Exhibit 13
UGI Corporation 2006 Annual Report
Financial Review
Business Overview
UGI Corporation (“UGI”) is a holding company that distributes and markets energy products and related services through subsidiaries and joint-venture affiliates. We are a domestic and international distributor of propane and butane (which are liquefied petroleum gases (“LPG”)); a provider of natural gas and electric service through regulated local distribution utilities; a generator of electricity through our ownership of electric generation assets and ownership interests in electric generation facilities; a regional marketer of energy commodities; and a provider of heating and cooling services.
We conduct a national propane distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”) and its principal operating subsidiaries AmeriGas Propane, L.P. (“AmeriGas OLP”) and AmeriGas Eagle Propane, L.P. (“Eagle OLP”). At September 30, 2006, UGI, through its wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”), held an approximate 44% effective interest in AmeriGas Partners. We refer to AmeriGas Partners and its subsidiaries together as the “Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) (1) conducts an LPG distribution business in France; (2) conducts LPG distribution businesses and participates in an LPG joint-venture business in central and eastern Europe (collectively, “Flaga”); and (3) participates in an LPG joint-venture business in the Nantong region of China. Our LPG distribution business in France is conducted through Antargaz, an operating subsidiary of AGZ Holding (“AGZ”), and its operating subsidiaries (collectively, “Antargaz”). We refer to our foreign operations collectively as “International Propane.” During Fiscal 2006, we formed a Dutch private limited liability company, UGI International Holdings, B.V., to hold our interests in Antargaz and Flaga.
Our natural gas and electric distribution utility businesses are conducted through UGI Utilities, Inc. and its subsidiary, UGI Penn Natural Gas, Inc. (“UGIPNG”). On August 24, 2006, UGI Utilities, Inc., through UGIPNG, acquired the natural gas utility business of PG Energy, an operating division of Southern Union Company (“PG Energy Acquisition”). See Note 2 to the Consolidated Financial Statements for a more detailed discussion. The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc. or UGI Utilities, Inc. and UGIPNG. UGI Utilities owns and operates (1) a natural gas distribution utility in eastern Pennsylvania (“UGI Gas”), (2) a natural gas distribution utility in northeastern Pennsylvania (“PNG Gas”), and (3) an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Gas and PNG Gas are collectively referred to herein as “Gas Utility.” Gas Utility and Electric Utility are subject to regulation by the Pennsylvania Public Utility Commission (“PUC”).
Enterprises also conducts an energy marketing business primarily in the eastern region of the United States through its subsidiaries (collectively, “Energy Services”). Energy Services’ wholly owned subsidiary UGI Development Company (“UGID”) owns and operates a 48-megawatt coal-fired electric generation station and owns a 6% interest in Pennsylvania-based electric generation assets. In addition, Energy Services’ wholly owned subsidiary UGI Asset Management, Inc., through its subsidiary Atlantic Energy, Inc. (collectively, “Asset Management”) owns a propane storage terminal located in Chesapeake, Virginia. Energy Services also owns and operates a natural gas liquefaction, storage and vaporization facility, propane storage and propane-air mixing assets. Through other subsidiaries, Enterprises owns and operates heating, ventilation, air-conditioning, refrigeration and electrical contracting services businesses in the Middle Atlantic states (“HVAC/R”).
This Financial Review should be read in conjunction with our Consolidated Financial Statements and Notes to Consolidated Financial Statements including the reportable segment information included in Note 17.
Results of Operations
The following analyses compare the Company’s results of operations for (1) the year ended September 30, 2006 (“Fiscal 2006”) with the year ended September 30, 2005 (“Fiscal 2005”) and (2) Fiscal 2005 with the year ended September 30, 2004 (“Fiscal 2004”).
2006 Compared with 2005
Consolidated Results
| Variance– | ||||||||||||||||||||||||
| Favorable | ||||||||||||||||||||||||
| 2006 | 2005 | (Unfavorable) | ||||||||||||||||||||||
| % of Total | % of Total | |||||||||||||||||||||||
| Net | Net | Net | Net | Net | ||||||||||||||||||||
| (Millions of dollars) | Income | Income | Income | Income | Income | % Change | ||||||||||||||||||
| AmeriGas Propane | $ | 25.1 | 14.2 | % | $ | 17.6 | 9.4 | % | $ | 7.5 | 42.6 | % | ||||||||||||
| International Propane | 67.1 | 38.1 | % | 99.4 | 53.0 | % | (32.3 | ) | (32.5 | )% | ||||||||||||||
| Gas Utility | 38.1 | 21.6 | % | 39.3 | 21.0 | % | (1.2 | ) | (3.1 | )% | ||||||||||||||
| Electric Utility | 10.5 | 6.0 | % | 11.5 | 6.1 | % | (1.0 | ) | (8.7 | )% | ||||||||||||||
| Energy Services | 31.3 | 17.8 | % | 21.7 | 11.6 | % | 9.6 | 44.2 | % | |||||||||||||||
| Corporate & Other | 4.1 | 2.3 | % | (2.0 | ) | (1.1 | )% | 6.1 | N.M. | |||||||||||||||
| Total | $ | 176.2 | 100.0 | % | $ | 187.5 | 100.0 | % | $ | (11.3 | ) | (6.0 | )% | |||||||||||
N.M. — Variance is not meaningful.
Executive Overview
Winter weather conditions in the United States and Europe are generally the most important variables affecting our annual earnings performance. This is because a substantial portion of the energy commodities we sell is used in heating applications. Temperatures in our domestic service territories were warmer than normal in Fiscal 2006 and warmer than in the prior year.
During Fiscal 2006, LPG and natural gas prices rose from what were already high levels in Fiscal 2005 contributing to conservation across our customer base, both domestically and internationally. We continued to focus on our core competencies as a marketer and distributor of energy products and services and during Fiscal 2006 (1) completed the PG Energy Acquisition which expanded our Gas Utility’s natural gas distribution operations into northeastern Pennsylvania by approximately 158,000 customers and (2) expanded our presence in central and eastern Europe through our 50% partnership interest in Zentraleuropa LPG Holding GmbH (“ZLH”) which was formed in February 2006. Our net income declined to $176.2 million in Fiscal 2006 from $187.5 million in Fiscal 2005. The change in our net income for Fiscal 2006 reflects (1) the absence of $14.2 million of net income recorded in Fiscal 2005 resulting from the resolution of certain of Antargaz’ non-income tax contingencies and (2) Antargaz’ return to more normal LPG margins from unusually high margins experienced
13
Financial Review(continued)
during Fiscal 2005. The effects of these two factors were partially offset by (1) a $5.3 million after-tax gain from Energy Services’ sale of its 50% partnership interest in Hunlock Creek Energy Ventures (“Energy Ventures”), (2) approximately $3.9 million lower after-tax losses on early extinguishments of debt primarily associated with AmeriGas Propane refinancings, and (3) a lower effective tax rate. During Fiscal 2006, the stronger dollar compared to the euro accounted for approximately $7 million of the decrease in net income from Fiscal 2005. Largely due to the beneficial effects of changes in management’s estimate of taxes to be paid associated with planned repatriation of foreign earnings, our effective tax rate declined approximately 3% in Fiscal 2006 compared to Fiscal 2005.
AmeriGas Propane’s 43% higher contribution to net income reflects (1) the lower after-tax losses on early extinguishments of debt associated with refinancings which reduced future annual interest expense and (2) higher average margin per retail gallon sold and higher fees in response to increases in operating and administrative expenses. International Propane’s Fiscal 2006 results primarily reflect the absence of Antargaz’ unusually high margins per gallon of LPG sold from which Fiscal 2005 benefited and the absence of a $14.2 million net after-tax gain associated with the resolution of certain non-income related tax contingencies offset, in part, by the lower estimate of taxes to be paid on the planned repatriation of foreign earnings. Energy Services’ improved results over the prior year reflect the gain on the sale of Energy Ventures and increased sales of liquid fuels to dual fuel customers. Looking ahead to Fiscal 2007, although energy prices are expected to retreat from the historic levels reached in Fiscal 2006, we anticipate customers will continue to make efforts to reduce their consumption of energy. As part of our business strategy, we continue to seek new growth opportunities through acquisitions. Although the PG Energy Acquisition did not have a material effect on our Fiscal 2006 results, we expect to see earnings growth from our Gas Utility as a result of the PG Energy Acquisition in Fiscal 2007. We also expect that International Propane will continue to face increasing competition with other LPG suppliers and other sources of energy.
| Increase | ||||||||||||||||
| AmeriGas Propane: | 2006 | 2005 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 2,119.3 | $ | 1,963.3 | $ | 156.0 | 7.9 | % | ||||||||
| Total margin (a) | $ | 775.5 | $ | 743.3 | $ | 32.2 | 4.3 | % | ||||||||
| Partnership EBITDA (b) | $ | 237.9 | $ | 215.9 | $ | 22.0 | 10.2 | % | ||||||||
| Operating income | $ | 184.1 | $ | 168.1 | $ | 16.0 | 9.5 | % | ||||||||
| Retail gallons sold (millions) | 975.2 | 1,034.9 | (59.7 | ) | (5.8 | )% | ||||||||||
| Degree days — % warmer than normal (c) | 10.2 | % | 6.9 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Partnership EBITDA (earnings before interest expense, income taxes and 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 or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane reportable segment (see Note 17 to Consolidated Financial Statements). | |
| (c) | Deviation from average heating degree days based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. |
Temperatures in AmeriGas Propane’s service territories based upon heating degree days during Fiscal 2006 were 10.2% warmer than normal compared with temperatures that were 6.9% warmer than normal during Fiscal 2005. Retail propane volumes sold decreased approximately 5.8% principally due to the warmer winter weather and the negative effects of customer conservation driven by continued high propane selling prices.
Retail propane revenues increased $136.8 million reflecting a $233.8 million increase due to higher average selling prices partially offset by a $97.0 million decrease due to the lower retail volumes sold. Wholesale propane revenues decreased $2.8 million reflecting a $27.4 million decrease due to lower volumes sold largely offset by a $24.6 million increase due to higher average selling prices. In Fiscal 2006, our average retail propane product cost per retail gallon sold was approximately 18% higher than in Fiscal 2005 resulting in higher year-over-year prices to our customers. The average wholesale cost per gallon of propane during Fiscal 2006 at Mont Belvieu, one of the major supply points in the United States, was approximately 21% greater than the average cost per gallon during Fiscal 2005. Total cost of sales increased to $1,343.8 million in Fiscal 2006 from $1,220.0 million in Fiscal 2005 primarily reflecting the increase in propane product costs partially offset by the decreased volumes sold. Total margin increased $32.2 million principally due to higher average propane margins per gallon and higher fees in response to increases in operating and administrative expenses.
Partnership EBITDA during Fiscal 2006 increased $22.0 million compared to Fiscal 2005 as a result of the previously mentioned increase in total margin and a $16.5 million decrease in the loss on the early extinguishments of debt from $33.6 million in Fiscal 2005 to $17.1 million in Fiscal 2006. These changes were partially offset by a $17.1 million increase in operating and administrative expenses and a $9.5 million decrease in other income primarily reflecting the absence of a $9.1 million pre-tax gain on the sale of its 50% ownership interest in Atlantic Energy to Energy Services which was recognized during Fiscal 2005. The $17.1 million loss on the early extinguishments of debt that was incurred during Fiscal 2006 was associated with the refinancings of AmeriGas OLP’s Series A and Series C First Mortgage Notes totaling $228.8 million and $59.6 million of the Partnership’s $60 million 10% Senior Notes with $350 million of 7.125% Senior Notes due 2016. The Partnership also used a portion of the proceeds from the issuance of the 7.125% Senior Notes to repay its $35 million term loan. The increase in operating and administrative expenses principally resulted from higher (1) vehicle fuel and lease costs, (2) employee compensation and benefits and (3) maintenance and repairs. These increases were partially offset by a $7.2 million favorable net expense reduction related to general insurance and litigation claims, primarily reflecting improved claims history. The Partnership recovered significant increases in certain costs, such as vehicle fuel, through delivery surcharges.
Operating income increased $16.0 million reflecting the increase in margin and a $1.2 million decrease in depreciation expense largely offset by the aforementioned $17.1 million higher operating and administrative expenses.
14
UGI Corporation 2006 Annual Report
| Increase | ||||||||||||||||
| International Propane: | 2006 | 2005 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 945.5 | $ | 943.9 | $ | 1.6 | 0.2 | % | ||||||||
| Total margin (a) | $ | 428.3 | $ | 499.8 | $ | (71.5 | ) | (14.3 | )% | |||||||
| Operating income | $ | 119.3 | $ | 193.8 | $ | (74.5 | ) | (38.4 | )% | |||||||
| Income before income taxes | $ | 93.9 | $ | 159.0 | $ | (65.1 | ) | (40.9 | )% | |||||||
| Antargaz retail gallons sold (millions) | 315.2 | 338.4 | (23.2 | ) | (6.9 | )% | ||||||||||
| Antargaz total margin, millions of euros (a) | € | 330.2 | € | 363.2 | € | (33.0 | ) | (9.1 | )% | |||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Temperatures in International Propane’s service territories based upon heating degree days during Fiscal 2006 were generally comparable to the prior year. During Fiscal 2006, the monthly average currency translation rate was $1.23 per euro compared to $1.27 per euro during Fiscal 2005. Antargaz’ retail LPG volumes sold decreased to 315.2 million gallons in Fiscal 2006 from 338.4 million gallons in Fiscal 2005 due in large part to the late onset of winter weather in December, lower agricultural volumes sold and the effects of customer conservation on volumes sold.
International Propane revenues increased slightly as approximately $12 million of increased revenues from Antargaz were largely offset by a decline in Flaga’s revenues. The increase in Antargaz’ revenues reflects higher retail LPG selling prices largely offset by the effects of the stronger dollar versus the euro. The decrease in Flaga’s revenues largely reflects the effects of Flaga’s Czech Republic and Slovakia businesses being contributed to ZLH in February of 2006. International Propane’s total cost of sales increased to $517.2 million in Fiscal 2006 from $444.1 million in Fiscal 2005 reflecting higher LPG product costs on lower retail volumes sold partially offset by the beneficial effects of the stronger dollar compared to the euro.
Total International Propane margin declined $71.5 million in Fiscal 2006 compared to Fiscal 2005 primarily (1) reflecting both the decline in Antargaz’ volumes and its unusually high LPG unit margins in Fiscal 2005 and (2) due to the stronger dollar versus the euro. Antargaz’ total base currency margin declined €33.0 million reflecting the lower volumes sold and lower unit margins.
The decrease in International Propane operating income principally reflects the decline in total margin, the absence of $18.8 million of income from the reversal of certain of Antargaz’ non-income tax related reserves which were recorded in the prior year (see discussion in “Antargaz Tax Matters”) partially offset by a decrease of $19.0 million in operating and administrative expenses. The decrease in operating and administrative expenses reflects the beneficial effects of the stronger dollar and lower euro-based operating and administrative expenses at Antargaz and Flaga. The decline in Flaga’s operating and administrative expenses largely reflect the absence of expenses from the businesses contributed to ZLH.
The decrease in International Propane income before income taxes reflects the decrease in operating income and a $1.4 million loss on early extinguishment of debt, partially offset by approximately $6.7 million lower interest expense and changes in minority interest. The decrease in interest expense is attributable to interest savings as a result of our refinancings which are discussed further in Financial Condition and Liquidity. The changes in minority interest reflect the minority interest holder’s share of costs associated with the shut-down of one of Antargaz’ majority owned filling centers.
| Increase | ||||||||||||||||
| Gas Utility: | 2006 | 2005 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 724.0 | $ | 585.1 | $ | 138.9 | 23.7 | % | ||||||||
| Total margin (a) | $ | 201.1 | $ | 195.0 | $ | 6.1 | 3.1 | % | ||||||||
| Operating income | $ | 84.2 | $ | 81.6 | $ | 2.6 | 3.2 | % | ||||||||
| Income before income taxes | $ | 62.4 | $ | 65.0 | $ | (2.6 | ) | (4.0 | )% | |||||||
| System throughput - billions of cubic feet (“bcf”) | 82.6 | 84.7 | (2.1 | ) | (2.5 | )% | ||||||||||
| Degree days — % warmer than normal (b) | 8.7 | % | 2.0 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Deviation from average heating degree days based upon weather statistics provided by NOAA for 4 airports located within UGI Gas’ service territory. Fiscal 2005 degree day statistics have been restated to reflect the current-year, four-location average from the previous single location average. PNG Gas’ degree days for the period from August 24, 2006 through September 30, 2006 were not material and have been excluded. |
Temperatures in Gas Utility’s service territory based upon heating degree days were 8.7% warmer than normal in Fiscal 2006 compared with temperatures that were 2.0% warmer than normal in Fiscal 2005. Total distribution system throughput declined 2.1 bcf in Fiscal 2006 despite 2.7 bcf of throughput contributed by PNG Gas’ operations during the period from August 24, 2006 through September 30, 2006. Notwithstanding year-over-year growth in the number of UGI Gas’ firm- residential, commercial and industrial (“retail core-market”) customers, its Fiscal 2006 throughput was approximately 6% lower than in Fiscal 2005 primarily due to a reduction in retail core-market customer usage largely resulting from warmer weather and customer conservation in response to the pass-through of higher natural gas costs.
The increase in Gas Utility revenues during Fiscal 2006 is principally the result of an $86.6 million increase in UGI Gas’ retail core-market revenues reflecting higher average purchased gas cost (“PGC”) rates; $43.0 million of higher revenues from UGI Gas’ low-margin off-system sales; and, to a much lesser extent, revenues from PNG Gas subsequent to the PG Energy Acquisition. Increases or decreases in retail core-market customer revenues and cost of sales result principally from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amount included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of the pass-through nature of the PGC recovery mechanism, increases or decreases in gas costs associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $522.9 million in Fiscal 2006 compared to $390.1 million in Fiscal 2005 largely reflecting the effects of the higher PGC rates, the higher low-margin off-system sales and, to a much lesser extent, cost of gas associated with PNG Gas’ operations subsequent to the PG Energy Acquisition.
15
Financial Review(continued)
The $6.1 million increase in Gas Utility total margin in Fiscal 2006 principally reflects greater margin generated from higher average interruptible delivery service unit margins and margin from PNG Gas partially offset by lower retail core-market margin. The increase in average interruptible delivery service unit margins reflects an increase in the spread between delivered prices for natural gas and alternative fuels, principally oil. The lower gross margin from retail core-market customers largely reflects the previously mentioned lower average usage per customer.
Gas Utility operating income increased $2.6 million in Fiscal 2006 as the $6.1 million increase in total margin was partially offset by a $2.6 million increase in depreciation and amortization expense, including depreciation expense associated with PNG Gas, and slightly higher operating and administrative expenses. Fiscal 2006 operating and administrative expenses were slightly higher than in Fiscal 2005 reflecting operating and administrative expenses from PNG Gas and higher uncollectible accounts and customer assistance expense partially offset by lower distribution system expenses resulting in large part from the mild heating-season weather and lower stock-based compensation expense.
The decrease in Gas Utility income before income taxes in Fiscal 2006 reflects the increase in operating income which was more than offset by higher interest expense. The higher interest expense resulted from higher average short-term debt outstanding, higher short-term interest rates and interest on long-term debt associated with the PG Energy Acquisition.
| Increase | ||||||||||||||||
| Electric Utility: | 2006 | 2005 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 98.0 | $ | 96.1 | $ | 1.9 | 2.0 | % | ||||||||
| Total margin (a) | $ | 41.7 | $ | 43.1 | $ | (1.4 | ) | (3.2 | )% | |||||||
| Operating income | $ | 20.7 | $ | 21.6 | $ | (0.9 | ) | (4.2 | )% | |||||||
| Income before income taxes | $ | 18.2 | $ | 19.9 | $ | (1.7 | ) | (8.5 | )% | |||||||
| Distribution sales — millions of kilowatt hours (“gwh”) | 1,005.0 | 1,021.8 | (16.8 | ) | (1.6 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. gross receipts taxes of $5.3 million and $5.2 million in Fiscal 2006 and Fiscal 2005, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Consolidated Statements of Income. |
Electric Utility’s Fiscal 2006 kilowatt-hour sales decreased 1.6% principally reflecting the effects of warmer heating-season weather. Electric Utility revenues increased 2.0% principally reflecting the effects of a 3.0% increase in its Provider of Last Resort (“POLR”) electric generation rates effective January 1, 2006 partially offset by the lower kilowatt-hour sales. Electric Utility’s cost of sales increased to $51.0 million in Fiscal 2006 from $47.8 million in Fiscal 2005 as a result of higher per-unit purchased power costs partially offset by the lower kilowatt-hour sales.
Electric Utility total margin in Fiscal 2006 decreased $1.4 million principally as a result of the lower kilowatt-hour sales and the increase in per-unit purchased power costs. In accordance with the terms of its POLR settlement which became effective in June 2006, Electric Utility expects to increase its POLR rates effective January 1, 2007 which will affect all metered customers. This increase is expected to raise the average cost to residential customers by approximately 35% over the costs in effect during calendar year 2006.
Electric Utility operating income decreased $0.9 million reflecting the decrease in total margin and slightly higher depreciation and amortization expense slightly offset by lower operating and administrative expenses. The decrease in Electric Utility income before income taxes in Fiscal 2006 reflects the decrease in operating income and higher interest expense resulting from higher average short-term debt outstanding and higher short-term interest rates.
| Energy Services: | 2006 | 2005 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,414.3 | $ | 1,355.0 | $ | 59.3 | 4.4 | % | ||||||||
| Total margin (a) | $ | 86.1 | $ | 73.6 | $ | 12.5 | 17.0 | % | ||||||||
| Operating income | $ | 53.1 | $ | 37.5 | $ | 15.6 | 41.6 | % | ||||||||
| Income before income taxes | $ | 53.1 | $ | 37.5 | $ | 15.6 | 41.6 | % | ||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Energy Services revenues increased to $1,414.3 million in Fiscal 2006 from $1,355.0 million in Fiscal 2005 despite an approximate 22% decline in natural gas volumes sold. Approximately $20 million of the total increase in revenues reflects a 5.5% increase in propane volumes sold combined with higher propane selling prices resulting from higher propane product costs. The decline in natural gas volumes sold largely reflects the effects of customer losses associated with, among other things, maintenance of our credit risk management policy in a high natural gas cost environment. The increase in propane volumes sold reflects, in part, the full-year ownership of its 20 million gallon propane storage terminal located in Chesapeake, Virginia. The propane terminal was purchased through two separate transactions with ConocoPhillips Company and AmeriGas Propane in November 2005. See Note 2 to Consolidated Financial Statements for additional information regarding the acquisition.
Energy Services total margin increased $12.5 million resulting from higher natural gas margins, including winter storage and peaking services, and, to a lesser extent, higher margin from its propane storage terminal.
The increase in Energy Services operating income and income before income taxes principally reflects the previously mentioned increase in total margin and a $9.1 million gain on the March 2006 sale of its 50% ownership interest in Energy Ventures partially offset by higher operating and administrative expenses. The increased operating and administrative expenses were largely associated with electric generation. As part of the consideration for the sale of our 50% ownership interest, Energy Ventures transferred its 48-megawatt coal-fired electric generation station to UGID. As a result, UGID is no longer incurring cost of sales associated with purchasing a portion of its power needs from Energy Ventures, but is incurring operating and administrative expenses associated with the operation of the electric generation station.
Interest Expense and Income Taxes.Interest expense decreased to $123.6 million in Fiscal 2006 from $130.2 million in Fiscal 2005 principally due to $12.4 million lower interest expense largely associated with debt refinancings in International Propane and AmeriGas Propane partially offset by higher interest expense associated with greater short-term borrowings with higher interest rates in Gas Utility and Electric Utility. The Company’s effective income tax rate was 36.0% in Fiscal 2006 and 38.9% in Fiscal 2005 reflecting management’s lower estimate of taxes to be paid associated with planned repatriation of foreign earnings.
16
UGI Corporation 2006 Annual Report
PG Energy Acquisition.On January 26, 2006, UGI signed a definitive agreement to acquire the natural gas utility business of PG Energy from Southern Union Company for approximately $580 million in cash, subject to certain adjustments associated with the working capital of the acquired business. UGI assigned its rights under the Purchase and Sale Agreement to UGIPNG. The transaction was approved by the PUC and effective August 24, 2006, UGIPNG acquired the regulated assets of PG Energy. The PG Energy business serves approximately 158,000 customers in thirteen counties in northeastern Pennsylvania. The cash payment of $580 million was funded by UGI Utilities with the net proceeds from the issuance of $275 million of UGI Utilities’ bank loans under a Credit Agreement dated as of August 18, 2006 (the “Bridge Loan”), cash capital contributions from UGI of $265 million and $40 million of borrowings under its revolving credit agreement for working capital. In September 2006, UGI Utilities repaid the Bridge Loan with proceeds from the issuance of $175 million of 5.753% Senior Notes due 2016 and $100 million of 6.206% Senior Notes due 2036.
2005 Compared with 2004
Consolidated Results
| Variance– | ||||||||||||||||||||||||
| Favorable | ||||||||||||||||||||||||
| 2005 | 2004 | (Unfavorable) | ||||||||||||||||||||||
| % of Total | % of Total | |||||||||||||||||||||||
| Net | Net | Net | Net | Net | ||||||||||||||||||||
| Income | Income | Income | Income | Income | % Change | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
| AmeriGas Propane | $ | 17.6 | 9.4 | % | $ | 29.4 | 26.3 | % | $ | (11.8 | ) | (40.1 | )% | |||||||||||
| International Propane | 99.4 | 53.0 | % | 13.3 | 11.9 | % | 86.1 | N.M. | ||||||||||||||||
| Gas Utility | 39.3 | 21.0 | % | 37.9 | 34.0 | % | 1.4 | 3.7 | % | |||||||||||||||
| Electric Utility | 11.5 | 6.1 | % | 11.0 | 9.9 | % | 0.5 | 4.5 | % | |||||||||||||||
| Energy Services | 21.7 | 11.6 | % | 18.2 | 16.3 | % | 3.5 | 19.2 | % | |||||||||||||||
| Corporate & Other | (2.0 | ) | (1.1 | )% | 1.8 | 1.6 | % | (3.8 | ) | N.M. | ||||||||||||||
| Total | $ | 187.5 | 100.0 | % | $ | 111.6 | 100.0 | % | $ | 75.9 | 68.0 | % | ||||||||||||
N.M. — Variance is not meaningful.
Highlights from Fiscal 2005:
| • | Increased net income contributed by all operating business units with the exception of AmeriGas Propane which (1) incurred a $9.4 million after-tax loss on the early extinguishment of debt associated with a refinancing that reduced future annual interest expense and (2) experienced reduced volumes sold due to customer conservation and warmer weather | |
| • | International Propane’s results included Antargaz for a full fiscal year, including a winter-heating season, whereas Fiscal 2004 included Antargaz as a 19.5% equity investment from October 1, 2003 through March 31, 2004 | |
| • | International Propane’s results included the beneficial effects of unusually high retail margin per gallon and a $14.2 million net after-tax gain associated with the resolution of certain non-income related tax contingencies | |
| • | Fiscal 2005 benefited from the absence of a $9.1 million pre-tax loss recorded in Fiscal 2004 on the forward purchase of euros used to fix a portion of the euro-denominated purchase price of AGZ |
| Increase | ||||||||||||||||
| AmeriGas Propane: | 2005 | 2004 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,963.3 | $ | 1,775.9 | $ | 187.4 | 10.6 | % | ||||||||
| Total margin | $ | 743.3 | $ | 746.7 | $ | (3.4 | ) | (0.5 | )% | |||||||
| Partnership EBITDA | $ | 215.9 | $ | 255.9 | $ | (40.0 | ) | (15.6 | )% | |||||||
| Operating income | $ | 168.1 | $ | 176.0 | $ | (7.9 | ) | (4.5 | )% | |||||||
| Retail gallons sold (millions) | 1,034.9 | 1,059.1 | (24.2 | ) | (2.3 | )% | ||||||||||
| Degree days — % warmer than normal | 6.9 | % | 4.9 | % | — | — | ||||||||||
Temperatures in AmeriGas Propane’s service territories based upon heating degree days were 6.9% warmer than normal in Fiscal 2005 compared with temperatures that were 4.9% warmer than normal during Fiscal 2004. Retail propane volumes sold decreased approximately 2.3% principally due to the warmer than normal winter weather and the negative effects of customer conservation on volumes sold, which is primarily attributed to increased propane selling prices. Low-margin wholesale propane volumes sold decreased during Fiscal 2005 reflecting lower volumes sold in connection with product cost hedging activities.
Retail propane revenues increased $199.1 million reflecting a $232.9 million increase due to higher average selling prices partially offset by a $33.8 million decrease due to the lower retail volumes sold. Wholesale propane revenues decreased $19.1 million reflecting a $54.1 million decrease due to lower volumes sold partially offset by a $35.0 million increase due to higher average selling prices. The higher average retail and wholesale selling prices per gallon reflect significantly higher propane product costs. The average wholesale cost per gallon of propane during Fiscal 2005 at Mont Belvieu was approximately 28% greater than the average cost per gallon during Fiscal 2004. Total cost of sales increased to $1,220.0 million in Fiscal 2005 from $1,029.2 million in Fiscal 2004 reflecting the higher propane product costs.
Total margin decreased $3.4 million principally due to the lower retail volumes sold partially offset by higher margin from ancillary sales and services and, to a much lesser extent, slightly higher average retail propane margins per gallon. Contributing to the decline in total margin during Fiscal 2005 was lower margin generated by our AmeriGas Cylinder Exchange program (formerly its Prefilled Propane Xchange®program) due largely to competitive pricing pressures and the high cost of propane.
Partnership EBITDA during Fiscal 2005 decreased $40.0 million compared to Fiscal 2004 as a result of (1) a $33.6 million loss on early extinguishment of debt resulting from the Partnership’s refinancing of its Senior Notes in May 2005, (2) a $17.1 million increase in operating and administrative expenses and (3) the $3.4 million decrease in total margin all of which were partially offset by a $14.0 million increase in other income. A $6.3 million increase in vehicle fuel expense and a $3.7 million increase in vehicle lease costs were the most significant causes of the increase in operating and administrative expenses. Increases in maintenance and repairs, uncollectible accounts expense and general insurance expense, among others, also contributed to the higher operating and administrative expenses. The increase in other income primarily reflects higher gains on fixed asset disposals and higher customer finance charges.
Operating income decreased $7.9 million reflecting the decrease in margin and the aforementioned higher operating and administrative
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Financial Review(continued)
expenses which were partially offset by the higher other income and a $7.4 million decrease in depreciation expense. The decrease in depreciation expense is largely attributed to lower capital expenditures related to AmeriGas Cylinder Exchange.
| Increase | ||||||||||||||||
| International Propane: | 2005 | 2004 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 943.9 | $ | 333.4 | $ | 610.5 | N.M. | |||||||||
| Total margin | $ | 499.8 | $ | 171.3 | $ | 328.5 | N.M. | |||||||||
| Operating income | $ | 193.8 | $ | 20.5 | $ | 173.3 | N.M. | |||||||||
| Income (loss) from equity investees | $ | (2.6 | ) | $ | 10.6 | $ | (13.2 | ) | N.M. | |||||||
| Income before income taxes | $ | 159.0 | $ | 13.7 | $ | 145.3 | N.M. | |||||||||
N.M. — Not meaningful due to Antargaz Acquisition on March 31, 2004.
International Propane’s results of operations in Fiscal 2005 significantly increased compared to Fiscal 2004 due to the consolidation of all of Antargaz’ operations for a full twelve months, including the winter-heating season, compared to the consolidation for only six months in Fiscal 2004 which primarily included the spring and summer months. Antargaz’ revenues, total margin and operating income during Fiscal 2005 were $869.9 million, $468.4 million and $188.3 million, respectively, compared to $270.8 million, $140.7 million and $15.1 million, respectively, from April 1, 2004 to September 30, 2004. Weather in International Propane’s service territories based upon heating degree days was warmer than normal during Fiscal 2005. During Fiscal 2005, Antargaz sold approximately 338 million retail gallons of LPG while experiencing weather that was approximately 4% warmer than normal compared to 336 million retail gallons sold while experiencing weather that was 5% warmer than normal during the twelve months ended September 30, 2004.
International Propane’s revenues increased significantly during Fiscal 2005 due to the absence of revenues in Fiscal 2004 when Antargaz was an equity investment during the first six months of the fiscal year and, to a lesser extent, higher LPG selling prices. Flaga’s revenues increased $11.4 million in Fiscal 2005 due to the effects of (1) higher LPG selling prices, (2) a 7% increase in volumes sold, largely resulting from the acquisition of the Czech business of BP PLC in the fourth quarter of Fiscal 2004 and (3) the beneficial currency translation effects of a stronger euro versus the dollar.
International Propane’s increase in total margin is attributable to Antargaz’ performance. Antargaz continued to benefit from high unit margins primarily reflecting the effects of declining LPG costs during much of the Fiscal 2005 heating season. Antargaz’ LPG purchases are principally denominated in U.S. dollars. Accordingly, its LPG costs further declined during the Fiscal 2005 heating season due to the strengthening euro versus the dollar. Based upon average historical unit margins, management estimated the positive effect of Antargaz’ high unit margins and the effects of a weak dollar on our net income during Fiscal 2005 to be approximately $0.25 per diluted share. The euro was translated at a monthly average exchange rate of 1.27 dollars per euro during Fiscal 2005 compared to 1.22 dollars per euro during Fiscal 2004. Flaga’s total margin decreased slightly in Fiscal 2005 resulting from lower margins per gallon of LPG as it was unable to pass on all of the higher average LPG costs to its customers.
The increase in International Propane operating income principally reflects the inclusion of Antargaz for twelve months, including $18.8 million resulting from the reversal of certain non-income tax related reserves (see discussion in “Antargaz Tax Matters”), the previously mentioned increase in margin and the absence of a $9.1 million loss incurred in the prior year resulting from the settlement of contracts for the forward purchase of euros used to fund a portion of the purchase price of the Antargaz Acquisition partially offset by higher operating and administrative expenses and higher depreciation and amortization resulting from the Antargaz Acquisition. Flaga’s operating income increased slightly primarily reflecting the favorable effects of a stronger euro versus the dollar and a decrease in operating and administrative expenses partially offset by the decrease in its margin.
International Propane income from equity investees in Fiscal 2005 includes losses related to Antargaz’ equity investment in Geovexin compared to Fiscal 2004 which includes equity investee income from our 19.5% ownership interest in AGZ through March 31, 2004.
The increase in International Propane income before income taxes reflects the increase in operating income partially offset by the decrease in equity investee income and greater interest expense resulting from the Antargaz Acquisition.
| Gas Utility: | 2005 | 2004 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 585.1 | $ | 560.4 | $ | 24.7 | 4.4 | % | ||||||||
| Total margin | $ | 195.0 | $ | 191.5 | $ | 3.5 | 1.8 | % | ||||||||
| Operating income | $ | 81.6 | $ | 80.1 | $ | 1.5 | 1.9 | % | ||||||||
| Income before income taxes | $ | 65.0 | $ | 64.2 | $ | 0.8 | 1.2 | % | ||||||||
| System throughput — billions of cubic feet (“bcf”) | 84.7 | 82.2 | 2.5 | 3.0 | % | |||||||||||
| Degree days — % warmer than normal | 2.0 | % | 2.9 | % | — | — | ||||||||||
Weather in Gas Utility’s service territory based upon heating degree days was 2.0% warmer than normal in Fiscal 2005 compared with weather that was 2.9% warmer than normal in Fiscal 2004. Total distribution system throughput increased in Fiscal 2005 due primarily to greater interruptible delivery service volumes. Notwithstanding the volume effects of the slightly colder weather and an increase in the number of retail core-market customers, Fiscal 2005 retail core-market throughput was substantially equal to Fiscal 2004 primarily due to a reduction in customer usage per degree day. The lower usage per degree day primarily reflects the effects of conservation in response to higher natural gas prices.
The increase in Gas Utility revenues during 2005 is principally the result of a $53.4 million increase in retail core-market revenues reflecting higher average PGC rates and, to a lesser extent, the increase in throughput and higher revenues from interruptible customers. These increases were partially offset by a $37.2 million decrease in revenues from low-margin off-system sales. Gas Utility’s cost of gas was $390.1 million in Fiscal 2005 compared to $368.9 million in Fiscal 2004 reflecting the effects of the higher PGC rates partially offset by lower cost of sales associated with lower off-system sales.
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UGI Corporation 2006 Annual Report
The $3.5 million increase in Gas Utility total margin in Fiscal 2005 principally reflects greater margin generated from higher interruptible delivery service volumes and higher average interruptible delivery service unit margins. The increase in average interruptible delivery service unit margins reflects an increase in the spread between delivered prices for natural gas and alternative fuels, principally oil. Gross margin from retail core-market customers was relatively stable as lower usage per degree day was offset by an increase in the number of customers.
Gas Utility operating income increased $1.5 million in Fiscal 2005 as the $3.5 million increase in total margin and a $1.9 million increase in other income were partially offset by higher operating and administrative expenses and a $1.2 million increase in depreciation and amortization. The increase in other income is due in large part to the absence of costs recorded in Fiscal 2004 related to a regulatory claim resulting from the discontinuance of natural gas service to certain customers. Fiscal 2005 operating and administrative expenses were slightly higher than in Fiscal 2004 as a $1.9 million increase in uncollectible accounts and customer assistance expenses, the absence of environmental insurance settlements received in the prior year and higher professional services expenses were partially offset by lower injuries and damages and distribution system expenses. The increase in depreciation expense reflects the normal effects of yearly capital expenditures.
The increase in Gas Utility income before income taxes in Fiscal 2005 reflects the increase in operating income partially offset by higher interest expense resulting from higher average short-term debt outstanding and higher short-term interest rates.
| Electric Utility: | 2005 | 2004 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 96.1 | $ | 89.7 | $ | 6.4 | 7.1 | % | ||||||||
| Total margin (a) | $ | 43.1 | $ | 41.6 | $ | 1.5 | 3.6 | % | ||||||||
| Operating income | $ | 21.6 | $ | 20.9 | $ | 0.7 | 3.3 | % | ||||||||
| Income before income taxes | $ | 19.9 | $ | 18.9 | $ | 1.0 | 5.3 | % | ||||||||
| Distribution sales — millions of kilowatt hours (“gwh”) | 1,021.8 | 983.9 | 37.9 | 3.9 | % | |||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. gross receipts taxes of $5.2 and $4.8 million in Fiscal 2005 and Fiscal 2004, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Consolidated Statements of Income. |
Electric Utility’s Fiscal 2005 kilowatt-hour sales increased principally reflecting slightly colder Fiscal 2005 heating-season weather and warmer Fiscal 2005 cooling-season weather which increased sales for air conditioning. The increase in Electric Utility revenues principally reflects the effects of a 4.5% increase in its POLR electric generation rates effective January 1, 2005 and the higher kilowatt-hour sales. Electric Utility’s cost of sales increased to $47.8 million in Fiscal 2005 from $43.3 million in Fiscal 2004 as a result of higher per-unit purchased power costs and the higher sales.
Electric Utility total margin in Fiscal 2005 increased $1.5 million principally as a result of the previously mentioned increase in POLR rates and the higher kilowatt-hour sales partially offset by the increase in per-unit purchased power costs. Operating income and income before income taxes in Fiscal 2005 were higher than the prior year as the increase in total margin was partially offset by higher operating and administrative costs, principally higher distribution system maintenance expenses.
| Energy Services: | 2005 | 2004 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,355.0 | $ | 967.2 | $ | 387.8 | 40.1 | % | ||||||||
| Total margin | $ | 73.6 | $ | 55.0 | $ | 18.6 | 33.8 | % | ||||||||
| Operating income | $ | 37.5 | $ | 31.1 | $ | 6.4 | 20.6 | % | ||||||||
| Income before income taxes | $ | 37.5 | $ | 31.1 | $ | 6.4 | 20.6 | % | ||||||||
The $387.8 million increase in Energy Services revenues in Fiscal 2005 resulted primarily from (1) increased natural gas prices and to a lesser extent an approximate 2% growth in natural gas volumes sold, (2) approximately $70 million of revenues generated by Asset Management’s propane terminal, which was acquired by Energy Services in November 2004, and (3) $9.2 million of increased revenues from UGID’s electric generation. The increase in UGID’s electric generation revenues largely reflects reduced electricity generated in Fiscal 2004 resulting from a scheduled plant maintenance outage. Energy Services total margin increased $18.6 million resulting from (1) a $10.0 million increase in natural gas related margin principally due to higher income from winter storage and peaking services, (2) Asset Management’s contribution of $5.6 million of margin and (3) increased margin from UGID.
The increase in Energy Services operating income and income before income taxes principally reflects the previously mentioned increase in total margin partially offset by $9.3 million higher operating and administrative expenses, $1.7 million higher depreciation and amortization and $1.3 million lower other income. The two main drivers of the increased operating and administrative expenses were operating and administrative expenses associated with the propane terminal since its acquisition in November 2004 and higher uncollectible accounts expense. The increase in depreciation and amortization is also largely attributable to Asset Management’s propane terminal since its acquisition.
Interest Expense and Income Taxes.Interest expense increased to $130.2 million in Fiscal 2005 from $119.1 million in Fiscal 2004 principally due to $13.9 million higher International Propane interest expense as a result of the Antargaz Acquisition partially offset by lower AmeriGas Propane interest expense. The Company’s effective income tax rate was 38.9% in Fiscal 2005 and 36.6% in Fiscal 2004.
Financial Condition and Liquidity
Capitalization and Liquidity
Total cash, cash equivalents and short-term investments were $201.0 million at September 30, 2006 compared with $385.0 million at September 30, 2005. Excluding cash, cash equivalents and short-term investments that reside at UGI’s operating subsidiaries at September 30, 2006 and 2005, we had $16.6 million and $138.7 million, respectively, of cash, cash equivalents and short-term investments. The primary sources of UGI’s cash are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business segments. The decline in cash and short-term investments largely reflects $265 million in cash used to fund a portion of the $580 million purchase price of PG Energy. In August 2006, UGI entered into a revolving credit facility which expires April 30, 2007. UGI may borrow up to $50 million on the facility. At September 30, 2006, no amounts were outstanding under UGI’s revolving credit facility.
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Financial Review(continued)
AmeriGas Propane’s ability to pay dividends to UGI is largely dependent upon distributions it receives from AmeriGas Partners. At September 30, 2006, our 44% effective ownership interest in the Partnership consisted of approximately 24.5 million Common Units and an approximate 2% general partner interest. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Third Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, the “Partnership Agreement”) relating to such fiscal quarter. The ability of the Partnership to pay distributions 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 ability of the Partnership to borrow under its Credit Agreement, to refinance maturing debt and to increase its long-term debt. Some of these factors are affected by conditions beyond our control including weather, competition in markets we serve, the cost of propane and changes in capital market conditions. Based upon the number of Partnership units outstanding on September 30, 2006, the amount of Available Cash needed annually to pay the distributions on all Units is approximately $133 million.
During Fiscal 2004, Antargaz’ then-current Senior Facilities Agreement was amended to permit AGZ to pay a one-time cumulative dividend of approximately $54.4 million which was based on 50% of AGZ’s consolidated net income on a French GAAP basis for the two-year period ended March 31, 2004. The amount of dividends received in Fiscal 2005, based on AGZ’s consolidated net income on a French GAAP basis for the period April 1, 2004 through September 30, 2004, was $1.3 million. Dividends remain subject to restrictions under its new Senior Facilities Agreement. The increased amount of International Propane’s dividends and cash payments in Fiscal 2006 largely reflects the effects of Antargaz’ significantly higher earnings in 2005 and its refinancing. We estimate dividends and cash payments from International Propane in Fiscal 2007 to be approximately $50 to $55 million.
During Fiscal 2006, 2005 and 2004, AmeriGas Propane, UGI Utilities, International Propane and Energy Services paid dividends and made cash payments to UGI and its subsidiaries as follows:
| Year Ended September 30, | 2006 | 2005 | 2004 | |||||||||
| (Millions of dollars) | ||||||||||||
| AmeriGas Propane | $ | 38.3 | $ | 45.4 | $ | 39.0 | ||||||
| UGI Utilities | 37.6 | 38.5 | 45.0 | |||||||||
| International Propane | 104.6 | 22.5 | 54.4 | |||||||||
| Energy Services | 34.8 | 9.0 | 15.0 | |||||||||
| Total | $ | 215.3 | $ | 115.4 | $ | 153.4 | ||||||
Dividends and other cash distributions are available to pay dividends on UGI Common Stock and for investment purposes.
On April 25, 2006, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.17625 per share or $0.705 per share on an annual basis, which was effective with the dividend payable on July 1, 2006 to shareholders of record on June 15, 2006. On April 24, 2006, AmeriGas Propane’s Board of Directors approved an increase in its quarterly distribution rate on AmeriGas Partners Common Units to $0.58 per Common Unit ($2.32 annually) from $0.56 per Common Unit ($2.24 annually). The increase in AmeriGas Partner’s distribution was effective with the payment of its distribution for the quarter ended June 30, 2006.
AmeriGas Partners.The Partnership’s debt outstanding at September 30, 2006 totaled $933.7 million. There were no amounts outstanding under AmeriGas OLP’s Credit Agreement at September 30, 2006.
Effective November 6, 2006, AmeriGas OLP entered into a new unsecured Credit Agreement that extended the expiration date to October 15, 2011, increased the Revolving Credit Facility to $125 million, tightened certain covenants and reduced certain costs. The Acquisition Facility remains at $75 million. The remaining principal terms of the former and new Credit Agreement are similar except that the obligations under the new Credit Agreement are unsecured. The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 million to finance the purchase of propane businesses or propane business assets or, to the extent it is not so used, for working capital and general purposes, subject to restrictions in the AmeriGas Partners Senior Notes indentures. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce the amount available for borrowings, totaled $58.9 million at September 30, 2006 and is approximately the same amount issued and outstanding during all of Fiscal 2006. At September 30, 2005, issued and outstanding letters of credit under the Revolving Credit Facility totaled $56.3 million and is approximately the same amount issued and outstanding during all of Fiscal 2005. AmeriGas OLP’s short-term borrowing needs are seasonal and are typically greatest during the fall and winter heating-season months due to the need to fund higher levels of working capital. Due in part to the issuance of 2.3 million Common Units in September 2005, the Partnership generally did not need to use its Revolving Credit Facility to fund its operations during Fiscal 2006. The average daily and peak bank loan borrowings outstanding under the Credit Agreement during Fiscal 2005 were $27.9 million and $98.0 million, respectively.
AmeriGas Partners periodically issues equity securities and may continue to do so. Proceeds from the Partnership’s equity offerings have generally been used by the Partnership to reduce indebtedness and for general Partnership purposes, including funding acquisitions. AmeriGas Partners has an effective unallocated debt and equity shelf registration statement with the U.S. Securities and Exchange Commission (“SEC”) under which it may issue Common Units or Senior Notes due 2016 in underwritten public offerings.
AmeriGas OLP must meet certain financial covenants in order to borrow under its Credit Agreement including, but not limited to, a minimum interest coverage ratio, a maximum debt to EBITDA ratio and a minimum EBITDA, as defined. AmeriGas OLP’s financial covenants calculated as of September 30, 2006 permitted it to borrow up to the maximum amount available under either the former or new Credit Agreement. For a more detailed discussion of the Partnership’s credit facilities, see Note 3 to Consolidated Financial Statements. Based upon existing cash balances, cash expected to be generated from operations and borrowings available under its Credit Agreement, the Partnership’s management believes that the Partnership will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2007.
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UGI Corporation 2006 Annual Report
International Propane.At September 30, 2006, Antargaz had total debt outstanding of€383.1 million ($485.9 million). There were no amounts borrowed under the revolving portion of the Senior Facilities Agreement during the twelve months ended September 30, 2006.
In December 2005, AGZ executed a five-year floating-rate Senior Facilities Agreement that expires on March 31, 2011 and consists of (1) a€380 million variable-rate term loan and (2) a€50 million revolving credit facility. AGZ executed interest rate swap agreements to fix the rate of interest on the term loan for the duration of the loan. The proceeds from the new term loan were used to repay its€175 million term loan, to fund the redemption of its€165 million High Yield Bonds and for general purposes.
The Senior Facilities term loan has been collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivable. Antargaz’ management believes that it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2007 principally with cash generated from operations.
The Senior Facilities Agreement restricts the ability of AGZ to, among other things, incur additional indebtedness and make investments. For a more detailed discussion of Antargaz’ debt, see Note 3 to Consolidated Financial Statements.
At September 30, 2006, Flaga had total outstanding debt of€55.8 million ($70.7 million). On July 26, 2006, Flaga entered into a euro-based term loan facility in the amount of€48 million ($60.9 million) and a new working capital facility with a major European bank for up to€8 million which both expire in September 2011. Borrowings under the working capital facility commitment totaled€7.4 million ($9.4 million) at September 30, 2006. Generally, principal payments on the term loan of€3 million are due semi-annually on March 31 and September 30 each year with final payments totaling€24.0 million due in 2011. Debt issued under these agreements is subject to guarantees by UGI. Flaga’s joint venture, ZLH, has multi-currency working capital facilities that provide for borrowings up to a total of€14 million, half of which is subject to guarantees by UGI. For a more detailed discussion of Flaga’s debt, see Note 3 to Consolidated Financial Statements.
UGI Utilities.UGI Utilities’ debt outstanding totaled $728.0 million at September 30, 2006. Included in this amount is $216.0 million of bank loans outstanding. In September 2006, UGI Utilities issued $175 million of 5.753% Senior Notes due 2016 and $100 million of 6.206% Senior Notes due 2036 and used the proceeds to fund a portion of the $580 million PG Energy Acquisition purchase price.
UGI Utilities has a revolving credit agreement under which it may borrow up to a total of $350 million. This agreement is currently scheduled to expire in August 2007, but may be automatically extended by UGI Utilities to August 2011. At September 30, 2006, there was $216.0 million outstanding under the revolving credit agreement. From time to time, UGI Utilities has entered into short-term borrowings under uncommitted arrangements with major banks in order to meet liquidity needs. Short-term borrowings, including amounts outstanding under the revolving credit agreements, are classified as bank loans on the Consolidated Balance Sheets. UGI Utilities’ credit agreement requires it to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. During Fiscal 2006 and 2005 average daily bank loan borrowings were $118.4 million and $52.9 million, respectively, and peak bank loan borrowings totaled $219.0 million and $91.4 million, respectively. Peak borrowings typically occur during the peak heating season months of December and January. The increase in average and peak bank loan borrowings during Fiscal 2006 reflects in large part borrowings to fund increased working capital primarily resulting from higher natural gas prices and borrowings related to the working capital of PNG Gas.
UGI Utilities has a shelf registration statement with the SEC under which it may issue up to an additional $75 million of Medium-Term Notes or other debt securities.
Based upon cash expected to be generated from Gas Utility and Electric Utility operations, borrowings available under its revolving credit agreement and the availability of its Medium-Term Notes, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2007. For a more detailed discussion of UGI Utilities’ long-term debt and revolving credit facilities, see Note 3 to Consolidated Financial Statements.
Energy Services.UGI Energy Services, Inc. (“ESI”) has a $200 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper expiring in April 2009, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers. Prior to September 2006, ESI’s Receivables Facility was $150 million. In order to provide additional short-term liquidity during the peak heating season due to increased energy product costs, the maximum level of funding available at any one time from this facility was temporarily increased to $300 million for the period from November 1, 2005 to April 24, 2006.
Under the Receivables Facility, ESI transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of ESI and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following the provisions of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” ESI continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC. At September 30, 2006, the outstanding balance of ESFC trade receivables was $24.1 million which is net of $60.5 million that was sold to the commercial paper conduit and removed from the balance sheet. Based upon cash expected to be generated from operations and borrowings available under its Receivables Facility, management believes that Energy Services will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2007.
21
Financial Review(continued)
In addition, a major bank has committed to issue up to $50 million of standby letters of credit, secured by cash or marketable securities (“LC Facility”). At September 30, 2006, there were no letters of credit outstanding. Energy Services expects to fund the collateral requirements with borrowings under its Receivables Facility. The LC Facility expires in April 2007.
Cash Flows
Operating Activities.Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally inventories and/or accounts receivable, is generally greatest. AmeriGas Propane and UGI Utilities primarily use bank loans to satisfy their seasonal operating cash flow needs. Energy Services uses its Receivables Facility to satisfy its operating cash flow needs. Antargaz has historically been successful funding its operating cash flow needs without using its revolver.
Cash flow provided by operating activities was $279.4 million in Fiscal 2006, $437.7 million in Fiscal 2005 and $260.7 million in Fiscal 2004. The decrease in cash flow from operating activities in Fiscal 2006 largely reflects the greater cash required to fund working capital. Cash flow from operating activities before changes in operating working capital was $404.6 million in Fiscal 2006, $426.5 million in Fiscal 2005 and $333.0 million in Fiscal 2004. Changes in operating working capital used cash flow of $125.2 million in Fiscal 2006 compared with cash flow provided of $11.2 million in Fiscal 2005 and cash flow used of $72.3 million in Fiscal 2004. The increase in cash needed to fund working capital in Fiscal 2006 largely reflects changes in accounts payable due in part to the timing of inventory purchases and payments, a decrease in accrued income taxes, and changes in deferred fuel costs partially offset by a decrease in accounts receivable.
Investing Activities.Investing activity cash flow is principally affected by capital expenditures and investments in property, plant and equipment, cash paid for acquisitions of businesses, changes in short-term investments and proceeds from sales of assets. Net cash flow used in investing activities was $707.5 million in Fiscal 2006, $196.3 million in Fiscal 2005 and $412.8 million in Fiscal 2004. The increase in cash used by investing activities largely reflects the $580 million paid for the PG Energy Acquisition and, to a lesser extent, increased capital expenditures. During Fiscal 2006, we spent $191.7 million for property, plant and equipment, $158.4 million in Fiscal 2005 and $133.7 million in Fiscal 2004. The increase largely reflects greater capital expenditures by International Propane, UGI Utilities and AmeriGas Propane. Our investing activities in Fiscal 2006 also include cash proceeds from the sale of our 50% ownership interest in Energy Ventures partially offset by cash used in the formation of our 50% ownership interest in ZLH.
Financing Activities.Cash flow provided by financing activities was $299.7 million in Fiscal 2006 compared with cash flow used by financing activities of $72.6 million in Fiscal 2005 and cash flow provided by financing activities of $159.0 million in Fiscal 2004. Financing activity cash flow changes are primarily due to issuances and repayments of long-term debt, net bank loan borrowings, dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units, and proceeds from public offerings of AmeriGas Partners Common Units and issuances of UGI Common Stock.
In December 2005, Antargaz entered into a€380 million term loan. The proceeds were used to repay the existing€175 million Senior Facilities term loan, redeem its€165 million of High Yield Bonds and for general corporate purposes. Antargaz incurred a $1.4 million loss on extinguishment of debt associated with its refinancings. Also, in December 2005, UGI Utilities refinanced $50 million of its maturing 7.14% Medium-Term Notes with the proceeds from the issuance of $50 million of 5.64% Medium-Term Notes due December 2015. In January 2006, the Partnership and AP Eagle Finance Corp. issued $350 million of 7.125% Senior Notes due 2016. The proceeds of this registered public debt offering were used to refinance AmeriGas OLP’s $160 million Series A and $68.8 million Series C First Mortgage Notes, including a make-whole premium, its $35 million term loan due October 1, 2006 and $59.6 million of the Partnership’s $60 million 10% Senior Notes due 2006 pursuant to a tender offer, plus a premium. The Partnership incurred a $17.1 million loss on early extinguishment of debt associated with these refinancings. As previously mentioned, UGI Utilities issued $175 million of 5.753% Senior Notes due 2016 and $100 million of 6.206% Senior Notes due 2036, the proceeds of which were used to fund a portion of the PG Energy Acquisition. During Fiscal 2006, UGI Utilities’ net bank loan borrowings totaled $134.8 million. Included in UGI Utilities’ Fiscal 2006 net bank loan borrowings are repayments of two $35 million borrowings with maturities greater than three months and a $20 million borrowing made on June 1, 2006, which was repaid in September 2006.
During Fiscal 2006, we paid cash dividends on UGI Common Stock of $72.5 million and the Partnership paid regular quarterly distributions on all limited partner units.
UGI Utilities Pension Plan
UGI Utilities sponsors two defined benefit pension plans (“Pension Plan”) for employees of UGI Utilities, UGIPNG, UGI and certain of UGI’s other subsidiaries. As a result of the PG Energy Acquisition, we acquired the pension assets and assumed the pension liabilities related to the Employees’ Retirement Plan of Southern Union Company Pennsylvania Division (the “Division Plan”). The fair value of Pension Plan assets was $274.6 million and $211.7 million at September 30, 2006 and 2005, respectively. The increase in the fair value of the Pension Plan assets substantially reflects the fair value of the Division Plan assets acquired. At September 30, 2006 and 2005, the Pension Plan’s assets exceeded accumulated benefit obligations by $6.0 million and $7.4 million, respectively. The Company is in full compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and
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UGI Corporation 2006 Annual Report
regulations, and does not anticipate it will be required to make a contribution to the Pension Plan in Fiscal 2007. Pre-tax pension expense associated with our Pension Plan reflected in Fiscal 2006, 2005 and 2004 results was $3.1 million, $3.0 million and $1.2 million, respectively. The increase in pension expense during this period reflects the changes in the market value of Pension Plan assets, decreases in the discount rate assumption and, beginning October 2004, the expiration of the Pension Plan’s transition asset amortization. Pension expense in Fiscal 2007 is expected to be approximately $2.4 million.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions) by our business segments for Fiscal 2006, 2005 and 2004. We also provide amounts we expect to spend in Fiscal 2007. Increases in capital expeditures are in support of growth and new marketing initiatives. We expect to finance Fiscal 2007 capital expenditures principally from cash generated by operations and borrowings under our credit facilities.
| Year Ended September 30, | 2007 | 2006 | 2005 | 2004 | ||||||||||||
| (Millions of dollars) | (estimate) | |||||||||||||||
| AmeriGas Propane | $ | 79.1 | $ | 70.7 | $ | 62.6 | $ | 61.7 | ||||||||
| International Propane | 70.9 | 55.5 | 42.0 | 27.6 | ||||||||||||
| Gas Utility | 70.7 | 49.2 | 38.8 | 35.5 | ||||||||||||
| Electric Utility | 6.4 | 9.0 | 7.5 | 5.3 | ||||||||||||
| Energy Services | 11.7 | 7.0 | 6.2 | 2.9 | ||||||||||||
| Other | 2.2 | 0.3 | 1.3 | 0.7 | ||||||||||||
| Total | $ | 241.0 | $ | 191.7 | $ | 158.4 | $ | 133.7 | ||||||||
Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2006. Such obligations include scheduled repayments of long-term debt, interest on long-term fixed rate debt, operating lease payments, unconditional purchase obligations for pipeline capacity, pipeline transportation and natural gas storage services and commitments to purchase natural gas, LPG and electricity. The following table presents contractual cash obligations under agreements existing as of September 30, 2006.
| Payments Due by Period | ||||||||||||||||||||
| 1 year | 2 - 3 | 4 - 5 | After | |||||||||||||||||
| Total | or less | years | years | 5 years | ||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
| Long-term debt | $ | 1,995.7 | $ | 31.4 | $ | 92.2 | $ | 615.1 | $ | 1,257.0 | ||||||||||
| Interest on long-term fixed rate debt | 1,084.1 | 120.2 | 231.3 | 205.1 | 527.5 | |||||||||||||||
| Operating leases | 248.2 | 55.1 | 83.8 | 56.1 | 53.2 | |||||||||||||||
| AmeriGas Propane supply contracts | 20.7 | 20.7 | — | — | — | |||||||||||||||
| International Propane supply contracts | 217.4 | 116.2 | 101.2 | — | — | |||||||||||||||
| Energy Services supply contracts | 661.5 | 548.1 | 113.4 | — | — | |||||||||||||||
| Gas Utility and Electric Utility supply, storage and transportation contracts | 886.1 | 367.2 | 301.6 | 130.4 | 86.9 | |||||||||||||||
| Total | $ | 5,113.7 | $ | 1,258.9 | $ | 923.5 | $ | 1,006.7 | $ | 1,924.6 | ||||||||||
Related Party Transactions
During Fiscal 2006, 2005 and 2004, we did not enter into any related party transactions that had a material effect on our financial condition, results of operations or cash flows.
Off-Balance Sheet Arrangements
We do not have any off balance sheet arrangements that are expected to have a material effect on our financial condition, change in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Utility Regulatory Matters
As a result of Pennsylvania’s Natural Gas Choice and Competition Act (the “Gas Competition Act”), since July 1, 1999, all natural gas consumers in Pennsylvania, including residential and smaller commercial and industrial customers (“core-market customers”), have been able to purchase gas supplies from entities other than natural gas distribution companies (“NGDCs”). Under the Gas Competition Act, NGDCs, like UGI Gas and PNG Gas, continue to serve as the supplier of last resort for all core-market customers, and such sales of gas, as well as the distribution service provided by NGDCs, continue to be subject to rate regulation by the PUC. As of September 30, 2006, fewer than two percent of UGI Gas’ core-market customers purchase their gas from alternate suppliers. Currently, none of PNG Gas’ core-market customers purchase their gas from alternate suppliers.
Prior to the PG Energy Acquisition on April 13, 2006, an application was filed with the PUC seeking an increase in base rates. In an order entered on November 30, 2006, the PUC approved a settlement of the base rate proceeding of PG Energy (PNG Gas). The settlement provides for an increase in natural gas distribution base rates of $12.5 million annually or approximately 4%, effective December 2, 2006. In addition, the settlement provides PNG Gas the ability to recover up to $1.0 million of additional corporate franchise tax through the state tax adjustment surcharge mechanism.
As a result of the Electricity Generation Customer Choice and Competition Act (the “Electric Competition Act”) that became effective January 1, 1997, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. As of September 30, 2006, none of Electric Utility’s customers have chosen an alternative electricity generation supplier. Electric Utility remains the provider of last resort (“POLR”) for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service, have been established in a series of PUC approved settlements, the latest of which became effective in June 2006 (collectively, the “POLR Settlement”).
Electric Utility’s POLR service rules provide for annual shopping periods during which customers may elect to remain on POLR service or choose an alternate supplier. Customers who do not select an alternate supplier are obligated to remain on POLR service until the next shopping period. Residential customers who return to POLR service must remain on POLR
23
Financial Review(continued)
service until the date of the second open shopping period after returning. Commercial and industrial customers who return to POLR service must remain on POLR service until the next open shopping period and may, in certain circumstances, be subject to generation rate surcharges. In October 2005, Electric Utility was notified by the only alternative electric generation supplier in its service territory that it would cease providing electric generation service during the first quarter of Fiscal 2006.
Consistent with the terms of the POLR Settlement, Electric Utility’s POLR rates increased 4.5% on January 1, 2005 and 3% on January 1, 2006 (a total of 7.5% above the total rates in effect on December 31, 2004). Electric Utility is permitted to further increase its POLR rates annually in January of 2007, 2008 and 2009. Electric Utility expects to increase its POLR rates effective January 1, 2007 which will affect all metered customers. This increase is expected to raise the average cost to residential customers by approximately 35% over the costs in effect during calendar year 2006. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR service contracts with certain of its customers. The PUC is currently developing post-rate-cap POLR regulations that are expected to further define POLR service obligations and pricing.
We account for the operations of Gas Utility and Electric Utility in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated operations and that the recovery of our regulatory assets is probable.
Manufactured Gas Plants
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, UGI Utilities divested all of its utility operations other than those which now constitute UGI Gas and Electric Utility.
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. In accordance with existing regulatory practices of the PUC, PNG Gas amortizes as removal cost over a five-year period site-specific environmental investigation and remediation costs.
As a result of the acquisition of PG Energy by UGI Utilities’ wholly-owned subsidiary, UGIPNG, UGIPNG became party to a Multi-Site Remediation Consent Order and Agreement between PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform annually a specified level of activities associated with environmental investigation and remediation work at eleven currently owned properties on which MGP-related facilities were operated (“Properties”). Under the Multi-Site Agreement, UGIPNG is not required to spend more than $1.1 million in any calendar year for such environmental expenditures, including costs to perform work on the Properties. Costs related to investigation and remediation of one property formerly owned by UGIPNG are also included in this cap. The Multi-Site Agreement terminates at the end of fifteen years but may be terminated by either party at the end of any two-year period beginning with the effective date.
UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating four claims against it relating to out-of-state sites. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.
On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for 47% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 million in remediation costs and $26 million in third-party claims relating to the site and estimates that future remediation costs could
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UGI Corporation 2006 Annual Report
be as high as $2.5 million. SCE&G further asserts that it has received a demand from the United States Justice Department for natural resource damages. UGI Utilities believes that it has good defenses to this claim and is defending the suit.
In April 2003, Citizens Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District for the District of Maine. In that action, the plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18 million to clean up the river. Citizens’ third party claims have been stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March 2005 that it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of Maine related to gas plant contaminants at this site. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. The amount of Citizens’ liability has not been finally determined. The court has stayed further proceedings while the City and Citizens discuss settlement. UGI Utilities believes that it has good defenses to Citizens’ claim and to any claim that the DEP may bring to recover its costs, and is defending the Citizens’ suit.
By letter dated July 29, 2003, Atlanta Gas Light Company (“AGL”) served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8 million incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. On March 22, 2005, the trial court granted UGI Utilities’ motion for summary judgment. AGL appealed and on September 6, 2006, the Eleventh Circuit Court of Appeals affirmed the trial court’s entry of summary judgment, effectively terminating the case.
AGL previously informed UGI Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL has informed UGI Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55 million. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site.
On September 20, 2001, Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70 million.
The trial court granted UGI Utilities’ motion for summary judgment and dismissed ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court’s decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. On October 7, 2005, UGI Utilities filed for reconsideration of the panel’s order, which was denied by the Second Circuit Court of Appeals on January 17, 2006. On April 14, 2006, Utilities filed a petition requesting that the United States Supreme Court review the decision of the Second Circuit Court of Appeals. On October 2, 2006, the Supreme Court entered an order inviting the Solicitor General to file a brief expressing the views of the United States in this case.
By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend another $11 million to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10 million. KeySpan believes that the cost could be as high as $20 million. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together the “Northeast Companies”), in the United States District court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215 million and asserted that UGI Utilities is responsible for approximately $103 million of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23 million. UGI Utilities believes that it has good defenses to this claim and is defending the suit.
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Financial Review(continued)
Antargaz Tax Matters
French tax authorities levy various taxes on legal entities and individuals regularly operating a business in France which are commonly referred to collectively as “business tax.” The amount of business tax charged annually is generally dependent upon the value of the entity’s tangible fixed assets. Prior to the Antargaz Acquisition, Antargaz filed suit against French tax authorities in connection with the assessment of business tax related to the tax treatment of certain of its owned tanks at customer locations. Elf Antar France and Elf Aquitaine, now Total France, former owners of Antargaz, agreed to indemnify Antargaz for all payments that would have been due from Antargaz in respect of the tax related to its tanks for the period from January 1, 1997 through December 31, 2000. Antargaz has recorded liabilities for business taxes related to various classes of equipment. On February 4, 2005, Antargaz received a letter that was issued by the French government to the French Committee of Butane and Propane (“CFBP”), a butane/propane industry group, concerning the business tax, that eliminated the requirement for Antargaz to pay business tax associated with tanks at certain customer locations. In addition, during Fiscal 2005, resolution was reached relating to business taxes relating to a prior year. Further changes in the French government’s interpretation of the tax laws or in the tax laws themselves could have either an adverse or a favorable effect on our results of operations. Our 2005 Consolidated Statement of Income includes a pre-tax gain of $18.8 million and a net after-tax gain of $14.2 million associated with the resolution of certain business tax matters related principally to prior years.
Market Risk Disclosures
Our primary market risk exposures are (1) market prices for propane and other LPG, natural gas and electricity; (2) changes in interest rates; and (3) foreign currency exchange rates.
The risk associated with fluctuations in the prices the Partnership and our International Propane operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for propane and other energy commodities. Their profitability is sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. International Propane and the Partnership may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements, and over-the-counter derivative commodity instruments including price swap and option contracts and Antargaz hedges a portion of its future U.S. dollar denominated LPG product purchases through the use of forward foreign exchange contracts. Antargaz may also enter into other contracts, similar to those used by the Partnership. Flaga has and may use derivative commodity instruments to reduce market risk associated with a portion of its propane purchases. Currently, Flaga’s hedging activities are not material to the Company’s financial position or results of operations. Over-the-counter derivative commodity instruments utilized to hedge forecasted purchases of propane are generally settled at expiration of the contract. In order to minimize credit risk associated with its derivative commodity contracts, the Partnership monitors established credit limits with the contract counterparties. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.
Gas Utility’s tariffs contain clauses that permit recovery of substantially all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations.
Electric Utility purchases its electric power needs from electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market. Prices for electricity can be volatile especially during periods of high demand or tight supply. As previously mentioned and in accordance with POLR settlements approved by the PUC, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. In accordance with these settlements, Electric Utility increased its POLR rates by 4.5% on January 1, 2005 and by 3% on January 1, 2006 (a total of 7.5% above the total rates in effect on December 31, 2004). Electric Utility is permitted, but not required, to further increase its POLR rates annually in January of 2007, 2008 and 2009. Electric Utility expects to increase its POLR rates effective January 1, 2007 which will affect all metered customers. This increase is expected to raise the average cost to residential customers by approximately 35% over the costs in effect during calendar year 2006. Wholesale prices for electricity can be volatile, especially during periods of high demand or tight supply. Currently, Electric Utility’s fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 31, 2009. With respect to its existing fixed-price power and capacity contracts, should any of the counterparties fail to provide electric power or capacity under the terms of such contracts, any increases in the cost of replacement power or capacity could negatively impact Electric Utility results. In order to reduce this nonperformance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. From time to time, Electric Utility enters into electric price swap agreements to reduce the volatility in the cost of a portion of its anticipated electricity requirements. At September 30, 2006, Electric Utility had an electric price swap agreement associated with purchases of a portion of electricity anticipated to occur in 2007.
In order to manage market price risk relating to substantially all of Energy Services’ fixed-price sales contracts for natural gas, Energy Services purchases exchange-traded and over-the-counter natural gas futures contracts or enters into fixed-price supply arrangements. Energy Services’ exchange-traded natural gas futures contracts are guaranteed by the New York Mercantile Exchange (“NYMEX”) and have nominal credit risk. The change in market value of these contracts generally
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UGI Corporation 2006 Annual Report
requires daily cash deposits in margin accounts with brokers. At September 30, 2006, Energy Services has $11.5 million of restricted cash on deposit in such margin accounts. Although Energy Services’ fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the natural gas suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas would adversely impact Energy Services’ results. In order to reduce this risk of supplier nonperformance, Energy Services has diversified its purchases across a number of suppliers.
UGID has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its interests in electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to supply electricity under these agreements, UGID would be required to purchase such electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact the Company’s results.
Asset Management has entered and may continue to enter into fixed-price sales agreements for a portion of its propane sales. In order to manage the market price risk relating to substantially all of its fixed-price sales contracts for propane, Asset Management enters into price swap and option contracts.
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact its fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt includes borrowings under AmeriGas OLP’s Credit Agreement, UGI Utilities’ short-term borrowings and a substantial portion of Antargaz’ and Flaga’s debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. At September 30, 2006 and 2005, combined borrowings outstanding under these agreements totaled $771.1 million and $400.6 million, respectively. Antargaz has effectively fixed the interest rate on its variable-rate debt through March 2011 through the use of interest rate swaps. Excluding the fixed portion of Antargaz’ variable-rate debt, based upon weighted average borrowings outstanding under variable-rate agreements during Fiscal 2006 and Fiscal 2005, an increase in short-term interest rates of 100 basis points (1%) would have increased our interest expense by $2.1 million and $2.4 million, respectively. In November 2006, Flaga effectively fixed the rate of interest for the duration of its term loan by entering into an interest rate swap agreement.
The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of $97.5 million and $68.0 million at September 30, 2006 and 2005, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $109.1 million and $74.4 million at September 30, 2006 and 2005, respectively.
Our long-term debt is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. This debt may have an interest rate that is more or less than the refinanced debt. In order to reduce interest rate risk associated with near to medium term forecasted issuances of fixed-rate debt, we may enter into interest rate protection agreements. Our primary exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign-denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investment in foreign subsidiaries (“net investment hedges”). Realized gains or losses associated with net investments in foreign operations remain in other comprehensive income until such foreign operations are liquidated. At September 30, 2006, we have no unsettled net investment hedges. With respect to our net investments in Flaga and Antargaz, a 10% decline in the value of the euro versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value by approximately $60.4 million, which amount would be reflected in other comprehensive income.
The following table summarizes the fair values of unsettled market risk sensitive derivative instruments held at September 30, 2006 and 2005. Fair values reflect the estimated amounts that we would receive or (pay) to terminate the contracts at the reporting date based upon quoted market prices of comparable contracts at September 30, 2006. The table also includes the changes in fair value that would result if there were a ten percent adverse change in (1) the market price of propane; (2) the market price of natural gas; (3) the market price of electricity; (4) interest rates on ten-year U.S. treasury notes and the three-month Euribor and; (5) the value of the euro versus the U.S. dollar. Gas Utility’s exchange traded natural gas call option and futures contracts are excluded from the table below because any associated net gains or losses are included in Gas Utility’s PGC recovery mechanism.
| Change in | ||||||||
| Fair Value | Fair Value | |||||||
| (Millions of dollars) | ||||||||
| September 30, 2006: | ||||||||
| Propane commodity price risk | $ | (26.4 | ) | $ | (21.2 | ) | ||
| Natural gas commodity price risk | (6.0 | ) | (10.4 | ) | ||||
| Electricity commodity price risk | 5.2 | (1.3 | ) | |||||
| Interest rate risk | 14.4 | (12.9 | ) | |||||
| Foreign currency exchange rate risk | 2.4 | (13.8 | ) | |||||
| September 30, 2005: | ||||||||
| Propane commodity price risk | $ | 50.8 | $ | (19.6 | ) | |||
| Natural gas commodity price risk | (1.5 | ) | (7.2 | ) | ||||
| Electricity commodity price risk | 6.1 | (1.4 | ) | |||||
| Interest rate risk | (6.2 | ) | (3.9 | ) | ||||
| Foreign currency exchange rate risk | 7.5 | (16.3 | ) | |||||
Because the Company’s derivative instruments generally qualify as hedges under SFAS 133, we expect that changes in the fair value of derivative instruments used to manage commodity or interest rate market risk would be substantially offset by gains or losses on the associated anticipated transactions.
27
Financial Review(continued)
Critical Accounting Policies and Estimates
The preparation of financial statements and related disclosures in compliance with accounting principles generally accepted in the United States of America requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Company’s operations and the use of estimates made by management. The Company has identified the following critical accounting policies and estimates that are most important to the portrayal of the Company’s financial condition and results of operations. Changes in these policies and estimates could have a material effect on the financial statements. The application of these accounting policies and estimates necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements. Management has reviewed these critical accounting policies, and the estimates and assumptions associated with them, with the Company’s Audit Committee. In addition, management has reviewed the following disclosures regarding the application of these critical accounting policies and estimates with the Audit Committee.
Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation regarding pending claims and legal actions that arise in the normal course of our businesses. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere, and UGIPNG owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with accounting principles generally accepted in the United States of America, the Company establishes reserves for pending claims and legal actions or environmental remediation obligations when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Reasonable estimates involve management judgments based on a broad range of information and prior experience. These judgments are reviewed quarterly as more information is received and the amounts reserved are updated as necessary. Such estimated reserves may differ materially from the actual liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted.
Regulatory Assets and Liabilities.Gas Utility and Electric Utility are subject to regulation by the PUC. In accordance with SFAS 71, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2006, our regulatory assets totaled $72.9 million. See Note 1 to the Consolidated Financial Statements.
Depreciation and Amortization of Long-lived Assets.We compute depreciation on UGI Utilities’ property, plant and equipment on a straight-line basis over the average remaining lives of its various classes of depreciable property and on our other property, plant and equipment on a straight-line basis over estimated useful lives generally ranging from 2 to 40 years. We also use amortization methods and determine asset values of intangible assets other than goodwill using reasonable assumptions and projections. Changes in the estimated useful lives of property, plant and equipment and changes in intangible asset amortization methods or values could have a material effect on our results of operations. As of September 30, 2006, our net property, plant and equipment totaled $2,214.7 million and we recorded depreciation expense of $130.9 million during Fiscal 2006.
Purchase Price Allocation.From time to time, the Company enters into material business combinations. In accordance with SFAS No. 141, “Business Combinations” (“SFAS 141”), the purchase price is allocated to the various assets and liabilities acquired at their estimated fair value. Fair values of assets acquired and liabilities assumed are based upon available information and we may involve an independent third party to perform an appraisal. Estimating fair values can be a complex and judgmental area and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, if necessary, up to one year from the acquisition date to finalize the purchase price allocation.
Impairment of Goodwill.Certain of the Company’s business units have goodwill resulting from purchase business combinations. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, management must determine the reporting unit’s fair value using quoted market prices or, in the absence of quoted market prices, valuation techniques which use discounted estimates of future cash flows to be generated by the reporting unit. These cash flow estimates involve management judgments based on a broad range of information and historical results. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill which would adversely impact our results of operations. As of September 30, 2006, our goodwill totaled $1,418.2 million.
Defined Benefit Pension Plans.The costs of providing benefits under our Pension Plan is dependent on historical information such as employee age, length of service, level of compensation and the actual rate of return on plan assets. In addition, certain assumptions relating to the future are used to determine pension expense including the discount rate applied to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase, among others. Pension Plan assets are held in trust and consist principally of equity and fixed income mutual funds. Changes in plan assumptions as well as fluctuations in actual equity or bond market returns could have a material impact on future pension costs. We believe the two most critical assumptions are the expected rate of return on plan assets and the discount rate. An unfavorable change in the expected rate of return on plan assets of 50 basis points would result in an increase in
28
UGI Corporation 2006 Annual Report
pre-tax pension expense of approximately $1.4 million in Fiscal 2007. An unfavorable change in the discount rate of 50 basis points would result in an increase in pre-tax pension expense of approximately $1.6 million in Fiscal 2007.
Income Taxes.We use the asset and liability method of accounting for income taxes. Under this method, income tax expense is recognized for the amount of taxes payable or refundable for the current year and for deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. We use assumptions, judgments and estimates to determine our current provision for income taxes. We also use assumptions, judgments and estimates to determine our deferred tax assets and liabilities and any valuation allowance to be recorded against a deferred tax asset. Our assumptions, judgments and estimates relative to the current provision for income tax give consideration to current tax laws, our interpretation of current tax laws and possible outcomes of current and future audits conducted by foreign and domestic tax authorities. Changes in tax law or our interpretation of such and the resolution of current and future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. Our assumptions, judgments and estimates relative to the amount of deferred income taxes take into account estimates of the amount of future taxable income, and actual operating results in future years could render our current assumptions, judgments and estimates inaccurate. Any of the assumptions, judgments and estimates mentioned above could cause our actual income tax obligations to differ significantly from our estimates. As of September 30, 2006, our net deferred tax liabilities were $435.6 million.
Recently Issued Accounting Pronouncements
Below is a listing of recently issued accounting pronouncements by the Financial Accounting Standards Board or guidance provided by the SEC. See Note 1 to the Consolidated Financial Statements for additional discussion of such pronouncements.
| Title of Guidance | Month of Issue | |
| SFAS No. 156, “Accounting for Servicing of Financial Assets — An Amendment of FASB Statement No. 140” | March 2006 | |
| FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” | June 2006 | |
| SFAS No. 157, “Fair Value Measures” | September 2006 | |
| SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other ostretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106, and 132(R)” | September 2006 | |
| Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements in Current Year Financial Statements” | September 2006 | |
Forward-Looking Statements
Information contained in this Financial Review and elsewhere in this Annual Report may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other LPG, oil, electricity, and natural gas and the capacity to transport product to our market areas; (3) changes in domestic and foreign laws and regulations, including safety, tax and accounting matters; (4) competitive pressures from the same and alternative energy sources; (5) failure to acquire new customers thereby reducing or limiting any increase in revenues; (6) liability for environmental claims; (7) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (8) adverse labor relations; (9) large customer, counter-party or supplier defaults; (10) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas, propane and LPG; (11) political, regulatory and economic conditions in the United States and in foreign countries, including foreign currency rate fluctuations, particularly in the euro; (12) reduced access to capital markets and interest 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 except as required by the federal securities laws.
29
UGI Corporation 2006 Annual Report
Report of Management
Financial Statements
The Company’s consolidated financial statements and other financial information contained in this Annual Report are prepared by management, which is responsible for their fairness, integrity and objectivity. The consolidated financial statements and related information were prepared in accordance with accounting principles generally accepted in the United States of America and include amounts that are based on management’s best judgments and estimates.
The 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 internal control and for monitoring the independence and performance of the Company’s independent registered public accounting firm and internal auditors. The Committee is also responsible for maintaining direct channels of communication among the Board of Directors, management, and both the independent registered public accounting firm and internal auditors.
PricewaterhouseCoopers LLP, our independent registered public accounting firm, is engaged to perform audits of our consolidated financial statements. These audits are performed in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our independent registered public accounting firm was given unrestricted access to all financial records and related data, including minutes of all meetings of the Board of Directors and committees of the Board. The Company believes that all representations made to the independent registered public accounting firm during their audits were valid and appropriate.
Management’s Report on
Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing of the Company’s internal control over financial reporting, using the criteria in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”). The scope of that assessment excluded the PG Energy business acquired on August 24, 2006 by UGI Penn Natural Gas, Inc. (“UGIPNG”). As of September 30, 2006, UGIPNG’s total assets represented approximately 13% of the Company’s consolidated total assets and less than 1% of its revenues. Such exclusion is permitted based upon current guidance of the U.S. Securities and Exchange Commission.
Internal control over financial reporting refers to the process designed by, and under the supervision of, our Chief Executive Officer and Chief Financial Officer, to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes policies and procedures that, among other things, 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. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changing conditions, or the degree of compliance with the policies or procedures may deteriorate.
Based on its assessment, management has concluded that the Company maintained effective internal control over financial reporting as of September 30, 2006, based on the COSO Framework. Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2006, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which follows.
Lon R. Greenberg
Chief Executive Officer
Anthony J. Mendicino
Chief Financial Officer
Michael J. Cuzzolina
Chief Accounting Officer
30
UGI Corporation 2006 Annual Report
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of UGI Corporation:
We have completed integrated audits of UGI Corporation’s 2006 and 2005 consolidated financial statements and of its internal control over financial reporting as of September 30, 2006 and an audit of its 2004 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated Financial Statements
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of UGI Corporation and its subsidiaries at September 30, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements effective October 1, 2005, the Company adopted Statement of Financial Accounting Standards No. 123(R) “Share-Based Payment (revised 2004).”
Internal Control over Financial Reporting
Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that the Company maintained effective internal control over financial reporting as of September 30, 2006 based on criteria established in Internal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded the PG Energy business from its assessment of internal control over financial reporting as of September 30, 2006 because it was acquired by the Company in a purchase business combination on August 24, 2006. We have also excluded the PG Energy business from our audit of internal control over financial reporting. The PG Energy business is a wholly-owned subsidiary whose total assets represent approximately 13% of total consolidated assets and total revenues represent less than 1% of total consolidated revenues as of and for the year ended September 30, 2006.
Philadelphia, Pennsylvania
December 8, 2006
31
Consolidated Balance Sheets
(Millions of dollars)
| September 30, | ||||||||
| 2006 | 2005 | |||||||
Assets | ||||||||
Current Assets | ||||||||
| Cash and cash equivalents | $ | 186.2 | $ | 310.1 | ||||
| Restricted cash | 14.2 | 4.9 | ||||||
| Short-term investments (at cost, which approximates fair value) | 0.6 | 70.0 | ||||||
| Accounts receivable (less allowances for doubtful accounts of $38.0 and $29.2, respectively) | 387.2 | 421.8 | ||||||
| Accrued utility revenues | 16.6 | 10.4 | ||||||
| Inventories | 340.4 | 239.9 | ||||||
| Deferred income taxes | 55.9 | 24.4 | ||||||
| Income taxes recoverable | 11.0 | — | ||||||
| Derivative financial instruments | 5.8 | 60.3 | ||||||
| Prepaid expenses and other current assets | 22.7 | 30.5 | ||||||
| Total current assets | 1,040.6 | 1,172.3 | ||||||
Property, Plant and Equipment | ||||||||
| AmeriGas Propane | 1,211.8 | 1,162.8 | ||||||
| International Propane | 588.0 | 541.8 | ||||||
| UGI Utilities | 1,553.9 | 985.7 | ||||||
| Other | 107.6 | 99.3 | ||||||
| 3,461.3 | 2,789.6 | |||||||
| Accumulated depreciation and amortization | (1,246.6 | ) | (986.9 | ) | ||||
| Net property, plant, and equipment | 2,214.7 | 1,802.7 | ||||||
Other Assets | ||||||||
| Goodwill | 1,418.2 | 1,231.2 | ||||||
| Intangible assets (less accumulated amortization of $62.8 and $45.4, respectively) | 163.3 | 172.6 | ||||||
| Utility regulatory assets | 72.9 | 61.3 | ||||||
| Investments in equity investees | 58.2 | 12.8 | ||||||
| Other assets | 112.6 | 118.6 | ||||||
| Total assets | $ | 5,080.5 | $ | 4,571.5 | ||||
See accompanying notes to consolidated financial statements.
32
UGI Corporation 2006 Annual Report
| September 30, | ||||||||
| 2006 | 2005 | |||||||
Liabilities and Stockholders’ Equity | ||||||||
Current Liabilities | ||||||||
| Current maturities of long-term debt | $ | 31.9 | $ | 252.0 | ||||
| UGI Utilities bank loans | 216.0 | 81.2 | ||||||
| Other bank loans | 9.4 | 16.2 | ||||||
| Accounts payable | 373.0 | 399.7 | ||||||
| Employee compensation and benefits accrued | 75.4 | 78.6 | ||||||
| Dividends and interest accrued | 31.1 | 40.8 | ||||||
| Income taxes accrued | — | 40.1 | ||||||
| Deposits and advances | 145.0 | 124.1 | ||||||
| Derivative financial instruments | 27.6 | 7.8 | ||||||
| Other current liabilities | 117.2 | 122.6 | ||||||
| Total current liabilities | 1,026.6 | 1,163.1 | ||||||
Debt and Other Liabilities | ||||||||
| Long-term debt | 1,965.0 | 1,392.5 | ||||||
| Deferred income taxes | 491.5 | 477.5 | ||||||
| Deferred investment tax credits | 6.8 | 7.2 | ||||||
| Other noncurrent liabilities | 351.5 | 327.3 | ||||||
| Total liabilities | 3,841.4 | 3,367.6 | ||||||
| Commitments and contingencies (Note 10) | ||||||||
| Minority interests, principally in AmeriGas Partners | 139.5 | 206.3 | ||||||
Common Stockholders’ Equity | ||||||||
| Common Stock, without par value | ||||||||
| (authorized - - 300,000,000 shares; issued — 115,152,994 shares) | 807.5 | 793.6 | ||||||
| Retained earnings | 370.0 | 266.3 | ||||||
| Accumulated other comprehensive (loss) income | (3.8 | ) | 16.5 | |||||
| 1,173.7 | 1,076.4 | |||||||
| Treasury stock, at cost | (74.1 | ) | (78.8 | ) | ||||
| Total common stockholders’ equity | 1,099.6 | 997.6 | ||||||
| Total liabilities and stockholders’ equity | $ | 5,080.5 | $ | 4,571.5 | ||||
33
UGI Corporation 2006 Annual Report
Consolidated Statements of Income
(Millions of dollars, except per share amounts)
(Millions of dollars, except per share amounts)
| Year Ended September 30, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
Revenues | ||||||||||||
| AmeriGas Propane | $ | 2,119.3 | $ | 1,963.3 | $ | 1,775.9 | ||||||
| International Propane | 945.5 | 943.9 | 333.4 | |||||||||
| UGI Utilities | 822.0 | 681.2 | 650.1 | |||||||||
| Energy Services and other | 1,334.2 | 1,300.3 | 1,025.3 | |||||||||
| 5,221.0 | 4,888.7 | 3,784.7 | ||||||||||
Costs and Expenses | ||||||||||||
| Cost of sales | 3,657.9 | 3,306.0 | 2,551.0 | |||||||||
| Operating and administrative expenses | 969.2 | 966.6 | 767.8 | |||||||||
| Utility taxes other than income taxes | 14.3 | 13.4 | 12.5 | |||||||||
| Depreciation and amortization | 148.7 | 146.4 | 132.3 | |||||||||
| Other income, net | (36.8 | ) | (46.7 | ) | (10.2 | ) | ||||||
| 4,753.3 | 4,385.7 | 3,453.4 | ||||||||||
Operating Income | 467.7 | 503.0 | 331.3 | |||||||||
| Income (loss) from equity investees | (2.2 | ) | (2.6 | ) | 11.3 | |||||||
| Loss on extinguishments of debt | (18.5 | ) | (33.6 | ) | — | |||||||
| Interest expense | (123.6 | ) | (130.2 | ) | (119.1 | ) | ||||||
Income before Income Taxes and Minority Interests | 323.4 | 336.6 | 223.5 | |||||||||
| Income taxes | (98.5 | ) | (119.2 | ) | (64.4 | ) | ||||||
| Minority interests, principally in AmeriGas Partners | (48.7 | ) | (29.9 | ) | (47.5 | ) | ||||||
Net Income | $ | 176.2 | $ | 187.5 | $ | 111.6 | ||||||
Earnings Per Common Share: | ||||||||||||
| Basic | $ | 1.67 | $ | 1.81 | $ | 1.18 | ||||||
| Diluted | $ | 1.65 | $ | 1.77 | $ | 1.15 | ||||||
Average Common Shares Outstanding (millions): | ||||||||||||
| Basic | 105.455 | 103.877 | 94.616 | |||||||||
| Diluted | 106.727 | 105.723 | 96.682 | |||||||||
See accompanying notes to consolidated financial statements.
34
UGI Corporation 2006 Annual Report
Consolidated Statements of Cash Flows
(Millions of dollars)
(Millions of dollars)
| Year Ended September 30, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
Cash Flows From Operating Activities | ||||||||||||
| Net income | $ | 176.2 | $ | 187.5 | $ | 111.6 | ||||||
| Reconcile to net cash provided by operating activities: | ||||||||||||
| Depreciation and amortization | 148.7 | 146.4 | 132.3 | |||||||||
| Minority interests principally in AmeriGas Partners | 48.7 | 29.9 | 47.5 | |||||||||
| Deferred income taxes, net | 7.4 | 12.1 | 3.0 | |||||||||
| Provision for uncollectible accounts | 25.0 | 25.1 | 17.3 | |||||||||
| Loss on extinguishments of debt | 18.5 | 33.6 | — | |||||||||
| Tax benefit on exercise of stock options | — | 10.2 | 2.9 | |||||||||
| Stock-based compensation expense | 6.9 | — | — | |||||||||
| Net change in settled accumulated other comprehensive income | (37.1 | ) | (3.8 | ) | 9.0 | |||||||
| Other, net | 10.3 | (14.5 | ) | 9.4 | ||||||||
| Net change in: | ||||||||||||
| Accounts receivable and accrued utility revenues | 34.8 | (81.5 | ) | 4.9 | ||||||||
| Inventories | (31.9 | ) | (29.4 | ) | (39.4 | ) | ||||||
| Deferred fuel costs | (17.9 | ) | 9.5 | (6.9 | ) | |||||||
| Accounts payable | (61.1 | ) | 70.0 | (49.7 | ) | |||||||
| Other current assets and liabilities | (49.1 | ) | 42.6 | 18.8 | ||||||||
| Net cash provided by operating activities | 279.4 | 437.7 | 260.7 | |||||||||
Cash Flows From Investing Activities | ||||||||||||
| Expenditures for property, plant and equipment | (191.7 | ) | (158.4 | ) | (133.7 | ) | ||||||
| Acquisitions of businesses, net of cash acquired | (590.4 | ) | (33.3 | ) | (308.6 | ) | ||||||
| Net proceeds from disposals of assets | 8.8 | 16.7 | 11.5 | |||||||||
| Net proceeds from sale of Energy Ventures | 13.3 | — | — | |||||||||
| Investments in ZLH | (10.1 | ) | — | — | ||||||||
| Decrease (increase) in short-term investments | 69.4 | (20.0 | ) | — | ||||||||
| Increase in restricted cash | (9.3 | ) | (4.9 | ) | — | |||||||
| Other, net | 2.5 | 3.6 | 18.0 | |||||||||
| Net cash used by investing activities | (707.5 | ) | (196.3 | ) | (412.8 | ) | ||||||
Cash Flows From Financing Activities | ||||||||||||
| Dividends on UGI Common Stock | (72.5 | ) | (67.4 | ) | (56.3 | ) | ||||||
| Distributions on AmeriGas Partners publicly held Common Units | (73.6 | ) | (66.6 | ) | (62.4 | ) | ||||||
| Issuances of debt | 1,145.4 | 576.0 | 30.1 | |||||||||
| Repayments of debt | (918.3 | ) | (544.4 | ) | (77.4 | ) | ||||||
| Increase (decrease) in UGI Utilities bank loans with maturities of three months or less | 204.8 | (49.7 | ) | 20.2 | ||||||||
| Other bank loans (decrease) increase | 2.2 | (0.3 | ) | 0.1 | ||||||||
| Redemption of UGI Utilities preferred shares subject to mandatory redemption | — | (20.0 | ) | — | ||||||||
| Excess tax benefits from equity-based payment arrangements | 0.9 | — | — | |||||||||
| Issuances of AmeriGas Partners Common Units | — | 72.7 | 51.2 | |||||||||
| Issuances of UGI Common Stock | 10.8 | 27.1 | 254.1 | |||||||||
| Repurchases of UGI Common Stock | — | — | (0.6 | ) | ||||||||
| Net cash provided (used) by financing activities | 299.7 | (72.6 | ) | 159.0 | ||||||||
Effect of Exchange Rate Changes on Cash | 4.5 | (8.3 | ) | 0.6 | ||||||||
| Cash and cash equivalents (decrease) increase | $ | (123.9 | ) | $ | 160.5 | $ | 7.5 | |||||
Cash and Cash Equivalents: | ||||||||||||
| End of year | $ | 186.2 | $ | 310.1 | $ | 149.6 | ||||||
| Beginning of year | 310.1 | 149.6 | 142.1 | |||||||||
| Decrease (increase) | $ | (123.9 | ) | $ | 160.5 | $ | 7.5 | |||||
See accompanying notes to consolidated financial statements.
35
UGI Corporation 2006 Annual Report
Consolidated Statements of Stockholders’ Equity
(Millions of dollars, except per share amounts)
(Millions of dollars, except per share amounts)
| Accumulated | Notes | |||||||||||||||||||||||
| Other | Receivable | |||||||||||||||||||||||
| Common | Retained | Comprehensive | from | Treasury | ||||||||||||||||||||
| Stock | Earnings | Income (Loss) | Employees | Stock | Total | |||||||||||||||||||
Balance September 30, 2003 | $ | 511.7 | $ | 90.9 | $ | 4.7 | $ | (0.4 | ) | $ | (108.2 | ) | $ | 498.7 | ||||||||||
| Net income | 111.6 | 111.6 | ||||||||||||||||||||||
| Net gain on derivative instruments (net of tax of $15.0) | 22.6 | 22.6 | ||||||||||||||||||||||
| Reclassification of net gains on derivative instruments (net of tax of $6.9) | (10.6 | ) | (10.6 | ) | ||||||||||||||||||||
| Foreign currency translation adjustments (net of tax of $0.9) | 5.9 | 5.9 | ||||||||||||||||||||||
| Comprehensive income | 111.6 | 17.9 | 129.5 | |||||||||||||||||||||
| Cash dividends on Common Stock ($0.60 per share) | (56.3 | ) | (56.3 | ) | ||||||||||||||||||||
| Common Stock issued: | ||||||||||||||||||||||||
| Public offering | 239.6 | 239.6 | ||||||||||||||||||||||
| Employee and director plans | 4.6 | 10.3 | 14.9 | |||||||||||||||||||||
| Dividend reinvestment plan | 1.3 | 1.2 | 2.5 | |||||||||||||||||||||
| Net gain in connection with issuances of units by AmeriGas Partners (net of tax of $6.6) | 5.6 | 5.6 | ||||||||||||||||||||||
| Common Stock reacquired | (0.6 | ) | (0.6 | ) | ||||||||||||||||||||
| Payments on notes receivable from employees | 0.2 | 0.2 | ||||||||||||||||||||||
Balance September 30, 2004 | 762.8 | 146.2 | 22.6 | (0.2 | ) | (97.3 | ) | 834.1 | ||||||||||||||||
| Net income | 187.5 | 187.5 | ||||||||||||||||||||||
| Net gain on derivative instruments (net of tax of $7.9) | 12.9 | 12.9 | ||||||||||||||||||||||
| Reclassification of net gains on derivative instruments (net of tax of $2.1) | (2.7 | ) | (2.7 | ) | ||||||||||||||||||||
| Foreign currency translation adjustments (net of tax of $6.5) | (16.3 | ) | (16.3 | ) | ||||||||||||||||||||
| Comprehensive income (loss) | 187.5 | (6.1 | ) | 181.4 | ||||||||||||||||||||
| Cash dividends on Common Stock ($0.65 per share) | (67.4 | ) | (67.4 | ) | ||||||||||||||||||||
| Common Stock issued: | ||||||||||||||||||||||||
| Employee and director plans | 17.2 | 17.7 | 34.9 | |||||||||||||||||||||
| Dividend reinvestment plan | 1.6 | 0.8 | 2.4 | |||||||||||||||||||||
| Net gain in connection with issuances of units by AmeriGas Partners (net of tax of $16.0) | 12.0 | 12.0 | ||||||||||||||||||||||
| Payments on notes receivable from employees | 0.2 | 0.2 | ||||||||||||||||||||||
Balance September 30, 2005 | 793.6 | 266.3 | 16.5 | — | (78.8 | ) | 997.6 | |||||||||||||||||
| Net income | 176.2 | 176.2 | ||||||||||||||||||||||
| Net loss on derivative instruments (net of tax of $43.7) | (63.7 | ) | (63.7 | ) | ||||||||||||||||||||
| Reclassification of net losses on derivative instruments (net of tax of $13.2) | 17.5 | 17.5 | ||||||||||||||||||||||
| Foreign currency translation adjustments (net of tax of $8.1) | 25.9 | 25.9 | ||||||||||||||||||||||
| Comprehensive income (loss) | 176.2 | (20.3 | ) | 155.9 | ||||||||||||||||||||
| Cash dividends on Common Stock ($0.69 per share) | (72.5 | ) | (72.5 | ) | ||||||||||||||||||||
| Common Stock issued: | ||||||||||||||||||||||||
| Employee and director plans | 5.6 | 3.8 | 9.4 | |||||||||||||||||||||
| Dividend reinvestment plan | 1.4 | 0.9 | 2.3 | |||||||||||||||||||||
| Stock-based compensation expense | 6.9 | 6.9 | ||||||||||||||||||||||
Balance September 30, 2006 | $ | 807.5 | $ | 370.0 | $ | (3.8 | ) | $ | — | $ | (74.1 | ) | $ | 1,099.6 | ||||||||||
See accompanying notes to consolidated financial statements.
36
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 1 — Organization and Significant Accounting Policies
Organization.UGI Corporation (“UGI”) is a holding company that owns and operates natural gas and electric utilities, electricity generation, retail propane distribution, energy marketing and related businesses in the United States. Through foreign subsidiaries and joint-venture affiliates, UGI also distributes liquefied petroleum gases (“LPG”) in France, central and eastern Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”
We conduct a national propane distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”) and its principal operating subsidiaries AmeriGas Propane, L.P. (“AmeriGas OLP”) and AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (“Eagle OLP”). AmeriGas Partners, AmeriGas OLP and Eagle OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. AmeriGas OLP and Eagle OLP (collectively referred to as “the Operating Partnerships”) comprise the largest retail propane distribution business in the United States serving residential, commercial, industrial, motor fuel and agricultural customers from locations in 46 states. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30, 2006, the General Partner and its wholly owned subsidiary Petrolane Incorporated (“Petrolane”) collectively held a 1% general partner interest and 42.7% limited partner interest in AmeriGas Partners, and an effective 44.3% ownership interests in AmeriGas OLP and Eagle OLP.
Our limited partnership interest in AmeriGas Partners comprises 24,525,004 Common Units. The remaining 56.3% interest in AmeriGas Partners comprises 32,272,101 publicly held Common Units representing limited partner interests.
The Partnership has no employees. Employees of the General Partner conduct, direct and manage the activities of AmeriGas Partners and AmeriGas OLP. The General Partner also provides management and administrative services to AmeriGas Eagle Holdings, Inc., the general partner of Eagle OLP, under a management services agreement. The General Partner is reimbursed monthly for all direct and indirect expenses it incurs on behalf of the Partnership including all General Partner employee compensation costs and a portion of UGI employee compensation and administrative costs. Although the Partnership’s operating income represents a significant portion of our consolidated operating income, the Partnership’s impact on our consolidated net income is considerably less due to the Partnership’s significant minority interest.
Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) (1) conducts an LPG distribution business in France; (2) conducts LPG distribution businesses and participates in an LPG joint-venture business in central and eastern Europe (collectively, “Flaga”); and (3) participates in an LPG joint-venture business in the Nantong region of China. We refer to our foreign operations collectively as “International Propane.” Our LPG distribution business in France is conducted through Antargaz, a subsidiary of AGZ Holding (“AGZ”), and its operating subsidiaries (collectively, “Antargaz”). During 2006, we formed a Dutch private limited liability company, UGI International Holdings, B.V. to hold our interests in Antargaz and Flaga.
Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary, UGI Utilities, Inc. and its subsidiary, UGI Penn Natural Gas, Inc. (“UGIPNG”). UGI Utilities, Inc. owns and operates (1) a natural gas distribution utility in eastern Pennsylvania (“UGI Gas”), (2) a natural gas distribution utility in northeastern Pennsylvania (“PNG Gas”) which was acquired effective August 24, 2006, and (3) an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). On August 24, 2006, UGI Utilities, Inc., through UGIPNG, acquired the natural gas businesses of PG Energy, an operating division of Southern Union Company (see Note 2). UGI Gas and PNG Gas (collectively, “Gas Utility”) are subject to regulation by the Pennsylvania Public Utility Commission (“PUC”). The term “UGI Utilities” is used sometimes as abbreviated reference to UGI Utilities, Inc. or UGI Utilities, Inc. and UGIPNG.
In addition, Enterprises conducts an energy marketing business primarily in the eastern region of the United States through its wholly owned first- and second-tier subsidiaries (collectively, “Energy Services”). Energy Services’ wholly owned subsidiary UGI Development Company (“UGID”) and UGID’s subsidiaries own and operate a 48-megawatt coal-fired electric generation station and a 6% interest in Pennsylvania-based electric generation assets. In addition, Energy Services’ wholly owned subsidiary UGI Asset Management, Inc. through its subsidiary Atlantic Energy, Inc. (collectively, “Asset Management”) owns a propane storage terminal located in Chesapeake, Virginia. Through other subsidiaries, Enterprises owns and operates heating, ventilation, air-conditioning, refrigeration and electrical contracting services businesses in the Middle Atlantic States (“HVAC/R”).
UGI was incorporated in Pennsylvania in 1991. UGI is not subject to regulation by the PUC. UGI is a “holding company” under the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). PUHCA 2005 and the implementing regulations of the Federal Energy Regulatory Commission (“FERC”) give FERC access to certain holding company books and records and impose certain accounting, record-keeping, and reporting requirements on holding companies. PUHCA 2005 also provides state utility regulatory commissions with access to holding company books and records in certain circumstances. Pursuant to a waiver granted in accordance with FERC’s regulations on the basis of UGI’s status as a single-state holding company system, UGI is not subject to certain of the accounting, record-keeping, and reporting requirements prescribed by FERC’s regulations.
Consolidation Principles.The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We eliminate all significant intercompany accounts and transactions when we consolidate. We report the public’s limited partner interests in the Partnership and
37
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 1 continued
other parties’ interests in our consolidated, but less than 100% owned, subsidiaries of Antargaz, as minority interests. Entities in which we own 50% or less and in which we exercise significant influence over operating and financial policies are accounted for by the equity method (see Note 15). Effective with our March 2004 acquisition of the remaining 80.5% ownership interests in AGZ and our November 2004 acquisition of the remaining 50% ownership interest in Atlantic Energy, Inc., we began consolidating all of their operations (see Note 2). Investments in equity investees are included in other assets in the Consolidated Balance Sheets. Gains resulting from issuances and sales of AmeriGas Partners’ Common Units are recorded as increases to common stockholders’ equity with corresponding decreases to minority interests in accordance with U.S. Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin No. 51, “Accounting for Sales of Common Stock by a Subsidiary.” In addition, we record deferred income tax liabilities with a corresponding reduction in common stockholders’ equity associated with such gains (see Note 14).
Reclassifications.We have reclassified certain prior-year balances to conform to the current-year presentation.
Use of Estimates.We make estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States of America. These estimates and assumptions affect the reported amounts of assets and liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.
Regulated Utility Operations.We account for the operations of Gas Utility and Electric Utility in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated utility operations and that the recovery of our regulatory assets is probable.
Regulatory assets and liabilities associated with Gas Utility and Electric Utility operations included in our accompanying balance sheets at September 30 comprise the following:
| 2006 | 2005 | |||||||
| Regulatory assets: | ||||||||
| Income taxes recoverable | $ | 64.3 | $ | 58.6 | ||||
| Postretirement benefits | 5.4 | 1.7 | ||||||
| Other | 3.2 | 1.0 | ||||||
| Total regulatory assets | $ | 72.9 | $ | 61.3 | ||||
| Regulatory liabilities: | ||||||||
| Postretirement benefits | $ | 3.8 | $ | 2.8 | ||||
| Deferred fuel costs | 12.2 | 17.4 | ||||||
| Total regulatory liabilities | $ | 16.0 | $ | 20.2 | ||||
UGI Utilities’ regulatory liabilities relating to postretirement benefits and deferred fuel costs are included in “other noncurrent liabilities” and “other current liabilities,” respectively, on the Consolidated Balance Sheets. UGI Utilities does not recover a rate of return on its regulatory assets.
Derivative Instruments.SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. For a detailed description of the derivative instruments we use, our objectives for using them, and related supplemental information required by SFAS 133, see Note 11.
Consolidated Statements of Cash Flows.We define cash equivalents as 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. Restricted cash represents cash deposited in our natural gas futures accounts to satisfy margin requirements.
We paid interest totaling $129.3 in 2006, $130.6 in 2005 and $117.7 in 2004. We paid income taxes totaling $142.6 in 2006, $54.7 in 2005 and $70.2 in 2004.
Revenue Recognition.We recognize revenues from the sale of propane and other LPG principally as product is delivered to customers. Revenue from the sale of appliances and equipment is recognized at the time of sale or installation. We record UGI Utilities’ regulated revenues for service provided to the end of each month which includes an accrual for certain unbilled amounts based upon estimated usage. We reflect the impact of UGI Utilities’ rate increases or decreases at the time they become effective. Energy Services records revenues when energy products are delivered to customers.
Inventories.Our inventories are stated at the lower of cost or market. We determine cost using an average cost method for natural gas, propane and other LPG, specific identification for appliances and the first-in, first-out (“FIFO”) method for all other inventories.
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UGI Corporation 2006 Annual Report
Earnings Per Common Share.Basic earnings per share reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for 2006, 2005 and 2004:
| 2006 | 2005 | 2004 | ||||||||||
| Denominator (millions of shares): | ||||||||||||
| Average common shares outstanding for basic computation | 105.455 | 103.877 | 94.616 | |||||||||
| Incremental shares issuable for stock options and awards | 1.272 | 1.846 | 2.066 | |||||||||
| Average common shares outstanding for diluted computation | 106.727 | 105.723 | 96.682 | |||||||||
Income Taxes.AmeriGas Partners and the Operating Partnerships are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on our share of (1) the Partnership’s current taxable income or loss and (2) the differences between the book and tax bases of the Partnership’s assets and liabilities. The Operating Partnerships have subsidiaries which operate in corporate form and are directly subject to federal income taxes.
Gas Utility and Electric Utility record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. They also record a deferred income tax liability for tax benefits that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to 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 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.The amounts we assign to property, plant and equipment of businesses we acquire are based upon estimated fair value at date of acquisition. When Gas Utility and Electric Utility retire depreciable utility plant and equipment, we charge the original cost, net of removal costs and salvage value, to accumulated depreciation for financial accounting purposes. When our unregulated businesses retire or otherwise dispose of plant and equipment, we remove the cost and accumulated depreciation from the appropriate accounts and any resulting gain or loss is recognized in “Other income, net” in the Consolidated Statements of Income. We record depreciation expense for UGI Utilities’ plant and equipment on a straight-line method over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.5% in 2006, 2.4% in 2005 and 2.3% in 2004. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.8% in 2006, 2.9% in 2005 and 2.8% in 2004. We compute depreciation expense on plant and equipment associated with our LPG operations using the straight-line method over estimated service lives generally ranging from 15 to 40 years for buildings and improvements; 7 to 40 years for storage and customer tanks and cylinders; and 2 to 12 years for vehicles, equipment, and office furniture and fixtures. We compute depreciation expense on plant and equipment associated with our electric generation assets on a straight-line basis over 25 years. Depreciation expense was $130.9 in 2006, $127.8 in 2005 and $119.9 in 2004.
Costs to install Partnership-owned tanks, net of amounts billed to customers, are capitalized and amortized over the estimated period of benefit not exceeding ten years.
Intangible Assets.Intangible assets comprise the following at September 30:
| 2006 | 2005 | |||||||
| Goodwill (not subject to amortization) | $ | 1,418.2 | $ | 1,231.2 | ||||
| Other intangible assets: | ||||||||
| Customer relationships, noncompete agreements and other | 183.0 | $ | 177.2 | |||||
| Trademark (not subject to amortization) | 43.1 | 40.8 | ||||||
| Gross carrying amount | 226.1 | 218.0 | ||||||
| Accumulated amortization | (62.8 | ) | (45.4 | ) | ||||
| Net carrying amount | $ | 163.3 | $ | 172.6 | ||||
The changes in the carrying amount of intangible assets during the year ended September 30, 2006 principally reflects business acquisitions and the effects of foreign currency translation.
We amortize customer relationship and noncompete agreement intangibles over their estimated periods of benefit which do not exceed 15 years. Amortization expense of intangible assets was $16.5 in 2006, $16.9 in 2005 and $11.1 in 2004 including amortization expense associated with customer contracts recorded in cost of sales. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2007 — $15.7; Fiscal 2008 — $15.4; Fiscal 2009 — $14.7; Fiscal 2010 — $13.3; Fiscal 2011 — $12.7.
In accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), we amortize intangible assets over their useful lives unless we determined their lives to be indefinite. Goodwill and other intangible assets with indefinite lives are not amortized but are subject to tests for impairment at least annually. SFAS 142 requires that we perform impairment tests annually or more frequently if events or circumstances indicate that the value of goodwill might be impaired. When performing our impairment tests, we use quoted market prices or, in the absence of quoted market prices, valuation techniques which use discounted estimates of future cash flows. No provisions for goodwill impairments were recorded during 2006, 2005 or 2004.
Stock-Based Compensation.Effective October 1, 2005, the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”). Prior to October 1, 2005, as permitted, we applied the provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), in recording compensation expense for
39
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 1 continued
grants of stock, stock options and other equity instruments (“Units”) to employees. Under APB 25, the Company did not record any compensation expense for stock options, but provided the required pro forma disclosures as if we had determined compensation expense under the fair value method prescribed by the provisions of SFAS No. 123 (prior to its revision). As permitted by SFAS 123R, under the modified prospective approach, effective October 1, 2005, we began recording compensation expense for awards that were not vested as of that date and we did not restate any prior periods. The adoption of SFAS 123R resulted in pre-tax stock option expense of $3.8 during the twelve months ended September 30, 2006. SFAS 123R also requires the calculation of an accumulated pool of tax windfalls using historical data from the effective date of SFAS No. 123 (prior to its revision). We have calculated a tax windfall pool using the shortcut method and any future tax shortfalls related to equity-based compensation will be charged against common stock up to the amount of the tax windfall pool.
In accordance with SFAS 123R, all of our equity-based compensation cost is measured on grant date, date of modification, if any, or at the end of the period based upon the fair value of that award and is recognized in the income statement over the requisite service period. For periods prior to and subsequent to the adoption of SFAS 123R, we used the Black-Scholes option-pricing model to estimate the fair value of each option. Equity-based awards that can be settled at our option in cash or shares of UGI Common Stock are presented in the Consolidated Balance Sheets as liabilities. Effective in June 2006, the Company modified the settlement terms of certain awards granted to 28 employees January 1, 2006 which did not impact the number of the awards to employees. As a result of this modification, a portion of these awards is presented as equity (fixed settlement terms) and a portion remains a liability (settlement in cash or Common Stock at the employees’ discretion) in the Consolidated Balance Sheet as of September 30, 2006. We used the Monte Carlo valuation model to estimate the fair value of these modified Unit awards. The Company did not record any incremental compensation expense as a result of this modification.
We also modified the settlement terms of all of our Unit awards granted to our seven non-employee directors. Unit awards made to our non-employee directors are now settled 65% in shares of UGI Common Stock and 35% in cash. Prior to this modification, these units were settled 100% in shares of UGI Common Stock. As a result of this modification, we recorded additional pre-tax stock-based compensation expense of $1.0 during the year ended September 30, 2006.
Certain employees of the General Partner have been granted the right to receive AmeriGas Partners Common Units. Awards up to a total of 500,000 AmeriGas Partners Common Units may have performance terms similar to UGI Unit awards and compensation expense is estimated and recorded in the same manner and awards up to a total of 200,000 AmeriGas Partners Common Units have service requirements only. The General Partner made a modification to the settlement of certain of its AmeriGas Partner Common Unit awards. The Partnership did not incur any incremental compensation expense as a result of this modification.
We recognized total pre-tax equity-based compensation expense of $9.0 ($6.0 after-tax), $15.5 ($10.1 after-tax) and $14.3 ($9.3 after-tax) in 2006, 2005 and 2004, respectively. The chart below reflects the effects on net income and basic and diluted earnings per share for 2005 and 2004 as if we had applied the provisions of SFAS 123R (prior to the adoption of SFAS 123R).
| Year Ended September 30, | ||||||||
| 2005 | 2004 | |||||||
| Net income, as reported | $ | 187.5 | $ | 111.6 | ||||
| Add: Stock and unit-based employee expense included in reported net income, net of related tax effects | 10.1 | 9.3 | ||||||
| Deduct: Total stock and unit-based employee compensation expense determined under the fair value method for all awards, net of related tax effects | (11.9 | ) | (10.4 | ) | ||||
| Pro forma net income | $ | 185.7 | $ | 110.5 | ||||
| Basic earnings per share: | ||||||||
| As reported | $ | 1.81 | $ | 1.18 | ||||
| Pro forma | $ | 1.79 | $ | 1.17 | ||||
| Diluted earnings per share: | ||||||||
| As reported | $ | 1.77 | $ | 1.15 | ||||
| Pro forma | $ | 1.76 | $ | 1.14 | ||||
For a description of our stock and unit-based compensation plans and related disclosures, see Note 8.
Deferred Debt Issuance Costs.Included in other assets are net deferred debt issuance costs of $19.9 at September 30, 2006 and $10.1 at September 30, 2005. We are amortizing these costs over the terms of the related debt.
Refundable Tank and Cylinder Deposits.Included in other non-current liabilities are customer paid deposits on Antargaz owned tanks and cylinders of $207.4 and $200.6 at September 30, 2006 and 2005, respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.
Computer Software Costs.We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.
Deferred Fuel Costs.Gas Utility’s tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost (“PGC”) rates. The clauses provide for periodic adjustments to PGC rates for the difference between the total amount of purchased gas costs collected from customers and the recoverable costs incurred. In accordance with SFAS 71, we defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers.
Environmental and Other Legal Matters.We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Amounts accrued generally reflect our best estimate of costs expected to be incurred or the minimum liability associated with a range of expected environmental response costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those
40
UGI Corporation 2006 Annual Report
instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred removal costs. In accordance with existing regulatory practices at the PUC, site-specific environmental investigation and remediation costs associated with PNG Gas are amortized as removal costs over a five-year period. At September 30, 2006, neither the Company’s undiscounted amount nor its accrued liability for environmental investigation and cleanup costs was material.
Similar to environmental issues, we accrue investigation and other legal costs for other matters when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated (see Note 10).
Foreign Currency Translation.Balance sheets of international subsidiaries and our investment in international LPG joint ventures are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity method results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income. Where the local currency is not the functional currency, translation adjustments are recorded in net income.
Employee Retirement Plans.The Company uses a market related value of plan assets and the expected long-term rate of return on plan assets to determine the expected return on plan assets associated with its pension plans. The market related value of plan assets other than equities in our pension plans is based upon the market price of the plan assets or similar assets. The market related value of equities in our pension plans is calculated by rolling forward the prior-year’s market related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market related value. See Note 5.
Comprehensive Income.Comprehensive income comprises net income and other comprehensive (loss) income. Other comprehensive (loss) income principally results from gains and losses on derivative instruments qualifying as cash flow hedges and foreign currency translation adjustments.
The components of accumulated other comprehensive income (loss) at September 30, 2006 and 2005 follow:
| Derivative | Foreign | |||||||||||
| Instruments | Currency | |||||||||||
| Gains | Translation | |||||||||||
| (Losses) | Adjustments | Total | ||||||||||
| Balance — September 30, 2006 | $ | (23.4 | ) | $ | 19.6 | $ | (3.8 | ) | ||||
| Balance — September 30, 2005 | $ | 17.7 | $ | (1.2 | ) | $ | 16.5 | |||||
Recently Issued Accounting Pronouncements.In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R),” (“SFAS 158”). SFAS 158 requires an employer to recognize the funded status of each of its defined pension and postretirement benefit plans as a net asset or liability in its balance sheet with an offsetting amount in accumulated other comprehensive income, and to recognize changes in that funded status in the year in which changes occur through comprehensive income. SFAS 158 is effective as of the end of our fiscal year ending September 30, 2007. Had SFAS 158 been applied to our September 30, 2006 Balance Sheet, we estimate that the impact would have resulted in a reduction of long-term assets of $19.3, an increase of long-term liabilities of $24.3, a net reduction of deferred tax liabilities of $17.4 and decreased stockholders’ equity of $26.2. However, the effect at any future date could differ significantly depending on the measurement of our pension and other postretirement benefit plan assets and obligations at that date.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. The provisions of this standard apply to other accounting pronouncements that require or permit fair value measurements. The provisions of SFAS 157 are effective for our fiscal year beginning October 1, 2008. We are currently evaluating the impact, if any, of the provisions of SFAS 157.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108 “Considering the Effects of Prior Year Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered when quantifying a current year misstatement. The provisions of SAB 108 are effective for the end of our fiscal year ending September 30, 2007.
In June 2006, the FASB issued Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes,” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 provides guidance on the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition. FIN 48 is effective for our fiscal year beginning October 1, 2007. We are currently evaluating the impact that this standard will have on our Consolidated Financial Statements.
In March 2006, the Financial Accounting Standards Board issued SFAS No. 156, “Accounting for Servicing of Financial Assets — An Amendment of FASB Statement No. 140” (“SFAS 156”). SFAS 156 requires that all separately recognized servicing assets and servicing liabilities be initially measured at fair value, unless it is impracticable to do so. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. SFAS 156 is effective as of the beginning of our fiscal year ending September 30, 2007. The adoption of SFAS 156 will not have a material impact on our Consolidated Financial Statements.
41
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 2 — Acquisitions and Investments
On August 24, 2006, UGI Utilities acquired certain assets and assumed certain liabilities of Southern Union Company’s (“SU’s’”) PG Energy Division, a natural gas distribution business located in northeastern Pennsylvania, and all of the issued and outstanding stock of SU’s wholly-owned subsidiary, PG Energy Services, Inc. (the “PG Energy Acquisition”) pursuant to a Purchase and Sale Agreement, as amended, between SU and UGI dated as of January 26, 2006 (the “Agreement”). The acquired businesses are referred to herein as PNG Gas. Immediately prior to the PG Energy Acquisition, UGI assigned its rights and obligations under the Agreement to UGI Utilities’ newly formed subsidiary, UGI Penn Natural Gas, Inc. (“UGIPNG”). Consistent with our growth strategies, the PG Energy Acquisition added approximately 158,000 customers increasing UGI Utilities’ presence in northeastern Pennsylvania.
Under the terms of the Agreement, on August 24, 2006, UGI Utilities paid SU the acquisition price of $580 (excluding transaction fees and expenses) which is subject to working capital adjustments. The cash payment of $580 was funded with net proceeds from the issuance of $275 of UGI Utilities’ bank loans under a Credit Agreement dated as of August 18, 2006 (the “Bridge Loan”), cash capital contributions from UGI of $265 and $40 from borrowings under UGI Utilities’ revolving credit agreement for working capital. In September 2006, UGI Utilities repaid the Bridge Loan with proceeds from the issuance of $175 of 5.753% Senior Notes due 2016 and $100 of 6.206% Senior Notes due 2036.
The assets and liabilities of PNG Gas are included in our Consolidated Balance Sheet at September 30, 2006. The operating results of PNG Gas are included in our consolidated results beginning August 24, 2006. The preliminary purchase price allocation has not been finalized because we are still in the process of reviewing and determining the fair value of certain of PNG Gas’ assets acquired and liabilities assumed, principally working capital adjustments and amounts associated with environmental liabilities. The purchase price is subject to a working capital adjustment, pursuant to the terms of the Agreement, equal to the difference between an estimated $68.1 and the actual working capital as of the closing date agreed to by both UGI Utilities and SU.
The preliminary purchase price of PNG Gas, including estimated transaction fees and expenses of $9.8, has been allocated to the assets acquired and liabilities assumed, as follows:
| Working capital | $ | 49.6 | ||
| Property, plant and equipment | 362.3 | |||
| Goodwill | 182.9 | |||
| Regulatory assets | 6.7 | |||
| Other assets | 0.8 | |||
| Noncurrent liabilities | (12.5 | ) | ||
| Total | $ | 589.8 | ||
Substantially all of the estimated goodwill is expected to be deductible for income tax purposes over a fifteen-year period.
The following table presents unaudited pro forma income statement and basic and diluted per share data for the years ended September 30, 2006 and 2005 as if the acquisition of PNG Gas had occurred as of the beginning of that period:
| 2006 | 2005 | |||||||
| (pro forma) | (pro forma) | |||||||
| Revenues | $ | 5,545.7 | $ | 5,176.1 | ||||
| Net income | 88.5 | 199.5 | ||||||
| Earnings per share: | ||||||||
| Basic | $ | 0.84 | $ | 1.92 | ||||
| Diluted | $ | 0.83 | $ | 1.89 | ||||
The pro forma results of operations reflect PNG Gas’ historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The pro forma amounts are not necessarily indicative of the operating results that would have occurred had the PG Energy Acquisition been completed as of the date indicated, nor are they necessarily indicative of future operating results. The unaudited pro forma results for the twelve months ended September 30, 2006 include a writedown of goodwill of $98 recorded by SU during the three months ended December 31, 2005.
Pursuant to the Agreement, SU and UGIPNG entered into a Transition Services Agreement (“TSA”) whereby each party will be a provider and receiver of certain services to the other. The principal services include general business continuity, information technology, accounting and tax services. Services under the TSA will be provided through the expiration of the term relating to each service or until such time as mutually agreed upon by SU and UGIPNG.
On February 15, 2006, Flaga entered into a joint venture with a subsidiary of Progas GmbH & Co KG (“Progas”) to create a company for the retail distribution of LPG in portions of central and eastern Europe. Headquartered in Dortmund, Germany, Progas is controlled by Thyssen’sche Handelsgesellschaft m.b.H. The joint venture company, Zentraleuropa LPG Holding (“ZLH”), an Austrian limited liability company, through its subsidiaries engages in the business of retail distribution of LPG in the Czech Republic, Hungary, Poland, Slovakia and Romania. In forming the joint venture, Flaga contributed the shares of its LPG subsidiaries operating in the Czech Republic and Slovakia to ZLH and paid €9.2 cash to Progas. Progas contributed the shares of its LPG subsidiaries operating in the Czech Republic, Hungary, Poland, Romania and Slovakia to ZLH. These LPG operating subsidiaries distributed approximately 77 million gallons of LPG in these five countries in 2005. ZLH is owned and controlled equally by Flaga and Progas. In a related transaction, Flaga purchased Progas’ retail LPG business in Austria.
Also during 2006, AmeriGas OLP acquired two retail propane distribution businesses and a cylinder refurbishing business for total cash consideration of approximately $2.8. The pro forma effects of these and Flaga’s transactions were not material. The operating results of these businesses have been included in our results of operations from their respective dates of acquisition.
42
UGI Corporation 2006 Annual Report
In March 2006, UGID sold its 50% ownership interest in Hunlock Creek Energy Ventures (“Energy Ventures”) to Allegheny Energy Supply Hunlock Creek, LLC. Energy Ventures’ assets primarily comprised a 44-megawatt gas-fired combustion turbine electric generator and a 48-megawatt coal-fired electric generation facility. As part of the consideration in this sale, Energy Ventures transferred the 48-megawatt coal-fired electric generation station to UGID. UGID recorded a net pre-tax gain of $9.1 ($5.3 after-tax) associated with this transaction, which is reflected in other income, net in the Consolidated Statement of Income for the twelve months ended September 30, 2006.
During 2005, AmeriGas OLP acquired several retail propane distribution businesses for total cash consideration of approximately $22.7. HVAC/R acquired a commercial and residential electrical contracting business in September 2005. The operating results of these businesses have been included in our operating results from their respective dates of acquisition. The pro forma effects of these transactions were not material.
In November 2004, UGI Asset Management, Inc. acquired from ConocoPhillips Company and AmerE Holdings, Inc. (a wholly owned, indirect subsidiary of AmeriGas OLP) in separate transactions 100% of the issued and outstanding common stock of Atlantic Energy for an aggregate purchase price of approximately $24 in cash, including post-closing adjustments (the “AEI Acquisition”). The AEI Acquisition has been accounted for as a step acquisition in the Consolidated Financial Statements. In connection with this acquisition, Atlantic Energy and AmeriGas OLP entered into a long-term propane supply agreement.
On March 31, 2004 (the “Closing Date”), UGI, through its subsidiary, UGI Bordeaux Holding (as assignee of UGI France), completed its acquisition of the remaining outstanding 80.5% ownership interests of AGZ, a French corporation and the parent company of Antargaz, a French corporation and a leading distributor of LPG in France, pursuant to the terms of (i) a Share Purchase Agreement dated as of February 17, 2004, by and among UGI France, UGI, PAI partners, a French corporation, and certain officers, directors and managers of AGZ and Antargaz and their affiliates, and (ii) that certain Medit Joinder Agreement dated February 20, 2004, by and among UGI France, UGI, Medit Mediterranea GPL, S.r.L., a company incorporated under the laws of Italy (“Medit”), and PAI partners (herein referred to as the “Antargaz Acquisition”). The acquisition of the remaining interests in AGZ is consistent with our growth strategies and core competencies.
The purchase price on the Closing Date of €261.8 or $319.2 (excluding transaction fees and expenses) was subject to post-closing working capital and net debt adjustments. UGI used the cash proceeds from its March 2004 public offering of 15 million shares of its common stock and $89.0 of available cash to fund the purchase price. In accordance with the Share Purchase Agreement, UGI paid an additional €5.8 ($7.1) as a result of post-closing adjustments. In addition, we incurred transaction fees and expenses of $5.4. See Note 8 for additional information regarding the issuance of UGI Common Stock.
The Antargaz Acquisition has been accounted for as a step acquisition. UGI’s initial 19.5% equity investment in AGZ has been allocated to 19.5% of AGZ’s assets and liabilities at March 31, 2004. The amount by which the carrying value of UGI’s equity investment exceeded the aforementioned allocation has been recorded as goodwill.
The purchase price of the remaining 80.5% of AGZ, including transaction fees and expenses, has been allocated to the assets acquired and liabilities assumed, as follows:
| Working capital | $ | 28.7 | ||
| Property, plant and equipment | 337.0 | |||
| Goodwill | 469.3 | |||
| Customer relationships (estimated useful life of twelve years) | 97.1 | |||
| Trademark and other intangible assets | 38.6 | |||
| Long-term debt (including current maturities) | (392.6 | ) | ||
| Deferred income taxes | (108.8 | ) | ||
| Minority interests | (11.1 | ) | ||
| Other assets and liabilities | (126.5 | ) | ||
| Total | $ | 331.7 | ||
None of the goodwill is expected to be deductible for income tax purposes.
The assets and liabilities of AGZ have been included in our Consolidated Balance Sheets since March 31, 2004. The operating results of AGZ are included in our consolidated results beginning April 1, 2004. For periods prior to April 1, 2004, our 19.5% equity interest in AGZ is reflected in our Consolidated Financial Statements under the equity method of accounting.
The following table presents unaudited pro forma income statement and basic and diluted per share data for the year ended September 30, 2004 as if the Antargaz Acquisition had occurred as of the beginning of that period:
| 2004 | ||||
| (pro forma) | ||||
| Revenues | $ | 4,293.0 | ||
| Net income | 168.2 | |||
| Earnings per share: | ||||
| Basic | $ | 1.66 | ||
| Diluted | $ | 1.62 | ||
The pro forma results of operations reflect AGZ’s historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The pro forma amounts are not necessarily indicative of the operating results that would have occurred had the acquisition been completed as of the date indicated, nor are they necessarily indicative of future operating results.
In addition, during the year ended September 30, 2004, AmeriGas OLP completed several smaller acquisitions of retail propane businesses, HVAC/R acquired a commercial refrigeration business and Flaga acquired a retail propane distribution business in the Czech Republic. The pro forma effect of these transactions is not material.
43
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 3 — Debt
Long-term debt comprises the following at September 30:
| 2006 | 2005 | |||||||
AmeriGas Propane: | ||||||||
| AmeriGas Partners Senior Notes: | ||||||||
| 8.875%, due May 2011 (including unamortized premium of $0.2 and $0.3, respectively, effective rate — 8.46%) | $ | 14.8 | $ | 14.9 | ||||
| 10%, due April 2006 (effective rate — 10.125%) | — | 60.0 | ||||||
| 7.25%, due May 2015 | 415.0 | 415.0 | ||||||
| 7.125%, due May 2016 | 350.0 | — | ||||||
| AmeriGas OLP First Mortgage Notes: | ||||||||
| Series A, 9.34% - 11.71%, due April 2006 through April 2009 (including unamortized premium of $3.6 in 2005, effective rate — 8.91%) | — | 163.6 | ||||||
| Series C, 8.83%, due April 2006 through April 2010 | — | 68.8 | ||||||
| Series D, 7.11%, due March 2009 (including unamortized premium of $0.9 and $1.3, respectively, effective rate — 6.52%) | 70.9 | 71.3 | ||||||
| Series E, 8.50%, due July 2010 (including unamortized premium of $0.1, effective rate — 8.47%) | 80.1 | 80.1 | ||||||
| AmeriGas OLP Term Loan | — | 35.0 | ||||||
| Other | 2.9 | 4.8 | ||||||
| Total AmeriGas Propane | $ | 933.7 | 913.5 | |||||
International Propane: | ||||||||
| Antargaz Senior Facilities term loan, due March 2011 | 483.5 | 210.4 | ||||||
| Antargaz 10% High Yield Bonds, due July 2011 (including unamortized premium of $17.0 in 2005, effective rate — 7.68%) | — | 215.4 | ||||||
| Flaga Acquisition Note, due through September 2006 | — | 55.9 | ||||||
| Flaga euro special purpose facility | — | 2.0 | ||||||
| Flaga Term Loan | 60.9 | — | ||||||
| Other | 2.6 | 5.4 | ||||||
| Total International Propane | 547.0 | 489.1 | ||||||
UGI Utilities: | ||||||||
| Senior Notes: | ||||||||
| 5.75% Notes, due October 2016 | 175.0 | — | ||||||
| 6.21% Notes, due October 2034 | 100.0 | — | ||||||
| Medium-Term Notes: | ||||||||
| 7.14% Notes, due December 2005 (effective rate — 6.64%) | — | 30.0 | ||||||
| 7.14% Notes, due December 2005 | — | 20.0 | ||||||
| 7.17% Notes, due June 2007 | 20.0 | 20.0 | ||||||
| 5.53% Notes, due September 2012 | 40.0 | 40.0 | ||||||
| 5.37% Notes, due August 2013 | 25.0 | 25.0 | ||||||
| 5.16% Notes, due May 2015 | 20.0 | 20.0 | ||||||
| 7.37% Notes, due October 2015 | 22.0 | 22.0 | ||||||
| 5.64% Notes, due December 2015 | 50.0 | — | ||||||
| 7.25% Notes, due November 2017 | 20.0 | 20.0 | ||||||
| 6.50% Notes, due August 2033 | 20.0 | 20.0 | ||||||
| 6.13% Notes, due October 2034 | 20.0 | 20.0 | ||||||
| Total UGI Utilities | 512.0 | 237.0 | ||||||
| Other | 4.2 | 4.9 | ||||||
| Total long-term debt | 1,996.9 | 1,644.5 | ||||||
| Less current maturities (including net unamortized premium of $0.5 and $4.2, respectively) | (31.9 | ) | (252.0 | ) | ||||
| Total long-term debt due after one year | $ | 1,965.0 | $ | 1,392.5 | ||||
Scheduled principal repayments of long-term debt due in fiscal years 2007 to 2011 follows:
| 2007 | 2008 | 2009 | 2010 | 2011 | ||||||||||||||||
| AmeriGas Propane | $ | 1.4 | $ | 0.7 | $ | 70.5 | $ | 80.2 | $ | 14.7 | ||||||||||
| UGI Utilities | 20.0 | — | — | — | — | |||||||||||||||
| International Propane | 8.6 | 7.9 | 7.8 | 7.7 | 512.4 | |||||||||||||||
| Other | 1.4 | 3.7 | 1.6 | 0.1 | — | |||||||||||||||
| Total | $ | 31.4 | $ | 12.3 | $ | 79.9 | $ | 88.0 | $ | 527.1 | ||||||||||
AmeriGas Propane
AmeriGas Partners Senior Notes.The 7.25% and 7.125% Senior Notes generally cannot be redeemed at our option prior to May 20, 2010 and 2011, respectively. The 8.875% Senior Notes generally may be redeemed at our option (pursuant to a tender offer), however, a redemption premium applies through May 19, 2009. In January 2006, AmeriGas Partners refinanced its Series A and Series C First Mortgage Notes totaling $228.8, a $35 term loan and $59.6 of the Partnership’s $60 10% Senior Notes with $350 of its 7.125% Senior Notes due 2016. In May 2005, AmeriGas Partners refinanced $373.4 of its 8.875% Senior Notes pursuant to a tender offer with $415 of 7.25% Senior Notes. AmeriGas Partners recognized losses of $17.1 and $33.6 associated with these refinancings which amounts are reflected in “Loss on extinguishments of debt” in the 2006 and 2005 Consolidated Statements of Income, respectively. AmeriGas Partners may, under certain circumstances following the disposition of assets or a change of control, be required to offer to prepay its 7.25% and 7.125% Senior Notes.
AmeriGas OLP First Mortgage Notes.As of November 6, 2006, AmeriGas OLP’s First Mortgage Notes are no longer collateralized by substantially all of its assets. The General Partner is co-obligor of the Series D and E First Mortgage Notes. AmeriGas OLP may prepay the First Mortgage Notes, in whole or in part. These prepayments include a make whole premium. Following the disposition of assets or a change of control, AmeriGas OLP may be required to offer to prepay the First Mortgage Notes, in whole or in part.
AmeriGas OLP Credit Agreement.Effective November 6, 2006, AmeriGas OLP entered into a new unsecured Credit Agreement (“Credit Agreement”) consisting of (1) a Revolving Credit Facility and (2) an Acquisition Facility. The General Partner and Petrolane are guarantors of amounts outstanding under the Credit Agreement. Reference made to the Credit Agreement relates to both the former and new Credit Agreement, as appropriate.
Under the Revolving Credit Facility, AmeriGas OLP may borrow up to $125 ($100 prior to November 6, 2006), including a $100 sublimit for letters of credit, which is subject to restrictions in the AmeriGas Partners Senior Notes indentures (see “Restrictive Covenants” below). The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Revolving Credit Facility expires on October 15, 2011, but may be extended for additional one-year periods with the consent of the participating banks representing at least 80% of the commitments thereunder. There were no borrowings outstanding under AmeriGas OLP’s Revolving Credit Agreement at September 30, 2006 and 2005. Issued and
44
UGI Corporation 2006 Annual Report
outstanding letters of credit, which reduce available borrowings under the Revolving Credit Facility, totaled $58.9 and $56.3 at September 30, 2006 and 2005, respectively.
The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 to finance the purchase of propane businesses or propane business assets or, to the extent it is not so used, for working capital and general purposes, subject to restrictions in the Senior Notes indentures. The Acquisition Facility operates as a revolving facility through October 15, 2011, at which time amounts then outstanding will be immediately due and payable. There were no amounts outstanding under the Acquisition Facility at September 30, 2006 and 2005.
The Revolving Credit Facility and the Acquisition Facility permit AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate (8.25% at September 30, 2006), or at a two-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the Credit Agreement, plus a margin. The margin on Eurodollar Rate borrowings (which ranges from 1.00% to 1.75%, and the Credit Agreement facility fee rate (which ranges from 0.25% to 0.375%) are dependent upon AmeriGas OLP’s ratio of funded debt to earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”), each as defined in the Credit Agreement.
AmeriGas OLP Term Loan.In April 2005, AmeriGas OLP entered into a $35.0 variable-rate term loan due October
1, 2006 (“AmeriGas OLP Term Loan”), which bore interest plus margin at the same rates as the Credit Agreement. Proceeds from the AmeriGas OLP Term Loan were used to repay a portion of the $53.8 maturing AmeriGas OLP First Mortgage Notes. The Partnership used a portion of the proceeds from the issuance of the 7.125% Senior Notes due 2016 to repay the AmeriGas OLP Term Loan in January 2006.
1, 2006 (“AmeriGas OLP Term Loan”), which bore interest plus margin at the same rates as the Credit Agreement. Proceeds from the AmeriGas OLP Term Loan were used to repay a portion of the $53.8 maturing AmeriGas OLP First Mortgage Notes. The Partnership used a portion of the proceeds from the issuance of the 7.125% Senior Notes due 2016 to repay the AmeriGas OLP Term Loan in January 2006.
Restrictive Covenants.The 7.25% and 7.125% Senior Notes of AmeriGas Partners restrict the ability of the Partnership and AmeriGas OLP 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.
The Credit Agreement and First Mortgage Notes restrict the incurrence of additional indebtedness and also restrict certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The Credit Agreement and First Mortgage Notes require a maximum ratio of total indebtedness to EBITDA, as defined. In addition, the Credit Agreement requires that AmeriGas OLP maintain a minimum ratio of EBITDA to interest expense, as defined. Generally, as long as no default exists or would result, the Partnership and AmeriGas OLP are 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.
International Propane
On December 7, 2005, Antargaz executed a new five-year, floating rate Senior Facilities Agreement with a major French bank providing for a €380 term loan and a €50 revolving credit facility. AGZ Finance notified the holders of its High Yield Bonds of its decision to redeem them, including a premium, pursuant to the Trust Deed. The proceeds of the term loan were used in December 2005 to repay immediately the existing €175 Senior Facilities term loan, to fund the redemption of the €165 High Yield Bonds in January 2006, including a premium, and for general corporate purposes. As a result of this refinancing, we incurred a pre-tax loss on extinguishment of debt of $1.4 ($0.9 after-tax). In addition, AGZ has executed interest rate swap agreements with the same bank to fix the rate of interest on the term loan for the duration of the loan at a rate of approximately 3.25% (see Note 11).
Antargaz’ term loan bears interest at euribor or libor plus margin, as defined by the Senior Facilities Agreement. The margin (which ranges from 0.70% to 1.15%) is dependent upon Antargaz’ ratio of total net debt to EBITDA, each as defined by the Senior Facilities Agreement. The Senior Facilities debt has been collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivable.
Effective in July 2006, Flaga entered into a euro-based, variable-rate term loan facility in the amount of €48 and a working capital facility of up to €8 which expire in September 2011. The term loan bears interest at a rate of 0.52% to 1.45% over one-to twelve-month euribor rates (as chosen by Flaga from time to time). Generally, principal payments of €3 on the term loan are due semi-annually on March 31 and September 30 each year with final payments totaling €24 due in 2011. The effective interest rate on Flaga’s term loan, at September 30, 2006 was 3.72%. In November 2006, Flaga effectively fixed the rate of interest for the duration of its term loan at 3.91% plus margin by entering into an interest rate swap agreement. Flaga may prepay the term loan, in whole or in part, without incurring any premium. Flaga refinanced its multi-currency acquisition note (“Acquisition Note”) with the proceeds from its term loan. The Acquisition Note bore interest at a rate of 1.25% over one- to twelve-month euribor rates (as chosen by Flaga from time to time). The effective interest rate on the Acquisition Note was 3.44% at September 30, 2005.
Flaga’s borrowings under its working capital facility at September 30, 2006 totaled €7.4 ($9.4). Borrowings at September 30, 2005 under its former working capital loan commitments totaled €13.5 ($16.2). Amounts outstanding under the working capital facilities are classified as bank loans. Borrowings under its working capital facility bear interest at market rates (a daily euro-based rate) plus a margin and borrowings under Flaga’s former special purpose facility bore interest at market rates. The weighted-average interest rates on Flaga’s bank loan borrowings outstanding were 4.23% at September 30, 2006 and 3.45% at September 30, 2005.
45
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 3 continued
Restrictive Covenants and Guarantees.The Senior Facilities Agreement restricts the ability of AGZ and its subsidiaries, including Antargaz, to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets. Under this agreement, AGZ is generally permitted to make restricted payments, such as dividends, if the ratio of net debt to EBITDA on a French GAAP basis, as defined in the agreement is less than 3.75 to 1.00 and if no event of default exists or would exist upon payment of such restricted payment.
The Flaga term loan and working capital facility are subject to guarantees of UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending bank may accelerate repayment of the debt.
Flaga’s joint venture, ZLH, has multi-currency working capital facilities that provide for borrowings up to a total of €14, half of which is subject to guarantees by UGI.
UGI Utilities
Revolving Credit Agreements.UGI Utilities has a revolving credit agreement with banks providing for borrowings of up to $350. This agreement is currently scheduled to expire in August 2007, but may be automatically extended by UGI Utilities to August 2011. Under this agreement, UGI Utilities may borrow at various prevailing interest rates, including LIBOR and the banks’ prime rate. UGI Utilities pays quarterly facility fees on this credit line. UGI Utilities had revolving credit agreement borrowings totaling $216.0 at September 30, 2006 and $11.2 at September 30, 2005, which we classify as bank loans. From time to time, UGI Utilities has entered into other short-term borrowings in order to meet liquidity needs. Such borrowings are also classified as bank loans. At September 30, 2005, UGI Utilities had two separate $35 borrowings outstanding under uncommitted arrangements with major banks. These borrowings were repaid in February and March 2006. The weighted-average interest rates on UGI Utilities’ bank loans were 5.58% at September 30, 2006 and 4.41% at September 30, 2005.
Restrictive Covenants.UGI Utilities’ credit agreement requires UGI Utilities to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
Note 4 — Income Taxes
Income before income taxes comprises the following:
| 2006 | 2005 | 2004 | ||||||||||
| Domestic | $ | 207.7 | $ | 158.7 | $ | 160.7 | ||||||
| Foreign | 67.0 | 148.0 | 15.3 | |||||||||
| Total income before income taxes | $ | 274.7 | $ | 306.7 | $ | 176.0 | ||||||
The provisions for income taxes consist of the following:
| 2006 | 2005 | 2004 | ||||||||||
| Current expense: | ||||||||||||
| Federal | $ | 54.2 | $ | 49.8 | $ | 46.8 | ||||||
| State | 12.0 | 14.6 | 14.4 | |||||||||
| Foreign | 24.9 | 42.7 | 0.2 | |||||||||
| Total current expense | 91.1 | 107.1 | 61.4 | |||||||||
| Deferred (benefit) expense: | ||||||||||||
| Federal | 2.3 | 0.3 | 4.3 | |||||||||
| State | 1.3 | 1.6 | (1.6 | ) | ||||||||
| Foreign | 4.2 | 10.6 | 0.7 | |||||||||
| Investment tax credit amortization | (0.4 | ) | (0.4 | ) | (0.4 | ) | ||||||
| Total deferred expense (benefit) | 7.4 | 12.1 | 3.0 | |||||||||
| Total income tax expense | $ | 98.5 | $ | 119.2 | $ | 64.4 | ||||||
Federal income taxes for 2006 and 2005 are net of foreign tax credits of $41.4 and $25.4, respectively. The tax benefits associated with nonqualified stock options reduced taxes currently payable by $0.8, $10.2 and $2.9 for 2006, 2005 and 2004, respectively.
A reconciliation from the statutory federal tax rate to our effective tax rate is as follows:
| 2006 | 2005 | 2004 | ||||||||||
| Statutory federal tax rate | 35.0 | % | 35.0 | % | 35.0 | % | ||||||
| Difference in tax rate due to: | ||||||||||||
| State income taxes, net of federal | 3.4 | 2.6 | 4.8 | |||||||||
| Planned repatriation of foreign earnings net of foreign tax credits | (3.3 | ) | 2.2 | — | ||||||||
| Other, net | 0.9 | (0.9 | ) | (3.2 | ) | |||||||
| Effective tax rate | 36.0 | % | 38.9 | % | 36.6 | % | ||||||
46
UGI Corporation 2006 Annual Report
Deferred tax liabilities (assets) comprise the following at September 30:
| 2006 | 2005 | |||||||
| Excess book basis over tax basis of property, plant and equipment | $ | 332.9 | $ | 330.2 | ||||
| SAB 51 gains | 94.1 | 94.1 | ||||||
| Intangibles | 53.1 | 53.7 | ||||||
| Utility regulatory assets | 29.9 | 25.4 | ||||||
| Pension plan assets and liabilities | 4.6 | 9.3 | ||||||
| Unrepatriated foreign earnings | 4.4 | 9.4 | ||||||
| Accumulated other comprehensive income | — | 10.3 | ||||||
| Deferred expenses | 19.7 | 2.2 | ||||||
| Other | 5.0 | 6.3 | ||||||
| Gross deferred tax liabilities | 543.7 | 540.9 | ||||||
| Self-insured property and casualty liability | (12.9 | ) | (12.2 | ) | ||||
| Employee-related benefits | (29.6 | ) | (23.5 | ) | ||||
| Premium on long-term debt | (0.2 | ) | (6.7 | ) | ||||
| Tax litigation | (1.7 | ) | (4.4 | ) | ||||
| Deferred investment tax credits | (2.8 | ) | (3.0 | ) | ||||
| Utility regulatory liabilities | (9.1 | ) | (7.4 | ) | ||||
| Operating loss carryforwards | (20.2 | ) | (12.6 | ) | ||||
| Allowance for doubtful accounts | (10.4 | ) | (6.8 | ) | ||||
| Foreign tax credit carryforwards | (28.3 | ) | (31.7 | ) | ||||
| Accumulated other comprehensive income | (12.1 | ) | — | |||||
| Other | (20.1 | ) | (17.1 | ) | ||||
| Gross deferred tax assets | (147.4 | ) | (125.4 | ) | ||||
| Deferred tax assets valuation allowance | 39.3 | 37.6 | ||||||
| Net deferred tax liabilities | $ | 435.6 | $ | 453.1 | ||||
UGI Utilities had recorded deferred tax liabilities of approximately $40.4 as of September 30, 2006 and $37.3 as of September 30, 2005, pertaining to utility temporary differences, principally a result of accelerated tax depreciation for state income tax purposes, the tax benefits of which previously were or will be flowed through to ratepayers. These deferred tax liabilities have been reduced by deferred tax assets of $2.8 at September 30, 2006 and $3.0 at September 30, 2005, pertaining to utility deferred investment tax credits. UGI Utilities had recorded regulatory income tax assets related to these net deferred taxes of $64.3 as of September 30, 2006 and $58.6 as of September 30, 2005. These regulatory income tax assets represent future revenues expected to be recovered through the ratemaking process. We will recognize this regulatory income tax asset in deferred tax expense as the corresponding temporary differences reverse and additional income taxes are incurred.
Foreign net operating loss carryforwards of Flaga totaled approximately $35.0 all of which have no expiration date. At September 30, 2006, deferred tax assets relating to operating loss carryforwards include $8.5 for Flaga, $1.6 for certain operations of AGZ, $2.4 for certain operations of AmeriGas Propane, and $7.7 of deferred tax assets associated with state net operating loss carryforwards expiring through 2025. A valuation allowance of $9.4 has been provided for all deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries because, on a state reportable basis, it is more likely than not that these assets will be unusable. A valuation allowance of $1.6 was also provided for certain operations of AGZ.
We have foreign tax credit carryforwards of approximately $28.3 expiring through 2010, resulting from the planned repatriation of AGZ’s accumulated earnings and profits included in U.S. taxable income since its acquisition. Since we expect that these credits will expire unused, a valuation allowance has been provided for the entire foreign tax credit carryforward amount.
Note 5 — Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans.We sponsor two defined benefit pension plans (“Pension Plan”) for employees of UGI, UGI Utilities, including employees of UGIPNG, 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, and postretirement life insurance benefits to nearly all domestic active and retired employees. In addition, Antargaz employees are covered by a defined benefit pension plan and a postretirement medical plan. As a result of the PG Energy Acquisition, we acquired the pension assets and assumed the pension liabilities related to the Employees’ Retirement Plan of Southern Union Company Pennsylvania Division (the “Division Plan”).
47
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 5 continued
The following provides a reconciliation of projected benefit obligations, plan assets, and funded status of these plans as of September 30:
| Pension | Other Postretirement | |||||||||||||||
| Benefits | Benefits | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Change in benefit obligations: | ||||||||||||||||
| Benefit obligations — beginning of year | $ | 247.9 | $ | 232.3 | $ | 23.4 | $ | 32.8 | ||||||||
| Service cost | 6.1 | 5.6 | 0.4 | 0.4 | ||||||||||||
| Interest cost | 14.3 | 14.0 | 1.3 | 1.7 | ||||||||||||
| Actuarial (gain) loss | (12.1 | ) | 6.9 | (0.4 | ) | (1.7 | ) | |||||||||
| PG Energy Acquisition | 71.3 | — | 2.4 | — | ||||||||||||
| Plan amendments | — | — | — | (7.6 | ) | |||||||||||
| Plan settlement | — | — | (1.6 | ) | — | |||||||||||
| Foreign currency loss (gain) | 0.6 | (0.2 | ) | 0.2 | (0.1 | ) | ||||||||||
| Benefits paid | (11.4 | ) | (10.7 | ) | (1.8 | ) | (2.1 | ) | ||||||||
| Benefit obligations — end of year | $ | 316.7 | $ | 247.9 | $ | 23.9 | $ | 23.4 | ||||||||
Change in plan assets: | ||||||||||||||||
| Fair value of plan assets — beginning of year | $ | 215.3 | $ | 200.2 | $ | 11.3 | $ | 10.2 | ||||||||
| Actual return on plan assets | 11.6 | 25.5 | 0.9 | 0.8 | ||||||||||||
| Foreign currency gain | 0.2 | (0.1 | ) | — | — | |||||||||||
| Employer contributions | 0.4 | 0.4 | 1.7 | 2.3 | ||||||||||||
| PG Energy Acquisition | 62.3 | — | — | — | ||||||||||||
| Plan settlement | — | — | (0.8 | ) | — | |||||||||||
| Benefits paid | (11.4 | ) | (10.7 | ) | (1.8 | ) | (2.1 | ) | ||||||||
| Fair value of plan assets — end of year | $ | 278.4 | $ | 215.3 | $ | 11.3 | $ | 11.2 | ||||||||
| Funded status of the plans | $ | (38.3 | ) | $ | (32.6 | ) | $ | (12.6 | ) | $ | (12.2 | ) | ||||
| Unrecognized net actuarial loss | 43.2 | 46.2 | 2.4 | 3.7 | ||||||||||||
| Unrecognized prior service cost | (0.4 | ) | 1.1 | (2.3 | ) | (2.5 | ) | |||||||||
| Unrecognized net transition (asset) obligation | — | — | 0.7 | 0.8 | ||||||||||||
| Prepaid (accrued) benefit cost — end of year | $ | 4.5 | $ | 14.7 | $ | (11.8 | ) | $ | (10.2 | ) | ||||||
Weighted-average assumptions as of September 30 (a): | ||||||||||||||||
| Discount rate | 6.0 | % | 5.7 | % | 6.0 | % | 5.7 | % | ||||||||
| Expected return on plan assets | 8.5 | % | 9.0 | % | 5.6 | % | 5.8 | % | ||||||||
| Rate of increase in salary levels | 3.8 | % | 4.0 | % | 3.8 | % | 4.0 | % | ||||||||
| (a) | Represents domestic plan assumptions. Assumptions for the foreign plans are based on market conditions in France. |
Net pension expense is determined using assumptions as of the beginning of each fiscal year and, in the case of UGIPNG’s pension and postretirement plans, as of August 31, 2006. Funded status is determined using assumptions as of the end of each fiscal year. The expected rate of return on assets assumption is based on the rates of return for certain asset classes and the allocation of plan assets among those asset classes as well as actual historic long-term rates of return on our plan assets.
Net periodic pension expense and other postretirement benefit costs include the following components:
| Pension | Other Postretirement | |||||||||||||||||||||||
| Benefits | Benefits | |||||||||||||||||||||||
| 2006 | 2005 | 2004 | 2006 | 2005 | 2004 | |||||||||||||||||||
| Service cost | $ | 6.1 | $ | 5.6 | $ | 5.0 | $ | 0.4 | $ | 0.4 | $ | 0.2 | ||||||||||||
| Interest cost | 14.3 | 14.0 | 13.0 | 1.3 | 1.7 | 1.8 | ||||||||||||||||||
| Expected return on assets | (19.3 | ) | (18.0 | ) | (17.3 | ) | (0.6 | ) | (0.5 | ) | (0.5 | ) | ||||||||||||
| Amortization of: | ||||||||||||||||||||||||
| Transition (asset) obligation | — | — | (1.4 | ) | 0.2 | 0.8 | 0.9 | |||||||||||||||||
| Prior service cost | 0.8 | 0.7 | 0.7 | (0.2 | ) | (0.1 | ) | — | ||||||||||||||||
| Actuarial (gain) loss | 2.0 | 1.5 | 1.2 | 0.2 | 0.2 | 0.3 | ||||||||||||||||||
| Antargaz Acquisition(a) | — | — | 0.3 | — | — | 0.2 | ||||||||||||||||||
| Net benefit cost (income) | 3.9 | 3.8 | 1.5 | 1.3 | 2.5 | 2.9 | ||||||||||||||||||
| Change in regulatory and other assets and liabilities | (0.4 | ) | — | — | 2.7 | 1.6 | 0.9 | |||||||||||||||||
| Net expense (income) | $ | 3.5 | $ | 3.8 | $ | 1.5 | $ | 4.0 | $ | 4.1 | $ | 3.8 | ||||||||||||
| (a) | In 2004, amounts related to Antargaz’ pension and other postretirement welfare benefits are reflected in the above table as “Antargaz Acquisition.” Such amounts in 2006 and 2005 are not segregated and are included in the appropriate components. |
Pension Plan assets are held in trust. Although the Pension Plan projected benefit obligations exceeded plan assets at September 30, 2006 and 2005, plan assets exceeded accumulated benefit obligations by $6.0 and $7.4, respectively. The Company did not make any contributions in 2006 nor does it believe it will be required to make any contributions to the Pension Plan during the year ending September 30, 2007 for ERISA funding purposes. At September 30, 2006, the accumulated benefit obligation of AGZ benefits exceeded the plan assets by $5.3. However, the accrual recorded in our Consolidated Balance Sheet at September 30, 2006 exceeds the minimum pension liability. Antargaz does not expect to make any contributions to fund AGZ benefits during the year ending September 30, 2007.
Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under SFAS No. 106, “Employers Accounting for Postretirement Benefits Other than Pensions.” The difference between such amounts and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Effective July 1, 2005, substantially all retirees and their beneficiaries participating in the UGI Utilities’ postretirement benefit program were enrolled in insured Medicare Advantage plans. As a result, the net benefit cost declined for periods subsequent to July 1, 2005. Additionally, the UGI Utilities’ required contribution to the VEBA during the year ending September 30, 2007 is not expected to be material.
Expected payments for pension benefits and for other postretirement welfare benefits are as follows:
| Other | ||||||||
| Pension | Postretirement | |||||||
| Benefits | Benefits | |||||||
| Fiscal 2007 | $ | 14.7 | $ | 1.7 | ||||
| Fiscal 2008 | 15.1 | 1.7 | ||||||
| Fiscal 2009 | 15.5 | 1.8 | ||||||
| Fiscal 2010 | 16.0 | 1.8 | ||||||
| Fiscal 2011 | 16.6 | 1.8 | ||||||
| Fiscal 2012-2016 | 95.1 | 8.9 | ||||||
48
UGI Corporation 2006 Annual Report
In accordance with our investment strategy to obtain long-term growth, our target asset allocations are to maintain a mix of 60% equities and the remainder in fixed income funds or cash equivalents. The targets and actual allocations for the Pension Plan assets and VEBA trust assets at September 30 are as follows:
| Target | Pension Plan | VEBA | ||||||||||||||||||||||
| Pension Plan | VEBA | 2006 | 2005 | 2006 | 2005 | |||||||||||||||||||
| Equities | 60 | % | 60 | % | 60 | % | 60 | % | 63 | % | 62 | % | ||||||||||||
| Fixed income funds | 40 | % | 30 | % | 40 | % | 40 | % | 30 | % | 31 | % | ||||||||||||
| Cash equivalents | N/A | 10 | % | N/A | N/A | 7 | % | 7 | % | |||||||||||||||
UGI Common Stock comprised approximately 7% and 11% of Pension Plan assets at September 30, 2006 and 2005, respectively.
The assumed domestic health care cost trend rates are 10% for fiscal 2007, decreasing to 5.5% in fiscal 2011. A one percentage point change in the assumed health care cost trend rate would change the 2006 postretirement benefit cost and obligation as follows:
| 1% Increase | 1% Decrease | |||||||
| Effect on total service and interest costs | $ | 0.1 | $ | (0.1 | ) | |||
| Effect on postretirement benefit obligation | $ | 0.7 | $ | (0.6 | ) | |||
We also sponsor unfunded and non-qualified supplemental executive retirement plans. At September 30, 2006 and 2005, the projected benefit obligations of these plans were $17.0 and $14.8, respectively. We recorded net benefit costs for these plans of $2.4 in 2006, $2.0 in 2005, and $1.9 in 2004. We also recorded a settlement loss of $1.5 in 2004 associated with these plans.
Defined Contribution Plans.We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for either mandatory or discretionary employer matching contributions at various rates. The cost of benefits under the savings plans totaled $7.8 in 2006, $8.3 in 2005, and $8.2 in 2004.
Note 6 — Inventories
Inventories comprise the following at September 30:
| 2006 | 2005 | |||||||
| LPG and natural gas | $ | 140.5 | $ | 134.6 | ||||
| Utility natural gas and LPG | 157.0 | 69.2 | ||||||
| Materials, supplies and other | 42.9 | 36.1 | ||||||
| Total inventories | $ | 340.4 | $ | 239.9 | ||||
Note 7 — Series Preferred Stock
UGI has 10,000,000 shares of UGI Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, authorized for issuance. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2006 or 2005.
UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, authorized for issuance. At September 30, 2006, there were no UGI Utilities Series Preferred Stock outstanding.
On October 1, 2004, UGI Utilities redeemed all 200,000 shares of its $7.75 UGI Utilities Series Preferred Stock at a price of $100 per share together with full cumulative dividends. The redemption was funded with proceeds from the October 2004 issuance of $20 of 6.13% Medium-Term Notes due October 2034.
Note 8 — Common Stock and Incentive Stock Award Plans
In March 2004, UGI Corporation sold 15.6 million shares (including shares sold to the underwriters upon exercise of their overallotment option in April 2004) of UGI Common Stock in an underwritten public offering at a public offering price of $16.05 per share. As stated in Note 2, the proceeds of the public offering of approximately $239 were used primarily to fund a portion of the purchase price of the remaining ownership interests in AGZ.
UGI Common Stock share activity for 2004, 2005, and 2006 follows:
| Issued | Treasury | Outstanding | ||||||||||
| Balance September 30, 2003 | 99,596,194 | (14,197,478 | ) | 85,398,716 | ||||||||
| Issued: | ||||||||||||
| Public offering | 15,556,800 | — | 15,556,800 | |||||||||
| Employee and director plans | — | 1,306,500 | 1,306,500 | |||||||||
| Dividend reinvestment plan | — | 160,380 | 160,380 | |||||||||
| Reacquired | — | — | — | |||||||||
| Balance September 30, 2004 | 115,152,994 | (12,730,598 | ) | 102,422,396 | ||||||||
| Issued: | ||||||||||||
| Employee and director plans | — | 2,320,478 | 2,320,478 | |||||||||
| Dividend reinvestment plan | — | 106,584 | 106,584 | |||||||||
| Balance September 30, 2005 | 115,152,994 | (10,303,536 | ) | 104,849,458 | ||||||||
| Issued: | ||||||||||||
| Employee and director plans | — | 498,642 | 498,642 | |||||||||
| Dividend reinvestment plan | — | 106,262 | 106,262 | |||||||||
| Balance September 30, 2006 | 115,152,994 | (9,698,632 | ) | 105,454,362 | ||||||||
Stock Option and Incentive Plans.Under UGI’s 2004 Omnibus Equity Compensation Plan (“OECP”), we may grant options to acquire shares of Common Stock, or issue Units to key employees and non-employee directors. The exercise price for options may not be less than the fair market value on the grant date. Grants of stock options or Units may vest immediately or ratably over a period of years (generally three to four year periods), and stock options generally can be exercised no later than ten years from the grant date.
Under the OECP, awards representing up to 7,000,000 shares of Common Stock may be granted. The maximum number of shares that may be issued pursuant to grants other than stock options or dividend equivalents is 1,600,000 shares. In addition, the OECP provides that both option grants and Units may provide for the crediting of Common Stock
49
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 8 continued
dividend equivalents to participants’ accounts. Dividend equivalents on employee awards will be paid in cash. Dividend equivalents on non-employee director awards are paid in additional Common Stock Units. Unit awards granted to employees and non-employee directors are settled in shares of Common Stock and cash. Beginning with 2006 grants, Unit awards granted to Antargaz employees are settled in shares of Common Stock. The actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid to employees, is generally dependent upon the achievement of market performance goals and service conditions. It is the Company’s practice to issue treasury shares to satisfy option exercises and Unit awards. The Company does not expect to repurchase shares for such purposes during the year ending September 30, 2007. During 2006, 2005 and 2004, the Company made stock-based awards other than stock options representing 187,326, 286,230, and 293,569 shares, respectively, having weighted-average grant date fair values per Unit of $22.74, $22.62 and $20.46, respectively. At September 30, 2006, awards representing 923,662 shares of Common Stock were outstanding under our equity compensation plans. There are stock options outstanding under other predecessor plans, however, since January 2004 no awards have been made under any plan other than the OECP.
Stock option transactions under all of our plans for 2004, 2005 and 2006 follow:
| Average | Intrinsic | |||||||||||
| Shares | Option Price | Value | ||||||||||
| Shares under option 151 September 30, 2003 | 4,964,978 | 9.41 | ||||||||||
| Granted | 1,494,500 | 16.82 | ||||||||||
| Exercised | (1,042,052 | ) | 7.89 | $ | 8.6 | |||||||
| Forfeited | (88,500 | ) | 12.85 | |||||||||
| Shares under option — September 30, 2004 | 5,328,926 | 11.71 | ||||||||||
| Granted | 1,596,100 | 21.13 | ||||||||||
| Exercised | (1,913,668 | ) | 8.41 | $ | 30.4 | |||||||
| Forfeited | (58,340 | ) | 21.91 | |||||||||
| Shares under option — September 30, 2005 | 4,953,018 | 15.95 | ||||||||||
| Granted | 1,159,100 | 20.67 | ||||||||||
| Exercised | (232,766 | ) | 11.09 | $ | 2.7 | |||||||
| Forfeited | (35,500 | ) | 19.26 | |||||||||
| Shares under option — September 30, 2006 | 5,843,852 | 17.06 | $ | 43.2 | ||||||||
| Options exercisable 2004 | 2,718,670 | 9.01 | ||||||||||
| Options exercisable 2005 | 2,093,821 | 12.38 | ||||||||||
| Options exercisable 2006 | 3,146,952 | 14.56 | $ | 31.1 | ||||||||
| Non-vested options — September 30, 2006 | 2,696,900 | 19.97 | $ | 12.1 | ||||||||
Cash received from the exercises of stock options and associated tax benefits were $2.6 and $1.0, respectively, during the year ended September 30, 2006. As of September 30, 2006, the average remaining terms of shares under option, options exercisable and unvested options were 7.3 years, 6.4 years and 8.4 years, respectively. As of September 30, 2006, there was $3.1 of unrecognized compensation cost associated with non-vested stock options that is expected to be recognized over a weighted-average period of 1.9 years.
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2006:
| Range of exercise prices | ||||||||||||
| $6.88 - | $12.57 - | $18.23 - | ||||||||||
| $ 10.63 | $ 17.01 | $ 27.90 | ||||||||||
| Options outstanding at September 30, 2006: | ||||||||||||
| Number of options | 798,850 | 2,299,902 | 2,745,100 | |||||||||
| Weighted average remaining contractual life (in years) | 4.58 | 6.66 | 8.59 | |||||||||
| Weighted average exercise price | $ | 9.64 | $ | 15.06 | $ | 20.89 | ||||||
| Options exercisable at September 30, 2006: | ||||||||||||
| Number of options | 798,850 | 1,743,902 | 604,200 | |||||||||
| Weighted average exercise price | $ | 9.64 | $ | 14.58 | $ | 21.03 | ||||||
The following table illustrates Unit award activity:
| Weighted-Average | ||||||||||||
| Number of | Grant Date Fair | |||||||||||
| UGI Units | Value (per Unit) | |||||||||||
| Non-vested Units — September 30, 2005 | 313,227 | $ | 21.35 | |||||||||
| Granted | 187,326 | $ | 22.74 | |||||||||
| Forfeited | (967 | ) | $ | 21.25 | ||||||||
| Vested | (274,681 | ) | $ | 21.42 | ||||||||
| Non-vested Units — September 30, 2006 | 224,905 | $ | 22.46 | |||||||||
During 2006, a portion of vested Unit awards were settled in shares of UGI Common Stock and approximately $2.3 in cash. As of September 30, 2006, there was a total of approximately $6.1 of unrecognized compensation cost associated with 656,417 Unit awards that is expected to be recognized over a weighted average period of 1.6 years. The total fair values of Units that vested during 2006, 2005, and 2004 were $7.6, $9.3 and $9.4, respectively. As of September 30, 2006, total liabilities of $13.9 associated with Unit awards are reflected in other current liabilities and other noncurrent liabilities in the Consolidated Balance Sheet.
At September 30, 2006, 1,896,508 shares of Common Stock were available for future grants under the OECP, of which up to 644,595 may be issued pursuant to grants other than stock options or dividend equivalents.
Other Equity-Based Compensation Plans and Awards.Under the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan (“2000 Propane Plan”), the General Partner may grant to key employees the right to receive a total of 500,000 AmeriGas Partners Common Units (“Common Units”), or cash equivalent to the fair market value of such Common Units. In addition, the 2000 Propane Plan authorizes the crediting of Partnership Common Unit distribution equivalents to participants’ accounts. Any distribution equivalents will be paid in cash. The actual number of Common Units (or their cash equivalent) ultimately issued, and the actual amount of distribution equivalents paid, is dependent upon the achievement of market performance goals and service conditions. Generally, each grant, unless paid, will terminate when the participant ceases to be employed by the General Partner. We also have a nonexecutive Common Unit plan under which the General Partner may grant awards of up to a total of 200,000 Common Units to key employees who do not participate in the 2000 Propane Plan.
50
UGI Corporation 2006 Annual Report
Generally, awards under the nonexecutive plan vest at the end of a three-year period and will be paid in Common Units and cash. The General Partner made awards under the 2000 Propane Plan and the nonexecutive plan representing 38,350, 41,100 and 51,200 Common Units in 2006, 2005 and 2004, respectively, having weighted-average grant date fair values per Common Unit of $35.33, $36.09 and $35.42, respectively. At September 30, 2006 and 2005, awards representing 113,517 and 116,000 Common Units, respectively, were outstanding. At September 30, 2006, 346,972 and 150,750 Common Units were available for future grants under the 2000 Propane Plan and the nonexecutive plan, respectively.
The following table illustrates AmeriGas Partners Common Unit award activity:
| Number of | Weighted-Average | |||||||
| AmeriGas Partners | Grant Date Fair | |||||||
| Common Units | Value (per Unit) | |||||||
| Non-vested Units — September 30, 2005 | 116,000 | $ | 31.81 | |||||
| Granted | 38,350 | $ | 35.33 | |||||
| Forfeited | (9,000 | ) | $ | 30.89 | ||||
| Vested | (6,750 | )(a) | $ | 23.20 | ||||
| Performance criteria not met | (25,083 | ) | $ | 30.43 | ||||
| Non-vested Units — September 30, 2006 | 113,517 | $ | 33.89 | |||||
| (a) | Represents awards under the non-executive plan of 4,500 that were settled through the issuance of new AmeriGas Partners Common Units and 2,250 that were settled in cash. |
As of September 30, 2006, there was a total of approximately $1.5 of unrecognized compensation cost associated with 113,517 Common Unit awards that is expected to be recognized over a weighted average period of 1.7 years. The total fair values of Common Units that vested during 2006, 2005, and 2004 were $0.2, $1.0 and $1.6, respectively. As of September 30, 2006, total liabilities of $2.2 associated with Common Unit awards are reflected in other current liabilities and other noncurrent liabilities in the Consolidated Balance Sheet.
Fair Value Information.The per share weighted-average fair value of stock options granted under our option plans was $3.88 in 2006, $2.81 in 2005 and $1.89 in 2004. 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 expected life of option awards represents the period of time which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on the historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on the historical UGI dividend rates. The risk free interest rate is based upon U.S. Treasury bonds with comparable terms to the options in effect on the date of grant.
The assumptions we used for option grants during 2006, 2005 and 2004 are as follows:
| 2006 | 2005 | 2004 | ||||||||||
| Expected life of option | 6 years | 6 years | 6 years | |||||||||
| Weighted-average volatility | 21.3% | 17.7% | 18.2% | |||||||||
| Weighted-average dividend yield | 3.4% | 4.1% | 4.9% | |||||||||
| Expected volatility | 21.2% - 22.6% | 17.1% - 17.8% | 17.6% - 18.4% | |||||||||
| Expected dividend yield | 2.8% - 3.4% | 3.7% - 4.2% | 4.4% - 5.0% | |||||||||
| Risk free interest rate | 4.3% - 4.9% | 3.9% - 4.3% | 3.5% - 4.4% | |||||||||
Stock Ownership Policy.Under the terms of our Stock Ownership Policy, executives and certain key employees are required to own UGI Common Stock in amounts ranging from 6,000 to 300,000 shares. Prior to the enactment of the Sarbanes-Oxley Act of 2002, we offered full recourse, interest-bearing loans to employees in order to assist them in meeting the ownership requirements. The Company is no longer offering loans under this program. At September 30, 2006 and 2005, there were no loans outstanding under this program. At September 30, 2004, loans outstanding totaled $0.2.
Note 9 — 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 are made 98% to limited partners and 2% to the General Partner. The Partnership may pay an incentive distribution to the General Partner if Available Cash exceeds the Minimum Quarterly Distribution of $0.55 and the First Target Distribution of $0.055 per unit on all units.
Note 10 — Commitments and Contingencies
We lease various buildings and other facilities and transportation, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $60.3 in 2006, $55.1 in 2005, and $50.4 in 2004.
Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows:
| After | ||||||||||||||||||||||||
| 2007 | 2008 | 2009 | 2010 | 2011 | 2011 | |||||||||||||||||||
| AmeriGas Propane | $ | 47.0 | $ | 40.6 | $ | 34.7 | $ | 29.6 | $ | 23.7 | $ | 50.7 | ||||||||||||
| UGI Utilities | 4.2 | 3.2 | 2.1 | 1.5 | 1.1 | 2.5 | ||||||||||||||||||
| International Propane and other | 3.9 | 2.5 | 0.7 | 0.2 | — | — | ||||||||||||||||||
| Total | $ | 55.1 | $ | 46.3 | $ | 37.5 | $ | 31.3 | $ | 24.8 | $ | 53.2 | ||||||||||||
Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation and natural gas storage services, which Gas Utility may terminate at various
51
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 10 continued
dates through 2016. Gas Utility’s costs associated with transportation and storage capacity agreements are included in its annual PGC filing with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices.
Electric Utility purchases its capacity requirements and electric energy needs under contracts with various suppliers and on the spot market. Contracts with producers for capacity and energy needs expire at various dates through fiscal 2011.
Energy Services enters into fixed price contracts with suppliers to purchase natural gas to meet its sales commitments. Generally, these contracts have terms of less than two years.
The Partnership enters into fixed-price and, from time to time, variable-priced contracts to purchase a portion of its supply requirements. These contracts generally have terms of less than one year.
International Propane, particularly Antargaz, enters into variable-priced contracts to purchase a portion of its supply requirements. Generally, these contracts have terms that do not exceed three years.
The following table presents contractual obligations under Gas Utility, Electric Utility, Energy Services, AmeriGas Propane and International Propane supply, storage and service contracts existing at September 30, 2006:
| After | ||||||||||||||||||||||||
| 2007 | 2008 | 2009 | 2010 | 2011 | 2011 | |||||||||||||||||||
| Gas Utility and Electric Utility supply, storage and transportation contracts | $ | 367.2 | $ | 157.1 | $ | 144.5 | $ | 84.0 | $ | 46.4 | $ | 86.9 | ||||||||||||
| Energy Services supply contracts | 548.1 | 113.1 | 0.3 | — | — | — | ||||||||||||||||||
| AmeriGas Propane supply contracts | 20.7 | — | — | — | — | — | ||||||||||||||||||
| International Propane supply contracts | 116.2 | 58.0 | 43.2 | — | — | — | ||||||||||||||||||
| Total | $ | 1,052.2 | $ | 328.2 | $ | 188.0 | $ | 84.0 | $ | 46.4 | $ | 86.9 | ||||||||||||
The Partnership and International Propane also enter into other contracts to purchase LPG to meet supply requirements. Generally, these contracts are one- to three-year agreements subject to annual review and call for payment based on either market prices at date of delivery or fixed prices.
On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired the propane distribution businesses of Columbia Energy Group (the “2001 Acquisition”) pursuant to the terms of a purchase agreement (the “2001 Acquisition Agreement”) by and among Columbia Energy Group (“CEG”), Columbia Propane Corporation (“Columbia Propane”), Columbia Propane, L.P. (“CPLP”), CP Holdings, Inc. (“CPH,” and together with Columbia Propane and CPLP, the “Company Parties”), AmeriGas Partners, AmeriGas OLP and the General Partner (together with AmeriGas Partners and AmeriGas OLP, the “Buyer Parties”). As a result of the 2001 Acquisition, AmeriGas OLP acquired all of the stock of Columbia Propane and CPH and substantially all of the partnership interests of CPLP. Under the terms of an earlier acquisition agreement (the “1999 Acquisition Agreement”), the Company Parties agreed to indemnify the former general partners of National Propane Partners, L.P. (a predecessor company of the Columbia Propane businesses) and an affiliate (collectively, “National General Partners”) against certain income tax and other losses that they may sustain as a result of the 1999 acquisition by CPLP of National Propane Partners, L.P. (the “1999 Acquisition”) or the operation of the business after the 1999 Acquisition (“National Claims”). At September 30, 2006, the potential amount payable under this indemnity by the Company Parties was approximately $58. These indemnity obligations will expire on the date that CPH acquires the remaining outstanding partnership interest of CPLP, which is expected to occur on or after July 19, 2009. Under the terms of the 2001 Acquisition Agreement, CEG agreed to indemnify the Buyer Parties and the Company Parties against any losses that they sustain under the 1999 Acquisition Agreement and related agreements (“Losses”), including National Claims, to the extent such claims are based on acts or omissions of CEG or the Company Parties prior to the 2001 Acquisition. The Buyer Parties agreed to indemnify CEG against Losses, including National Claims, to the extent such claims are based on acts or omissions of the Buyer Parties or the Company Parties after the 2001 Acquisition. CEG and the Buyer Parties have agreed to apportion certain losses resulting from National Claims to the extent such losses result from the 2001 Acquisition itself.
Samuel and Brenda Swiger and their son (the “Swigers”) sustained personal injuries and property damage as a result of a fire that occurred when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, allegedly resulting from the defendants’ failure to install underground propane lines at depths required by applicable safety standards. In 2003, AmeriGas OLP settled the individual personal injury and property damage claims of the Swigers. In 2004, the court granted the plaintiffs’ motion to include customers acquired from Columbia Propane in August 2001 as additional potential class members and the plaintiffs amended their complaint to name additional parties pursuant to such ruling. Subsequently, in March 2005, AmeriGas OLP filed a crossclaim against CEG, former owner of Columbia Propane, seeking indemnification for conduct undertaken by Columbia Propane prior to AmeriGas OLP’s acquisition. Class counsel has indicated that the class is seeking compensatory damages in excess of $12 plus punitive damages, civil penalties and attorneys’ fees. We believe we have good defenses to the claims of the class members and intend to defend against the remaining claims in this lawsuit.
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other
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UGI Corporation 2006 Annual Report
residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, UGI Utilities divested all of its utility operations other than those which now constitute UGI Gas and Electric Utility.
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. In accordance with existing regulatory practices of the PUC, PNG Gas currently amortizes as removal cost over a five-year period site-specific environmental investigation and remediation costs.
As a result of the acquisition of PG Energy by UGI Utilities’ wholly-owned subsidiary, UGIPNG, UGIPNG became party to a Multi-Site Remediation Consent Order and Agreement between PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform annually a specified level of activities associated with environmental investigation and remediation work at eleven currently owned properties on which MGP-related facilities were operated (“Properties”). Under the Multi-Site Agreement, UGIPNG is not required to spend more than $1.1 in any calendar year for such environmental expenditures, including costs to perform work on the Properties. Costs related to investigation and remediation of one property formerly owned by UGIPNG are also included in this cap. The Multi-Site Agreement terminates at the end of fifteen years but may be terminated by either party at the end of any two-year period beginning with the effective date.
UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating four claims against it relating to out-of-state sites. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.
On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for 47% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 in remediation costs and $26 in third-party claims relating to the site and estimates that future remediation costs could be as high as $2.5. SCE&G further asserts that it has received a demand from the United States Justice Department for natural resource damages. UGI Utilities believes that it has good defenses to this claim and is defending the suit.
In April 2003, Citizens Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District for the District of Maine. In that action, the plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18 to clean up the river. Citizens’ third party claims have been stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March 2005 that it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of Maine related to gas plant contaminants at this site. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. The amount of Citizens’ liability has not been finally determined. The court has stayed further proceedings while the City and Citizens discuss settlement. UGI Utilities believes that it has good defenses to Citizens’ claim and to any claim that the DEP may bring to recover its costs, and is defending the Citizens’ suit.
By letter dated July 29, 2003, Atlanta Gas Light Company (“AGL”) served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8 incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. On March 22, 2005, the trial court granted UGI Utilities’ motion for summary judgment. AGL appealed and on September 6, 2006, the Eleventh Circuit Court of Appeals affirmed the trial court’s entry of summary judgment, effectively terminating the case.
53
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 10 continued
AGL previously informed UGI Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL has informed UGI Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site.
On September 20, 2001, Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70.
The trial court granted UGI Utilities’ motion for summary judgment and dismissed ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court’s decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. On October 7, 2005, UGI Utilities filed for reconsideration of the panel’s order, which was denied by the Second Circuit Court of Appeals on January 17, 2006. On April 14, 2006, Utilities filed a petition requesting that the United States Supreme Court review the decision of the Second Circuit Court of Appeals. On October 2, 2006, the Supreme Court entered an order inviting the Solicitor General to file a brief expressing the views of the United States in this case.
By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10. KeySpan believes that the cost could be as high as $20. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together the “Northeast Companies”) in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215 and asserted that UGI Utilities is responsible for approximately $103 of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23. UGI Utilities believes that it has good defenses to this claim and is defending the suit.
French tax authorities levy various taxes on legal entities and individuals regularly operating a business in France which are commonly referred to collectively as “business tax.” The amount of business tax charged annually is generally dependent upon the value of the entity’s tangible fixed assets. Prior to the Antargaz Acquisition, Antargaz filed suit against French tax authorities in connection with the assessment of business tax related to certain of its owned tanks at customer locations. Elf Antar France and Elf Aquitaine, now Total France, former owners of Antargaz, agreed to indemnify Antargaz for all payments which would have been due from Antargaz in respect of the tax related to its tanks for the period from January 1, 1997 through December 31, 2000. During the year ended September 30, 2005, Antargaz was required to remit payment to the French tax authorities with respect to this matter and Antargaz was fully reimbursed pursuant to the indemnity agreement. The indemnity from the former owners is reflected in our balance sheet as both an asset and a liability. At September 30, 2006, the remaining amount subject to the indemnification is immaterial.
On February 4, 2005, Antargaz received a letter that was issued by the French government to the French Committee of Butane and Propane (“CFBP”), a butane/propane industry group, concerning the business tax, that eliminated the requirement for Antargaz to pay business tax associated with tanks at certain customer locations. In addition, during 2005 resolution was reached relating to business taxes relating to a prior year. Further changes in the French government or tax authorities’ interpretation of the tax laws or in the tax laws themselves, could have either an adverse or a favorable effect on our results of operations. Our 2005 Statement of Income includes a pre-tax gain of $18.8 and net after-tax gain of $14.2 associated with the resolution of business tax matters related principally to prior years.
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 and result in losses in excess of recorded amounts. We are
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UGI Corporation 2006 Annual Report
unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows.
Note 11 — Financial Instruments
In accordance with its commodity hedging policy, the Partnership uses derivative instruments, including price swap and option contracts and contracts for the forward sale of propane, to manage the cost of a portion of its forecasted purchases of propane and to manage market risk associated with propane storage inventories. These derivative instruments have been designated by the Partnership as cash flow or fair value hedges under SFAS 133. The fair values of these derivative instruments are affected by changes in propane product prices. In addition to these derivative instruments, the Partnership may also enter into contracts for the forward purchase of propane as well as fixed-price supply agreements to manage propane market price risk. These contracts generally qualify for the normal purchases and normal sales exception of SFAS 133 and therefore are not adjusted to fair value.
Flaga also uses derivative instruments, principally price swap contracts, to reduce market risk associated with purchases of LPG. These contracts may or may not qualify for hedge accounting under SFAS 133.
Antargaz uses forward foreign exchange contracts and may use other derivative instruments, similar to those used by the Partnership, to manage the cost of a portion of its forecasted purchases of LPG.
Energy Services uses exchange-traded and over-the-counter natural gas futures contracts to manage market risk associated with forecasted purchases of natural gas it sells under firm commitments. In addition, Energy Services uses price swap and option contracts to manage market risk associated with forecasted purchases of propane it sells under firm commitments. These derivative instruments are designated as cash flow hedges. The fair values of these futures and swap and option contracts are affected by changes in natural gas and propane prices.
In accordance with its commodity hedging policy, Gas Utility may enter into natural gas call option and futures contracts to reduce volatility in the cost of gas it purchases for its firm-residential, commercial and industrial (“retail core-market”) customers and Electric Utility may enter into electric swap agreements in order to reduce the volatility in the cost of anticipated electricity requirements. Because the cost of the natural gas option and futures contracts and any associated losses or gains will be included in Gas Utility’s PGC recovery mechanism, as these contracts are marked to fair value in accordance with SFAS 133, any losses or gains are deferred for future recovery from or refund to Gas Utility’s ratepayers.
We are a party to a number of contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts are not subject to the accounting requirements of SFAS 133 because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business or the value of the contract is directly associated with the price or value of a service.
We enter into interest rate protection agreements (“IRPAs”) designed to manage interest rate risk associated with planned issuances of fixed-rate long-term debt. We designate these IRPAs as cash flow hedges. Gains or losses on IRPAs are included in other comprehensive income and are reclassified to interest expense as the interest expense on the associated debt issue affects earnings.
Antargaz has entered into interest rate swap agreements to fix the variable interest rates on its Senior Facilities term loan through 2011.
During the years ended September 30, 2006, 2005 and 2004, amounts recognized in earnings representing cash flow hedge ineffectiveness were not material.
Gains and losses included in accumulated other comprehensive income at September 30, 2006 relating to cash flow hedges will be reclassified into (1) cost of sales when the forecasted purchase of LPG, natural gas or electricity subject to the hedges impacts net income and (2) interest expense when interest on anticipated issuances of fixed-rate long-term debt is reflected in net income. Included in accumulated other comprehensive income at September 30, 2006 are net after-tax losses of approximately $2.4 from IRPAs associated with forecasted issuances of debt generally anticipated to occur during the next several years and with settled IRPAs. The amount of this net loss that is expected to be reclassified into net income during the next twelve months is not material. Also included in accumulated other comprehensive income at September 30, 2006 are (1) net after-tax losses of approximately $25.0 principally associated with future purchases of natural gas and propane generally anticipated to occur during the next twelve months, (2) net after-tax gains of approximately $3.0 associated with future electric supply purchases expected to occur in 2007 and (3) gains of $1.6 associated with forecasted U.S. dollar-denominated purchases of LPG generally anticipated to occur during the next three years. The amount of the gains that is expected to be reclassified into net income during the next twelve months associated with the U.S. dollar-denominated purchases is not material. The actual amount of gains or losses on unsettled derivative instruments that ultimately is reclassified into net income will depend upon the value of such derivative contracts when settled. The fair value of derivative instruments is included in other current assets, other assets, other current liabilities and other noncurrent liabilities in the Consolidated Balance Sheets.
55
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 11 continued
The primary currency for which the Company has exchange rate risk is the euro. The U.S. dollar value of our foreign-denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investments in foreign subsidiaries. If a derivative is designated as a hedge of an investment in a foreign subsidiary and qualifies for hedge accounting, any realized gains or losses remain in other comprehensive income until such foreign operations have been liquidated. At September 30, 2006, a net after-tax loss of $0.6 is included in accumulated other comprehensive income associated with settled net investment hedges.
The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amounts and estimated fair values of our remaining financial instruments (including unsettled derivative instruments) at September 30 are as follows:
| Carrying | Estimated | |||||||
| Amount | Fair Value | |||||||
2006: | ||||||||
| Natural gas futures and options contracts | $ | (6.0 | ) | $ | (6.0 | ) | ||
| Electric supply swap | 5.2 | 5.2 | ||||||
| Propane swap and option contracts | (26.4 | ) | (26.4 | ) | ||||
| Interest rate protection and swap agreements | 14.4 | 14.4 | ||||||
| Foreign currency swaps | 2.4 | 2.4 | ||||||
| Long-term debt | 1,996.9 | 2,006.8 | ||||||
2005: | ||||||||
| Natural gas futures and options contracts | $ | (1.5 | ) | $ | (1.5 | ) | ||
| Electric supply swap | 6.1 | 6.1 | ||||||
| Propane swap and option contracts | 50.8 | 50.8 | ||||||
| Interest rate protection and swap agreements | (6.2 | ) | (6.2 | ) | ||||
| Foreign currency swaps | 7.5 | 7.5 | ||||||
| Long-term debt | 1,644.5 | 1,730.7 | ||||||
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. Fair values of derivative instruments reflect the estimated amounts that we would receive or pay to terminate the contracts at the reporting date based upon quoted market prices of comparable contracts at September 30, 2006 and 2005.
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, money market mutual funds and securities guaranteed by the U.S. Government or its agencies. The credit risk from trade accounts receivable is limited because we have a large customer base, which extends across many different U.S. markets and several foreign countries. We attempt to minimize the credit risk associated with our derivative financial instruments through the application of credit policies.
Note 12 — Energy Services Accounts Receivable Securitization Facility
UGI Energy Services, Inc. (“ESI”) has a $200 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper expiring in April 2009, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers. Prior to September 2006, ESI’s Receivables Facility was $150. In order to provide additional short-term liquidity during the peak heating season due to increased energy product costs, the maximum level of funding available at any one time from this facility was temporarily increased to $300 for the period from November 1, 2005 to April 24, 2006.
Under the Receivables Facility, ESI transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of ESI and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following the provisions of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” ESI continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC.
During 2006 and 2005, ESI sold trade receivables totaling $1,306.0 and $1,253.6, respectively, to ESFC. During 2006 and 2005, ESFC sold an aggregate $859.5 and $475.5, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At September 30, 2006, the outstanding balance of ESFC trade receivables was $24.1 which is net of $60.5 that was sold to the commercial paper conduit and removed from the balance sheet. At September 30, 2005, the outstanding balance of ESFC trade receivables was $77.8 which is net of $23.5 that was sold to the commercial paper conduit and removed from the balance sheet. Losses on sales of receivables to the commercial paper conduit that occurred during the years ended September 30, 2006, 2005 and 2004, which are included in other income, net, were $3.3, $0.9 and $0.4, respectively.
In addition, a major bank has committed to issue up to $50 of standby letters of credit, secured by cash or marketable securities (“LC Facility”). Energy Services expects to fund the collateral requirements with borrowings under its Receivables Facility. The LC Facility expires April 2007.
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UGI Corporation 2006 Annual Report
Note 13 — Other Income, Net
Other income (loss), net, comprises the following:
| 2006 | 2005 | 2004 | ||||||||||
| Interest and interest-related income | $ | 15.8 | $ | 6.3 | $ | 3.2 | ||||||
| Utility non-tariff service income | 1.0 | 1.3 | 2.0 | |||||||||
| Gain (loss) on sales of fixed assets | (0.1 | ) | 3.4 | 0.1 | ||||||||
| Gain on sale of Energy Ventures | 9.1 | — | — | |||||||||
| Foreign currency hedge loss | — | — | (9.1 | ) | ||||||||
| Finance charges | 8.4 | 7.6 | 6.5 | |||||||||
| French business tax reversal | — | 19.9 | — | |||||||||
| Other | 2.6 | 8.2 | 7.5 | |||||||||
| Total other income, net | $ | 36.8 | $ | 46.7 | $ | 10.2 | ||||||
Note 14 — AmeriGas Partners Common Unit Issuances
Gains on sales of AmeriGas Partners Common Unit issuances are determined in accordance with the guidance in SEC Staff Accounting Bulletin No. 51, “Accounting for Sales of Common Stock by a Subsidiary” (“SAB 51”). Gains result when the public offering price of the AmeriGas Partners Common Units exceeds the associated carrying amount of our investment in the Partnership on the date of sale.
In September 2005, AmeriGas Partners sold 2,300,000 Common Units in an underwritten public offering at a public offering price of $33.00 per unit. The net proceeds of the public offering totaling $72.7 and the associated capital contributions from the General Partner totaling $1.5 were contributed to AmeriGas OLP, and used to reduce indebtedness under its bank credit agreement and for general partnership purposes. Concurrent with this sale of Common Units, the Company recorded a gain in the amount of $28.0 which is reflected in the Company’s balance sheet as an increase in common stockholders’ equity and a corresponding decrease in minority interests in AmeriGas Partners in accordance with the guidance in SAB 51. The gain had no effect on the Company’s net income or cash flow. Total deferred income tax liabilities of $16.0 associated with this gain with a corresponding decrease to stockholders’ equity were recorded and reflected in the Consolidated Balance Sheet at September 30, 2005.
On May 26, 2004, AmeriGas Partners sold 2,000,000 Common Units in an underwritten public offering at a public offering price of $25.61 per unit. On June 10, 2004, the underwriters partially exercised their overallotment option in the amount of 100,000 Common Units. The net proceeds of the public offering totaling $51.2 and associated capital contributions from the General Partner totaling $1.0 were contributed to AmeriGas OLP and used to reduce indebtedness under its bank credit agreement and for general partnership purposes. Concurrent with this sale of Common Units, the Company recorded a gain in the amount of $12.2 which is reflected in the Company’s balance sheet as an increase in common stockholders’ equity. Deferred income tax liabilities of $6.6 associated with this gain with a corresponding decrease in common stockholders’ equity were recorded and reflected in the Consolidated Balance Sheet at September 30, 2004. The gain had no effect on the Company’s net income or cash flow.
Note 15 — Investments in Equity Investees
Our principal investments accounted for using the equity method and our approximate percentage ownership interest in each at September 30, 2006 and 2005 are as follows:
| Company | 2006 | 2005 | ||||||
| ZLH (a) | 50.0 | % | N/A | |||||
| China Gas Partners | 50.0 | % | 50.0 | % | ||||
| Energy Ventures (b) | N/A | 50.0 | % | |||||
| Geovexin | 44.9 | % | 44.9 | % | ||||
| (a) | Flaga entered into this joint venture in February 2006 (see Note 2). | |
| (b) | Energy Services sold its 50% ownership interest in Energy Ventures in March 2006 (see Note 2). |
(Loss) income from our equity investees was $(2.2) in 2006, $(2.6) in 2005 and $11.3 in 2004. Income from our equity investees in 2004 reflect our 19.5% ownership interest in Antargaz until March 31, 2004 (see Note 2). Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2006, 2005 or 2004. Summarized financial information for our equity investments are not presented because they are not material to our Consolidated Balance Sheets or Consolidated Statements of Income.
57
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 16 — Quarterly Data (unaudited)
The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate because of the seasonal nature of our businesses.
| December 31, | March 31, | June 30, | September 30, | |||||||||||||||||||||||||||||
| 2005 | 2004 | (a) | 2006 | (b) | 2005 | 2006 | (c) | 2005 | (d) | 2006 | 2005 | |||||||||||||||||||||
| Revenues | $ | 1,577.9 | $ | 1,362.4 | $ | 1,845.5 | $ | 1,787.7 | $ | 919.1 | $ | 932.5 | $ | 878.5 | $ | 806.1 | (e) | |||||||||||||||
| Operating income | $ | 160.2 | $ | 175.0 | $ | 262.6 | $ | 287.7 | $ | 38.5 | $ | 37.6 | $ | 6.4 | $ | 2.7 | ||||||||||||||||
| Income (loss) from equity investees | $ | (0.6 | ) | $ | (0.7 | ) | $ | (0.6 | ) | $ | (0.6 | ) | $ | — | $ | (0.7 | ) | $ | (1.0 | ) | $ | (0.6 | ) | |||||||||
| Net income (loss) | $ | 57.5 | $ | 78.2 | $ | 104.0 | $ | 117.3 | $ | 18.7 | $ | 0.7 | $ | (4.0 | ) | $ | (8.7 | ) | ||||||||||||||
| Earnings (loss) per share: | ||||||||||||||||||||||||||||||||
| Basic | $ | 0.55 | $ | 0.76 | $ | 0.99 | $ | 1.13 | $ | 0.18 | $ | 0.01 | $ | (0.04 | ) | $ | (0.08 | ) | ||||||||||||||
| Diluted | $ | 0.54 | $ | 0.74 | $ | 0.98 | $ | 1.12 | $ | 0.18 | $ | 0.01 | $ | (0.04 | ) | $ | (0.08 | ) | ||||||||||||||
| (a) | Includes the effects of the resolution of certain Antargaz business tax contingencies which increased operating income by $19.9 and net income by $14.9 or $0.14 per diluted share. | |
| (b) | Includes a gain on the sale of our 50% ownership interest in Energy Ventures which increased net income by $5.3 or $0.05 per diluted share and a loss on early extinguishments of AmeriGas Propane’s debt which decreased net income by $4.6 or $0.04 per diluted share. | |
| (c) | Includes the effects of changes in management’s estimate of taxes to be paid associated with planned repatriation of foreign earnings which increased net income by approximately $5.0 or $0.05 per diluted share. | |
| (d) | Includes a loss on early extinguishment of AmeriGas Propane’s debt which increased net loss by $9.4 or $0.09 per diluted share. | |
| (e) | Revenues reflect the elimination of fiscal year 2005 intercompany transactions of approximately $124. |
Note 17 — Segment Information
We have organized our business units into six reportable segments generally based upon products sold, geographic location (domestic or international) and regulatory environment. Our reportable segments are: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment comprising Flaga and our international propane equity investments (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Energy Services. We refer to both international segments collectively as “International Propane.”
AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers from locations in 46 states. Our International Propane segments’ revenues are derived principally from the distribution of LPG to retail customers in France and Austria. Gas Utility’s revenues are derived principally from the sale and distribution of natural gas to customers in eastern Pennsylvania. Electric Utility derives its revenues principally from the distribution of electricity in two northeastern Pennsylvania counties. Energy Services revenues are derived from the sale of natural gas and, to a lesser extent, LPG, electricity and fuel oil to customers located primarily in the eastern region of the United States.
The accounting policies of our reportable segments are the same as those described in Note 1. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. The Company’s definition of Partnership EBITDA may be different from that used by other companies. We evaluate the performance of our International Propane, Gas Utility, Electric Utility and Energy Services segments principally based upon their income (loss) before income taxes.
No single customer represents more than ten percent of our consolidated revenues. In addition, all of our reportable segments’ revenues, other than those of our International Propane segments, are derived from sources within the United States, and all of our reportable segments’ long-lived assets, other than those of our International Propane segments, are located in the United States.
58
UGI Corporation 2006 Annual Report
Financial information by reportable business segment follows:
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| International Propane | ||||||||||||||||||||||||||||||||||||
| AmeriGas | Gas | Electric | Energy | International | Corporate & | |||||||||||||||||||||||||||||||
| Total | Eliminations | Propane | Utility | Utility | Services | Antargaz | Other (b) | Other (c) | ||||||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||
| Revenues | $ | 5,221.0 | $ | (156.1 | )(d) | $ | 2,119.3 | $ | 724.0 | $ | 98.0 | $ | 1,414.3 | $ | 881.9 | $ | 63.6 | $ | 76.0 | |||||||||||||||||
| Cost of sales | $ | 3,657.9 | $ | (152.3 | )(d) | $ | 1,343.8 | $ | 522.9 | $ | 51.0 | $ | 1,328.2 | $ | 478.4 | $ | 38.8 | $ | 47.1 | |||||||||||||||||
| Operating income | $ | 467.7 | $ | — | $ | 184.1 | $ | 84.2 | $ | 20.7 | $ | 53.1 | $ | 115.4 | $ | 3.9 | $ | 6.3 | ||||||||||||||||||
| Income (loss) from equity investees | (2.2 | ) | — | — | — | — | — | (1.6 | ) | (0.6 | ) | — | ||||||||||||||||||||||||
| Loss on extinguishments of debt | (18.5 | ) | — | (17.1 | ) | — | — | — | (1.4 | ) | — | — | ||||||||||||||||||||||||
| Interest expense | (123.6 | ) | — | (74.1 | ) | (21.8 | ) | (2.5 | ) | — | (23.1 | ) | (1.7 | ) | (0.4 | ) | ||||||||||||||||||||
| Minority interests | (48.7 | ) | (0.4 | ) | (51.3 | ) | — | — | — | 3.0 | — | — | ||||||||||||||||||||||||
| Income before income taxes | $ | 274.7 | $ | (0.4 | ) | $ | 41.6 | $ | 62.4 | $ | 18.2 | $ | 53.1 | $ | 92.3 | $ | 1.6 | $ | 5.9 | |||||||||||||||||
| Depreciation and amortization | $ | 148.7 | $ | — | $ | 72.5 | $ | 23.3 | $ | 3.3 | $ | 6.7 | $ | 38.2 | $ | 3.9 | $ | 0.8 | ||||||||||||||||||
| Partnership EBITDA (a) | $ | 237.9 | $ | |||||||||||||||||||||||||||||||||
| Total assets | $ | 5,080.5 | $ | (340.7 | ) | $ | 1,627.2 | $ | 1,504.3 | $ | 105.3 | $ | 238.5 | $ | 1,406.8 | $ | 183.4 | $ | 355.7 | |||||||||||||||||
| Capital expenditures | $ | 191.7 | $ | — | $ | 70.7 | $ | 49.2 | $ | 9.0 | $ | 7.0 | $ | 47.9 | $ | 7.6 | $ | 0.3 | ||||||||||||||||||
| Investments in equity investees | $ | 58.2 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 58.2 | $ | — | ||||||||||||||||||
| Goodwill | $ | 1,418.2 | $ | (4.0 | ) | $ | 619.1 | $ | 182.9 | $ | — | $ | 11.8 | $ | 560.7 | $ | 40.9 | $ | 6.8 | |||||||||||||||||
2005 | ||||||||||||||||||||||||||||||||||||
| Revenues | $ | 4,888.7 | $ | (124.1 | )(d) | $ | 1,963.3 | $ | 585.1 | $ | 96.1 | $ | 1,355.0 | $ | 869.9 | $ | 74.0 | $ | 69.4 | |||||||||||||||||
| Cost of sales | $ | 3,306.0 | $ | (120.0 | )(d) | $ | 1,220.0 | $ | 390.1 | $ | 47.8 | $ | 1,281.4 | $ | 401.5 | $ | 42.6 | $ | 42.6 | |||||||||||||||||
| Operating income | $ | 503.0 | $ | — | $ | 168.1 | $ | 81.6 | $ | 21.6 | $ | 37.5 | $ | 188.3 | (e) | $ | 5.5 | $ | 0.4 | |||||||||||||||||
| Income (loss) from equity investees | (2.6 | ) | — | — | — | — | — | (2.5 | ) | (0.1 | ) | — | ||||||||||||||||||||||||
| Loss on extinguishments of debt | (33.6 | ) | — | (33.6 | ) | — | — | — | — | — | — | |||||||||||||||||||||||||
| Interest expense | (130.2 | ) | — | (79.8 | ) | (16.6 | ) | (1.7 | ) | — | (28.6 | ) | (2.9 | ) | (0.6 | ) | ||||||||||||||||||||
| Minority interests | (29.9 | ) | 3.9 | (33.1 | ) | — | — | — | (0.7 | ) | — | — | ||||||||||||||||||||||||
| Income before income taxes | $ | 306.7 | $ | 3.9 | $ | 21.6 | $ | 65.0 | $ | 19.9 | $ | 37.5 | $ | 156.5 | (e) | $ | 2.5 | $ | (0.2 | ) | ||||||||||||||||
| Depreciation and amortization | $ | 146.4 | $ | — | $ | 73.7 | $ | 20.7 | $ | 3.1 | $ | 5.7 | $ | 37.6 | $ | 4.9 | $ | 0.7 | ||||||||||||||||||
| Partnership EBITDA (a) | $ | 215.9 | ||||||||||||||||||||||||||||||||||
| Total assets | $ | 4,571.5 | $ | (348.1 | ) | $ | 1,672.9 | $ | 803.6 | $ | 99.8 | $ | 296.1 | $ | 1,404.8 | $ | 152.4 | $ | 490.0 | |||||||||||||||||
| Capital expenditures | $ | 158.4 | $ | — | $ | 62.6 | $ | 38.8 | $ | 7.5 | $ | 6.2 | $ | 38.5 | $ | 3.5 | $ | 1.3 | ||||||||||||||||||
| Investments in equity investees | $ | 12.8 | $ | — | $ | — | $ | — | $ | — | $ | 8.5 | $ | 1.6 | $ | 2.7 | $ | — | ||||||||||||||||||
| Goodwill | $ | 1,231.2 | $ | (4.0 | ) | $ | 618.2 | $ | — | $ | — | $ | 11.8 | $ | 531.4 | $ | 67.5 | $ | 6.3 | |||||||||||||||||
2004 | ||||||||||||||||||||||||||||||||||||
| Revenues | $ | 3,784.7 | $ | — | $ | 1,775.9 | $ | 560.4 | $ | 89.7 | $ | 967.2 | $ | 270.8 | $ | 62.6 | $ | 58.1 | ||||||||||||||||||
| Cost of sales | $ | 2,551.0 | $ | — | $ | 1,029.2 | $ | 368.9 | $ | 43.3 | $ | 912.2 | $ | 130.1 | $ | 32.0 | $ | 35.3 | ||||||||||||||||||
| Operating income | $ | 331.3 | $ | — | $ | 176.0 | $ | 80.1 | $ | 20.9 | $ | 31.1 | $ | 15.1 | $ | 5.4 | $ | 2.7 | ||||||||||||||||||
| Income (loss) from equity investees | 11.3 | — | 0.7 | — | — | — | 10.8 | (0.2 | ) | — | ||||||||||||||||||||||||||
| Interest expense | (119.1 | ) | — | (83.1 | ) | (15.9 | ) | (2.0 | ) | — | (14.0 | ) | (3.6 | ) | (0.5 | ) | ||||||||||||||||||||
| Minority interests | (47.5 | ) | — | (47.7 | ) | — | — | — | 0.1 | 0.1 | — | |||||||||||||||||||||||||
| Income before income taxes | $ | 176.0 | $ | — | $ | 45.9 | $ | 64.2 | $ | 18.9 | $ | 31.1 | $ | 12.0 | $ | 1.7 | $ | 2.2 | ||||||||||||||||||
| Depreciation and amortization | $ | 132.3 | $ | — | $ | 80.7 | $ | 19.5 | $ | 3.0 | $ | 4.0 | $ | 18.5 | $ | 5.5 | $ | 1.1 | ||||||||||||||||||
| Partnership EBITDA (a) | $ | 255.9 | $ | |||||||||||||||||||||||||||||||||
| Total assets | $ | 4,242.6 | $ | (322.1 | ) | $ | 1,567.9 | $ | 765.5 | $ | 89.7 | $ | 182.8 | $ | 1,352.3 | $ | 156.2 | $ | 450.3 | |||||||||||||||||
| Capital expenditures | $ | 133.7 | $ | — | $ | 61.7 | $ | 35.5 | $ | 5.3 | $ | 2.9 | $ | 23.6 | $ | 4.0 | $ | 0.7 | ||||||||||||||||||
| Investments in equity investees | $ | 20.0 | $ | — | $ | 3.5 | $ | — | $ | — | $ | 9.6 | $ | 4.1 | $ | 2.8 | $ | — | ||||||||||||||||||
| Goodwill | $ | 1,245.9 | $ | — | $ | 608.2 | $ | — | $ | — | $ | 2.8 | $ | 561.6 | $ | 68.2 | $ | 5.1 | ||||||||||||||||||
| (a) | The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income: |
| Year ended September 30, | 2006 | 2005 | 2004 | |||||||||
| Partnership EBITDA (i) | $ | 237.9 | $ | 215.9 | $ | 255.9 | ||||||
| Depreciation and amortization (ii) | (72.5 | ) | (73.6 | ) | (80.6 | ) | ||||||
| Minority interests (iii) | 1.6 | 1.3 | 1.4 | |||||||||
| Income (loss) from equity investees | — | — | (0.7 | ) | ||||||||
| Intercompany gain on sale of Atlantic Energy | — | (9.1 | ) | — | ||||||||
| Loss on extinguishments of debt | 17.1 | 33.6 | — | |||||||||
| Operating income | $ | 184.1 | $ | 168.1 | $ | 176.0 | ||||||
| (i) | Includes $9.1 gain on the sale of Atlantic Energy to Energy Services during Fiscal 2005. See Note 2. | |
| (ii) | Excludes General Partner depreciation and amortization of $0.1 in both 2005 and 2004. | |
| (iii) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
| (b) | International Other principally comprises Flaga, its joint-venture business, ZLH, and our joint-venture business in China. | |
| (c) | Corporate & Other results of operations principally comprise UGI Enterprises’ HVAC/R operations, net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses, and interest income. Corporate & Other assets principally comprise cash and short-term investments and an intercompany loan. The intercompany interest associated with the intercompany loan is eliminated in the segment presentation. | |
| (d) | Represents the elimination of intersegment transactions primarily associated with Energy Services’ revenues from sales to Gas Utility and AmeriGas Propane totaling $101.0 and $37.3 in 2006, respectively, and $89.2 and $25.9 in 2005, respectively. | |
| (e) | International Propane-Antargaz’ operating income and income before income taxes for Fiscal 2005 include $18.8 associated with the resolution of certain business tax contingencies (see Note 10). |
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