Adopted" below. INVENTORIES AND PREPAID PROPANE PURCHASES. Our inventories are stated at the lower of cost or market. We determine cost principally on an average or first-in, first-out ("FIFO") method except for appliances for which we use the specific identification method. From time to time the Partnership enters into contracts with certain suppliers requiring it to prepay all or a portion of the purchase price of a fixed volume of propane for future delivery. These prepayments are included in prepaid expenses and other current assets in the Consolidated Balance Sheets. 31 20 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) EARNINGS PER COMMON SHARE. Basic earnings per share are based on the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and awards. In the following table, we present the shares used in computing basic and diluted earnings per share for 2000, 1999 and 1998:
2000 1999 1998 ------ ------ ------ Denominator (millions of shares): Average common shares outstanding for basic computation 27.219 31.954 32.971 Incremental shares issuable for stock options and awards .036 .062 .152 ------ ------ ------ Average common shares outstanding for diluted computation 27.255 32.016 33.123 ------ ------ ------
INCOME TAXES. AmeriGas Partners and the Operating Partnership are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on our share of (1) the Partnership's current taxable income or loss and (2) the difference between the book and tax basis of the Partnership's assets and liabilities. The Operating Partnership does, however, have subsidiaries which operate in corporate form and are directly subject to federal income taxes. UGI Utilities' regulated operations record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. UGI Utilities also records a deferred tax liability for tax benefits that are flowed through to ratepayers when temporary differences originate and establishes a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse. We are amortizing deferred investment tax credits related to UGI Utilities' plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION. We record property, plant and equipment at cost. The amounts we assign to property, plant and equipment of businesses we acquire are based upon estimated fair value at date of acquisition. When we retire Utilities' plant, we charge its original cost and the net cost of its removal to accumulated depreciation for financial accounting purposes. When we retire or dispose of other plant and equipment, we remove from the accounts the cost and accumulated depreciation and include in income any gains or losses. We record depreciation expense for Utilities' plant on a straight-line method over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.6% in 2000, and 2.7% in 1999 and 1998. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 3.5% in 2000, and 3.2% in 1999 and 1998. We compute depreciation expense on plant and equipment associated with our propane operations using the straight-line method over estimated service lives generally ranging from 15 to 40 years for buildings and improvements; 7 to 30 years for storage and customer tanks and cylinders; and 5 to 10 years for vehicles, equipment and office furniture and fixtures. Depreciation expense was $69.3 million in 2000, $63.6 million in 1999, and $61.4 million in 1998. INTANGIBLE ASSETS. Intangible assets comprise the following at September 30:
2000 1999 ------ ------ Goodwill (less accumulated amortization of $126.6 million and $109.8 million, respectively) $566.8 $538.4 Excess reorganization value (less accumulated amortization of $60.2 million and $52.3 million, respectively) 101.3 109.2 Other (less accumulated amortization of $3.4 million and $3.8 million, respectively) 7.4 5.5 ------ ------ Total intangible assets $675.5 $653.1 ====== ======
Substantially all of our goodwill is a result of propane purchase business combinations. This goodwill is amortized on a straight-line basis over 40 years. We amortize excess reorganization value (resulting from Petrolane's July 15, 1993 reorganization under Chapter 11 of the U.S. Bankruptcy Code) on a straight-line basis over 20 years. We amortize other intangible assets over the estimated periods of benefit which do not exceed ten years. Amortization expense of intangible assets was $26.5 million in 2000, $24.3 million in 1999, and $24.9 million in 1998. We evaluate the impairment of long-lived assets, including intangibles, whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. STOCK-BASED COMPENSATION. As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), we apply the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"), in recording compensation expense for grants of stock, stock options, and other equity instruments to employees. 32 21 UGI Corporation 2000 Annual Report OTHER ASSETS. Included in other assets are net deferred debt issuance costs of $10.8 million at September 30, 2000 and $10.9 million at September 30, 1999. We are amortizing these costs over the term of the related debt. COMPUTER SOFTWARE COSTS. Prior to October 1, 1999, we included in property, plant and equipment external and incremental internal costs associated with computer software we developed or obtained for use in our businesses. Effective October 1, 1999, we adopted Statement of Position No. 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use" ("SOP 98-1"), which requires companies to capitalize the cost of computer software, including nonincremental internal costs, once certain criteria have been met. We amortize computer software costs on a straight-line basis over periods of three to seven years once the installed software is ready for its intended use. The adoption of SOP 98-1 did not have a material effect on our financial position or results of operations. DEFERRED FUEL COSTS. Gas Utility's tariffs contain clauses which permit recovery of certain purchased gas costs ("PGCs") in excess of the level of such costs included in base rates. The clauses provide for a periodic adjustment for the difference between the total amount collected from customers under each clause and the recoverable costs incurred. We defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers. ENVIRONMENTAL LIABILITIES. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. We do not discount to present value the costs of future expenditures for environmental liabilities. We intend to pursue recovery of any incurred costs through all appropriate means, including regulatory relief. Gas Utility is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. Gas Utility is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred removal costs. FOREIGN CURRENCY TRANSLATION. Financial statements of international subsidiaries are translated into U.S. dollars using the exchange rate at each balance sheet date for assets and liabilities and a weighted-average exchange rate for each period for revenues and expenses. Where the local currency is the functional currency, translation adjustments are recorded in accumulated other comprehensive income. Where the local currency is not the functional currency, translation adjustments are recorded in net income. Currency adjustments did not materially impact the Company's results of operations or accumulated comprehensive income in 2000, 1999 or 1998. COMPREHENSIVE INCOME. Our comprehensive income principally includes net earnings or loss and unrealized gains or losses on available for sale securities. In 1998, our comprehensive income was the same as our net income. The net changes in accumulated comprehensive income in 1999 and 2000, which resulted principally from changes in unrealized gains on securities, is reflected net of income taxes of $0.3 million. ACCOUNTING PRINCIPLES NOT YET ADOPTED. In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 was amended in June 2000 by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" ("SFAS 138") which addressed a limited number of issues causing implementation difficulties. SFAS 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that an entity recognize all derivative instruments as either assets or liabilities and measure them at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. To the extent derivative instruments qualify and are designated as hedges of the variability in cash flows associated with forecasted transactions, the effective portion of the gain or loss on such derivative instruments will generally be reported in other comprehensive income and the ineffective portion, if any, will be reported in net income. Such amounts recorded in accumulated other comprehensive income will be reclassified into net income when the forecasted transaction affects earnings. To the extent derivative instruments qualify and are designated as hedges of changes in the fair value of an existing asset, liability or firm commitment, the gain or loss on the hedging instrument will be recognized currently in earnings along with changes in the fair value of the hedged asset, liability or firm commitment attributable to the hedged risk. The Company was required to adopt the provisions of SFAS 133 effective October 1, 2000. Virtually all of the Company's derivative instruments outstanding as of October 1, 2000 qualify and have been designated as hedging the variability in cash flows associated with forecasted transactions. The adoption of SFAS 133 will result in an after-tax cumulative effect charge to net income of $0.3 million and an after-tax cumulative effect increase to accumulated other comprehensive income of $7.1 million. Because the Company's derivative instruments historically have been highly effective in hedging the exposure to changes in cash flows associated with forecasted purchases or sales of natural gas and propane, changes in the fair value of propane inventories, and changes in the risk-free rate of interest on anticipated issuances of long-term debt, we do not expect the adoption of SFAS 133 to have a material impact on our future results of operations. Although the Company expects the derivative instruments it currently uses to hedge to continue to be highly effective, if they are deemed not highly effective in the future, or if the Company uses 33 22 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) derivative instruments that do not meet the stringent requirements for hedge accounting under SFAS 133, our future earnings could reflect greater volatility. Additionally, if a cash flow hedge is discontinued because the original forecasted transaction is no longer expected to occur, any gain or loss in accumulated comprehensive income associated with the hedged transaction will be immediately recognized in net income. In order to comply with the provisions of the Securities and Exchange Commission Staff Accounting Bulletin No. 101 entitled "Revenue Recognition" ("SAB 101"), which is effective for the Company on October 1, 2000, the Company will record a cumulative effect charge to net income of approximately $2.3 million related to the Partnership's method of recognizing revenue associated with nonrefundable tank fees largely for residential customers. Consistent with a number of its competitors in the propane industry, the Partnership receives nonrefundable fees for installed Partnership-owned tanks. Historically, such fees, which are generally received annually, were recorded as revenue when billed. In accordance with SAB 101, effective October 1, 2000, the Partnership will record such nonrefundable fees on a straight-line basis over one year. The adoption of SAB 101 is not expected to have a material impact on the Company's future financial condition or results of operations. Also, during fiscal 2001, the Partnership plans to change its method of accounting for tank installation costs which are not billed to customers. Currently, all direct costs to install Partnership-owned tanks at a customer location are expensed as incurred. The Partnership believes that these costs should now be capitalized and amortized over the period benefited. On date of adoption, this change in accounting method will result in a cumulative effect increase to net income. The Company is in the process of evaluating the impact of such change on its financial condition and results of operations. NOTE 2 -UTILITY REGULATORY MATTERS ELECTRIC UTILITY RESTRUCTURING ORDER. On June 19, 1998, the PUC entered its Opinion and Order ("Electricity Restructuring Order") in Electric Utility's restructuring proceeding pursuant to the Electricity Customer Choice Act. Under the terms of the Electricity Restructuring Order, commencing January 1, 1999, Electric Utility is authorized to recover $32.5 million in stranded costs (on a full revenue requirements basis which includes all income and gross receipts taxes) over a four-year period through a Competitive Transition Charge ("CTC") (together with carrying charges on unrecovered balances of 7.94%) and to charge unbundled rates for generation, transmission and distribution services. Stranded costs are electric generation-related costs that traditionally would be recoverable in a regulated environment but may not be recoverable in a competitive electric generation market. Electric Utility's recoverable stranded costs include $8.7 million for the buy-out of a 1993 power purchase agreement with an independent power producer. Under the terms of the Electricity Restructuring Order and in accordance with the Electricity Customer Choice Act, Electric Utility's rates for transmission and distribution services are capped through July 1, 2001. In addition, Electric Utility generally may not increase the generation component of prices as long as stranded costs are being recovered through the CTC. This generation rate cap is expected to extend through December 31, 2002. Since January 1, 1999, all of Electric Utility's customers have been permitted to select an alternative generation supplier. Customers choosing an alternative supplier receive a "shopping credit." As permitted by the Electricity Restructuring Order, on October 1, 1999, Electric Utility transferred its electric generation assets to its wholly owned nonregulated subsidiary, UGI Development Company ("UGIDC"). In June 1998, Electric Utility discontinued the application of SFAS 71 as it relates to the electric generation portion of its business, which assets comprise less than 15% of Electric Utility's total assets. The discontinuance of SFAS 71 did not have a material effect on our financial position or results of operations. NATURAL GAS COMPETITION ACT. On June 22, 1999, the Gas Competition Act was signed into law. The purpose of the Gas Competition Act is to provide all natural gas consumers in Pennsylvania with the ability to purchase their gas supplies from the supplier of their choice. Under the Gas Competition Act, local gas distribution companies ("LDCs") may continue to sell gas to customers, and such sales of gas, as well as distribution services provided by LDCs, continue to be subject to price regulation by the PUC. As of January 1, 2000, the Gas Competition Act, in conjunction with a companion bill, eliminated the gross receipts tax on sales of gas. Generally, LDCs will serve as the supplier of last resort for all residential and small commercial and industrial customers unless the PUC approves another supplier of last resort. LDCs are generally precluded from increasing rates for the recovery of costs, other than gas costs, until January 1, 2001. The Gas Competition Act requires energy marketers seeking to serve customers of LDCs to accept assignment of a portion of the LDC's pipeline capacity and storage contracts at contract rates, thus avoiding the creation of stranded costs. After July 1, 2002, a natural gas supplier may petition the PUC to avoid such contract release or assignment. The PUC, however, may only grant the petition if certain findings are made and the LDC fully recovers the cost of contracts. On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas Utility's restructuring plan substantially as filed. Among other things, the restructuring plan (1) provides for the recovery of costs associated with existing pipeline capacity and supply contracts; (2) increases Gas Utility's base rates for firm customers; and (3) changes the calculation of PGC rates. The effect of (2) and 34 23 UGI Corporation 2000 Annual Report (3) above is to reduce the financial impact of volatility in revenues from customers who have the ability to switch to an alternate fuel under interruptible rates and increase our sensitivity to changes in weather. Because the Gas Competition Act requires alternate suppliers to accept assignment of a portion of the LDC's pipeline capacity and storage contracts, we do not believe the Gas Competition Act and the Gas Restructuring Order will have a material adverse impact on our financial condition or results of operations. REGULATORY ASSETS AND LIABILITIES. The following regulatory assets and liabilities are included in our accompanying balance sheets at September 30:
2000 1999 --------------------------------------------------------------- Regulatory assets: Income taxes recoverable $47.7 $46.9 Power agreement buy-out 3.5 6.8 Other postretirement benefits 2.9 3.1 Deferred fuel costs 7.2 3.4 Other 1.0 0.9 --------------------------------------------------------------- Total regulatory assets $62.3 $61.1 --------------------------------------------------------------- Regulatory liabilities: Other postretirement benefits $ 4.0 $2.8 Refundable state taxes -- 1.0 --------------------------------------------------------------- Total regulatory liabilities $ 4.0 $3.8 ---------------------------------------------------------------
NOTE 3 - DEBT Long-term debt comprises the following at September 30:
2000 1999 ----------------------------------------------------------------------------------- AmeriGas Propane: AmeriGas Partners Senior Notes, 10.125%, due April 2007 $ 100.0 $ 100.0 Operating Partnership First Mortgage Notes: Series A, 9.34%-11.71%, due April 2000 through April 2009 (including unamortized premium of $10.6 and $12.1, respectively, calculated at an 8.91% effective rate) 208.6 220.1 Series B, 10.07%, due April 2001 through April 2005 (including unamortized premium of $5.9 and $8.0, respectively, calculated at an 8.74% effective rate) 205.9 208.0 Series C, 8.83%, due April 2003 through April 2010 110.0 110.0 Series D, 7.11%, due March 2009 (including unamortized premium of $2.7 and $2.9, respectively, calculated at a 6.52% effective rate) 72.7 72.9 Series E, 8.50%, due July 2010 (including unamortized premium of $0.2 calculated at an 8.47% effective rate) 80.2 -- Operating Partnership Acquisition Facility 70.0 23.0 Other 9.8 10.7 ----------------------------------------------------------------------------------- Total AmeriGas Propane 857.2 744.7 ----------------------------------------------------------------------------------- UGI Utilities: Medium-Term Notes: 7.25% Notes, due November 2017 20.0 20.0 7.17% Notes, due June 2007 20.0 20.0 6.17% Notes, due March 2001 15.0 15.0 7.37% Notes, due October 2015 22.0 22.0 6.73% Notes, due October 2002 26.0 26.0 6.62% Notes, due May 2005 20.0 20.0 6.50% Senior Notes, due August 2003 (less unamortized discount of $0.1) 49.9 49.9 9.71% Notes, due September 2000 -- 7.1 ----------------------------------------------------------------------------------- Total UGI Utilities 172.9 180.0 ----------------------------------------------------------------------------------- Other: FLAGA EURO note, due September 2001 through September 2006 65.5 77.0 FLAGA Austrian shilling debt -- 6.8 FLAGA EURO special purpose facility 11.9 -- Other 8.1 7.8 ----------------------------------------------------------------------------------- Total long-term debt 1,115.6 1,016.3 Less current maturities (85.9) (26.7) ----------------------------------------------------------------------------------- Total long-term debt due after one year $1,029.7 $ 989.6 -----------------------------------------------------------------------------------
35 24 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Long-term debt due in fiscal years 2001 to 2005 follows:
2001 2002 2003 2004 2005 --------------------------------------------------------------- AmeriGas Propane $64.5 $66.5 $60.0 $56.7 $56.2 UGI Utilities 15.0 -- 76.0 -- 20.0 Other 6.4 10.8 16.6 9.9 15.7 --------------------------------------------------------------- Total $85.9 $77.3 $152.6 $66.6 $91.9 ---------------------------------------------------------------
AMERIGAS PROPANE AMERIGAS PARTNERS SENIOR NOTES. The 10.125% Senior Notes of AmeriGas Partners are redeemable prior to their maturity date. A redemption premium applies until April 15, 2004. In addition, AmeriGas Partners may, under certain circumstances following the disposition of assets or a change of control, be required to offer to prepay the Senior Notes. OPERATING PARTNERSHIP FIRST MORTGAGE NOTES. The Operating Partnership's First Mortgage Notes are collateralized by substantially all of its assets. The General Partner and its wholly owned subsidiary Petrolane are co-obligors of the Series A, B, and C First Mortgage Notes, and the General Partner is co-obligor of the Series D and E First Mortgage Notes. The Operating Partnership may prepay the First Mortgage Notes, in whole or in part. These prepayments include a make whole premium. Following the disposition of assets or a change of control, the Operating Partnership may be required to offer to prepay the First Mortgage Notes, in whole or in part. OPERATING PARTNERSHIP BANK CREDIT AGREEMENT. The Operating Partnership's Bank Credit Agreement consists of a Revolving Credit Facility and an Acquisition Facility. The Operating Partnership's obligations under the Bank Credit Agreement are collateralized by substantially all of its assets. The General Partner and Petrolane are co-obligors of amounts outstanding under the Bank Credit Agreement. Under the Revolving Credit Facility, the Operating Partnership may borrow up to $100 million (including a $35 million sublimit for letters of credit) subject to restrictions in the 10.125% Senior Notes of AmeriGas Partners (see "Restrictive Covenants" below). The Revolving Credit Facility expires September 15, 2002, but may be extended for additional one-year periods with the consent of the participating banks representing at least 80% of the commitments thereunder. The Revolving Credit Facility permits the Operating Partnership to borrow at various prevailing interest rates, including the Base Rate, defined as the higher of the Federal Funds Rate plus 0.50% or the agent bank's reference rate (9.50% at September 30, 2000), or at two-week, one-, two-, three-, or six-month offshore interbank offering rates ("IBOR"), plus a margin. The margin on IBOR borrowings (which ranges from 0.50% to 1.75%) and the Revolving Credit Facility commitment fee rate are dependent upon the Operating Partnership's ratio of funded debt to earnings before interest expense, income taxes, depreciation and amortization ("EBITDA"), each as defined in the Bank Credit Agreement. The Operating Partnership had borrowings under the Revolving Credit Facility totaling $30 million at September 30, 2000 and $22 million at September 30, 1999, which we classify as bank loans. The weighted-average interest rates on the bank loans outstanding were 8.11% as of September 30, 2000 and 6.26% as of September 30, 1999. Issued outstanding letters of credit under the Revolving Credit Facility totaled $1.5 million at September 30, 2000 and $5.9 million at September 30, 1999. The Acquisition Facility provides the Operating Partnership with the ability to borrow up to $75 million to finance the purchase of propane businesses or propane business assets. The Acquisition Facility operates as a revolving facility through September 15, 2002, at which time amounts then outstanding will be immediately due and payable. The Acquisition Facility permits the Operating Partnership to borrow at the Base Rate or at two-week, one-, two-, three-, or six-month IBOR, plus a margin. The margin on IBOR borrowings and the Acquisition Facility commitment fee rate are dependent upon the Operating Partnership's ratio of funded debt to EBITDA, as defined. The weighted-average interest rates on Acquisition Facility loans outstanding were 8.12% as of September 30, 2000 and 6.02% as of September 30, 1999. GENERAL PARTNER FACILITY. The Operating Partnership also has a revolving credit agreement with the General Partner under which it may borrow up to $20 million to fund working capital, capital expenditures, and interest and Partnership distribution payments. This agreement is coterminous with, and generally comparable to, the Operating Partnership's Revolving Credit Facility except that borrowings under the General Partner Facility are unsecured and subordinated to all senior debt of the Partnership. Interest rates on borrowings are based upon one-month IBOR. Commitment fees are determined in the same manner as fees under the Revolving Credit Facility. UGI has agreed to contribute up to $20 million to the General Partner to fund such borrowings. RESTRICTIVE COVENANTS. The 10.125% Senior Notes of AmeriGas Partners restrict the ability of the Partnership to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets. Under the Senior Notes Indenture, AmeriGas Partners is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. These conditions include: 1. no event of default exists or would exist upon making such distributions and 2. the Partnership's consolidated fixed charge coverage ratio, as defined, is greater than 1.75-to-1. 36 25 UGI Corporation 2000 Annual Report If the ratio in item 2 above is less than or equal to 1.75-to-1, the Partnership may make cash distributions in a total amount not to exceed $24 million less the total amount of distributions made during the immediately preceding 16 fiscal quarters. At September 30, 2000, such ratio was 2.14-to-1. The Bank Credit Agreement and the First Mortgage Notes restrict the incurrence of additional indebtedness and also restrict certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, sales of assets and other transactions. They also require the ratio of total indebtedness, as defined, to EBITDA, as defined (calculated on a rolling four-quarter basis or eight-quarter basis divided by two), to be less than or equal to 5.25-to-1. In addition, the Bank Credit Agreement requires that the Operating Partnership maintain a ratio of EBITDA to interest expense, as defined, of at least 2.25-to-1 on a rolling four-quarter basis. Generally, as long as no default exists or would result, the Operating Partnership is permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter. At September 30, 2000, the Partnership was in compliance with its financial covenants. UGI UTILITIES REVOLVING CREDIT AGREEMENTS. At September 30, 2000, UGI Utilities had revolving credit agreements with four banks providing for borrowings of up to $122 million through June 2003. UGI Utilities may borrow at various prevailing interest rates, including LIBOR. UGI Utilities pays quarterly commitment fees on these credit lines. UGI Utilities had borrowings under these agreements totaling $100.4 million at September 30, 2000 and $87.4 million at September 30, 1999, which we classify as bank loans. The weighted-average interest rates on UGI Utilities bank loans were 7.12% at September 30, 2000 and 5.90% at September 30, 1999. RESTRICTIVE COVENANTS. UGI Utilities' credit agreements have restrictions on such items as total debt, working capital, debt service, and payments for investments. They also require consolidated tangible net worth of at least $125 million. At September 30, 2000, UGI Utilities was in compliance with its financial covenants. OTHER FLAGA's EURO note bears interest at a rate of 1.25% over one- to twelve-month EURIBOR rates (as chosen by the Company from time to time). The effective interest rates on the EURO note at September 30, 2000 and September 30, 1999 were 5.71% and 5.00%, respectively. On or after September 10, 2003, the Company may prepay the EURO note, in whole or in part. Prior to March 11, 2005, such prepayments shall be at a premium. FLAGA has EURO loan commitments from a foreign bank in the form of (1) a 15 million EURO special purpose facility and (2) a 9 million EURO working capital facility. Borrowings under the FLAGA special purpose facility can be used to repay certain debt obligations of FLAGA existing at the acquisition date and for general business purposes. The working capital facility expires September 28, 2001, but may be extended for an additional three-year period with the bank's consent. Loans under the special purpose facility and the working capital facility bear interest at market rates. The weighted-average interest rates on FLAGA's working capital facility and special purpose facility at September 30, 2000 were 5.78% and 5.25%, respectively. Borrowings under the EURO working capital facility at September 30, 2000, and FLAGA's now terminated Swiss franc denominated bank loan facility at September 30, 1999, totaled $4.3 million and $11.6 million, respectively. The FLAGA EURO note, special purpose facility and the working capital facility are subject to guarantees of UGI. In addition, under certain conditions regarding changes in the credit rating of UGI Utilities' long-term debt, the lending bank may require UGI to grant additional security or may accelerate repayment of the debt prior to its scheduled maturity. NOTE 4 -- INCOME TAXES Income before income taxes comprises the following:
2000 1999 1998 ---------------------------------------------------------------- Domestic $93.4 $100.5 $76.9 Foreign (7.0) -- -- ---------------------------------------------------------------- Total income before income taxes $86.4 $100.5 $76.9 ----------------------------------------------------------------
The provisions for income taxes consist of the following:
2000 1999 1998 ---------------------------------------------------------------- Current: Federal $28.6 $29.2 $19.6 State 8.3 6.3 4.7 ---------------------------------------------------------------- Total current 36.9 35.5 24.3 Deferred: Federal 5.7 6.8 10.0 State (0.2) 1.3 0.5 Foreign (1.9) -- -- Investment tax credit amortization (0.4) (0.4) (0.4) ---------------------------------------------------------------- Total deferred 3.2 7.7 10.1 ---------------------------------------------------------------- Total income tax expense $40.1 $43.2 $34.4 ----------------------------------------------------------------
37 26 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) A reconciliation from the statutory federal tax rate to our effective tax rate is as follows:
2000 1999 1998 ----------------------------------------------------------------------------------- Statutory federal tax rate 35.0% 35.0% 35.0% Difference in tax rate due to: State income taxes, net of federal benefit 7.5 5.2 6.1 Nondeductible amortization of goodwill 5.8 4.6 6.2 Other, net (1.9) (1.8) (2.6) ----------------------------------------------------------------------------------- Effective tax rate 46.4% 43.0% 44.7% -----------------------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September 30:
2000 1999 ------------------------------------------------------------------------------------------ Excess book basis over tax basis of property, plant and equipment $ 172.5 $ 177.0 Regulatory assets 25.6 25.3 Other 13.7 10.1 ------------------------------------------------------------------------------------------ Gross deferred tax liabilities 211.8 212.4 ------------------------------------------------------------------------------------------ Self-insured property and casualty liability (8.2) (8.6) Employee-related benefits (12.0) (12.3) Premium on long-term debt (4.4) (5.2) Deferred investment tax credits (3.8) (4.0) Power purchase agreement liability (2.2) (3.2) Operating loss carryforwards (8.3) (4.2) Allowance for doubtful accounts (2.6) (2.5) Other (11.1) (13.8) ------------------------------------------------------------------------------------------ Gross deferred tax assets (52.6) (53.8) ------------------------------------------------------------------------------------------ Deferred tax assets valuation allowance 1.9 2.0 ------------------------------------------------------------------------------------------ Net deferred tax liabilities $ 161.1 $ 160.6 ------------------------------------------------------------------------------------------
UGI Utilities had recorded deferred tax liabilities of approximately $31.7 million as of September 30, 2000 and $31.4 million as of September 30, 1999 pertaining to utility temporary differences, principally a result of accelerated tax depreciation, the tax benefits of which previously were or will be flowed through to ratepayers. These deferred tax liabilities have been reduced by deferred tax assets of $3.8 million at September 30, 2000 and $4.0 million at September 30, 1999, pertaining to utility deferred investment tax credits. UGI Utilities had recorded a regulatory income tax asset related to these net deferred taxes of $47.7 million as of September 30, 2000 and $46.9 million as of September 30, 1999. This regulatory income tax asset represents future revenues expected to be recovered through the ratemaking process. We will recognize this regulatory income tax asset in deferred tax expense as the corresponding temporary differences reverse and additional income taxes are incurred. At September 30, 2000, the amount of federal operating loss carryforwards which were generated by a domestic subsidiary prior to its acquisition totaled $5.2 million. These operating loss carryforwards expire through the year 2010. The use of pre-acquisition operating loss carryforwards is subject to Internal Revenue Code limitations. We do not believe these limitations will affect our ability to utilize these carryforwards prior to their expiration. Foreign operating loss carryforwards of FLAGA totaled approximately $19.0 million at September 30, 2000. Approximately $3.0 million of these operating loss carryforwards expire through 2005. The remaining approximately $16.0 million have no expiration date. The tax benefit of these foreign operating loss carryforwards of $6.4 million has been reduced by a valuation allowance of $1.7 million due to the uncertainty of realizing certain of these operating loss carryforwards. NOTE 5 -- EMPLOYEE RETIREMENT PLANS DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS We sponsor a defined benefit pension plan ("UGI Utilities Pension Plan") for employees of UGI, UGI Utilities, and certain of UGI's other wholly owned subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and a limited number of active employees meeting certain age and service requirements, and postretirement life insurance benefits to nearly all active and retired employees. The following provides a reconciliation of benefit obligations, plan assets, and funded status of the plans as of September 30:
Other Pension Postretirement Benefits Benefits --------------------- --------------------- 2000 1999 2000 1999 ---------------------------------------------------------------------------------------------------- CHANGE IN BENEFIT OBLIGATIONS: Benefit obligations - beginning of year $ 149.5 $ 164.8 $ 16.8 $ 16.9 Service cost 3.2 3.8 0.1 0.1 Interest cost 11.8 11.2 1.4 1.2 Actuarial (gain) loss (4.4) (21.4) 3.0 (0.2) Benefits paid (9.2) (8.9) (1.6) (1.2) ---------------------------------------------------------------------------------------------------- Benefit obligations - end of year $ 150.9 $ 149.5 $ 19.7 $ 16.8 ---------------------------------------------------------------------------------------------------- CHANGE IN PLAN ASSETS: Fair value of plan assets - beginning of year $ 202.1 $ 183.3 $ 4.9 $ 4.9 Actual return on plan assets 30.6 27.7 0.3 0.2 Employer contributions -- -- 2.2 1.0 Benefits paid (9.2) (8.9) (1.0) (1.2) ---------------------------------------------------------------------------------------------------- Fair value of plan assets - end of year $ 223.5 $ 202.1 $ 6.4 $ 4.9 ---------------------------------------------------------------------------------------------------- Funded status of the plans $ 72.6 $ 52.6 $ (13.3) $ (11.9) Unrecognized net actuarial gain (54.8) (36.8) (3.0) (5.8) Unrecognized prior service cost 4.0 4.7 -- -- Unrecognized net transition (asset) obligation (6.3) (7.9) 10.5 11.4 ---------------------------------------------------------------------------------------------------- Prepaid (accrued) benefit cost - end of year $ 15.5 $ 12.6 $ (5.8) $ (6.3) ---------------------------------------------------------------------------------------------------- ASSUMPTIONS AS OF SEPTEMBER 30: Discount rate 8.2% 7.8% 8.2% 7.8% Expected return on plan assets 9.5 9.5 6.0 6.0 Rate of increase in salary levels 4.5 4.5 4.5 4.5 ----------------------------------------------------------------------------------------------------
38 27 UGI Corporation 2000 Annual Report Net periodic pension income and other postretirement benefit costs include the following components:
Pension Other Benefits Postretirement Benefits --------------------------------- --------------------------------- 2000 1999 1998 2000 1999 1998 ------------------------------------------------------------------------------------------------------ Service cost $ 3.2 $ 3.8 $ 3.4 $ 0.1 $ 0.1 $ 0.1 Interest cost 11.8 11.2 10.9 1.4 1.2 1.2 Expected return on assets (17.0) (16.3) (15.2) (0.3) (0.2) (0.2) Amortization of: Transition (asset) obligation (1.6) (1.6) (1.6) 0.9 0.9 0.9 Prior service cost 0.6 0.6 0.6 -- -- -- Actuarial (gain) loss -- -- -- (0.2) (0.2) (0.3) ------------------------------------------------------------------------------------------------------ Net postretirement cost (income) (3.0) (2.3) (1.9) 1.9 1.8 1.7 Change in regulatory assets & liabilities -- -- -- 1.4 1.7 1.9 ------------------------------------------------------------------------------------------------------ Net expense (income) $ (3.0) $ (2.3) $ (1.9) $ 3.3 $ 3.5 $ 3.6 ------------------------------------------------------------------------------------------------------
Pension plan assets are held in trust and consist principally of equity and fixed income mutual funds and investment grade corporate and U.S. government obligations. UGI Common Stock comprises less than 2% of trust assets at September 30, 2000. Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary Employee Benefit Trust ("VEBA") to pay retiree health care and life insurance benefits and to fund the UGI Utilities' postretirement benefit liability. UGI Utilities is required to fund its postretirement benefit obligations by depositing into the VEBA the annual amount of postretirement benefits costs determined under SFAS 106, "Employers Accounting for Postretirement Benefits Other Than Pensions." The difference between such amounts and amounts included in UGI Utilities' rates is deferred for future recovery from, or refund to, ratepayers. VEBA investments consist principally of money market funds. The assumed health care cost trend rates are 10% for fiscal 2001, decreasing to 5.5% in fiscal 2005. A one percentage point change in the assumed health care cost trend rate would change the 2000 postretirement benefit cost and obligation as follows:
1% 1% Increase Decrease ---------------------------------------------------------------------- Effect on total service and interest costs $0.1 $(0.1) Effect on postretirement benefit obligation $1.1 $(1.1) ----------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key employees. At September 30, 2000 and 1999, the projected benefit obligations of these plans were not material. We recorded expense for these plans of $0.9 million in 2000, $1.6 million in 1999, and $2.4 million in 1998. DEFINED CONTRIBUTION PLANS We sponsor a 401(k) savings plan for eligible employees of UGI, UGI Utilities, and certain of UGI's other wholly owned subsidiaries ("UGI Utilities Savings Plan"). Generally, participants in the UGI Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. We may, at our discretion, match a portion of participants' contributions. We also sponsor a 401(k) savings plan for eligible employees of the General Partner ("AmeriGas Propane Savings Plan"). Participants in the AmeriGas Propane Savings Plan may contribute a portion of their compensation on a before-tax basis. We match employee contributions to the AmeriGas Propane Savings Plan on a dollar-for-dollar basis up to 5% of eligible compensation. The cost of benefits under the savings plans totaled $5.9 million in 2000, $4.8 million in 1999, and $5.1 million in 1998. NOTE 6 -- INVENTORIES Inventories comprise the following at September 30:
2000 1999 ---------------------------------------------------------------- Propane gas $ 47.3 $38.1 Utility fuel and gases 33.6 24.5 Materials, supplies and other 36.5 24.5 ---------------------------------------------------------------- Total inventories $117.4 $87.1 ----------------------------------------------------------------
NOTE 7 -- SERIES PREFERRED STOCK The UGI Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, has 5,000,000 shares authorized for issuance. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2000 or 1999. UGI Utilities Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, has 2,000,000 shares authorized for issuance. The holders of shares of UGI Utilities Series Preferred Stock have the right to elect a majority of UGI Utilities' Board of Directors (without cumulative voting) if dividend payments on any series are in arrears in an amount equal to four quarterly dividends. This election right continues until the arrearage has been cured. We have paid cash dividends at the specified annual rates on all outstanding UGI Utilities Series Preferred Stock. At September 30, 2000 and 1999, UGI Utilities had outstanding 200,000 shares of $7.75 Series cumulative preferred stock. UGI Utilities is required to establish a sinking fund to redeem on October 1 in each year, commencing October 1, 2004, 10,000 shares of its $7.75 Series at a price of $100 per share. The $7.75 Series is redeemable, in whole or in part, at the option of UGI Utilities on or after October 1, 2004, at a price of $100 per share. All outstanding shares of $7.75 Series Preferred Stock are subject to mandatory redemption on October 1, 2009, at a price of $100 per share. 39 28 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) NOTE 8 -- COMMON STOCK AND INCENTIVE STOCK AWARD PLANS On September 7, 1999, pursuant to strategic and financial initiatives announced on July 28, 1999, we repurchased 4.5 million shares of Common Stock through a "Dutch auction" tender offer for $109.1 million, or $24.25 per share. The repurchased shares are held in treasury. In addition, during 1999, in conjunction with the Company's proposed merger with Unisource (see Note 14), we purchased 1.4 million shares of Common Stock for $23.2 million. Common Stock share activity for 1998, 1999 and 2000 follows:
Issued Treasury Outstanding ====================================================================================== Balance September 30, 1997 33,198,731 (336,715) 32,862,016 Issued: Employee and director plans -- 243,915 243,915 Dividend reinvestment plan -- 108,353 108,353 Acquisitions -- 42,078 42,078 Reacquired -- (433,100) (433,100) ------------------------------------------------------------------------------------- Balance September 30, 1998 33,198,731 (375,469) 32,823,262 Issued: Employee and director plans -- 175,040 175,040 Dividend reinvestment plan -- 136,587 136,587 Reacquired -- (5,864,496) (5,864,496) ------------------------------------------------------------------------------------- Balance September 30, 1999 33,198,731 (5,928,338) 27,270,393 Issued: Employee and director plans -- 62,525 62,525 Dividend reinvestment plan -- 114,430 114,430 Reacquired -- (453,639) (453,639) ------------------------------------------------------------------------------------- Balance September 30, 2000 33,198,731 (6,205,022) 26,993,709 -------------------------------------------------------------------------------------
STOCK OPTION PLANS Under UGI's current employee stock option and incentive plans, we may grant options to acquire shares of Common Stock, or issue shares of restricted stock, to key employees. The exercise price for options granted under all plans may not be less than the fair market value on the grant date. Grants of stock options or restricted stock under these plans may vest immediately, or ratably over a period of years, and stock options generally can be exercised no later than ten years from the grant date. Under the 2000 Stock Incentive Plan ("2000 Incentive Plan"), up to 1,100,000 shares of Common Stock may be issued in connection with stock options and grants of restricted stock. However, no more than 500,000 shares of restricted stock may be granted. In addition, the 2000 Incentive Plan provides that both option grants and restricted stock grants may provide for the crediting of Common Stock dividend equivalents to participants' accounts. Dividend equivalents will be paid in cash, and such payments may, at the participants' request, be deferred. Grants of restricted stock will be contingent upon the achievement of objective performance goals. At September 30, 2000, no grants have been made under the 2000 Incentive Plan. Under the 1997 Stock Option and Dividend Equivalent Plan ("1997 SODEP Plan"), we may grant options to acquire a total of 1,500,000 shares of Common Stock. Certain option grants under the 1997 SODEP Plan provided for the crediting of dividend equivalents subject to the Company's total shareholder return relative to a peer group of companies during the three-year period ended December 31, 1999. Based upon such performance, no dividend equivalent payments were made. Under the 1992 Non-Qualified Stock Option Plan, we may grant options to acquire a total of 500,000 shares of Common Stock to key employees who do not participate in the 2000 Incentive Plan or the 1997 SODEP Plan. In addition to these employee incentive plans, the Company may grant options to acquire up to a total of 200,000 shares of Common Stock to each of the Company's nonemployee Directors. No Director may be granted options to acquire more than 10,000 shares of Common Stock in any calendar year, and the exercise price may not be less than the fair market value of the Common Stock on the grant date. Generally all options will be fully vested on the grant date and exercisable only while the participant is a Director. Stock option transactions under all of our plans for 1998, 1999 and 2000 follow:
Shares Average Option Price ================================================================================ Shares under option - September 30, 1997 1,175,001 $21.670 ------------------------------------------------------------------------- Granted 54,583 22.469 Exercised (198,121) 20.650 Forfeited (1,708) 23.962 ------------------------------------------------------------------------- Shares under option - September 30, 1998 1,029,755 21.905 ------------------------------------------------------------------------- Granted 231,806 20.406 Exercised (27,250) 21.978 Forfeited (18,750) 21.152 ------------------------------------------------------------------------- Shares under option - September 30, 1999 1,215,561 21.632 ------------------------------------------------------------------------- Granted 794,750 20.683 Exercised (30,000) 22.625 Forfeited (96,667) 22.302 ------------------------------------------------------------------------- Shares under option - September 30, 2000 1,883,644 21.181 ------------------------------------------------------------------------- Options exercisable 1998 1,014,755 21.921 Options exercisable 1999 984,061 21.725 Options exercisable 2000 947,144 21.696 -------------------------------------------------------------------------
For options outstanding as of September 30, 2000, the exercise prices range from $18.625 to $26.25. The weighted-average remaining contractual life of these options is 7.1 years. At September 30, 2000, 1,453,103 shares of Common Stock were available for future option grants under all of our stock option plans. OTHER STOCK-BASED COMPENSATION PLANS AND AWARDS On December 13, 1999, the General Partner adopted the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan ("2000 Propane Plan"). Under the 2000 Propane Plan, the General Partner may 40 29 UGI Corporation 2000 Annual Report grant to key employees the right to receive a total of 500,000 AmeriGas Partners Common Units, or cash generally equivalent to the fair market value of such Common Units, upon the achievement of objective performance goals. In addition, the 2000 Propane Plan provides that grants may provide for the crediting of Partnership distribution equivalents to participants' accounts. Distribution equivalents will be paid in cash, and such payment may, at the participant's request, be deferred. Generally, each grant, unless paid, will terminate when the participant ceases to be employed by the General Partner. At September 30, 2000, no grants have been made under the 2000 Propane Plan. Under the 1997 AmeriGas Propane, Inc. Long-Term Incentive Plan ("1997 Propane Plan"), the General Partner granted to key employees the right to receive AmeriGas Partners Common Units, or cash generally equivalent to their fair market value, on the payment date. The 1997 Propane Plan also provided for the crediting of dividend equivalents to participant's accounts. The actual number of Common Units (or their cash equivalent) awarded, and the amount of the distribution equivalent, depended upon the date when the cash generation-based requirements for early conversion of AmeriGas Partners Subordinated Units were met. Because such requirements were achieved at March 31, 1999, 81,226 Common Units were issued, and $1.1 million in cash payments were made, in May 1999. Under the 1997 UGI Corporation Directors' Equity Compensation Plan ("1997 Directors' Plan"), we make annual awards to our nonemployee Board Directors of (1) "Units," each representing an interest equivalent to one share of Common Stock, and (2) Common Stock for a portion of their annual retainer. Board Directors may also elect to receive the cash portion of their retainer fee and all or a portion of their meeting fees in the form of Units. The 1997 Directors' Plan also provides for the crediting of dividend equivalents in the form of additional Units. Units and dividend equivalents are fully vested when credited to a Director's account and will be converted to shares of Common Stock and paid upon retirement or termination of service. Units issued relating to annual awards and deferred compensation totaled 12,017, 9,137 and 7,043 in 2000, 1999 and 1998, respectively. At September 30, 2000 and 1999, there were 53,294 and 41,277 Units, respectively, outstanding. In June 1999, we awarded 103,000 shares of restricted stock to key executives. These awards vest four years from date of issuance but may vest earlier if certain Common Stock performance goals are met. Recipients have the right to vote the shares and to receive dividends during the restriction period. FAIR VALUE INFORMATION The per share weighted-average fair value of stock options granted under our option plans was $3.76 in 2000, $2.58 in 1999, and $1.98 in 1998. These amounts were determined using the Black-Scholes option pricing model, which values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments, and the risk-free interest rate over the expected life of the option. The assumptions we used for option grants during 2000, 1999 and 1998 are as follows:
2000 1999 1998 --------------------------------------------------------------- Expected life of option 6 years 6 years 6 years Expected volatility 26.5% 19.3% 16.2% Expected dividend yield 6.2% 6.2% 6.0% Risk free interest rate 6.6% 5.9% 4.6% ---------------------------------------------------------------
We use the intrinsic value method prescribed by APB 25 for our stock-based employee compensation plans. We recognized, under the provisions of APB 25, total stock-based compensation expense (income) of $(0.8) million in 2000, $1.9 million in 1999, and $1.0 million in 1998. Stock-based compensation income in 2000 reflects the reversal of $2.1 million of accrued dividend equivalent payments relating to the 1997 SODEP Plan. If we had determined compensation expense under the fair value method prescribed by SFAS 123, net income and diluted earnings per share for 2000, 1999 and 1998 would have been as follows:
2000 1999 1998 --------------------------------------------------------------- Net earnings: As reported $44.7 $55.7 $40.3 Pro forma 44.2 55.3 40.2 Diluted earnings per share: As reported $1.64 $1.74 $1.22 Pro forma 1.62 1.73 1.21 ---------------------------------------------------------------
STOCK OWNERSHIP POLICY The Company has a stock ownership policy ("Stock Ownership Policy") for executives and key employees. Under the terms of the Stock Ownership Policy, executives and certain key employees are required to own UGI Common Stock having a fair value equal to 40% to 450% of their base salaries. Participants have from three months to three years to comply with the Stock Ownership Policy. We offer full recourse, interest-bearing loans to employees in order to assist them in meeting the ownership requirements. Each loan may not exceed ten years and is collateralized by the Common Stock purchased. At September 30, 2000 and 1999, loans outstanding totaled $5.2 million and $4.1 million, respectively. NOTE 9 - PREFERENCE STOCK PURCHASE RIGHTS Holders of our Common Stock own one-half of one right (as described below) for each outstanding share of Common Stock. Each right entitles the holder to purchase one one-hundredth of a share of First Series Preference Stock, without par value, at an exercise price of $120 per one one-hundredth of a share or, under the circumstances summarized below, to purchase the common stock described in the following paragraph. The rights are exercisable only if a person or group, other than certain underwriters: 41 30 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) 1. acquires 20% or more of our Common Stock ("Acquiring Person") or 2. announces or commences a tender offer for 30% or more of our Common Stock. We are entitled to redeem the rights at five cents per right at any time before the earlier of: 1. the expiration of the rights in April 2006 or 2. ten days after a person or group has acquired 20% of our Common Stock if a majority of continuing Directors concur and, in certain circumstances, thereafter. Each holder of a right, other than an Acquiring Person, is entitled to purchase, at the exercise price of the right, Common Stock having a market value of twice the exercise price of the right if: 1. an Acquiring Person merges with UGI or engages in certain other transactions with us or 2. a person acquires 40% or more of our Common Stock. In addition, if, after UGI (or an Acquiring Person) publicly announces that an Acquiring Person has become such, UGI engages in a merger or other business combination transaction in which: 1. we are not the surviving corporation, or 2. we are the surviving corporation, but our Common Stock is changed or exchanged, or 3. 50% or more of our assets or earning power is sold or transferred, then each holder of a right is entitled to purchase, at the exercise price of the right, common stock of the acquiring company having a market value of twice the exercise price of the right. The rights have no voting or dividend rights and, until exercisable, have no dilutive effect on our earnings. NOTE 10 - PARTNERSHIP DISTRIBUTIONS The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash for such quarter. Available Cash generally means: 1. all cash on hand at the end of such quarter, 2. plus all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter, 3. less the amount of cash reserves established by the General Partner in its reasonable discretion. The General Partner may establish reserves for the proper conduct of the Partnership's business and for distributions during the next four quarters. In addition, certain of the Partnership's debt agreements require reserves be established for the payment of debt principal and interest. Distributions of Available Cash will generally be made 98% to the Common and Subordinated unitholders and 2% to the General Partner. The Partnership may pay an incentive distribution if Available Cash exceeds the Minimum Quarterly Distribution of $0.55 ("MQD") on all units. If there is sufficient Available Cash, the holders of Common Units have the right to receive the MQD, plus any arrearages, before the distribution of Available Cash to holders of Subordinated Units. Common Units will not accrue arrearages for any quarter after the Subordination Period (as defined below), and Subordinated Units will not accrue arrearages for any quarter. Pursuant to the Agreement of Limited Partnership of AmeriGas Partners ("Partnership Agreement"), because the required cash generation-based objectives were achieved as of March 31, 1999, a total of 9,891,074 Subordinated Units held by the General Partner and its wholly owned subsidiary, Petrolane, were converted into Common Units on May 18, 1999. The remaining outstanding 9,891,072 Subordinated Units, all of which are held by the General Partner, are eligible to convert to Common Units on the first day after the record date for any quarter ending on or after March 31, 2000 in respect of which: 1. distributions of Available Cash from Operating Surplus (as defined in the Partnership Agreement) equal or exceed the MQD on each of the outstanding Common and Subordinated units for each of the four consecutive nonoverlapping four-quarter periods immediately preceding such date, 2. the Adjusted Operating Surplus (as defined in the Partnership Agreement) generated during both (1) each of the two immediately preceding nonoverlapping four-quarter periods and (2) the immediately preceding sixteen-quarter period, equals or exceeds the MQD on each of the Common and Subordinated units outstanding during those periods, and 3. there are no arrearages on the Common Units. The ability of the Partnership to attain the cash-based performance and distribution requirements will depend upon a number of factors including highly seasonal operating results, changes in working capital, asset sales and debt refinancings. Due to the historical "look-back" provisions of the conversion test, the possibility is remote that the Partnership will satisfy the cash-based performance requirements for conversion any earlier than in respect of the quarter ending March 31, 2002. 42 31 UGI Corporation 2000 Annual Report NOTE 11 - COMMITMENTS AND CONTINGENCIES We lease various buildings and transportation, computer, and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $34.1 million in 2000, $35.3 million in 1999, and $33.5 million in 1998. Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows:
After 2001 2002 2003 2004 2005 2005 --------------------------------------------------------------------------------------------- AmeriGas Propane $ 27.2 $ 22.0 $ 16.8 $ 13.7 $ 11.3 $ 24.7 UGI Utilities 3.6 3.1 2.5 1.7 0.9 0.7 International Propane 0.1 0.1 0.1 -- -- -- Other 2.4 2.3 2.1 1.8 1.7 6.7 --------------------------------------------------------------------------------------------- Total $ 33.3 $ 27.5 $ 21.5 $ 17.2 $ 13.9 $ 32.1 ---------------------------------------------------------------------------------------------
Gas Utility has gas supply agreements with producers and marketers with terms of less than one year. Gas Utility also has agreements for firm pipeline transportation and storage capacity which Gas Utility may terminate at various dates through 2015. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot market prices. Prior to August 1, 1999, Pennsylvania Power & Light Company ("PP&L"), pursuant to a 1992 power supply agreement for bundled energy and capacity, supplied all of Electric Utility's electric power requirements above that provided by other sources. As part of a settlement of all disputes concerning the 1992 power supply agreement, during 1999 Electric Utility and PP&L entered into a new power supply agreement under which PP&L will supply all of Electric Utility's capacity requirements in excess of its capacity resources acquired from other sources through February 2001, and 32 megawatts of energy in each hour of the day through December 2000. Electric Utility has a number of other power supply agreements with PP&L and other power producers having various length terms expiring through December 2001. In high usage months, Electric Utility meets its additional electric power needs, above those provided by these contracts and its own generation facilities, through monthly market-based contracts and through spot purchases at market prices as delivered. In September 2000, UGIDC agreed to joint venture with a subsidiary of Allegheny Energy, Inc. ("Allegheny") to own and operate electric generation facilities, including Electric Utility's coal-fired Hunlock Creek generating station ("Hunlock"). Initially, UGIDC will contribute to the joint venture Hunlock, certain related assets, and approximately $6 million in cash. Allegheny will contribute a newly-constructed gas-fired combustion turbine generator to be operated at Hunlock's site. Each partner will be entitled to purchase 50% of the output of the joint venture at cost. The joint venture is expected to become operational in December 2000. The Partnership enters into contracts to purchase propane and Energy Services enters into contracts to purchase natural gas to meet a portion of their supply requirements. Generally, such contracts have terms of less than one year and call for payment based on either fixed prices or market prices at date of delivery. The Partnership has succeeded to certain lease guarantee obligations of Petrolane, a predecessor company of the Partnership, relating to Petrolane's divestiture of nonpropane operations before its 1989 acquisition by QFB Partners. Future lease payments under these leases total approximately $32 million at September 30, 2000. The leases expire through 2010, and some of them are currently in default. The Partnership has succeeded to the indemnity agreement of Petrolane by which Texas Eastern Corporation ("Texas Eastern"), a prior owner of Petrolane, agreed to indemnify Petrolane against any liabilities arising out of the conduct of businesses that do not relate to, and are not a part of, the propane business, including lease guarantees. To date, Texas Eastern has directly satisfied defaulted lease obligations without the Partnership's having to honor its guarantee. In addition, the Partnership has succeeded to Petrolane's agreement to indemnify Shell Petroleum N.V. ("Shell") for various scheduled claims, including claims related to antitrust actions, that were pending against Tropigas de Puerto Rico ("Tropigas"). Petrolane had entered into this indemnification agreement in conjunction with its sale of the international operations of Tropigas to Shell in 1989. The Partnership also succeeded to Petrolane's right to seek indemnity on these claims first from International Controls Corp., which sold Tropigas to Petrolane, and then from Texas Eastern. To date, neither the Partnership nor Petrolane has paid any sums under this indemnity. In 1999, a case brought by an unsuccessful entrant into the Puerto Rican propane market was dismissed by the Supreme Court of Puerto Rico for lack of subject matter jurisdiction, with the Court concluding that the Public Service Commission of Puerto Rico has exclusive jurisdiction over the matter. In the only pending litigation, the Supreme Court of Puerto Rico denied the motion of the defendants to dismiss, remanding the matter to the trial court for proceedings consistent with its ruling. In this case the plaintiff seeks treble damages in excess of $11.7 million. We believe that the probability the Partnership will be required to directly satisfy the above lease obligations and the remaining claim subject to the indemnification agreements is remote. We, along with other companies, have been named as a potentially responsible party ("PRP") in several administrative proceedings and private party recovery actions for the cleanup, or recovery of costs associated with cleanup, of various waste sites, including some Superfund sites. In addition, we have identified environmental contamination at several of our properties and have voluntarily undertaken investigation and, as appropriate, remediation of these sites in cooperation with appropriate environmental agencies or private parties. 43 32 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) Prior to the general availability of natural gas, in the 1800s through the mid-1900s, most gas for lighting and heating nationwide was manufactured from combustibles such as coal, oil and coke. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the federal "Comprehensive Environmental Response, Compensation and Liability Act," or "Superfund Law," and may be present on the sites of former manufactured gas plants ("MGPs"). UGI Utilities and its former subsidiaries owned and operated a number of MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the mid-1930s, UGI Utilities was one of the largest public utility holding companies in the country. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, UGI Utilities divested all of its utility operations other than those which now constitute Gas Utility and Electric Utility. UGI Utilities has been notified of several sites outside Pennsylvania on which (1) gas plants were formerly operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or private parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating two claims against it relating to out-of state sites. Management believes that UGI Utilities should not have significant liability in those instances in which a former subsidiary operated an MGP because UGI Utilities generally is not legally liable for the obligations of its subsidiaries. Under certain circumstances, however, a court could find a parent company liable for environmental damage caused by a subsidiary company when the parent company either (1) itself operated the facility causing the environmental damage or (2) otherwise so controlled the subsidiary that the subsidiary's separate corporate form should be disregarded. There could be, therefore, significant future costs of an uncertain amount associated with environmental damage caused by MGPs that UGI Utilities owned or directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that the subsidiary's separate corporate form should be disregarded. UGI Utilities has identified 40 sites in Pennsylvania where either (1) UGI Utilities formerly conducted some MGP operations or (2) UGI Utilities owns or at one time owned the site. Because Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with Pennsylvania sites, the Company does not expect its costs for Pennsylvania sites to be material to future results of operations. UGI Utilities has filed suit against more than fifty insurance companies alleging that the defendants breached contracts of insurance by failing to indemnify UGI Utilities for certain environmental costs. The suit seeks to recover more than $11 million in such costs. During 2000, UGI Utilities entered into settlement agreements with several of the insurers and recorded pre-tax income of $4.5 million which amount is included in operating and administrative expenses in the 2000 Consolidated Statement of Income. In addition to these matters, there are other pending claims and legal actions arising in the normal course of our businesses. We cannot predict with certainty the final results of environmental and other matters. However, it is reasonably possible that some of them could be resolved unfavorably to us. Management believes, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position but could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. NOTE 12 -- FINANCIAL INSTRUMENTS The carrying amounts of financial instruments included in current assets and current liabilities (excluding current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amounts and estimated fair values of our long-term debt and UGI Utilities Series Preferred Stock at September 30 are as follows:
Carrying Estimated Amount Fair Value ------------------------------------------------------------------ 2000: Long-term debt: AmeriGas Propane $857.2 $882.5 UGI Utilities 172.9 167.8 Other 85.5 85.6 UGI Utilities Series Preferred Stock 20.0 21.0 1999: Long-term debt: AmeriGas Propane $744.7 $761.3 UGI Utilities 180.0 174.8 Other 91.6 91.1 UGI Utilities Series Preferred Stock 20.0 20.9 -----------------------------------------------------------------
We estimate the fair value of long-term debt by using current market prices and by discounting future cash flows using rates available for similar type debt. The estimated fair value of UGI Utilities Series Preferred Stock is based on the fair value of redeemable preferred stock with similar credit ratings and redemption features. We have financial instruments such as short-term investments and trade accounts receivable which could expose us to concentrations of credit risk. We limit our credit risk from short-term investments by investing only in investment-grade commercial paper and in U.S. Government securities. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different U.S. markets. 44 33 UGI Corporation 2000 Annual Report We utilize derivative instruments to hedge market risk resulting from changes in the price of natural gas and propane, and changes in interest rates. We attempt to minimize our credit risk with our counterparties through the application of credit policies. At September 30, 2000 and 1999, the Partnership was a party to an interest rate protection agreement covering $50 million of long-term debt to be issued in fiscal 2001. The counterparty to this agreement is a large financial institution. The estimated fair value of this agreement was $2.5 million at September 30, 2000 and $3.2 million at September 30, 1999. At September 30, 2000 and 1999, Energy Services held exchange traded natural gas futures contracts with total notional amounts of $30.2 million and $26.6 million, respectively. Net deferred gains on settled and unsettled contracts totaled $6.6 million at September 30, 2000 and $3.3 million at September 30, 1999. At September 30, 1999, Energy Services also held exchange traded heating oil futures and option contracts with a total notional amount of $6.5 million and an estimated fair value of $(0.2) million. At September 30, 2000 and 1999, the Partnership was a party to propane price swap and option agreements with private counterparties with total notional amounts of $74.8 million and $12.9 million, respectively. Agreements outstanding at September 30, 2000 mature through March 2001. The estimated fair values of these swap and option agreements were $6.5 million and $2.9 million at September 30, 2000 and 1999, respectively. NOTE 13 - ACQUISITIONS During 2000, the Partnership acquired several propane distribution businesses, and Enterprises acquired an HVAC business, for net cash consideration of $65.3 million. The excess of the purchase price over the amount preliminarily allocated to the net assets acquired was approximately $42 million. During 1999 and 1998, the Partnership acquired several retail propane distribution businesses for net cash consideration of $3.9 million and $8.1 million, respectively. These acquisitions were recorded using the purchase method of accounting. Under the purchase method, the purchase price has been allocated to assets acquired and liabilities assumed based upon estimated fair values. The operating results of these businesses have been included in the consolidated results from their respective dates of acquisition. In addition to these acquisitions, during 1999 the Company paid $4.9 million for a 25% equity interest in a propane distribution business in Nantong, China, which is being accounted for on the equity method of accounting. On September 21, 1999, Enterprises, through subsidiaries, acquired all of the outstanding stock of FLAGA for net cash consideration of $73.7 million and the assumption of approximately $18 million of debt. The cash purchase price was financed through the issuance of EURO denominated debt. The acquisition of FLAGA has been accounted for using the purchase method of accounting. The excess of the purchase price over the amount allocated to the net assets acquired totaled $57.5 million. For accounting convenience only, September 30, 1999 was deemed to be the acquisition date. As a result, the acquisition of FLAGA did not impact the Company's 1999 results of operations. The unaudited pro forma revenues, net income and diluted earnings per share of the Company for 1999, as if the acquisition of FLAGA had occurred as of October 1, 1998, are $1,434.0 million, $52.0 million, and $1.62, respectively. The pro forma results of operations give effect to FLAGA's historical operating results in accordance with U.S. generally accepted accounting principles and adjustments for interest expense, goodwill amortization and depreciation expense, and income taxes, but do not adjust for normal weather conditions and anticipated operating efficiencies. In management's opinion, the unaudited pro forma results are not indicative of the actual results that would have occurred had the acquisition of FLAGA occurred as of October 1, 1998, or of future operating results under the ownership and management of the Company. The pro forma effect of the other businesses acquired during 2000, 1999 and 1998 was not material to our results of operations. NOTE 14 - TERMINATED MERGER - UNISOURCE WORLDWIDE, INC. On May 25, 1999, the Company announced that Unisource Worldwide, Inc. ("Unisource") had entered into a merger agreement with Georgia-Pacific Corp. ("GP") and that it would allow Unisource to terminate the previously announced Agreement and Plan of Merger (the "Merger Agreement") among Unisource, UGI and Vulcan Acquisition Corp. (a wholly owned subsidiary of UGI) which would have provided for the merger of the Company and Unisource. Because the board of directors of Unisource decided to enter into a merger agreement with GP, Unisource was required to pay the Company a $25 million merger termination fee pursuant to the terms of the Merger Agreement. The Company received the termination fee on May 28, 1999. The fee, net of related merger expenses, is classified as merger fee income and expenses, net, in the 1999 Consolidated Statement of Income. NOTE 15 - OTHER INCOME, NET Other income, net, comprises the following:
2000 1999 1998 --------------------------------------------------------------------------- Interest and interest-related income $ (9.3) $ (8.5) $ (8.6) Loss on Partnership's interest rate protection agreements -- -- 4.0 Gain on sales of investments (1.8) -- (2.3) Gain on sales of fixed assets (3.6) (2.2) (2.0) Pension income (3.0) (2.3) (1.9) Other (9.2) (3.8) (1.9) --------------------------------------------------------------------------- Total other income, net $ (26.9) $ (16.8) $ (12.7) ---------------------------------------------------------------------------
45 34 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars, except per share amounts and where indicated otherwise) NOTE 16-- QUARTERLY DATA (UNAUDITED)
December 31, March 31, June 30, September 30, 1999 1998 2000(a) 1999(b) 2000 1999(c) 2000(d) 1999 ---------------------------------------------------------------------------------------------------------------------------------- Revenues $ 466.6 $ 373.7 $ 610.4 $ 499.2 $ 335.9 $ 259.3 $ 348.8 $ 251.4 Operating income (loss) 70.7 61.5 117.9 115.6 8.7 9.4 (6.1) (10.6) Net income (loss) 21.1 18.0 38.8 37.5 (4.7) 11.4 (10.5) (11.2) Net income (loss) per share- Basic 0.77 0.55 1.42 1.15 (0.17) 0.36 (0.39) (0.37) Diluted 0.77 0.55 1.42 1.14 (0.17) 0.36 (0.39) (0.37) ----------------------------------------------------------------------------------------------------------------------------------
The quarterly data above includes all adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) which we consider necessary for a fair presentation. Our quarterly results fluctuate because of the seasonal nature of our businesses. (a) Includes income from a litigation settlement which increased operating income by $2.4 million and net income by $1.4 million or $0.05 per share. (b) Includes merger expenses of $1.6 million which decreased net income by $1.1 million or $0.03 per share. (c) Includes merger termination fee income of $25 million, less $3.5 million of merger related expenses, which increased net income by $14.0 million or $0.44 per share. (d) Includes income from a litigation settlement which decreased operating loss by $2.1 million and net loss by $1.2 million or $0.04 per share. NOTE 17 -- SEGMENT INFORMATION SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131"), defines operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. We have determined that the Company has five such business segments: (1) AmeriGas Propane; (2) Gas Utility; (3) Electric Utility; (4) Energy Services; and (5) an international propane segment comprising FLAGA and our equity investments in China and Romania. AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies principally to retail customers from locations in 45 states. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern and southeastern Pennsylvania. Electric Utility derives its revenues from the sale and distribution of electricity in two northeastern Pennsylvania counties. Although the Electricity Customer Choice Act unbundled the pricing for Electric Utility's electric generation, transmission and distribution services, we currently manage and evaluate these business components on a combined basis. Energy Services revenues are derived from the sale of natural gas and, to a lesser extent, electricity to customers located primarily in the Middle Atlantic and New England states. Our International Propane segment revenues result principally from the distribution of propane to retail customers in Austria, the Czech Republic and Slovakia. The accounting policies of our reportable segments are substantially the same as those described in Note 1. We evaluate our AmeriGas Propane and International Propane segments' performance principally based upon earnings before interest expense, income taxes, depreciation and amortization ("EBITDA"). We evaluate the performance of our Gas Utility, Electric Utility and Energy Services segments principally based upon their earnings before income taxes. No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments' revenues, other than those of our International Propane segment, are derived from sources within the U.S., and all of our reportable segments' long-lived assets, other than those of our International Propane segment, are located in the U.S. Financial information by business segment follows: 46 35
AmeriGas Gas Electric Energy Total Eliminations Propane Utility Utility Services ---------------------------------------------------------------------------------------------------------------------------------- 2000 Revenues $1,761.7 $ (3.1) $1,120.1 $ 359.0 $ 77.9 $ 146.9 EBITDA $ 288.7 $ -- $ 158.6 $ 105.3 $ 19.6 $ 3.0 Depreciation and amortization (97.5) -- (68.4) (19.1) (4.5) (0.2) ---------------------------------------------------------------------------------------------------------------------------------- Operating income (loss) 191.2 -- 90.2 86.2 15.1 2.8 Interest expense (98.5) -- (74.7) (16.2) (2.2) -- Minority interest (6.3) -- (6.3) -- -- -- ---------------------------------------------------------------------------------------------------------------------------------- Income (loss) before income taxes $ 86.4 $ -- $ 9.2 $ 70.0 $ 12.9 $ 2.8 Total assets $2,278.8 $ (19.0) $1,281.7 $ 656.7 $ 97.4 $ 36.2 Capital expenditures $ 71.0 $ -- $ 30.4 $ 31.7 $ 4.7 $ 0.1 Investments in foreign equity investees $ 5.5 $ -- $ -- $ -- $ -- $ -- ================================================================================================================================== 1999 Revenues $1,383.6 $ (2.3) $ 872.5 $ 345.6 $ 75.0 $ 90.4 EBITDA $ 265.6 $ -- $ 158.8 $ 87.0 $ 16.7 $ 2.7 Depreciation and amortization (89.7) -- (66.3) (19.0) (4.0) (0.1) ---------------------------------------------------------------------------------------------------------------------------------- Operating income (loss) 175.9 -- 92.5 68.0 12.7 2.6 Merger fee income, net 19.9 -- -- -- -- -- Interest expense (84.6) -- (66.5) (15.2) (2.3) -- Minority interest (10.7) -- (10.7) -- -- -- ---------------------------------------------------------------------------------------------------------------------------------- Income (loss) before income taxes $ 100.5 $ -- $ 15.3 $ 52.8 $ 10.4 $ 2.6 Total assets $2,140.5 $ (15.6) $1,221.9 $ 620.4 $ 95.3 $ 17.4 Capital expenditures $ 73.7 $ -- $ 34.6(a) $ 31.9 $ 4.5 $ 0.2 Investments in foreign equity investees $ 6.3 $ -- $ -- $ -- $ -- $ -- ================================================================================================================================== 1998 Revenues $1,439.7 $ (3.0) $ 914.4 $ 350.2 $ 72.1 $ 103.0 EBITDA $ 258.0 $ -- $ 153.3 $ 83.0 $ 13.6 $ 2.1 Depreciation and amortization (87.8) -- (65.4) (18.2) (3.9) (0.1) ---------------------------------------------------------------------------------------------------------------------------------- Operating income (loss) 170.2 -- 87.9 64.8 9.7 2.0 Interest expense (84.4) -- (66.1) (15.3) (2.3) -- Minority interest (8.9) -- (8.9) -- -- -- ---------------------------------------------------------------------------------------------------------------------------------- Income (loss) before income taxes $ 76.9 $ -- $ 12.9 $ 49.5 $ 7.4 $ 2.0 Total assets $2,074.6 $ (17.1) $1,238.2 $ 594.4 $ 95.6 $ 14.3 Capital expenditures $ 69.2 $ -- $ 31.9 $ 32.0 $ 5.2 $ 0.1 Investments in foreign equity investees $ 2.1 $ -- $ -- $ -- $ -- $ -- ==================================================================================================================================
International Other Corporate & Propane Enterprises Other ------------------------------------------------------------------------------------ 2000 Revenues $ 50.5 $ 7.3 $ 3.1 EBITDA $ 1.9 $ (5.0) $ 5.3 Depreciation and amortization (4.6) (0.5) (0.2) ------------------------------------------------------------------------------------ Operating income (loss) (2.7) (5.5) 5.1 Interest expense (4.8) -- (0.6) Minority interest -- -- -- ------------------------------------------------------------------------------------ Income (loss) before income taxes $ (7.5) $ (5.5) $ 4.5 Total assets $ 113.7 $ 28.2 $ 83.9 Capital expenditures $ 1.8 $ 2.3 $ -- Investments in foreign equity investees $ 5.5 $ -- $ -- ================================================================================== 1999 Revenues $ -- $ 0.1 $ 2.3 EBITDA $ (0.1) $ (5.7) $ 6.2 Depreciation and amortization -- -- (0.3) ------------------------------------------------------------------------------------ Operating income (loss) (0.1) (5.7) 5.9 Merger fee income, net -- -- 19.9 Interest expense -- -- (0.6) Minority interest -- -- -- ------------------------------------------------------------------------------------ Income (loss) before income taxes $ (0.1) $ (5.7) $ 25.2 Total assets $ 143.2 $ 3.7 $ 54.2 Capital expenditures $ -- $ 2.5 $ -- Investments in foreign equity investees $ 6.3 $ -- $ -- ================================================================================== 1998 Revenues $ -- $ -- $ 3.0 EBITDA $ (1.0) $ (1.8) $ 8.8 Depreciation and amortization -- -- (0.2) ------------------------------------------------------------------------------------ Operating income (loss) (1.0) (1.8) 8.6 Interest expense -- -- (0.7) Minority interest -- -- -- ------------------------------------------------------------------------------------ Income (loss) before income taxes $ (1.0) $ (1.8) $ 7.9 Total assets $ 2.3 $ 0.1 $ 146.8 Capital expenditures $ -- $ -- $ -- Investments in foreign equity investees $ 2.1 $ -- $ -- ==================================================================================
(a) Includes capital leases of $3.5 million. 47