Exhibit 99.2
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) discusses our results of operations and our financial condition. MD&A should be read in conjunction with our Items 1 & 2, “Business and Properties,” our Item 1A, “Risk Factors” and our Consolidated Financial Statements in Item 8 below including “Segment Information” included in Note 21 to Consolidated Financial Statements.
Executive Overview
Our net income attributable to UGI Corporation in Fiscal 2009 was $258.5 million, an increase of 20% over Fiscal 2008 net income attributable to UGI Corporation of $215.5 million. A number of factors contributed to this improved performance. The most significant contributor to the improved performance was a substantial year-over-year decline in LPG commodity costs both in the U.S. and in our International Propane operations. Commodity prices for LPG declined precipitously as we entered our critical winter heating season in the first quarter of Fiscal 2009 following a significant increase in LPG prices during most of the second half of Fiscal 2008. As a result of the declines in LPG commodity prices, our AmeriGas Propane and International Propane businesses realized higher than normal retail unit margins. Although LPG commodity prices rose modestly later in Fiscal 2009 from earlier Fiscal 2009 low levels, U.S. propane commodity prices at the end of Fiscal 2009 were approximately 35% lower than at September 30, 2008, and propane prices in Europe at the end of Fiscal 2009 were approximately 29% lower than at the end of Fiscal 2008. Also contributing to improved performance during Fiscal 2009, most of our domestic and international business units experienced weather that was, to varying degrees, colder than in Fiscal 2008. Our Gas Utility results in Fiscal 2009 were better than in Fiscal 2008 in large part reflecting accretive income from the operations of CPG Gas acquired on October 1, 2008. During Fiscal 2009, CPG Gas and PNG Gas filed separate requests with the PUC to increase base operating revenues. We received PUC approval of increased rates that went into effect in late August 2009. The combined increases in annual base rate revenues approved totaled $29.8 million. Due to the timing of the new rates, they did not have a material impact on our Fiscal 2009 results. Results in Fiscal 2009 also benefited from the Partnership’s November 2008 sale of its California LPG storage facility which increased net income attributable to UGI Corporation by $10.4 million.
Partially offsetting the previously-mentioned contributions to our net income attributable to UGI Corporation in Fiscal 2009 were lower results from Energy Services and Electric Utility, a charge associated with the Antargaz Competition Authority Matter and the global recession’s effects on general economic activity in all of our business units. Lower and less volatile commodity prices for natural gas and a general decline in demand for electricity due in large part to the economic recession resulted in lower electricity prices in Fiscal 2009. These lower prices resulted in reduced margins from spot sales of electricity. In addition, Energy Services’ electricity generation volumes were reduced by higher production outages and electric generation expenses were higher in Fiscal 2009 due in part to charges related to obligations associated with its ongoing Hunlock Station repowering project. Electric Utility results declined in Fiscal 2009 reflecting the impact of the recession on volumes sold and higher purchased power costs. Our Fiscal 2009 net income attributable to UGI Corporation was also reduced by a $10.0 million charge at Antargaz based on our initial assessment of a Statement of Objections received from France’s Competition Authority.
The U.S. dollar was stronger versus the euro in Fiscal 2009 compared to Fiscal 2008. Although the stronger dollar generally resulted in lower translated International Propane operating results, the effects of the stronger dollar on reported International Propane net income attributable to UGI Corporation were substantially offset by gains on forward currency contracts used to hedge purchases of dollar-denominated LPG.
Looking ahead, our results in Fiscal 2010 will be influenced by a number of factors including heating-season temperatures in our business units, the length and severity of the global recession on economic activity, and the level and volatility of commodity prices for natural gas, LPG and electricity. As previously mentioned, the precipitous decline in LPG commodity prices principally during the first quarter of Fiscal 2009 resulted in higher than normal unit margins in our AmeriGas Propane and International Propane businesses. We expect that average retail unit margins in Fiscal 2010 in our International Propane business will be lower than the average unit margins realized in Fiscal 2009 when LPG commodity prices declined significantly entering our critical winter heating season. At Energy Services, sustained low prices for electricity sales would continue to negatively impact results. At UGI Utilities, our Electric Utility’s default service settlement with the PUC, which becomes effective January 1, 2010, allows for the recovery of prudently incurred electricity costs but eliminates the opportunity for Electric Utility to realize revenue in excess of such costs on electricity sales. This will result in a reduction in Electric Utility’s Fiscal 2010 operating income.
1
We believe that each of our business units has sufficient liquidity in the form of revolving credit facilities, letters of credit and guarantee agreements to fund business operations for the foreseeable future. Due in large part to declining commodity prices for LPG and natural gas, Fiscal 2009 cash flow was stronger than Fiscal 2008 as our total investment in working capital, principally accounts receivable and inventories, declined. We do not have significant amounts of long-term debt maturing or revolving credit agreements terminating at our major business units until late in Fiscal 2011.
Results of Operations
The following analyses compare the Company’s results of operations for (1) Fiscal 2009 with Fiscal 2008 and (2) Fiscal 2008 with the year ended September 30, 2007 (“Fiscal 2007”).
Fiscal 2009 Compared with Fiscal 2008
Consolidated Results
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:
| Variance- Favorable | ||||||||||||||||||||||||
| Fiscal 2009 | Fiscal 2008 | (Unfavorable) | ||||||||||||||||||||||
| % of | % of | % | ||||||||||||||||||||||
| (Millions of dollars) | Amount | Total | Amount | Total | Amount | Change | ||||||||||||||||||
| AmeriGas Propane | $ | 65.0 | 25.1 | % | $ | 43.9 | 20.4 | % | $ | 21.1 | 48.1 | % | ||||||||||||
| International Propane | 78.3 | 30.3 | % | 52.3 | 24.3 | % | 26.0 | 49.7 | % | |||||||||||||||
| Gas Utility | 70.3 | 27.2 | % | 60.3 | 28.0 | % | 10.0 | 16.6 | % | |||||||||||||||
| Electric Utility | 8.0 | 3.1 | % | 13.1 | 6.1 | % | (5.1 | ) | (38.9 | )% | ||||||||||||||
| Energy Services | 38.1 | 14.7 | % | 45.3 | 21.0 | % | (7.2 | ) | (15.9 | )% | ||||||||||||||
| Corporate & Other | (1.2 | ) | (0.4 | )% | 0.6 | 0.2 | % | (1.8 | ) | N.M. | ||||||||||||||
| Total Net Income Attributable to UGI Corporation | $ | 258.5 | 100.0 | % | $ | 215.5 | 100.0 | % | $ | 43.0 | 20.0 | % | ||||||||||||
N.M. — Variance is not meaningful.
Highlights — Fiscal 2009 versus Fiscal 2008
| • | Higher unit margins at AmeriGas Propane and Antargaz reflect significant declines in LPG commodity prices entering our critical heating season. |
| • | Most of our business units experienced Fiscal 2009 heating-season temperatures that were to varying degrees colder than in Fiscal 2008. |
| • | Fiscal 2009 Gas Utility results include the benefit of the CPG Acquisition on October 1, 2008. |
| • | AmeriGas Partners’ sale of its California LPG storage terminal generated net income attributable to UGI Corporation of $10.4 million. |
| • | The global economic recession reduced overall business activity in all of our business units. |
| • | International Propane results reflect a $10.0 million charge for the Antargaz Competition Authority Matter. |
| • | Energy Services’ results were adversely impacted by lower income from electricity generation. |
| • | Electric Utility results were lower reflecting the effects of higher cost of sales and lower demand as a result of the recession. |
Our consolidated results of operations for the years ended September 30, 2009, 2008 and 2007 include the effects of the Financial Accounting Standards Board’s accounting guidance for the presentation of noncontrolling interests in consolidated financial statements. For further discussion see Note 3 to consolidated financial statements.
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| Increase | ||||||||||||||||
| AmeriGas Propane | 2009 | 2008 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 2,260.1 | $ | 2,815.2 | $ | (555.1 | ) | (19.7 | )% | |||||||
| Total margin (a) | $ | 943.6 | $ | 906.9 | $ | 36.7 | 4.0 | % | ||||||||
| Partnership EBITDA (b) | $ | 381.4 | $ | 313.0 | $ | 68.4 | 21.9 | % | ||||||||
| Operating income | $ | 300.5 | $ | 235.0 | $ | 65.5 | 27.9 | % | ||||||||
| Retail gallons sold (millions) | 928.2 | 993.2 | (65.0 | ) | (6.5 | )% | ||||||||||
| Degree days — % (warmer) than normal (c) | (2.5 | )% | (3.0 | )% | — | — | ||||||||||
| (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) 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 segment (see Note 21 to Consolidated Financial Statements). | |
| (c) | Deviation from average heating degree-days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. Fiscal 2008 data has been adjusted to correct a NOAA error. |
Based upon heating degree-day data, average temperatures in our service territories during Fiscal 2009 were 2.5% warmer than normal compared with temperatures in the prior year that were 3.0% warmer than normal. Fiscal 2009 retail gallons sold were 6.5% lower than Fiscal 2008 reflecting, among other things, the adverse effects of the significant deterioration in general economic activity which has occurred over the last year and continued customer conservation. During Fiscal 2009, average wholesale propane commodity prices at Mont Belvieu, Texas, one of the major supply points in the U.S., were more than 50% lower than such prices in Fiscal 2008. The decrease in the average wholesale commodity prices in Fiscal 2009 reflects the effects of a precipitous decline in commodity propane prices principally during the first quarter of Fiscal 2009 following a substantial increase in prices during most of the second half of Fiscal 2008. Although wholesale propane prices in Fiscal 2009 rebounded modestly from prices experienced earlier in the year, at September 30, 2009 such prices remained approximately 35% lower than at September 30, 2008.
Retail propane revenues declined $463.2 million in Fiscal 2009 reflecting a $303.6 million decrease as a result of the lower retail volumes sold and a $159.6 million decrease due to lower average selling prices. Wholesale propane revenues declined $69.5 million reflecting an $83.7 million decrease from lower wholesale selling prices partially offset by a $14.2 million increase from higher wholesale volumes sold. Total cost of sales decreased $591.8 million to $1,316.5 million principally reflecting the effects of the previously mentioned lower propane commodity prices and the lower volumes sold.
Total margin was $36.7 million greater in Fiscal 2009 reflecting the beneficial impact of higher than normal retail unit margins resulting from the previously mentioned rapid decline in propane commodity costs that occurred primarily as we entered the critical winter heating season in the first quarter of Fiscal 2009. The increase in total propane margin was partially offset by lower terminal revenue and ancillary sales and fee income.
The $68.4 million increase in Fiscal 2009 Partnership EBITDA reflects the effects of a $39.9 million pre-tax gain from the November 2008 sale of the Partnership’s California LPG storage facility and the previously mentioned $36.7 million increase in total margin. These increases were partially offset by slightly higher operating and administrative expenses and slightly lower other income. The slightly higher operating and administrative expenses reflects, in large part, higher compensation and benefit expenses, higher costs associated with facility maintenance projects and higher litigation and self insured liability and casualty charges offset principally by lower vehicle fuel expenses (due to lower propane, diesel and gasoline prices) and lower Fiscal 2009 uncollectible accounts expense.
3
Operating income increased $65.5 million in Fiscal 2009 reflecting the previously mentioned $68.4 million increase in EBITDA partially offset by slightly higher depreciation and amortization expense associated with acquisitions and plant and equipment expenditures made since the prior year.
| Increase | ||||||||||||||||
| International Propane | 2009 (a) | 2008 | (Decrease) | |||||||||||||
| (Millions of euros) | ||||||||||||||||
| Revenues | € | 712.7 | € | 749.8 | € | (37.1 | ) | (4.9 | )% | |||||||
| Total margin (b) | € | 392.7 | € | 314.9 | € | 77.8 | 24.7 | % | ||||||||
| Operating income | € | 116.3 | € | 70.4 | € | 45.9 | 65.2 | % | ||||||||
| Income before income taxes | € | 95.3 | € | 48.8 | € | 46.5 | 95.3 | % | ||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 955.3 | $ | 1,124.8 | $ | (169.5 | ) | (15.1 | )% | |||||||
| Total margin (b) | $ | 525.8 | $ | 472.9 | $ | 52.9 | 11.2 | % | ||||||||
| Operating income | $ | 151.4 | $ | 106.8 | $ | 44.6 | 41.8 | % | ||||||||
| Income before income taxes | $ | 122.0 | $ | 73.0 | $ | 49.0 | 67.1 | % | ||||||||
| Antargaz retail gallons sold | 289.3 | 292.6 | (3.3 | ) | (1.1 | )% | ||||||||||
| Degree days — % (warmer) than normal (c) | (2.9 | )% | (4.1 | )% | — | — | ||||||||||
| (a) | Reflects the consolidation of ZLH subsequent to Flaga’s January 2009 acquisition of the 50% of ZLH it did not already own. | |
| (b) | Total margin represents total revenues less total cost of sales. | |
| (c) | Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30 locations in our French service territory. |
Based upon heating degree day data, temperatures in Antargaz’ service territory were approximately 2.9% warmer than normal during Fiscal 2009 compared with temperatures that were approximately 4.1% warmer than normal during Fiscal 2008. Temperatures in Flaga’s service territory were warmer than normal and warmer than Fiscal 2008. Wholesale propane product costs declined significantly during late Fiscal 2008 and the first quarter of Fiscal 2009 as we entered the critical winter heating season. As a result, the average wholesale commodity price for propane in northwest Europe in Fiscal 2009 was approximately 41% lower than such price in Fiscal 2008. Similar declines in average wholesale butane prices were experienced in Fiscal 2009. Antargaz’ Fiscal 2009 retail LPG volumes were slightly lower than in Fiscal 2008 reflecting the colder Fiscal 2009 weather offset by the effects of the deterioration of general economic conditions in France, customer conservation and competition from alternate energy sources.
Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. During Fiscal 2009, the average currency translation rate was $1.35 per euro compared to a rate of $1.51 per euro during Fiscal 2008. Although the stronger dollar resulted in lower translated International Propane operating results, the effects of the stronger dollar on reported International Propane net income attributable to UGI Corporation were substantially offset by gains on forward currency contracts used to hedge purchases of dollar-denominated LPG.
International Propane euro-based revenues decreased€37.1 million or 4.9% in Fiscal 2009 reflecting lower average selling prices partially offset by an increase in revenues from the consolidation of ZLH. The lower average selling prices reflect the previously mentioned year-over-year decrease in wholesale LPG product costs. In U.S. dollars, revenues declined $169.5 million or 15.1% reflecting the previously mentioned total lower euro-based revenues and the effects of the stronger U.S. dollar. International Propane’s total cost of sales decreased to€320.0 million in Fiscal 2009 from€434.9 million in Fiscal 2008, a 26.4% decline, principally reflecting the lower per-unit LPG commodity costs and, to a much lesser extent, the effects of gains on forward currency contracts used to hedge purchases of dollar-denominated LPG. On a U.S. dollar basis, cost of sales decreased $222.4 million or 34.1%.
4
International Propane euro-based total margin increased€77.8 million or 24.7% in Fiscal 2009 largely reflecting the beneficial impact of higher than normal retail unit margins at Antargaz resulting from the rapid and sharp decline in LPG commodity costs that occurred as we entered the winter heating season in the first quarter of Fiscal 2009 and, to a lesser extent, incremental total margin from the consolidation of ZLH beginning in January 2009. Also affecting the year-over-year comparison was the fact that Antargaz was adversely affected by lower unit margins in Fiscal 2008 as a result of the rapid increase in LPG product costs which occurred in Fiscal 2008. In U.S. dollars, total margin increased $52.9 million or 11.2% reflecting the effects of the stronger dollar on translated euro base-currency revenues and cost of sales.
International Propane euro-based operating income increased€45.9 million or 65.2% in Fiscal 2009 principally reflecting the previously mentioned increase in total margin reduced by a€7.1 million charge related to a French Competition Authority Matter (as further described below under “Antargaz Competition Authority Matter”) and higher operating and administrative costs. The higher operating and administrative costs principally resulted from the consolidation of the operations of ZLH and, to a much lesser extent, higher operating expenses at Antargaz. On a U.S. dollar basis, operating income increased $44.6 million or 41.8% reflecting the previously-mentioned increase in U.S. dollar-denominated total margin and lower U.S. dollar-denominated operating and administrative expenses and depreciation and amortization partially offset by the $10.0 million charge related to the Antargaz Competition Authority Matter. Euro-based income before income taxes was€46.5 million (95.3%) greater than in the prior year principally reflecting the higher operating income and lower average effective interest rates on Antargaz’ term loan. In U.S. dollars, income before income taxes increased $49.0 million (67.1%) reflecting the benefit of the higher dollar-denominated operating income and lower Antargaz interest expense including the effects of the stronger dollar. Loss from International Propane equity investees was higher in Fiscal 2009 due to expenditures associated with the anticipated closure of an LPG storage facility.
| Gas Utility | 2009 | 2008 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,241.0 | $ | 1,138.3 | $ | 102.7 | 9.0 | % | ||||||||
| Total margin (a) | $ | 387.8 | $ | 307.2 | $ | 80.6 | 26.2 | % | ||||||||
| Operating income | $ | 153.5 | $ | 137.6 | $ | 15.9 | 11.6 | % | ||||||||
| Income before income taxes | $ | 111.3 | $ | 100.5 | $ | 10.8 | 10.7 | % | ||||||||
| System throughput — billions of cubic feet (“bcf”) | 149.7 | 133.7 | 16.0 | 12.0 | % | |||||||||||
| Degree days — % colder (warmer) than normal (b) | 4.1 | % | (2.7 | )% | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Deviation from average heating degree days for the 15-year period 1990–2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory. |
Temperatures in the Gas Utility service territory based upon heating degree days were 4.1% colder than normal in Fiscal 2009 compared with temperatures that were 2.7% warmer than normal in Fiscal 2008. In Fiscal 2009, Gas Utility began calculating normal degree days using the 15-year period 1990-2004. Previously, normal degree days were based upon recent 30-year periods. For comparison purposes, the Fiscal 2008 weather variance has been recalculated using the new 15-year period. Total distribution throughput increased 16.0 bcf in Fiscal 2009 principally reflecting the effects of the October 1, 2008 CPG Acquisition and increases in core-market volumes resulting from the colder Fiscal 2009 weather and year-over-year customer growth. Gas Utility’s core-market customers principally comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers. These increases in system throughput were partially offset by the effects on volumes sold and transported due to lower demand from commercial and industrial customers as a result of the deterioration in general economic activity and customer conservation.
5
Gas Utility revenues increased $102.7 million in Fiscal 2009 principally reflecting $187.4 million of incremental revenues from CPG Gas largely offset by lower revenues from low-margin off-system sales. Increases or decreases in retail core-market revenues and cost of sales principally result 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 amounts 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 this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $853.2 million in Fiscal 2009 compared with $831.1 million in Fiscal 2008 principally reflecting incremental cost of sales of $117.0 million associated with CPG Gas partially offset principally by the cost of sales effect of the lower off-system sales.
Gas Utility total margin increased $80.6 million in Fiscal 2009 principally reflecting incremental margin from CPG Gas and higher total core-market margin resulting from the higher core-market volumes sold.
The increase in Gas Utility operating income during Fiscal 2009 principally reflects the previously mentioned greater total margin partially offset by higher operating and administrative and depreciation expenses, principally incremental expenses associated with CPG Gas, and, to a lesser extent, higher pension expense, costs associated with environmental matters and greater distribution system maintenance expenses. Income before income taxes also increased reflecting the previously mentioned higher operating income partially offset by higher interest expense associated with $108 million Senior Notes issued to finance a portion of the CPG Acquisition.
| Electric Utility | 2009 | 2008 | Decrease | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 138.5 | $ | 139.2 | $ | (0.7 | ) | (0.5 | )% | |||||||
| Total margin (a) | $ | 39.3 | $ | 47.0 | $ | (7.7 | ) | (16.4 | )% | |||||||
| Operating income | $ | 15.4 | $ | 24.4 | $ | (9.0 | ) | (36.9 | )% | |||||||
| Income before income taxes | $ | 13.7 | $ | 22.4 | $ | (8.7 | ) | (38.8 | )% | |||||||
| Distribution sales — millions of kilowatt hours (“gwh”) | 965.7 | 1,004.4 | (38.7 | ) | (3.9 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $7.6 million and $7.9 million during Fiscal 2009 and Fiscal 2008, 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 kilowatt-hour sales in Fiscal 2009 were lower than in Fiscal 2008. Temperatures based upon heating degree days in Electric Utility’s service territory were approximately 5.0% colder than last year resulting in greater sales to Electric Utility’s residential heating customers. These greater sales were more than offset, however, by lower sales to commercial and industrial customers as a result of the deterioration in general economic activity and lower weather-related air-conditioning sales during the summer of Fiscal 2009. Notwithstanding the lower sales, Electric Utility revenues were about equal with last year as a result of higher POLR rates and greater revenues from spot market sales of electricity. Electric Utility cost of sales increased to $91.6 million in Fiscal 2009 from $84.3 million in Fiscal 2008 principally reflecting greater purchased power costs.
Electric Utility total margin decreased $7.7 million during Fiscal 2009 principally reflecting the higher cost of sales and the effects of the lower sales volumes.
6
Electric Utility operating income and income before income taxes in Fiscal 2009 were $9.0 million and $8.7 million lower than in Fiscal 2008, respectively, reflecting the previously mentioned lower total margin and higher operating and administrative costs including higher customer assistance expenses and greater pension expense.
| Increase | ||||||||||||||||
| Energy Services | 2009 | 2008 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,224.7 | $ | 1,619.5 | $ | (394.8 | ) | (24.4 | )% | |||||||
| Total margin (a) | $ | 126.2 | $ | 124.1 | $ | 2.1 | 1.7 | % | ||||||||
| Operating income | $ | 64.8 | $ | 77.3 | $ | (12.5 | ) | (16.2 | )% | |||||||
| Income before income taxes | $ | 64.8 | $ | 77.3 | $ | (12.5 | ) | (16.2 | )% | |||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Energy Services total revenues declined $394.8 million or 24.4% in Fiscal 2009 principally reflecting the effects on revenues of lower unit prices for natural gas, electricity and propane due to year-over-year declines in such energy commodity prices.
Total margin from Energy Services increased $2.1 million in Fiscal 2009 reflecting greater total margin principally from peaking supply services and retail electricity sales partially offset by lower electric generation total margin. The decrease in electric generation total margin reflects lower spot-market prices for electricity and lower volumes generated due in large part to electricity generation facility outages. The decrease in Energy Service’s operating income and income before income taxes in Fiscal 2009 largely reflects the previously mentioned increase in total margin more than offset by higher electric generation operating and maintenance costs and charges related to obligations associated with its ongoing Hunlock Station repowering project, and higher asset management costs. The decrease in operating income and income before income taxes also reflects greater costs associated with Energy Service’s receivables securitization facility as a result of higher amounts needed to fund futures brokerage account margin calls and greater facility fees subsequent to the renewal of the securitization facility in April 2009.
Interest Expense and Income Taxes.Consolidated interest expense decreased slightly to $141.1 million in Fiscal 2009 from $142.5 million in Fiscal 2008 principally due to lower International Propane interest expense, attributable to lower effective interest rates and the stronger U.S. dollar, lower interest on UGI Utilities revolving credit agreement borrowings and lower interest expense on AmeriGas Propane long-term debt largely offset by incremental interest expense on CPG Acquisition debt. Our effective income tax rate was slightly lower in Fiscal 2009 reflecting the effects of a higher percentage of pretax income from noncontrolling interests, principally in AmeriGas Partners, not subject to income taxes.
Fiscal 2008 Compared with Fiscal 2007
Consolidated Results
Consolidated Results
Net Income Attributable to UGI Corporation by Business Units:
| Variance- Favorable | ||||||||||||||||||||||||
| Fiscal 2008 | Fiscal 2007 | (Unfavorable) | ||||||||||||||||||||||
| % of | % of | % | ||||||||||||||||||||||
| (Millions of dollars) | Amount | Total | Amount | Total | Amount | Change | ||||||||||||||||||
| AmeriGas Propane | $ | 43.9 | 20.4 | % | $ | 53.2 | 26.0 | % | $ | (9.3 | ) | (17.5 | )% | |||||||||||
| International Propane | 52.3 | 24.3 | % | 44.9 | 22.0 | % | 7.4 | 16.5 | % | |||||||||||||||
| Gas Utility | 60.3 | 28.0 | % | 59.0 | 28.9 | % | 1.3 | 2.2 | % | |||||||||||||||
| Electric Utility | 13.1 | 6.1 | % | 13.7 | 6.7 | % | (0.6 | ) | (4.4 | )% | ||||||||||||||
| Energy Services | 45.3 | 21.0 | % | 34.5 | 16.9 | % | 10.8 | 31.3 | % | |||||||||||||||
| Corporate & Other | 0.6 | 0.2 | % | (1.0 | ) | (0.5 | )% | 1.6 | N.M. | |||||||||||||||
| Total Net Income Attributable to UGI Corporation | $ | 215.5 | 100.0 | % | $ | 204.3 | 100.0 | % | $ | 11.2 | 5.5 | % | ||||||||||||
N.M. — Variance is not meaningful.
7
Highlights — Fiscal 2008 versus Fiscal 2007
| • | Energy Services Fiscal 2008 results benefited from greater income from peaking supply and storage management services and higher electric generation margin. |
| • | Fiscal 2008 International Propane results improved driven by a return to more normal weather compared with the record-setting warm weather experienced in Fiscal 2007. |
| • | Significant increases in LPG cost during most of Fiscal 2008 caused all propane businesses to experience increased conservation and certain of our International Propane business units to experience modest unit margin reductions. |
| • | AmeriGas Propane total margin was higher in Fiscal 2008 despite the effects of price-induced customer conservation on volumes sold. |
| Increase | ||||||||||||||||
| AmeriGas Propane | 2008 | 2007 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 2,815.2 | $ | 2,277.4 | $ | 537.8 | 23.6 | % | ||||||||
| Total margin (a) | $ | 906.9 | $ | 840.2 | $ | 66.7 | 7.9 | % | ||||||||
| Partnership EBITDA (b) | $ | 313.0 | $ | 338.7 | $ | (25.7 | ) | (7.6 | )% | |||||||
| Operating income | $ | 235.0 | $ | 265.8 | $ | (30.8 | ) | (11.6 | )% | |||||||
| Retail gallons sold (millions) | 993.2 | 1,006.7 | (13.5 | ) | (1.3 | )% | ||||||||||
| Degree days — % (warmer) than normal (c) | (3.0 | )% | (6.5 | )% | — | — | ||||||||||
| (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) 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 segment (see Note 21 to Consolidated Financial Statements). | |
| (c) | Deviation from average heating degree-days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. Fiscal 2008 data has been adjusted to correct a NOAA error. |
Based upon heating degree-day data, average temperatures in AmeriGas Propane’s service territories were 3.0% warmer than normal in Fiscal 2008 compared with temperatures that were 6.5% warmer than normal in Fiscal 2007. Notwithstanding the slightly colder Fiscal 2008 weather and the full year benefits of acquisitions made in Fiscal 2007, retail gallons sold were slightly lower reflecting, among other things, customer conservation in response to increasing propane product costs and a weak economy. The average wholesale propane product cost at Mont Belvieu, Texas, increased nearly 50% during Fiscal 2008 over the average cost during Fiscal 2007.
Retail propane revenues increased $480.7 million in Fiscal 2008 reflecting a $507.0 million increase due to the higher average selling prices partially offset by a $26.3 million decrease as a result of the lower retail volumes sold. Wholesale propane revenues increased $47.8 million in Fiscal 2008 reflecting a $55.1 million increase from higher average wholesale selling prices partially offset by a $7.3 million decrease from lower wholesale volumes sold. Other revenues increased $9.3 million reflecting in large part higher fee income. Total cost of sales increased $471.1 million to $1,908.3 million in Fiscal 2008 reflecting higher propane product costs.
Total margin was $66.7 million greater in Fiscal 2008 principally reflecting higher average propane margin per retail gallon sold and, to a much lesser extent, higher fee income.
8
Partnership EBITDA in Fiscal 2008 was $313.0 million compared to EBITDA of $338.7 million in Fiscal 2007. Fiscal 2007 EBITDA includes $46.1 million resulting from the sale of the Partnership’s Arizona storage facility. Excluding the effects of this gain in Fiscal 2007, EBITDA in Fiscal 2008 increased $20.4 million over Fiscal 2007 principally reflecting the previously mentioned increase in total margin partially offset by a $47.9 million increase in operating and administrative expenses. The increased operating expenses reflect expenses associated with acquisitions, increased vehicle fuel and maintenance expenses, greater general insurance expense and, to a lesser extent, higher uncollectible accounts expenses largely attributable to the higher revenues.
AmeriGas Propane’s operating income decreased $30.8 million in Fiscal 2008 reflecting the lower EBITDA and higher depreciation and amortization expense resulting from the full-year effects of Fiscal 2007 propane business acquisitions and plant and equipment expenditures.
| Increase | ||||||||||||||||
| International Propane | 2008 | 2007 | (Decrease) | |||||||||||||
| (Millions of euros) | ||||||||||||||||
| Revenues | € | 749.8 | € | 602.4 | € | 147.4 | 24.5 | % | ||||||||
| Total margin (a) | € | 314.9 | € | 309.8 | € | 5.1 | 1.6 | % | ||||||||
| Operating income | € | 70.4 | € | 73.3 | € | (2.9 | ) | (4.0 | )% | |||||||
| Income before income taxes | € | 48.8 | € | 51.4 | € | (2.6 | ) | (5.1 | )% | |||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,124.8 | $ | 800.4 | $ | 324.4 | 40.5 | % | ||||||||
| Total margin (a) | $ | 472.9 | $ | 411.8 | $ | 61.1 | 14.8 | % | ||||||||
| Operating income | $ | 106.8 | $ | 94.5 | $ | 12.3 | 13.0 | % | ||||||||
| Income before income taxes | $ | 73.0 | $ | 64.1 | $ | 8.9 | 13.9 | % | ||||||||
| Antargaz retail gallons sold (millions) | 292.6 | 269.1 | 23.5 | 8.7 | % | |||||||||||
| Degree days — % (warmer) than normal (b) | (4.1 | )% | (21.1 | )% | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30 locations in our French service territory. |
Based upon heating degree-day data, temperatures in Antargaz’ service territory were approximately 4.1% warmer than normal during Fiscal 2008 compared with temperatures that were approximately 21.1% warmer than normal during Fiscal 2007. Temperatures in Flaga’s service territory were also warmer than normal and significantly colder than the prior year. Principally as a result of the colder weather, Antargaz’ retail volumes sold increased to 292.6 million gallons in Fiscal 2008 from 269.1 million gallons in Fiscal 2007. Flaga also recorded higher retail gallons sold in Fiscal 2008. The beneficial volume effects on Antargaz resulting from the colder weather were partially offset by customer conservation in response to substantially higher LPG commodity costs, the loss of a low-margin industrial customer and a weaker economy. The average wholesale price for propane in northwest Europe during Fiscal 2008 was nearly 35% higher than such average price in Fiscal 2007.
During Fiscal 2008, the average currency translation rate was $1.51 per euro compared to a rate of $1.34 during Fiscal 2007. The effects of the weaker dollar on year-over-year International Propane net income attributable to UGI Corporation were substantially offset, however, by the impact of losses on forward currency contracts used to purchase dollar denominated LPG.
International propane euro-based revenues increased€147.4 million principally reflecting higher Antargaz and Flaga average selling prices during Fiscal 2008 and the higher Antargaz and Flaga retail volumes sold. International Propane’s total cost of sales increased to€434.9 million in Fiscal 2008 from€ 292.6 million in Fiscal 2007, largely reflecting the higher per-unit LPG commodity costs, the greater volumes sold and, to a much lesser extent, higher losses on forward currency contracts.
International Propane total margin increased€5.1 million or 1.6% in Fiscal 2008 reflecting the effects of the greater retail sales of LPG substantially offset by a decline in average retail unit margin per gallon primarily due to the significantly higher LPG commodity costs and increased competition in certain customer segments at Antargaz. In U.S. dollars, total margin increased $61.1 million or 14.8% principally reflecting the effects of the weaker dollar on translated euro base-currency revenues and cost of sales.
9
International Propane euro-based operating income decreased€2.9 million principally reflecting the previously mentioned€5.1 million increase in total margin more than offset by higher operating and administrative expenses, due in large part to the effects of the increased sales activity and higher fuel costs, and greater depreciation from plant and equipment additions. On a U.S. dollar basis, operating income increased $12.3 million as the previously-mentioned $61.1 million increase in total margin was substantially offset by higher U.S. dollar denominated operating and administrative expenses and depreciation and amortization expense. Euro-based income before income taxes was€2.6 million lower than last year primarily reflecting the lower operating income. In U.S. dollars, income before income taxes was $8.9 million higher than the prior year reflecting the higher operating income slightly offset by greater U.S. dollar translated interest expense. Although Flaga’s results, including those of ZLH, improved in Fiscal 2008 due in large part to the colder weather, ZLH continued to experience the effects on sales volumes of customer conservation and competition from alternative fuels and other suppliers caused in large part by high and increasing LPG commodity costs.
| Gas Utility | 2008 | 2007 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,138.3 | $ | 1,044.9 | $ | 93.4 | 8.9 | % | ||||||||
| Total margin (a) | $ | 307.2 | $ | 303.4 | $ | 3.8 | 1.3 | % | ||||||||
| Operating income | $ | 137.6 | $ | 136.6 | $ | 1.0 | .7 | % | ||||||||
| Income before income taxes | $ | 100.5 | $ | 96.7 | $ | 3.8 | 3.9 | % | ||||||||
| System throughput — billions of cubic feet (“bcf”) | 133.7 | 131.8 | 1.9 | 1.4 | % | |||||||||||
| Degree days — % (warmer) than normal (b) | (2.7 | )% | (2.4 | )% | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory. |
Temperatures in the Gas Utility service territory based upon heating degree days were 2.7% warmer than normal in Fiscal 2008 compared with temperatures that were 2.4% warmer than normal in Fiscal 2007. Total distribution system throughput increased 1.9 bcf in Fiscal 2008 principally reflecting greater interruptible delivery service volumes (principally volumes associated with low margin cogeneration customers) and an increase in the number of Gas Utility core market customers partially offset by lower average usage per customer due in large part to price-induced customer conservation and a weak economy.
Gas Utility revenues increased $93.4 million in Fiscal 2008 principally reflecting a $57.4 million increase in revenues from off-system sales and the effects of higher average PGC rates on retail core-market revenues. Gas Utility’s cost of sales was $831.1 million in Fiscal 2008 compared with $741.5 million in Fiscal 2007 principally reflecting the greater off-system sales and the increase in average retail core-market PGC rates.
Gas Utility total margin increased $3.8 million in Fiscal 2008 primarily reflecting modest increases in interruptible delivery service and core market total margin.
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The increase in Gas Utility operating income principally reflects the previously mentioned $3.8 million increase in total margin and a $5.3 million increase in other income partially offset by modestly higher operating and administrative expenses. The higher other income reflects in large part greater storage contract fees and a $2.2 million postretirement benefit plan curtailment gain. The increase in operating and administrative expenses includes, among other things, higher environmental legal costs and greater uncollectible accounts expense. Gas Utility income before income taxes also reflects lower interest expense on bank loans.
| Increase | ||||||||||||||||
| Electric Utility | 2008 | 2007 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 139.2 | $ | 121.9 | $ | 17.3 | 14.2 | % | ||||||||
| Total margin (a) | $ | 47.0 | $ | 47.3 | $ | (0.3 | ) | (0.6 | )% | |||||||
| Operating income | $ | 24.4 | $ | 26.0 | $ | (1.6 | ) | (6.2 | )% | |||||||
| Income before income taxes | $ | 22.4 | $ | 23.6 | $ | (1.2 | ) | (5.1 | )% | |||||||
| Distribution sales — millions of kilowatt hours (“gwh”) | 1,004.4 | 1,010.6 | (6.2 | ) | (0.6 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $7.9 million and $6.9 million during Fiscal 2008 and Fiscal 2007, 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 kilowatt-hour sales in Fiscal 2008 were about equal to Fiscal 2007 on heating-season weather that was slightly warmer and cooling-season weather that was slightly cooler. Electric Utility revenues increased $17.3 million principally as a result of higher POLR rates. Electric Utility cost of sales increased to $84.3 million in Fiscal 2008 from $67.8 million in the prior year principally reflecting higher per-unit purchased power costs.
Electric Utility total margin in Fiscal 2008 was about equal to Fiscal 2007 reflecting the effects of the higher POLR rates offset principally by the higher per-unit purchased power costs and higher revenue-related taxes.
The decrease in Fiscal 2008 Electric Utility operating income reflects slightly higher operating and administrative costs including higher system maintenance and uncollectible accounts expense. Income before income taxes reflects the lower operating income partially offset by lower interest expense on bank loans.
| Energy Services | 2008 | 2007 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,619.5 | $ | 1,336.1 | $ | 283.4 | 21.2 | % | ||||||||
| Total margin (a) | $ | 124.1 | $ | 100.9 | $ | 23.2 | 23.0 | % | ||||||||
| Operating income | $ | 77.3 | $ | 57.4 | $ | 19.9 | 34.7 | % | ||||||||
| Income before income taxes | $ | 77.3 | $ | 57.4 | $ | 19.9 | 34.7 | % | ||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Notwithstanding retail gas volumes in Fiscal 2008 that were approximately equal to the prior-year period, Energy Services revenues increased $283.4 million principally reflecting the effects of higher commodity costs for natural gas and propane, higher electricity spot-market and fixed contract prices, and higher revenues from peaking supply services.
Total margin from Energy Services was $23.2 million higher in Fiscal 2008 reflecting greater total margin from peaking supply and storage management services, due in part to the expansion of peaking facilities and higher peaking rates charged, and higher electric generation margin resulting in large part from higher spot-market and fixed contract prices for electricity in Fiscal 2008 compared with Fiscal 2007. The increase in Energy Service’s operating income and income before income taxes in Fiscal 2008 principally reflects the previously mentioned $23.2 million increase in total margin partially offset by slightly higher operating and administrative expenses.
Interest Expense and Income Taxes.Consolidated interest expense increased to $142.5 million in Fiscal 2008 from $139.6 million in Fiscal 2007 principally due to higher interest expense associated with greater Partnership short-term borrowings to fund increases in working capital principally as a result of higher commodity prices for propane during Fiscal 2008 and the effects of foreign exchange on International Propane interest expense. Our effective income tax rate in Fiscal 2008 was slightly higher than in Fiscal 2007 reflecting the effects of a lower percentage of pretax income from noncontrolling interests, principally in AmeriGas Partners, not subject to income taxes.
11
Financial Condition and Liquidity
We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with proceeds from credit facilities or, in the case of Energy Services, a receivables securitization facility. These facilities are further described below. Long-term cash needs are generally met through issuance of long-term debt or equity securities.
Our cash and cash equivalents, excluding cash included in commodity futures brokerage accounts that are restricted from withdrawal, totaled $280.1 million at September 30, 2009 compared with $245.2 million of such cash and cash equivalents at September 30, 2008. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30, 2009 and 2008 UGI had $102.7 million and $97.2 million, respectively, of cash and cash equivalents. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.
The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business units.
AmeriGas Propane’s ability to pay dividends to UGI is dependent upon distributions it receives from AmeriGas Partners. At September 30, 2009, our 44% effective ownership interest in the Partnership consisted of approximately 24.7 million Common Units and combined 2% general partner interests. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Fourth 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 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 the Partnership’s control including weather, competition in markets it serves, the cost of propane and capital market conditions.
During Fiscal 2009, Fiscal 2008 and Fiscal 2007, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:
| Year Ended September 30, | 2009 | 2008 | 2007 | |||||||||
| (Millions of dollars) | ||||||||||||
| AmeriGas Propane | $ | 39.3 | $ | 38.6 | $ | 53.8 | ||||||
| UGI Utilities | 61.2 | 68.8 | 40.0 | |||||||||
| International Propane | 39.0 | 45.8 | 53.5 | |||||||||
| Energy Services | — | 18.4 | 6.1 | |||||||||
| Total | $ | 139.5 | $ | 171.6 | $ | 153.4 | ||||||
Dividends from AmeriGas Propane in Fiscal 2009 and Fiscal 2007 include the benefit of one-time $0.17 and $0.25 per Common Unit increases in the August 2009 and August 2007 quarterly distributions resulting from Fiscal 2009 and Fiscal 2007 sales of Partnership storage facilities, respectively (see below and Note 4 to Consolidated Financial Statements). Due to greater cash required for capital project expenditures, Energy Services did not pay dividends to UGI in Fiscal 2009 and received capital contributions from UGI totaling $46.8 million.
On April 29, 2009, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.20 per common share or $0.80 per common share on an annual basis. This quarterly dividend reflects an approximate 4% increase from the previous quarterly dividend rate of $0.1925. The new quarterly dividend rate was effective with the dividend paid on July 1, 2009 to shareholders of record on June 15, 2009. On April 28, 2009, the General Partner’s Board of Directors approved a Partnership distribution of $0.67 per Common Unit equal to an annual rate of $2.68 per Common Unit. This quarterly distribution reflects an increase of approximately 5% from the previous quarterly distribution rate of $0.64 per Common Unit. The new quarterly rate was effective with the distribution paid on May 18, 2009 to unitholders of record on May 8, 2009. On July 27, 2009, the General Partner’s Board of Directors approved a distribution of $0.84 per Common Unit payable on August 18, 2009 to unitholders of record on August 10, 2009. This distribution included the regular quarterly distribution of $0.67 per Common Unit and an additional $0.17 per Common Unit reflecting a one-time distribution of a portion of the proceeds from the Partnership’s November 2008 sale of its California storage facility.
12
Long-term Debt and Credit Facilities
The Company’s debt outstanding at September 30, 2009 totaled $2,296.2 million (including current maturities of long-term debt of $94.5 million) compared to $2,205.5 million of debt outstanding (including current maturities of long-term debt of $81.8 million) at September 30, 2008. Total debt outstanding at September 30, 2009 reflects the issuance of $108 million of UGI Utilities Senior Notes in conjunction with the CPG Acquisition. Total debt outstanding at September 30, 2009 principally consists of $865.6 million of Partnership debt, $622.9 million (€425.6 million) of International Propane debt, $794 million of UGI Utilities’ debt, and $13.7 million of other debt.
Due to the seasonal nature of the Company’s businesses, operating cash flows 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 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. During Fiscal 2009, Fiscal 2008 and Fiscal 2007, Antargaz generally funded its operating cash flow needs without using its revolving credit facility.
AmeriGas Partners.AmeriGas Partners’ total debt at September 30, 2009 includes long-term debt comprising $779.7 million of AmeriGas Partners’ Senior Notes, $80.0 million of AmeriGas OLP First Mortgage Notes and $5.9 million of other long-term debt. At September 30, 2009, there were no borrowings outstanding under AmeriGas OLP’s revolving credit agreements. In March 2009, AmeriGas OLP repaid $70 million of maturing First Mortgage Notes with cash generated from operations.
AmeriGas OLP’s Credit Agreement expires on October 15, 2011 and consists of (1) a $125 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. 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.
In order to provide for increased liquidity principally for cash collateral requirements, on April 17, 2009, AmeriGas OLP entered into a $75 million unsecured revolving credit facility (“2009 AmeriGas Supplemental Credit Agreement”) with three major banks. The 2009 AmeriGas Supplemental Credit Agreement expires on July 1, 2010 and permits AmeriGas OLP to borrow up to $75 million for working capital and general purposes.
There were no borrowings outstanding under the credit agreements at September 30, 2009. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce the amount available for borrowings, totaled $37.0 million at September 30, 2009. 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. The average daily and peak bank loan borrowings outstanding under the credit agreements in Fiscal 2009 were $43.8 million and $184.5 million, respectively. The average daily and peak bank loan borrowings outstanding under the AmeriGas OLP Credit Agreement in Fiscal 2008 were $39.1 million and $106.0 million, respectively. The higher peak bank loan borrowings in Fiscal 2009 resulted from the need to fund counterparty cash collateral obligations associated with derivative financial instruments used by the Partnership to manage market price risk associated with fixed sales price commitments to customers. These collateral obligations resulted from the precipitous decline in propane commodity prices that occurred early in Fiscal 2009. At September 30, 2009, the Partnership’s available borrowing capacity under the credit agreements was $238.0 million.
Based upon existing cash balances, cash expected to be generated from operations and borrowings available under AmeriGas OLP’s credit agreements, the Partnership’s management believes that the Partnership will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2010. For a more detailed discussion of the Partnership’s credit facilities, see Note 5 to Consolidated Financial Statements.
13
International Propane.International Propane’s total debt at September 30, 2009 includes long-term debt principally comprising $556.1 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan and $54.1 million (€37.0 million) outstanding under Flaga’s term loans. International Propane debt outstanding at September 30, 2009 also includes combined borrowings of $9.1 million (€6.2 million) under Flaga’s working capital facilities and $3.6 million (€2.5 million) of other long-term debt.
Antargaz. Antargaz has a five-year, floating rate Senior Facilities Agreement that expires on March 31, 2011. The Senior Facilities Agreement consists of (1) a€380 million variable-rate term loan and (2) a€50 million revolving credit facility. Antargaz executed interest rate swap agreements to fix the underlying euribor rate of interest on the term loan at approximately 3.25% for the duration of the loan. The effective interest rate on Antargaz’ term loan at September 30, 2009 was 3.94%. The Senior Facilities Agreement also includes a€50 million letter of credit facility. In order to minimize the interest margin it pays on Senior Facilities Agreement borrowings, in September 2008 Antargaz borrowed€50 million ($70.4 million), the total amount available under its revolving credit facility, which amount remained outstanding at September 30, 2008. This amount is included in bank loans on the September 30, 2008 Consolidated Balance Sheet. This borrowing was repaid by Antargaz on October 27, 2008. Excluding this borrowing in September 2008, no other amounts were borrowed under Antargaz’ revolving credit facility during Fiscal 2009 or Fiscal 2008.
The Senior Facilities Agreement restricts the ability of Antargaz to, among other things, incur additional indebtedness and make investments. For a more detailed discussion of Antargaz’ debt, see Note 5 to Consolidated Financial Statements.
Antargaz’ management believes that it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2010 with cash generated from operations, borrowings under its revolving credit facility and guarantees under its letter of credit facility.
Flaga. Flaga has two euro-based, amortizing variable-rate term loans. The principal outstanding on the first term loan was€30 million ($43.9 million) at September 30, 2009. Flaga has effectively fixed the euribor component of its interest rate on this term loan through September 2011 at 3.91% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2009 was 4.28%. The second euro-based variable-rate term loan, executed in August 2009, had an outstanding principal balance of€7 million ($10.2 million) on September 30, 2009. This term loan matures in June 2014. Flaga has effectively fixed the euribor component of its interest rate on this term loan at 2.16% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2009 was 5.03%.
Flaga has two working capital facilities totaling€24 million. Flaga has a multi-currency working capital facility that provides for borrowings and issuances of guarantees totaling€16 million of which€2.1 million ($3.0 million) was outstanding at September 30, 2009. Flaga also has an€8 million euro-denominated working capital facility of which€4.1 million ($6.1 million) was outstanding at September 30, 2009. Issued and outstanding guarantees, which reduce available borrowings under the working capital facilities, totaled€2.7 million ($3.9 million) at September 30, 2009. Amounts outstanding under the working capital facilities are classified as bank loans. During Fiscal 2009 and Fiscal 2008, peak bank loan borrowings totaled€18.6 million and€6.9 million, respectively. Average daily bank loan borrowings during Fiscal 2009 and Fiscal 2008 were€11.5 million and€5.6 million, respectively. For a more detailed discussion of Flaga’s debt, see Note 5 to Consolidated Financial Statements.
Based upon cash generated from operations, borrowings under its working capital facilities and capital contributions from UGI, Flaga’s management believes it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2010.
UGI Utilities.UGI Utilities’ total debt at September 30, 2009 includes long-term debt comprising $383 million of Senior Notes and $257 million of Medium-Term Notes. Total debt outstanding at September 30, 2009 also includes $154 million outstanding under UGI Utilities’ Revolving Credit Agreement.
14
UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement. This agreement expires in August 2011. Amounts outstanding under the Revolving Credit Agreement are classified as bank loans on the Consolidated Balance Sheets. During Fiscal 2009 and Fiscal 2008, peak bank loan borrowings totaled $312 million and $267 million, respectively. Average daily bank loan borrowings were $180.0 million in Fiscal 2009 and $121.0 million in Fiscal 2008. Revolving Credit Agreement borrowings were greater in Fiscal 2009 due in large part to increases in margin deposits associated with natural gas futures contracts as a result of declines in wholesale natural gas prices. UGI Utilities’ Revolving Credit Agreement requires it to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
Based upon cash expected to be generated from Gas Utility and Electric Utility operations and borrowings available under its Revolving Credit Agreement, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2010. For a more detailed discussion of UGI Utilities’ long-term debt and Revolving Credit Agreement, see Note 5 to Consolidated Financial Statements.
Energy Services.Energy Services has a $200 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper expiring in April 2010, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers. Management expects it will extend or replace the Receivables Facility prior to its termination date. Under the Receivables Facility, Energy services 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 Energy Services and its affiliates, including UGI. At September 30, 2009, the outstanding balance of ESFC trade receivables was $38.2 million which is net of $31.3 million that was sold to the commercial paper conduit and removed from the balance sheet. During Fiscal 2009 and Fiscal 2008, peak sales of receivables were $139.7 million and $71.0 million, respectively. The greater peak sales in Fiscal 2009 reflect greater cash needed to fund collateral deposits on natural gas NYMEX futures accounts due to the sharp decline in natural gas prices. Based upon cash expected to be generated from operations, borrowings available under its Receivables Facility and capital contributions from UGI for capital projects, management believes that Energy Services will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2010. For a more detailed discussion of the Receivables Facility, see Note 18 to Consolidated Financial Statements.
Cash Flows
Operating Activities.Year-to-year variations in cash flow from operations can be significantly affected by changes in operating working capital especially during periods of volatile energy commodity prices. During Fiscal 2009, commodity prices of LPG and natural gas decreased significantly compared with significant price increases during most of the second half of Fiscal 2008. The Fiscal 2009 decline in such commodity prices resulted in reduced investments in accounts receivable and LPG inventories which had the effect of significantly increasing cash flow from operating activities as further described below. Antargaz and the Partnership ended Fiscal 2009 with no bank loans outstanding and cash balances of $79.0 million and $59.2 million, respectively.
Cash flow provided by operating activities was $665.0 million in Fiscal 2009, $464.4 million in Fiscal 2008 and $456.2 million in Fiscal 2007. Cash flow from operating activities before changes in operating working capital was $611.7 million in Fiscal 2009, $525.3 million in Fiscal 2008 and $518.4 million in Fiscal 2007. The significant increase in Fiscal 2009 cash flow from operating activities before changes in operating working capital reflects the improved operating results of Antargaz and the Partnership as well as the effects of the CPG Acquisition on October 1, 2008. Changes in operating working capital provided (used) operating cash flow of $53.3 million in Fiscal 2009, $(60.9) million in Fiscal 2008 and $(62.2) million in Fiscal 2007. Cash flow from changes in operating working capital principally reflects the impacts of changes in LPG and natural gas prices on cash receipts from customers as reflected in changes in accounts receivable and accrued utility revenues; the timing of purchases and changes in LPG and natural gas prices on our investments in inventories; the timing of natural gas cost recoveries through Gas Utility’s PGC recovery mechanism; and the effects of the timing of payments and changes in purchase price per gallon of LPG and natural gas on accounts payable. Significantly greater Fiscal 2009 cash provided by changes in the Partnership’s and Antargaz’ accounts receivable and inventories principally reflects the effects on net cash receipts from customers and cash expenditures for purchases of inventories resulting from the lower Fiscal 2009 LPG prices. The significant increase in cash used to fund changes in accounts payable in Fiscal 2009 is principally due to the timing of payments and lower purchased prices for natural gas and LPG.
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Investing Activities.Investing activity cash flow is principally affected by expenditures for property, plant and equipment; cash paid for acquisitions of businesses; changes in restricted cash balances and proceeds from sales of assets. Net cash flow used in investing activities was $519.9 million in Fiscal 2009, $289.5 million in Fiscal 2008 and $223.8 million in Fiscal 2007. The primary reason for the increase in cash used by investing activities in Fiscal 2009 was business acquisitions, principally the CPG Acquisition, and greater cash expenditures for property, plant and equipment. Fiscal 2009 capital expenditures were higher due in large part to Energy Services’ capital project expenditures, increased Gas Utility capital expenditures associated with CPG Gas, and greater Partnership capital expenditures associated with a system software replacement project. Fiscal 2009 investing activity cash flows also reflect a reduction in restricted cash in natural gas futures brokerage accounts of $63.3 million compared with an increase of $57.5 million in Fiscal 2008. Changes in restricted cash in futures brokerage accounts are the result of the timing of settlement of natural gas futures contracts and changes in natural gas prices. During Fiscal 2009 and Fiscal 2007, the Partnership received $42.4 million and $49.0 million, respectively, in cash proceeds from the sales of propane storage facilities.
Financing Activities.Cash flow used by financing activities was $114.6 million, $180.1 million and $178.5 million in Fiscal 2009, Fiscal 2008 and Fiscal 2007, respectively. Changes in cash flow from financing activities 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 issuances of UGI and AmeriGas Partners equity instruments.
Fiscal 2009 issuances of long-term debt includes $108 million of Medium-Term Notes issued by UGI Utilities to finance a portion of the CPG Acquisition and a€7 million ($10.0) term loan issued by Flaga to fund a portion of the ZLH acquisition. During Fiscal 2009, AmeriGas OLP repaid $70 million of maturing First Mortgage Notes using cash generated from operations and Flaga made scheduled repayments of€6 million ($8.4) on its term loan. Changes in bank loans during Fiscal 2009 principally reflect $97 million of net borrowings by UGI Utilities offset in large part by Antargaz’ October 2008 repayment of its€50 million ($70.4 million) revolving credit facility loan borrowed in September 2008.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions but include capital leases) by our business segments for Fiscal 2009, Fiscal 2008 and Fiscal 2007. We also provide amounts we expect to spend in Fiscal 2010. We expect to finance Fiscal 2010 capital expenditures principally from cash generated by operations, borrowings under credit facilities and cash on hand.
| Year Ended September 30, | 2010 | 2009 | 2008 | 2007 | ||||||||||||
| (Millions of dollars) | (estimate) | |||||||||||||||
| AmeriGas Propane | $ | 82.0 | $ | 78.7 | $ | 62.8 | $ | 73.8 | ||||||||
| International Propane | 78.6 | 76.3 | 75.0 | 64.3 | ||||||||||||
| Gas Utility | 71.1 | 73.8 | 58.3 | 66.2 | ||||||||||||
| Electric Utility | 12.9 | 5.3 | 6.0 | 7.2 | ||||||||||||
| Energy Services | 106.6 | 66.2 | 30.7 | 10.7 | ||||||||||||
| Other | 3.0 | 1.4 | 1.4 | 0.9 | ||||||||||||
| $ | 354.2 | $ | 301.7 | $ | 234.2 | $ | 223.1 | |||||||||
The increases in Energy Services’ capital expenditures in Fiscal 2008, Fiscal 2009 and Fiscal 2010 principally reflect capital expenditures related to electric generation, LNG storage and peaking assets projects. The greater Electric Utility capital expenditures in Fiscal 2010 reflect increased electricity transmission capacity associated with additions to electric generating capacity in its service territory. Energy Services’ Fiscal 2009 capital expenditures were financed in large part by capital contributions from UGI. Energy Services’ expenditures in Fiscal 2010 principally relating to its Hunlock Station repowering project and an LNG storage expansion project are expected to be financed from capital contributions from UGI and bank borrowings. In addition, during Fiscal 2011 and Fiscal 2012 Energy Services expects to spend a total of approximately $90 million associated with these projects which amount is expected to be similarly financed. AmeriGas Propane capital expenditures in Fiscal 2009 and Fiscal 2010 include expenditures associated with a system software replacement.
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Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2009. 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, capital expenditures and derivative financial instruments. The following table presents contractual cash obligations under agreements existing as of September 30, 2009:
| Payments Due by Period | ||||||||||||||||||||
| Fiscal | Fiscal | Fiscal | ||||||||||||||||||
| (Millions of dollars) | Total | 2010 | 2011-2012 | 2013-2014 | Thereafter | |||||||||||||||
| Long-term debt (a) | $ | 2,133.1 | $ | 94.5 | $ | 654.5 | $ | 139.7 | $ | 1,244.4 | ||||||||||
| Interest on long-term fixed rate debt (b) | 805.4 | 126.6 | 200.8 | 172.2 | 305.8 | |||||||||||||||
| Operating leases | 230.5 | 61.5 | 86.0 | 49.8 | 33.2 | |||||||||||||||
| AmeriGas Propane supply contracts | 50.5 | 50.5 | — | — | — | |||||||||||||||
| International Propane supply contracts | 238.9 | 238.9 | — | — | — | |||||||||||||||
| Energy Services supply contracts | 545.2 | 436.4 | 108.8 | — | — | |||||||||||||||
| Gas Utility and Electric Utility supply, storage and transportation contracts | 558.0 | 218.9 | 182.7 | 101.0 | 55.4 | |||||||||||||||
| Derivative financial instruments (c) | 31.1 | 25.4 | 5.7 | — | — | |||||||||||||||
| Other purchase obligations (d) | 48.3 | 43.6 | 4.7 | — | — | |||||||||||||||
| Total | $ | 4,641.0 | $ | 1,296.3 | $ | 1,243.2 | $ | 462.7 | $ | 1,638.8 | ||||||||||
| (a) | Based upon stated maturity dates. | |
| (b) | Based upon stated interest rates adjusted for the effects of interest rate swaps. | |
| (c) | Represents the sum of amounts due from us if derivative financial instrument liabilities were settled at the September 30, 2009 amounts reflected in the Consolidated Balance Sheet (but excluding amounts associated with interest rate swaps). | |
| (d) | Includes material capital expenditure obligations. |
Components of other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2009 principally comprise refundable tank and cylinder deposits (as further described in Note 2 to Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”); litigation, property and casualty liabilities and obligations under environmental remediation agreements (see Note 15); pension and other post-employment benefit liabilities recorded in accordance with accounting guidance relating to employee retirement plans (see Note 7); and liabilities associated with executive compensation plans (see Note 13). These liabilities are not included in the table of Contractual Cash Obligations and Commitments because they are estimates of future payments and not contractually fixed as to timing or amount. In addition, we have committed to invest over the next several years a total of up to $25 million in a limited partnership that will focus on investments in the alternative energy sector.
Significant Acquisitions and Dispositions
On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas Utilities Corporation (now named UGI Central Penn Gas, Inc., “CPG”), the natural gas distribution utility of PPL (the “CPG Acquisition”), for cash consideration of $303.0 million less a final working capital adjustment of $9.7 million. Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central Penn, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas OLP for cash consideration of $33.6 million less a final working capital adjustment of $1.4 million (the “Penn Fuels Acquisition”). CPG distributes natural gas to approximately 76,000 customers in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. CPP sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition with a combination of $120 million cash contributed by UGI on September 25, 2008, proceeds from the issuance of $108 million principal amount of 6.375% Senior Notes due 2013 and approximately $75.0 million of borrowings under UGI Utilities’ Revolving Credit Agreement. AmeriGas OLP funded the acquisition of the assets of CPP with borrowings under the AmeriGas Credit Agreement, and UGI Utilities used the $33.6 million of cash proceeds from the sale of the assets of CPP to reduce its revolving credit agreement borrowings.
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On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated above-ground LPG storage facility located on leased property in California for net cash proceeds of $42.4 million. The gain from the sale increased net income attributable to UGI Corporation by $10.4 million or $0.10 per diluted share.
On January 29, 2009, Flaga purchased the 50% equity interest in ZLH it did not already own from its joint-venture partner, Progas GmbH & Co. KG (“Progas”), pursuant to a purchase agreement dated December 18, 2008. ZLH distributes LPG in the Czech Republic, Hungary, Poland, Slovakia and Romania. The cash purchase price for the 50% equity interest was not material.
Antargaz Competition Authority Matter
In June 2005, officials from France’s General Division of Competition, Consumption and Fraud Punishment (“DGCCRF”) conducted an unannounced inspection of, and obtained documents from, Antargaz’ headquarters building. Antargaz did not have any further contact with the DGCCRF regarding this matter until February 2007, when it received a letter from the DGCCRF requesting documents and information relating to Antargaz’ pricing policies and practices. In March 2007, and again in August 2007, the DGCCRF requested additional information from Antargaz and three joint ventures in which it participates. In July 2008, France’s Autorité de la concurrence (“Competition Authority”) interviewed Mr. Varagne, as President of Antargaz and President of the industry association, Comité Français du Butane et du Propane, about competitive practices in the LPG cylinder market in France.
On July 21, 2009, Antargaz received a Statement of Objections from the Competition Authority with respect to the investigation of Antargaz by the DGCCRF. A Statement of Objections (“Statement”) is part of French competition proceedings and generally follows an investigation under French competition laws. The Statement sets forth the Competition Authority’s findings; it is not a judgment or final decision. The Statement alleges that Antargaz engaged in certain anti-competitive practices in violation of French and European Union civil competition laws related to the cylinder market during the period from 1999 through 2004. The alleged violations occurred principally during periods prior to March 31, 2004, when UGI first obtained a controlling interest in Antargaz.
We have completed our review of the Statement of Objections and the related evidence and filed our written response with the Competition Authority on October 21, 2009. The Competition Authority will undertake a review of Antargaz’ response and begin preparation of its final pleading on the claims. This process is anticipated to take several months and Antargaz will have the opportunity to prepare a response to the Competition Authority’s final pleading. Based on an assessment of the information contained in the Statement, during the quarter ended June 30, 2009 we recorded a provision of $10.0 million (€7.1 million) related to this matter which amount is reflected in other income, net on the Fiscal 2009 Consolidated Statement of Income. The final resolution could result in payment of an amount significantly different from the amount we have recorded. We are unable to predict the timing of the final resolution of this matter (see Note 15 to the Consolidated Financial Statements).
Pension Plans
As of September 30, 2009, we sponsor two defined benefit pension plans (“Pension Plans”) for employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans the plans’ assets and benefit obligations of which are not material.
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Effective December 31, 2008, we merged two of our domestic defined benefit pension plans. As a result of the merger, we were required under U.S. generally accepted accounting principles (“GAAP”) to remeasure the combined plan’s assets and benefit obligations as of December 31, 2008. As a result of the remeasurement, Fiscal 2009 pension expense increased approximately $4.2 million for the period subsequent to the remeasurement due to the amortization of actuarial losses resulting from the general decline in the financial markets during Fiscal 2008 and Fiscal 2009 and a lower discount rate. The fair value of Pension Plans’ assets totaled $276.4 million and $241.0 million at September 30, 2009 and 2008, respectively. At September 30, 2009 and 2008, the underfunded position of Pension Plans, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plans’ assets, was $145.6 million and $59.6 million, respectively.
We believe we are in compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations. We anticipate that we will be required to make contributions to the Pension Plans during Fiscal 2010 but we do not expect such contributions to be material. Pre-tax pension costs associated with Pension Plans in Fiscal 2009 was $8.1 million. Pension cost associated with Pension Plans in Fiscal 2010 is expected to be approximately $11.5 million.
GAAP guidance associated with pension and other postretirement plans generally requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and other postretirement benefit plans with current year changes recognized in shareholders’ equity unless such amounts are subject to regulatory recovery. In accordance with this guidance, through September 30, 2009 we have recorded cumulative after-tax charges to UGI Corporation stockholders’ equity of $81.5 million in order to reflect the funded status of these plans. For a more detailed discussion of the Pension Plans and other postretirement benefit plans, see Note 7 to Consolidated Financial Statements.
Related Party Transactions
During Fiscal 2009, Fiscal 2008 and Fiscal 2007, 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
UGI primarily enters into guarantee arrangements on behalf of our consolidated subsidiaries. These arrangements are not subject to the recognition and measurement guidance relating to guarantees under GAAP.
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
Gas Utility
On January 28, 2009, PNG and CPG filed separate requests with the PUC to increase base operating revenues by $38.1 million annually for PNG and $19.6 million annually for CPG to fund system improvements and operations necessary to maintain safe and reliable natural gas service and energy assistance for low income customers as well as energy conservation programs for all customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on agreements with the opposing parties regarding the requested base operating revenue increases. On August 27, 2009, the PUC approved the settlement agreements which resulted in a $19.8 million base operating revenue increase for PNG Gas and a $10.0 million base operating revenue increase for CPG Gas. The increases became effective August 28, 2009 and did not have a material effect on Fiscal 2009 results.
Electric Utility
As a result of Pennsylvania’s ECC Act, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. Electric Utility remains the 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 through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006.
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In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement, Electric Utility increased its POLR rates effective January 1, 2009, which increased the average cost to a residential heating customer by approximately 1.5% over such costs in effect during calendar year 2008. Effective January 1, 2008, Electric Utility increased its POLR rates which increased the average cost to a residential heating customer by approximately 5.5% over such costs in effect during calendar year 2007. Effective January 1, 2007, Electric Utility increased the average cost to a residential heating customer by approximately 35% over such costs in effect during calendar year 2006.
On July 17, 2008, the PUC approved Electric Utility’s default service procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s default service regulations. These plans do not affect Electric Utility’s existing POLR settlement effective through December 31, 2009. The approved plans specify how Electric Utility will solicit and acquire default service supplies for residential customers for the period January 1, 2010 through May 31, 2014, and for commercial and industrial customers for the period January 1, 2010 through May 31, 2011 (collectively, the “Settlement Term”). UGI Utilities filed a rate plan on August 29, 2008 for the Settlement Term. On January 22, 2009, the PUC approved a settlement of the rate filing that provides for Electric Utility to fully recover its default service costs. On October 1, 2009, UGI Utilities filed a default service plan to establish procurement rules applicable to the period after May 31, 2011 for its commercial and industrial customers.
Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010 Electric Utility will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues. However, beginning January 1, 2010, Electric Utility will forego the opportunity to recover revenues in excess of actual costs as currently permitted under the POLR Settlement. This will result in a reduction in Electric Utility’s Fiscal 2010 operating income.
Manufactured Gas Plants
UGI Utilities
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the DEP requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (“PNG-COA”). The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 million and $1.1 million, respectively, in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP Properties and at the end of 2013 for well plugging activities. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At September 30, 2009, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $25.0 million. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets totaling $25.0 million.
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of 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, by the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.
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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, a five-year average of such prudently incurred remediation costs. At September 30, 2009 and 2008, neither UGI Gas’ undiscounted nor its accrued liability for environmental investigation and cleanup costs was material.
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 three claims against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary 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.
For additional information on the MGP sites outside of Pennsylvania currently subject to third-party claims or litigation, see Note 15 to Consolidated Financial Statements.
AmeriGas OLP
By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac Lake, New York on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by DEC disclosed contamination related to former MGP operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership has researched the history of the site and its ownership interest in the site. The Partnership has reviewed the preliminary site characterization study prepared by the DEC, the extent of contamination and the possible existence of other potentially responsible parties. The Partnership has communicated the results of its research to DEC and is awaiting a response before doing any additional investigation. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.
We cannot predict with certainty the final results of any of the MGP actions described above. 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 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.
Market Risk Disclosures
Our primary market risk exposures are (1) commodity price risk; (2) interest rate risk; and (3) foreign currency exchange rate risk. 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.
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Commodity Price Risk
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. The Partnership and International Propane 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. In addition, Antargaz hedges a portion of its future U.S. dollar denominated LPG product purchases through the use of forward foreign exchange contracts. Antargaz may from time-to-time enter into other contracts, similar to those used by the Partnership. Flaga has used and may use derivative commodity instruments to reduce market risk associated with a portion of its LPG purchases. Over-the-counter derivative commodity instruments utilized to hedge forecasted purchases of propane are generally settled at expiration of the contract.
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for a periodic adjustment 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. Gas Utility uses derivative financial instruments comprising futures contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism.
Electric Utility purchases its electric power needs from electricity suppliers under fixed-price energy contracts and, to a much lesser extent, on the spot market. Wholesale prices for electricity can be volatile especially during periods of high demand or tight supply. Electric Utility’s fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 2009. With respect to its existing fixed-price power contracts, should any of the counterparties fail to provide electric power under the terms of such contracts, any increases in the cost of replacement power 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. As previously mentioned, on January 22, 2009, the PUC approved a settlement of a rate filing that provides for Electric Utility to fully recover its default service costs beginning January 1, 2010. Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010, Electric Utility will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues.
In order to manage market price risk relating to substantially all of Energy Services’ fixed-price sales contracts for natural gas, Energy Services purchases over-the-counter and exchange-traded natural gas futures contracts or enters into fixed-price supply arrangements. Energy Services’ exchange-traded natural gas and electricity futures contracts are traded on the NYMEX and have nominal credit risk. 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. Energy Services has entered into 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, Energy Services enters into price swap and option contracts.
UGID has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its 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.
Because our business units have product cost management programs with contracts that include collateral and margin deposit requirement provisions, rapid declines in natural gas and LPG product costs can require our business units to post cash collateral with counterparties or make margin deposits in brokerage accounts.
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Electric Utility obtains financial transmission rights (“FTRs”) through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, by purchases at monthly PJM auctions. Energy Services purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. FTRs are financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electricity transmission grid. Although FTRs are economically effective as hedges of congestion charges, they do not currently qualify for hedge accounting treatment.
Interest Rate Risk
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 their 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 agreements, UGI Utilities’ Revolving Credit Agreement 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. Antargaz has effectively fixed the underlying euribor interest rate on its variable-rate debt through March 2011 and Flaga has fixed the underlying euribor interest rate on a substantial portion of its term loans through their scheduled maturity dates through the use of interest rate swaps. At September 30, 2009 and 2008, combined borrowings outstanding under these agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled approximately $163.1 million and $137.8 million, respectively. Excluding the fixed portions of Antargaz’ and Flaga’s variable-rate debt, and based upon weighted average borrowings outstanding under variable-rate agreements during Fiscal 2009 and Fiscal 2008, an increase in short-term interest rates of 100 basis points (1%) would have increased our Fiscal 2009 and Fiscal 2008 interest expense by $2.3 million and $1.9 million, respectively. The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of $91.0 million and $74.0 million at September 30, 2009 and 2008, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $100.7 million and $81.4 million at September 30, 2009 and 2008, respectively.
Our long-term debt associated with our domestic businesses 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, from time to time we enter into interest rate protection agreements.
Foreign Currency Exchange Rate Risk
Our primary currency 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 investments in foreign subsidiaries (“net investment hedges”). Realized gains or losses remain in accumulated other comprehensive income until such foreign operations are liquidated. At September 30, 2009, the fair value of unsettled net investment hedges was a loss of $5.7 million, which is included in foreign currency exchange rate risk in the table below. 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 $61.9 million, which amount would be reflected in other comprehensive income.
Derivative Financial Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise major energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. At September 30, 2009 and 2008, restricted cash in brokerage accounts totaled $7.0 million and $70.3 million, respectively.
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The following table summarizes the fair values of unsettled market risk sensitive derivative instruments assets and (liabilities) held at September 30, 2009 and 2008. The table also includes the changes in fair value that would result if there were a 10% adverse change in (1) the market price of LPG and gasoline; (2) the market price of natural gas; (3) the market price of electricity and electricity transmission congestion changes; (4) the three-month LIBOR and the three- and nine-month Euribor and; (5) the value of the euro versus the U.S. dollar. The fair value of Gas Utility’s exchange-traded natural gas futures contracts comprising losses $23.3 million at September 30, 2008 are excluded from the table below because any associated net gains or losses are included in Gas Utility’s PGC recovery mechanism. There were no such contracts at September 30, 2009.
| Asset (Liability) | ||||||||
| Change in | ||||||||
| Fair Value | Fair Value | |||||||
| (Millions of dollars) | ||||||||
| September 30, 2009: | ||||||||
| LPG commodity price risk | $ | 12.2 | $ | (14.4 | ) | |||
| FTR price risk | 2.9 | (0.3 | ) | |||||
| Natural gas commodity price risk | (0.4 | ) | (13.6 | ) | ||||
| Gasoline price risk | 0.1 | (0.2 | ) | |||||
| Electricity commodity price risk | (3.4 | ) | (1.7 | ) | ||||
| Interest rate risk | (34.4 | ) | (6.0 | ) | ||||
| Foreign currency exchange rate risk | (5.7 | ) | (18.2 | ) | ||||
| September 30, 2008: | ||||||||
| LPG commodity price risk | $ | (53.7 | ) | $ | (29.2 | ) | ||
| FTR price risk | 5.7 | (0.6 | ) | |||||
| Natural gas commodity price risk | (29.1 | ) | (21.7 | ) | ||||
| Electricity commodity price risk | (0.7 | ) | (0.2 | ) | ||||
| Interest rate risk | 9.1 | (9.9 | ) | |||||
| Foreign currency exchange rate risk | 3.4 | (19.5 | ) | |||||
Because our derivative instruments, other than FTRs and gasoline futures contracts, generally qualify as hedges under GAAP, we expect that changes in the fair value of derivative instruments used to manage commodity, currency or interest rate market risk would be substantially offset by gains or losses on the associated anticipated transactions.
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 accounting principles appropriate 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.
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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 PNG Gas and CPG Gas 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 accounting guidance associated with rate-regulated entities, 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, 2009, our regulatory assets totaled $141.5 million. See Notes 2 and 8 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, 2009, our net property, plant and equipment totaled $2,903.6 million and we recorded depreciation expense of $180.2 million during Fiscal 2009. As of September 30, 2009, our net intangible assets other than goodwill totaled $165.5 million and we recorded intangible amortization expense of $18.4 million during Fiscal 2009.
Purchase Price Allocations.From time to time, the Company enters into material business combinations. In accordance with accounting guidance associated with business combinations, the purchase price is allocated to the various assets acquired and liabilities assumed 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 appraisals. Estimating fair values can be complex and subject to significant business judgment 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 GAAP, 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, 2009, our goodwill totaled $1,582.3 million. We did not record any impairments of goodwill in Fiscal 2009, Fiscal 2008 or Fiscal 2007.
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Pension Plan Assumptions.The cost of providing benefits under our Pension Plans 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. Assets of the Pension Plans 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 fixed income market returns could have a material impact on future pension costs. We believe the two most critical assumptions are (1) the expected rate of return on plan assets and (2) the discount rate. A decrease in the expected rate of return on Pension Plans assets of 50 basis points to a rate of 8.0% would result in an increase in pre-tax pension cost of approximately $1.5 million in Fiscal 2010. A decrease in the discount rate of 50 basis points to a rate of 5.0% would result in an increase in pre-tax pension cost of approximately $2.4 million in Fiscal 2010.
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. Prior to Fiscal 2008, we established liabilities for tax-related contingencies when we believed it was probable that a liability had been incurred and the amount could be reasonably estimated. In Fiscal 2008, we adopted new guidance which establishes standards for recognition and measurement of positions taken or expected to be taken by an entity in its tax returns. Positions taken by an entity in its tax returns must satisfy a more-likely-than-not recognition threshold assuming the position will be examined by tax authorities with full knowledge of relevant information. 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. Actual taxable income or future estimates of taxable income could render our current assumptions, judgments and estimates inaccurate. Changes in the assumptions, judgments and estimates mentioned above could cause our actual income tax obligations to differ significantly from our estimates. As of September 30, 2009, our net deferred tax liabilities totaled $470.4 million.
Newly Adopted and Recently Issued Accounting Pronouncements
See Note 3 to Consolidated Financial Statements for a discussion of the effects of recently adopted accounting guidance as well as recently issued accounting guidance not yet adopted.
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