Electric Utility Fiscal 2011 operating income and income before income taxes declined $2.3 million and $2.9 million, respectively, principally reflecting the previously mentioned lower total margin, higher operating and maintenance expenses and, with respect to income before income taxes, higher allocated interest expense.
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Increase | |
Midstream & Marketing | | 2011 | | | 2010 | | | (Decrease) | |
(Millions of dollars) | | | | | | | | | | | | | | | | |
Revenues | | $ | 1,059.7 | | | $ | 1,145.9 | | | $ | (86.2 | ) | | | (7.5 | )% |
Total margin (a) | | $ | 139.7 | | | $ | 135.2 | | | $ | 4.5 | | | | 3.3 | % |
Operating income | | $ | 82.9 | | | $ | 120.0 | | | $ | (37.1 | ) | | | (30.9 | )% |
Income before income taxes | | $ | 80.2 | | | $ | 119.8 | | | $ | (39.6 | ) | | | (33.1 | )% |
| | |
(a) | | Total margin represents total revenues less total cost of sales. |
Midstream & Marketing total revenues decreased $86.2 million in Fiscal 2011 principally due to (1) the absence of revenues from Atlantic Energy’s import and transshipment facility ($90.8 million) and (2) lower total revenues from natural gas marketing activities ($46.9 million) attributable to lower natural gas prices. These decreases in revenues were partially offset principally by an increase in retail power sales revenues ($39.3 million) and incremental natural gas storage revenues ($7.9 million).
Fiscal 2011 total margin from Midstream & Marketing was modestly higher than in Fiscal 2010 as greater natural gas storage income ($8.4 million), energy peaking margin ($4.6 million), and natural gas and retail power marketing margin ($5.7 million) was offset by lower electric generation total margin ($9.7 million) and the absence of margin from Atlantic Energy ($8.0 million). The decrease in electric generation total margin principally reflects lower spot prices for electricity, increased coal costs at the Conemaugh electricity generating station and lower margin from UGID’s Hunlock Creek electricity generating station. The Hunlock Creek coal-fired generating station ceased operations in May 2010 to transition to a natural gas-fired generating station. The natural gas-fired generating station at Hunlock Creek commenced operations in July 2011. Due to an accident in late July 2011, one unit at Hunlock Creek was shut down for repair and is expected to restartrestarted in the spring ofearly summer 2012. Another unit at Hunlock Creek suffered flood damage during the fourth quarter of Fiscal 2011 and restarted in early November 2011.
The significant decrease in Midstream & Marketing’s operating income principally reflects the absence of the pre-tax gain from the Fiscal 2010 sale of Atlantic Energy ($36.5 million). The decline in income before income taxes reflects the decrease in operating income and greater interest expense ($2.5 million) principally the result of the change in accounting for Energy Services’ Receivables Facility and fees and charges associated with Energy Services’ new credit agreement (see Notes 35 and 18 to Consolidated Financial Statements).
Interest Expense and Income Taxes.Expense.Our consolidated interest expense was modestly higher in Fiscal 2011 principally reflecting higher Midstream & Marketing interest expense, due in part to the change in accounting for the Energy Services’ Receivables Facility, and higher Antargaz long-term debt interest expense partially offset by lower interest expense on Partnership debt from lower interest rates on refinanced long-term debt.
Income Taxes. Our effective income tax rate was lower in Fiscal 2011 reflecting the effects of (1) the impact of federal tax credits associated with solar energy projects; (2) the reversal of the $9.4 million nontaxable reserve associated with the French Competition Authority Matter at Antargaz; and (3) a reduction in UGI Utilities’ income taxes reflecting the regulatory effects of greater state
tax depreciation (as further described below under “Utility Matters”“UGI Utilities Income Taxes”).
35
Fiscal 2010 Compared with Fiscal 2009 Consolidated Results
Net Income (Loss) Attributable to UGI Corporation by Business Unit:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2010 | | | 2009 | | | Variance - Favorable (Unfavorable) | |
| | | | | | % of | | | | | | | % of | | | | | | | % of | |
(Millions of dollars) | | Amount | | | Total | | | Amount | | | Total | | | Amount | | | Total | |
AmeriGas Propane | | $ | 47.3 | | | | 18.1 | % | | $ | 65.0 | | | | 25.1 | % | | $ | (17.7 | ) | | | (27.2 | )% |
International Propane | | | 58.8 | | | | 22.5 | % | | | 78.3 | | | | 30.3 | % | | | (19.5 | ) | | | (24.9 | )% |
Gas Utility | | | 83.1 | | | | 31.8 | % | | | 70.3 | | | | 27.2 | % | | | 12.8 | | | | 18.2 | % |
Electric Utility | | | 6.8 | | | | 2.6 | % | | | 8.0 | | | | 3.1 | % | | | (1.2 | ) | | | (15.0 | )% |
Midstream & Marketing | | | 68.2 | | | | 26.1 | % | | | 38.1 | | | | 14.7 | % | | | 30.1 | | | | 79.0 | % |
Corporate & Other | | | (3.2 | ) | | | (1.1 | )% | | | (1.2 | ) | | | (0.4 | )% | | | (2.0 | ) | | | N.M. | |
| | | | | | | | | | | | | | | |
Net income attributable to UGI Corporation | | $ | 261.0 | | | | 100.0 | % | | $ | 258.5 | | | | 100.0 | % | | $ | 2.5 | | | | 1.0 | % |
| | | | | | | | | | | | | | | |
N.M. — Variance is not meaningful.
Highlights — Fiscal 2010 versus Fiscal 2009
| • | | Gas Utility results in Fiscal 2010 reflect the full-year impact of the PNG Gas and CPG Gas August 2009 base rate revenue increases. |
|
| • | | Midstream & Marketing’s Fiscal 2010 net income includes a $17.2 million after-tax gain on the sale of Midstream & Marketing’s Atlantic Energy subsidiary. |
|
| • | | AmeriGas Propane Fiscal 2010 results include a $3.3 million after-tax loss on interest rate hedges while Fiscal 2009 results include a $10.4 million after-tax gain from the sale of its California LPG storage terminal. |
|
| • | | Fiscal 2010 International Propane results reflect lower average unit margins compared with the higher than normal unit margins in Fiscal 2009. |
|
| • | | Midstream & Marketing’s Fiscal 2010 results benefited from greater natural gas and retail power margin. |
|
| • | | The lingering effects of the global economic recession continued to impact overall business activity in all of our business units. |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Increase | |
AmeriGas Propane | | 2010 | | | 2009 | | | (Decrease) | |
(Millions of dollars) | | | | | | | | | | | | | | | | |
Revenues | | $ | 2,320.3 | | | $ | 2,260.1 | | | $ | 60.2 | | | | 2.7 | % |
Total margin (a) | | $ | 925.2 | | | $ | 943.6 | | | $ | (18.4 | ) | | | (1.9 | )% |
Partnership EBITDA (b) | | $ | 321.0 | | | $ | 381.4 | | | $ | (60.4 | ) | | | (15.8 | )% |
Operating income | | $ | 235.8 | | | $ | 300.5 | | | $ | (64.7 | ) | | | (21.5 | )% |
Retail gallons sold (millions) | | | 893.4 | | | | 928.2 | | | | (34.8 | ) | | | (3.7 | )% |
Degree days – % (warmer) than normal (c) | | | (2.3 | )% | | | (3.1 | )% | | | — | | | | — | |
| | |
(a) | | Total margin represents total revenues less total cost of sales. |
|
(b) | | Partnership EBITDA 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 GAAP. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements). Partnership EBITDA (and operating income) in Fiscal 2010 includes a pre-tax loss associated with the discontinuance of interest rate hedges and a loss of $7 million associated with an increase in a litigation accrual. Partnership EBITDA (and operating income) in Fiscal 2009 includes a pre-tax gain of $39.9 million associated with the sale of the Partnership’s California LPG storage facility. |
36
| | |
(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 2010 data has been adjusted to correct a NOAA error. |
Based upon heating degree-day data, average temperatures in our service territories were 2.3% warmer than normal during Fiscal 2010 compared with temperatures in the prior year that were 3.1% warmer than normal. Fiscal 2010 retail gallons sold were lower reflecting, among other things, the lingering effects of the economic recession, customer conservation and customer attrition partially offset by volumes acquired through business acquisitions.
Retail propane revenues increased $20.2 million during Fiscal 2010 reflecting an increase as a result of higher average retail sales prices ($94.3 million) partially offset by lower retail volumes sold ($74.1 million). Wholesale propane revenues increased $46.7 million principally reflecting higher year-over-year wholesale selling prices ($37.5 million) and, to a lesser extent, higher wholesale volumes sold ($9.2 million). Average wholesale propane prices at Mont Belvieu, Texas, were approximately 47% higher during Fiscal 2010 compared with average wholesale propane prices during Fiscal 2009. The lower average wholesale propane prices in Fiscal 2009 principally resulted from a precipitous decline in prices that occurred during the first quarter of Fiscal 2009. Other revenues decreased $6.7 million in Fiscal 2010 compared with Fiscal 2009. Total cost of sales increased $78.6 million, to $1,395.1 million, principally reflecting the higher 2010 wholesale propane product costs.
Total margin was $18.4 million lower in Fiscal 2010 primarily due to lower total retail margin ($21.9 million). The lower total retail margin reflects the effects of the lower retail volumes sold ($31.4 million) partially offset by the effects of slightly higher average retail unit margins ($9.5 million) including higher unit margins in our AmeriGas Cylinder Exchange program.
The $60.4 million decrease in Partnership EBITDA during Fiscal 2010 reflects (1) the absence of a pre-tax gain recorded in Fiscal 2009 associated with the November 2008 sale of the Partnership’s California LPG storage facility ($39.9 million); (2) the previously mentioned decline in Fiscal 2010 total margin ($18.4 million); and (3) a loss from the discontinuance of interest rate hedges ($12.2 million). During the three months ended March 31, 2010, the Partnership’s management determined that it was likely that it would not issue $150 million of long-term debt during the summer of 2010 due to the Partnership’s strong cash flow and anticipated extension of all or a portion of the 2009 Supplemental Credit Agreement. As a result, the Partnership discontinued cash flow hedge accounting treatment for interest rate protection agreements associated with this previously anticipated debt issuance and recorded a $12.2 million loss which is reflected in other income, net, on the Fiscal 2010 Consolidated Statement of Income. These previously mentioned declines in EBITDA were partially offset by a decrease in operating and administrative expenses ($5.4 million) largely due to lower self-insured liability and casualty expenses ($9.2 million) and lower compensation and benefits expense ($4.7 million) partially offset by an increase in a litigation accrual recorded during the fourth quarter of Fiscal 2010 ($7.0 million).
37
Operating income in Fiscal 2010 decreased $64.7 million reflecting the previously mentioned decrease in Partnership EBITDA ($60.4 million) and slightly higher depreciation and amortization expense associated with fixed assets acquired during the past year ($3.6 million). Partnership interest expense was $5.2 million lower in Fiscal 2010 principally reflecting lower interest expense on lower long-term debt outstanding.
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Increase | |
International Propane | | 2010 | | | 2009 | | | (Decrease) | |
(Millions of euros) (a) | | | | | | | | | | | | | | | | |
Revenues | | € | 763.1 | | | € | 712.7 | | | € | 50.4 | | | | 7.1 | % |
Total margin (b) | | € | 345.8 | | | € | 392.7 | | | € | (46.9 | ) | | | (11.9 | )% |
Operating income | | € | 82.4 | | | € | 116.3 | | | € | (33.9 | ) | | | (29.1 | )% |
Income before income taxes | | € | 62.2 | | | € | 95.3 | | | € | (33.1 | ) | | | (34.7 | )% |
| | | | | | | | | | | | | | | | |
(Millions of dollars) (a) | | | | | | | | | | | | | | | | |
Revenues | | $ | 1,059.5 | | | $ | 955.3 | | | $ | 104.2 | | | | 10.9 | % |
Total margin (b) | | $ | 477.4 | | | $ | 525.8 | | | $ | (48.4 | ) | | | (9.2 | )% |
Operating income | | $ | 117.0 | | | $ | 151.4 | | | $ | (34.4 | ) | | | (22.7 | )% |
Income before income taxes | | $ | 89.5 | | | $ | 122.0 | | | $ | (32.5 | ) | | | (26.6 | )% |
| | | | | | | | | | | | | | | | |
Antargaz retail gallons sold | | | 279.9 | | | | 289.3 | | | | (9.4 | ) | | | (3.2 | )% |
Degree days – % (warmer) than normal (c) | | | (0.5 | )% | | | (2.9 | )% | | | — | | | | — | |
| | |
(a) | | Euro amounts represent amounts for Antargaz and Flaga. U.S. dollar amounts include Antargaz and Flaga as well as our operations in China and certain non-operating entities associated with our International Propane segment. |
|
(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 locations in our French service territory. |
International Propane operating results in Fiscal 2010 reflect the full-year consolidation of Zentraleuropa LPG Holdings GmbH (“ZLH”). In January 2009, Flaga purchased for cash consideration the 50% equity interest in ZLH it did not already own. International Propane acquisitions completed during Fiscal 2010 did not have a material effect on results of operations.
Based upon heating degree day data, temperatures in Antargaz’ service territory were 0.5% warmer than normal during Fiscal 2010 compared with temperatures that were 2.9% warmer than normal during Fiscal 2009. Temperatures in Flaga’s service territory were slightly colder than the prior year. The average wholesale commodity price for propane and butane in northwest Europe during Fiscal 2010 was approximately 48% higher than prices during Fiscal 2009. The lower average LPG wholesale prices in the prior-year period reflect precipitous declines in propane and butane wholesale prices principally during the first quarter of Fiscal 2009. Antargaz’ Fiscal 2010 retail propane volumes were lower than in the prior-year period principally as a result of reduced demand for crop drying earlier in Fiscal 2010 which was the result of an exceptionally dry 2009 summer, the effects of customer conservation and the lingering effects of the economic recession in France.
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 2010, the un-weighted average currency translation rate was $1.36 per euro compared to a rate of $1.35 per euro during Fiscal 2009, although the dollar was generally weaker than the euro during the peak earnings months of October to March in Fiscal 2010. The differences in exchange rates did not have a material impact on International Propane net income.
International Propane euro-based revenues increased €50.4 million or 7.1%. The higher Fiscal 2010 revenues principally resulted from the higher Fiscal 2010 wholesale LPG product costs. U.S. dollar revenues increased $104.2 million or 10.9% principally reflecting the higher euro-based revenues. International Propane’s euro-based total cost of sales increased to €417.3 million in Fiscal 2010 from €320.0 million in the prior year, an increase of 30.4%, reflecting the higher per-unit LPG commodity costs. U.S. dollar cost of sales increased to $582.1 million in Fiscal 2010 from $429.5 million in Fiscal 2009, an increase of 35.5%, principally reflecting the higher euro base-currency cost of sales.
38
International Propane euro-denominated total margin decreased €46.9 million or 11.9% in Fiscal 2010 principally reflecting lower Antargaz total margin (€49.7 million) reflecting the effects of lower average Antargaz retail unit margins (€37.8 million) and, to a much lesser extent, the lower Antargaz retail gallons sold (€10.3 million). Antargaz’ euro-denominated retail unit margins were lower in Fiscal 2010 compared with Fiscal 2009 as the prior-year unit margins were higher than normal due to the rapid and sharp decline in LPG commodity costs that occurred as Antargaz entered the Fiscal 2009 winter heating season. U.S. dollar total margin decreased $48.4 million or 9.2% principally reflecting the lower euro-denominated total margin.
International Propane euro base-currency operating income decreased €33.9 million or 29.1% in Fiscal 2010 principally reflecting the previously mentioned decrease in euro-based International Propane total margin (€46.9 million) offset by the absence of a charge associated with the Antargaz Competition Authority Matter recorded in the prior year (€7.1 million) and lower total Fiscal 2010 operating and administrative expenses (€10.5 million). On a U.S. dollar basis, operating income decreased $34.4 million or 22.7% reflecting the previously mentioned decrease in U.S. dollar-denominated total margin ($48.4 million) and higher depreciation expense ($3.9 million) partially offset by the absence of the charge for the Antargaz Competition Authority Matter recorded in the prior-year period ($10.0 million) and lower total operating and administrative expenses ($9.5 million). Euro base-currency income before income taxes was €33.1 million or 34.7% lower than in the prior-year period primarily reflecting the decline in operating income (€33.9 million). U.S. dollar income before income taxes decreased $32.5 million or 26.6%.
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Increase | |
Gas Utility | | 2010 | | | 2009 | | | (Decrease) | |
(Millions of dollars) | | | | | | | | | | | | | | | | |
Revenues | | $ | 1,047.5 | | | $ | 1,241.0 | | | $ | (193.5 | ) | | | (15.6 | )% |
Total margin (a) | | $ | 394.1 | | | $ | 387.8 | | | $ | 6.3 | | | | 1.6 | % |
Operating income | | $ | 175.3 | | | $ | 153.5 | | | $ | 21.8 | | | | 14.2 | % |
Income before income taxes | | $ | 134.8 | | | $ | 111.3 | | | $ | 23.5 | | | | 21.1 | % |
System throughput - billions of cubic feet (“bcf”) | | | 153.9 | | | | 149.7 | | | | 4.2 | | | | 2.8 | % |
Degree days – % (warmer) colder than normal (b) | | | (4.5 | )% | | | 4.9 | % | | | — | | | | — | |
| | |
(a) | | Total margin represents total revenues less total cost of sales. |
|
(b) | | Deviation from average heating degree days for the 15-year period 1995—2009 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 4.5% warmer than normal in Fiscal 2010 compared with temperatures that were 4.9% colder than normal in Fiscal 2009. Total distribution system throughput increased 4.2 bcf in Fiscal 2010, despite the warmer weather, principally reflecting an 8.5 bcf increase in low margin interruptible delivery service volumes. Gas Utility’s core market volumes decreased 6.2 bcf (9.0%) due to the previously mentioned warmer weather and to a lesser extent the sluggish economy and customer conservation.
Gas Utility revenues decreased $193.5 million during Fiscal 2010 principally reflecting a decline in revenues from retail core-market customers ($232.3 million) partially offset by a $29.4 million increase in revenues from low-margin off-system sales. The decrease in retail core-market revenues principally resulted from the effects of lower average PGC rates ($135.0 million) and the lower retail core-market volumes ($125.5 million). These decreases in revenues were partially offset by the effects of the PNG Gas and CPG Gas base operating revenue increases that became effective August 28, 2009. Gas Utility’s cost of gas was $653.4 million in Fiscal 2010 compared with $853.2 million in Fiscal 2009 principally reflecting the previously mentioned lower retail core-market sales and average PGC rates ($227.8 million) due to lower natural gas commodity prices.
39
Notwithstanding the decrease in distribution system volumes, Gas Utility total margin increased $6.3 million in Fiscal 2010. The increase is principally the result of the PNG Gas and CPG Gas base operating revenue increases ($28.2 million) substantially offset by the effect on total margin from the lower core-market volumes.
Gas Utility operating income in Fiscal 2010 increased $21.8 million principally reflecting lower operating and administrative costs ($15.6 million) and the previously mentioned increase in total margin ($6.3 million). Fiscal 2010 operating and administrative costs include, among other things, lower uncollectible accounts and customer assistance expenses ($11.5 million) and lower costs associated with environmental matters ($6.6 million). These decreases were partially offset by higher depreciation expense ($2.2 million) and higher pension expense ($2.1 million). The increase in income before income taxes reflects the previously mentioned higher operating income ($21.8 million) and lower interest expense ($1.6 million) due to lower average bank loan borrowings.
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Increase | |
Electric Utility | | 2010 | | | 2009 | | | (Decrease) | |
(Millions of dollars) | | | | | | | | | | | | | | | | |
Revenues | | $ | 120.2 | | | $ | 138.5 | | | $ | (18.3 | ) | | | (13.2 | )% |
Total margin (a) | | $ | 36.5 | | | $ | 39.3 | | | $ | (2.8 | ) | | | (7.1 | )% |
Operating income | | $ | 13.7 | | | $ | 15.4 | | | $ | (1.7 | ) | | | (11.0 | )% |
Income before income taxes | | $ | 11.9 | | | $ | 13.7 | | | $ | (1.8 | ) | | | (13.1 | )% |
Distribution sales – millions of kilowatt hours (“gwh”) | | | 972.6 | | | | 965.7 | | | | 6.9 | | | | 0.7 | % |
| | |
(a) | | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $6.6 million and $7.6 million during Fiscal 2010 and Fiscal 2009, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Consolidated Statements of Income. |
Temperatures based upon heating degree days in Fiscal 2010 were approximately 6.8% warmer than in Fiscal 2009. The impact on kilowatt-hour sales from the warmer heating-season weather was more than offset by higher air-conditioning related sales from significantly warmer 2010 late spring and summer weather.
Electric Utility revenues decreased $18.3 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the generation portion of their service and, to a lesser extent, lower default service (“DS”) rates effective January 1, 2010. Electric Utility decreased its DS rates effective January 1, 2010 pursuant to a January 22, 2009 settlement of its DS rate filing with the PUC. This reduced average costs to a residential general and residential heating customer by nearly 10% and 4%, respectively, over such costs in Fiscal 2009 and also reduced rates to commercial and industrial customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under previous Provider of Last Resort (“POLR”) rates in effect prior to January 1, 2010. Electric Utility cost of sales declined to $77.1 million in Fiscal 2010 compared to $91.6 million in Fiscal 2009 principally reflecting the effects of the previously mentioned generation supplier customer switching and lower purchased power costs. For additional information on Electric Utility DS and POLR service, see Note 8 to Consolidated Financial Statements.
Electric Utility total margin declined $2.8 million in Fiscal 2010 principally reflecting the reduction in margin resulting from the implementation of lower DS rates effective January 1, 2010.
40
Electric Utility operating income and income before income taxes in Fiscal 2010 were $1.7 million and $1.8 million lower, respectively, than in Fiscal 2009 reflecting the lower total margin ($2.8 million) partially offset by lower operating and administrative expenses ($1.1 million).
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Increase | |
Midstream & Marketing | | 2010 | | | 2009 | | | (Decrease) | |
(Millions of dollars) | | | | | | | | | | | | | | | | |
Revenues | | $ | 1,145.9 | | | $ | 1,224.7 | | | $ | (78.8 | ) | | | (6.4 | )% |
Total margin (a) | | $ | 135.2 | | | $ | 126.2 | | | $ | 9.0 | | | | 7.1 | % |
Operating income | | $ | 120.0 | | | $ | 64.8 | | | $ | 55.2 | | | | 85.2 | % |
Income before income taxes | | $ | 119.8 | | | $ | 64.8 | | | $ | 55.0 | | | | 84.9 | % |
| | |
(a) | | Total margin represents total revenues less total cost of sales. |
Midstream & Marketing total revenues decreased $78.8 million in Fiscal 2010 due to lower gas marketing revenues ($114.1 million) principally from lower average natural gas prices partially offset by the effects of higher retail power sales revenues ($36.8 million).
Total margin from Midstream & Marketing increased $9.0 million principally reflecting (1) higher natural gas marketing margin ($10.5 million) due to higher natural gas marketing unit margins and (2) higher total retail power marketing margin ($7.7 million) on higher volumes sold and larger average unit margins. These increases in margin were partially offset by a decrease in electric generation total margin ($6.9 million) principally from lower average unit margins. The increase in natural gas marketing total margin includes the impact of marketing initiatives focused on the small commercial customer segment. The increases in Midstream & Marketing’s operating income and income before income taxes principally reflects a pre-tax gain from the sale of its Atlantic Energy subsidiary ($36.5 million), the previously mentioned increase in total margin ($9.0 million) and lower operating and administrative costs ($4.8 million), principally from lower total electric generation operating and maintenance costs ($5.1 million), primarily costs associated with the Hunlock coal-fired generating station which ceased operating in May 2010 as it transitioned to a gas-fired generating station.
Interest Expense and Income Taxes.Consolidated interest expense decreased modestly to $133.8 million in Fiscal 2010 from $141.1 million in Fiscal 2009 principally due to lower interest expense on AmeriGas Propane debt ($5.2 million) and lower interest on UGI Utilities revolving credit agreement borrowings ($1.6 million). Our effective income tax rate was modestly higher in Fiscal 2010 principally reflecting the effects of a lower percentage of pretax income from noncontrolling interests, principally in AmeriGas Partners, generally not subject to income taxes.
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 borrowings under credit facilities and, in the case of Midstream & Marketing, also from a receivables purchase facility. Long-term cash needsrequirements not met by cash from operations 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 is restricted from withdrawal, totaled $238.5$319.9 million at September 30, 2012, compared with $238.5 million at September 30, 2011 compared with $260.7 million at September 30, 2010.. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30, 20112012 and 20102011, UGI had $81.4$107.9 million and $111.6$81.4 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, 2011,2012, our 44%27% effective ownership interest in the Partnership consisted of approximately 24.723.8 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. AmeriGas Propane, as general partner of AmeriGas Partners, L.P., is entitled to receive incentive distributions when AmeriGas Partners, L.P.’s quarterly distribution exceeds $0.605 per limited partner unit (see Note 14 to Consolidated Financial Statements).
41
During Fiscal 2011,2012, Fiscal 20102011 and Fiscal 2009,2010, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:
| | | | | | | | | | | | |
Year Ended September 30, | | 2011 | | | 2010 | | | 2009 | |
(Millions of dollars) | | | | | | | | | | | | |
AmeriGas Propane | | $ | 56.8 | | | $ | 44.4 | | | $ | 39.3 | |
UGI Utilities | | | 99.5 | | | | 74.0 | | | | 61.2 | |
International Propane | | | 32.9 | | | | 38.8 | | | | 39.0 | |
Midstream & Marketing | | | 30.0 | | | | 32.5 | | | | — | |
| | | | | | | | | |
Total | | $ | 219.2 | | | $ | 189.7 | | | $ | 139.5 | |
| | | | | | | | | |
|
| | | | | | | | | | | | |
Year Ended September 30, | | 2012 | | 2011 | | 2010 |
(Millions of dollars) | | | | | | |
AmeriGas Propane | | $ | 78.6 |
| | $ | 56.8 |
| | $ | 44.4 |
|
UGI Utilities | | 70.6 |
| | 99.5 |
| | 74.0 |
|
International Propane | | 14.9 |
| | 32.9 |
| | 38.8 |
|
Midstream & Marketing | | 55.0 |
| | 30.0 |
| | 32.5 |
|
Total | | $ | 219.1 |
| | $ | 219.2 |
| | $ | 189.7 |
|
In Fiscal 2012, Fiscal 2011 and Fiscal 2010, from Midstream & Marketing included proceeds from the sale of Atlantic Energy, LLC. Dividends from AmeriGas Propane in Fiscal 2009 include the benefit of a one-time $0.17 per unit increase in the August 2009 quarterly distribution resulting from the Partnership’s Fiscal 2009 sale of its California LPG storage facility (see below and Note 4 to Consolidated Financial Statements). In Fiscal 2011, Fiscal 2010 and Fiscal 2009, Midstream & Marketing received capital contributions from UGI totaling $30.1 million, $45.7 million $51.0 million and $46.8$51.0 million, respectively, to fund major LNG storage and electric generation capital projects as well as Marcellus Shale infrastructure projects. Dividends in Fiscal 2012 from Midstream & Marketing were used to fund a portion of the Shell Transaction which totaled $179.0 million in cash. Dividends in Fiscal 2010 from Midstream & Marketing included proceeds from the sale of Atlantic Energy, LLC.
On April 28, 2011, UGI’s24, 2012, UGI's Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.26$0.27 per common share or $1.04$1.08 per common share on an annual basis. This dividend reflectsreflected a 4% increase from the previous quarterly dividend rate of $0.25.$0.26. The new quarterly dividend rate was effective with the dividend payable on July 1, 2011,2012, to shareholders of record on June 15, 2011. Previously, on April 27, 2010, UGI’s Board of Directors approved a 25% increase in the quarterly dividend rate on UGI Common Stock to $0.25 per common share or $1.00 per common share on an annual basis. The new quarterly dividend rate was effective with the dividend payable on July 1, 2010 to shareholders of record on June 15, 2010. The higher than normal percentage dividend increase in Fiscal 2010 reflected our confidence in UGI’s future prospects and strong cash flows.2012.
On April 27, 2011,23, 2012, the General Partner’sPartner's Board of Directors approved a quarterly distribution of $0.74$0.80 per Common Unit equal to an annual rate of $2.96$3.20 per Common Unit. This distribution reflectsreflected an approximate 5% increase from the previous quarterly rate of $0.705$0.7625 per Common Unit. The new quarterly rate was effective with the distribution payable on May 18, 2011,2012, to unitholders of record on May 10, 2011.2012. Previously, on January 18, 2012, the General Partner's Board of Directors approved a quarterly distribution of $0.7625 per Common Unit equal to an annual rate of $3.05 per Common Unit. This distribution reflected an increase of 3% from the previous quarter's regular quarterly distribution rate of $0.74 per Common Unit.
As a result of the issuance of 29,567,362 AmeriGas Partners Common Units to ETP in conjunction with the Heritage Acquisition and related General Partner Common Unit transactions (see Note 4 to Consolidated Financial Statements), and the
issuance of 7 million AmeriGas Partners Common Units pursuant to AmeriGas Partners' public offering (see Note 14 to Consolidated Financial Statements), during Fiscal 2012, the Company recorded a $196.3 million increase in UGI Corporation stockholders' equity (which amount is net of deferred income taxes) and an associated $321.4 million pre-tax decrease in noncontrolling interests equity.
Long-term Debt and Credit Facilities
The Company’s debt outstanding at September 30, 20112012, totaled $2,296.4$3,679.4 million (including current maturities of long-term debt of $47.4$166.7 million and bank loan borrowings of $138.7 million)$165.1 million) compared to debt outstanding at September 30, 20102011, of $2,206.2$2,296.4 million (including current maturities of long-term debt of $573.6$47.4 million and bank loan borrowings of $200.4 million)$138.7 million). The significantly lower current maturities of long-term debt at September 30, 2011 primarily reflect the effects of the Fiscal 2011 refinancing of (1) Antargaz’ €380 million term loan ($508.7 million) and (2) one of Flaga’s euro-based term loans. Total debt outstanding at September 30, 20112012, consists of (1) $1,029.0$2,377.9 million of Partnership debt; (2) $590.2$594.9 million (€440.9 million) (€462.7 million) of International Propane debt; (3) $640$609.2 million of UGI Utilities’ debt; (4) $24.3$85.0 million of Midstream & Marketing debt; and (5) $12.9$12.4 million of other debt. For a detailed description of the Company’s debt, see below and Note 5 to Consolidated Financial Statements.
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 historically has used its Receivables Facility to satisfy its operating cash flow needs. Energy Services also has a three-year $170 million credit facility which it can use for working capital and general corporate purposes. Flaga principally uses borrowings under its credit agreements to satisfy its operating cash flow needs. During Fiscal 2012, Fiscal 2011 and Fiscal 2010, and Fiscal 2009, Antargaz generally funded its operating cash flow needs without using its revolving credit facilities.
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AmeriGas Partners.AmeriGas Partners’ total debt at September 30, 20112012, includes $920$2,250.8 million of AmeriGas Partners’ Senior Notes, $13.5$55.6 million of HOLP senior secured notes, $21.6 million of other long-term debt and $95.5$49.9 million of AmeriGas OLP bank loan borrowings.
In order to finance the cash portion of the Heritage Acquisition, on January 2011,12, 2012, AmeriGas PartnersFinance Corp. and AmeriGas Finance LLC (the “Issuers”) issued $470$550 million principal amount of 6.75% Notes due May 2020 and $1,000 million principal amount of 7.00% Notes due May 2022. The 6.75% Notes and the 7.00% Notes are fully and unconditionally guaranteed on a senior secured basis by AmeriGas Partners. The 6.75% and 7.00% Notes and the guarantees rank equal in right of payment with all of AmeriGas Partners' existing senior notes. In connection with the Heritage Acquisition, AmeriGas Partners, AmeriGas Finance Corp., AmeriGas Finance LLC and UGI entered into a Contingent Residual Support Agreement ("CRSA") with ETP pursuant to which ETP will provide contingent, residual support of $1.5 billion of debt ("Supported Debt" as defined in the CRSA).
On March 28, 2012, AmeriGas Partners announced that holders of approximately $383.5 million in aggregate principal amount of outstanding 6.50% Senior Notes due May 2021 (the “6.50% Senior Notes”). The proceeds from had validly tendered their notes in connection with the issuancePartnership's March 14, 2012, offer to purchase for cash up to $200 million of the 6.50% SeniorNotes. Tendered 6.50% Notes in the amount of $200 million were used in February 2011 to repayredeemed on March 28, 2012, at an effective price of 105%. During June 2012, AmeriGas Partners’ $415Partners repurchased approximately $19.2 million aggregate principal amount of its 7.25% Senior Notes due May 2015 pursuant to a tender offer and subsequent redemption. In addition, in February 2011, AmeriGas Partners redeemed the outstanding $14.6 million principal amount of its 8.875% Senior Notes due May 2011.7.00% Notes. The Partnership incurredrecorded a net loss of $18.8 million on these extinguishments of debt which amount is reflected on the Fiscal 2011 Consolidated Statement of Income under the caption “Loss on extinguishments of debt.”
In August 2011, AmeriGas Partners issued $450 million principal amount of 6.25% Senior Notes due August 2019 (the “6.25% Senior Notes”). The proceeds from the issuance of the 6.25% Senior Notes were used to repay AmeriGas Partners’ $350 million principal amount of its 7.125% Senior Notes due May 2016 pursuant to a tender offer and subsequent redemption. The Partnership incurred a loss of $19.3 million on this extinguishment of debt which amount is also reflected on the Fiscal 2011 Consolidated Statement of Income under the caption “Loss on extinguishments of debt.”$13.3 million associated with these transactions.
AmeriGas OLP has a $325$525 million unsecured credit agreement (“2011 AmeriGas Credit Agreement”) which expires on October 15, 2015. Concurrently with entering into2016. At September 30, 2012 and 2011, there were $49.9 million and $95.5 million of borrowings outstanding under the 2011 AmeriGas Credit Agreement on June 21, 2011, AmeriGas OLP terminated its then-existing $200 million revolving credit agreement dated as of November 6, 2006 and its $75 million credit agreement dated as of April 17, 2009.
At September 30, 2011 and 2010, there were $95.5 million and $91 million of borrowings outstanding under AmeriGas OLP credit agreements at average interest rates of 2.29%2.72% and 1.31%2.29%, respectively. Borrowings under the 2011 AmeriGas OLP credit agreementsCredit Agreement are classified as bank loans on the Consolidated Balance Sheets. During Fiscal 2012, the 2011 Credit Agreement was amended to, among other things, increase the total amount available to $525 million from $325 million previously, extend its expiration date to October 2016, and amend certain financial covenants as a result of the acquisition of Heritage Propane.
Issued and outstanding letters of credit under the 2011 AmeriGas OLP credit agreements,Credit Agreement, which reduce the amount available for borrowings, totaled $35.7$47.9 million and $35.7 million at September 30, 2012 and 2011, and 2010.respectively. The average daily and peak bank loan borrowings outstanding under the 2011 AmeriGas OLP credit agreementsCredit Agreement during Fiscal 20112012 were $151.1$95.3 million and $235$239.5 million, respectively. The average daily and peak bank loan borrowings outstanding under AmeriGas OLP credit agreements during Fiscal 20102011 were $43.9$151.1 million and $135$235 million, respectively.
Based upon existing cash balances, cash expected to be generated from operations and borrowings available under the 2011 AmeriGas Credit Agreement, the Partnership’s management believes that the Partnership will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2012 except for cash needs related to the acquisition2013.
International Propane.International Propane’s total debt at September 30, 20112012, includes $508.7$488.7 million (€380 million) outstanding under Antargaz’ 2011 Senior Facilities term loan and a combined $59.1$79.6 million (€44.261.9 million) outstanding under Flaga’s term loans. Total International Propane debt outstanding at September 30, 20112012 also includes (1) combined borrowings of $18.9$21.0 million (€14.116.3 million) outstanding under Flaga’s working capital facilities and (2) $3.5$5.6 million (€2.64.4 million) of other long-term debt.
Antargaz. In March 2011, Antargaz entered intohas a new five-year variable-rate term loan agreement with a consortium of banks (“2011 Senior Facilities Agreement”). The proceeds from the new term loan were used in March 2011 to repay Antargaz’ existing Senior Facilities Agreement borrowings.
The 2011 Senior Facilities Agreement consists of (1) a €380 million variable-rate term loan and (2) a €40 million revolving credit facility. Scheduled maturities under the term loan are €38 million due May 2014, €34.2 million due May 2015, and €307.8 million due March 2016. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of approximately 3.71% through the date of the term loan’s final maturity in March 2016. At September 30, 2011,2012, the effective interest rate on Antargaz’ term loan was 4.66%. UGI has guaranteed up to €100 million of payments under the 2011 Senior Facilities Agreement.
Antargaz’ management believes that it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 20122013 with cash generated from operations and borrowings under its 2011 Senior Facilities Agreement.
Flaga.In September 2011, Flaga entered intohas a €40 million ($51.4 million) euro-based term loan of which €26.7 million matures in August 2016 and €13.3 million matures in September 2016. This term loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin. Flaga has effectively fixed the euribor component of its interest rate on this term loan through September 2016 at 2.68% by entering into interest rate swap agreements. The effective interest rate on this term loan at September 30, 2012, was 5.18%.
In December 2011, was 4.76%. The proceeds ofFlaga entered into a €19.1 million ($24.6 million) euro-based variable-rate term loan agreement. Proceeds from the€40 million term loan were used, in large part, to repay €21 millionfund Flaga’s October 2011 acquisition of maturingShell’s LPG propane businesses in Finland, Norway, Sweden and Denmark. The term loan debt.matures in October 2016 and bears interest at three-month euribor rates plus a margin. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 1.79% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2012, was 4.35%.
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Flaga also has a euro-based variable-rate term loan which had an outstanding principal balance of €4.2€2.8 million ($5.6 million)3.6 million) on September 30, 2011.2012. Semi-annual principal payments of €0.7 million are due on December 31 and June 30 each year through June 2014. Flaga has effectively fixed the euribor component of the 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, 20112012, was 5.04%.
At September 30, 2011,2012, Flaga GmbH has threetwo principal working capital facilities (the "Flaga Credit Agreements") comprising (1) a €46 million multi-currency working capital facility which includes an uncommitted €6 million overdraft facility (the “Flaga 2011 Multi-currencyMulti-Currency Working Capital Facility”) and (2) twoa euro-denominated working capital facilitiesfacility that provideprovides for borrowings and issuances of guarantees totaling €12 million (the “Euro Facilities”Facility”). The Flaga 2011 Multi-currencyMulti-Currency Working Capital Facility expires in September 2014 and the Euro Facilities expireFacility expires in March 2012.September 2013. At September 30, 20112012 and 2010,2011, there were €4.3€11.9 million ($5.715.3 million) and €9.8€12.3 million ($13.416.5 million) of borrowings outstanding under the Flaga multi-currency working capital facilities, respectively, and €8.0 million ($10.7 million) and €7.9 million ($10.8 million) of borrowings outstanding under euro-denominated working capital facilities,Credit Agreements, respectively. These amounts are reflected as “Bank loans”bank loans on the Consolidated Balance Sheets.
At September 30, 20112012 and 2010,2011, the weighted-average interest rates on Flaga’s working capital facilitiesthe Flaga Credit Agreements were 3.39%2.31% and 3.64%3.39%, respectively. Issued and outstanding guarantees, which reduce available borrowings under these facilities,the Flaga Credit Agreements, totaled €12.1€19.2 million ($16.224.7 million) at September 30, 2011.2012. The average daily and peak bank loan borrowings outstanding under the Flaga Credit Agreements during Fiscal 2012 were €15.5 million and €17.8 million, respectively. The average daily and peak bank loan borrowings outstanding under Flaga principal working capital facilities during Fiscal 2011 were €16.4 million and €18.0 million, respectively. The average daily and peak bank loan borrowings outstanding under Flaga working capital facilities during Fiscal 2010 were €12.7 million and €17.8 million, respectively.
Based upon cash generated from operations and borrowings under its existing or new working capital facilities, Flaga’s management believes it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2012.2013.
UGI Utilities.UGI Utilities’ total debt at September 30, 20112012, includes long-term debt comprising $383$383.0 million of Senior Notes, and $257$217.0 million of Medium-Term Notes. There were no amounts outstanding at September 30, 2011, under Notes and $9.2 million of bank loan borrowings.
UGI Utilities 2011 Revolving Credit Agreement.
On May 25, 2011, UGI Utilities entered into an unsecured, revolvinghas a credit agreement (the “UGI Utilities 2011 Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350 million revolving credit agreement dated as of August 11, 2006. The UGI Utilities 2011 Credit Agreement which expires in May 2012 but may be extended to October 2015 if UGI Utilities satisfies certain requirements relating to approval by the PUC.2015. Borrowings under the UGI Utilities 2011 Credit Agreement are classified as bank loans. At September 30, 2012, there were $9.2 million of borrowings outstanding under UGI Utilities 2011 Credit Agreement. There were no amounts outstanding at September 30, 2011.
During Fiscal 20112012 and Fiscal 2010,2011, average daily bank loan borrowings were $16.2 million and $17.6 million, and $69.9 million, respectively,
and peak bank loan borrowings totaled $70.6 million and $90 million, and $217 million, respectively.
Based upon cash expected to be generated from Gas Utility and Electric Utility operations and borrowings available under the UGI Utilities 2011 Revolving Credit Agreement, UGI Utilities’ management believes that it will be able to meet its anticipated contractual commitments and projected cash commitmentsneeds during Fiscal 2012.2013.
Midstream & Marketing.Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $170 million (including a $50 million sublimit for letters of credit) which expires in August 2013. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries and to fund dividend payments provided that, after giving effect to such dividend payments, Energy Services maintains a specified ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement. Borrowings outstanding under the Energy Services Credit Agreement totaled $10$85.0 million at September 30, 2011. There were no borrowings under this facility during Fiscal 2010.2012. Energy Services intends to extend its credit agreement and increase its borrowing capacity prior to its scheduled expiration.
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Energy Services also has a $200 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper. The Receivables Facility expiresis currently scheduled to expire in April 2012,2013, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes. Energy Services intends to extend its Receivables Facility prior to its scheduled expiration in April 2012.2013.
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 some or all of 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. Through September 30, 2010, this two-step transaction was accounted for as a sale of receivables following GAAP for accounting for transfers and servicing of financial assets and extinguishments of liabilities. Effective October 1, 2010, the Company adopted a new accounting standard that changed the accounting for the Receivables Facility. Beginning October 1, 2010, trade receivables transferred to the commercial paper conduit remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit. Additionally, beginning October 1, 2010, the Company records interest expense on amounts owed to the commercial paper conduit.
At September 30, 2011,2012, the outstanding balance of ESFC trade receivables was $52.1$43.5 million of which no amount was sold to the commercial paper conduit. At September 30, 2011, the outstanding balance of ESFC trade receivables was $52.1 million and there was $14.3$14.3 million that was sold to the commercial paper conduit and reflected inas bank loans on the Consolidated Balance Sheet. At September 30, 2010, the outstanding balance of ESFC trade receivables was $44.0 million which is net of $12.1 million that was sold to the commercial paper conduit and removed from the balance sheet in accordance with GAAP in effect prior to October 1, 2010. During Fiscal 20112012 and Fiscal 2010,2011, peak sales of receivables were $31.7$51.5 million and $45.7$31.7 million, respectively, and average daily amounts sold were $1.3$15.6 million and $8.5$1.3 million, respectively.
Based upon cash expected to be generated from operations, borrowings available under the Energy Services Credit Agreement and Receivables Facility, and capital contributions from UGI, management believes that Energy Services will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2012.2013.
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 volatilesignificant changes in energy commodity prices.
Cash flow provided by operating activities was $554.7$707.7 million in Fiscal 2011, $598.82012, $554.7 million in Fiscal 20102011 and $665.0$598.8 million in Fiscal 2009.2010. Cash flow from operating activities before changes in operating working capital was $697.6$622.5 million in Fiscal 2011, $663.82012, $697.6 million in Fiscal 20102011 and $611.7$663.8 million in Fiscal 2009.2010. The decrease in cash flow from operating activities before changes in operating working capital in Fiscal 2012 compared to Fiscal 2011 reflects, in large part, the effects of the lower operating results in Fiscal 2012 and lower cash flow associated with settled commodity derivative contracts. Changes in operating working capital provided (used) provided operating cash flow of $(142.9)$85.2 million in Fiscal 2011, $(65.0)2012, $(142.9) million in Fiscal 20102011 and $53.3$(65.0) million in Fiscal 2009.2010. Cash flow from changes in operating working capital principally reflects the impacts of changes in LPG and natural gas prices on operating working capital, primarily accounts receivable, inventories and accounts payable, and inventories, and the timing and amount of natural gas cost recoveries or refunds through Gas Utility’s PGC recovery mechanism. The significantly lower Fiscal 2010higher cash provided by changes in working capital compared to Fiscal 2009 reflects in large part the effects on operating working capital of an increase in LPG commodity prices in Fiscal 20102012 compared with Fiscal 2011 largely reflects, among other things, the timing of the Heritage Acquisition on cash receipts from Heritage Propane customers and the effects of lower volumes sold due to the effectswarm weather on operating working capitalchanges in accounts receivable.
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 inby investing activities was $415.4$1,904.5 million in Fiscal 2011, $399.32012, $415.4 million in Fiscal 20102011 and $519.9$399.3 million in Fiscal 2009.2010. The significant increase in cash flow used in Fiscal 2012 principally reflects cash paid for the Heritage Acquisition (net of cash acquired) of approximately $1.4 billion. Cash used for acquisitions of businesses in Fiscal 2012 also includes the Shell Transaction. Expenditures for property, plant and equipment totaled $339.4 million in Fiscal 2012, $360.7 millionin Fiscal 2011 and 2010 reflect greater capital expenditures associated with Midstream & Marketing’s natural gas storage and electric generation projects. Acquisitions of businesses$347.3 million in Fiscal 2011 include $18.5 million of International Propane acquisitions and $34.0 million of Partnership acquisitions. Acquisitions in Fiscal 2010 include $48.7 million of expenditures associated with our International Propane businesses and $34.3 million of acquisition capital expenditures at the Partnership. Acquisitions in Fiscal 2009 include UGI Utilities’ acquisition of CPG ($292.6 million).2010. Cash from changes in restricted cash in futures brokerage accounts provided cash of $14.2 million in Fiscal 2012 and $17.6 million Fiscal 2011, and used cash of cash$27.8 million in Fiscal 2011; used $27.8 million of cash in Fiscal 2010; and provided $63.3 million of cash in Fiscal 2009.2010. The amount of restricted cash required in such accounts is generally the result of changes in underlying commodity prices. During Fiscal 2010, we received $66.6 million in cash proceeds from the sale of Atlantic Energy and in Fiscal 2009 the Partnership received $42.4 million of cash associated with the sale of the Partnership’s California LPG facility.Energy.
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Financing Activities.Cash flow usedprovided (used) by financing activities was $152.1$1,278.5 million in Fiscal 2011, $213.62012, $(152.1) million in Fiscal 20102011 and $114.6$(213.6) million in Fiscal 2009.2010. 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.
In order to finance the cash portion of the Heritage Acquisition, on January 12, 2012, AmeriGas Partners issued $550 million principal amount of 6.75% Notes due 2020 and $1.0 billion principal amount of 7.00% Notes due 2022. In March 2012, AmeriGas Partners sold 7 million Common Units in an underwritten public offering and used a portion of the net proceeds to repay $200 million of outstanding 6.50% Senior Notes due May 2021, to reduce bank loan borrowings and for general corporate purposes. In June 2012, AmeriGas Partners repurchased $19.2 million aggregate principal amount of outstanding 7.00% Notes. Repayments of AmeriGas Partners debt includes transaction fees and expenses associated with these extinguishments in Fiscal 2012. Distributions on AmeriGas Partners publicly held Common Units in Fiscal 2012 increased over Fiscal 2011 reflecting the greater number of Common Units outstanding and higher Fiscal 2012 quarterly per-unit distribution rates.
During Fiscal 2011, AmeriGas Partners redeemed $415 million principal amount of 7.25% AmeriGas Partners Senior Notes due 2015 and $14.6 million principal amount of its 8.875% Senior Notes due May 2011 with proceeds from the issuance of $470 million principal amount of 6.50% AmeriGas Partners Senior Notes due 2021. Also during Fiscal 2011, AmeriGas Partners redeemed $350 million principal amount of its 7 1/8% Senior Notes due 2016 with proceeds from the issuance of $450 million principal amount of its 6.25% Senior Notes due 2019. A portion of the proceeds from the issuances of the seniorSenior Notes were also used to reduce AmeriGas OLP bank loan borrowings. Repayments of AmeriGas Partners debt includes $30.6 million of transaction fees and expenses associated with these extinguishments. At our International Propane operations,extinguishments in Fiscal 2011. Also during Fiscal 2011, Antargaz repaid its maturing €380 million Senior Facilities Agreement borrowings with the proceeds from its new 2011 Senior Facilities Agreement and Flaga repaid €21 million of maturing term loan debt with the proceeds from its new €40 million euro-denominated term loan. As a result of the previously mentioned change in accounting for the Energy Services Receivables Facility which became effective October 1, 2010, net cash borrowed under the Receivables Facility, which totaled $2.2 million during Fiscal 2011, are reflected in Fiscal 2011 financing activities cash flows. Before the change in accounting, these borrowings were reflected within cash flow from operating activities. In September 2010, Antargaz, in order to minimize the interest it would be required to pay under its then-existing Senior Facilities Agreement, borrowed €50 million ($68.2 million) under the Senior Facilities revolving credit facility. This amount was repaid by Antargaz in October 2010.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions but include capital leases) by our business segments for Fiscal 2011,2012, Fiscal 20102011 and Fiscal 2009.2010. We also provide amounts we expect to spend in Fiscal 2012.2013. We expect to finance Fiscal 20122013 capital expenditures principally from cash generated by operations, borrowings under credit facilities and cash on hand.
| | | | | | | | | | | | | | | | |
Year Ended September 30, | | 2012 | | | 2011 | | | 2010 | | | 2009 | |
(Millions of dollars) | | (estimate) | | | | | | | | | | | | | |
AmeriGas Propane | | $ | 80.3 | | | $ | 77.2 | | | $ | 83.2 | | | $ | 78.7 | |
International Propane | | | 61.3 | | | | 65.4 | | | | 59.0 | | | | 76.3 | |
Gas Utility | | | 89.1 | | | | 91.3 | | | | 73.5 | | | | 73.8 | |
Electric Utility | | | 5.9 | | | | 7.5 | | | | 8.1 | | | | 5.3 | |
Midstream & Marketing | | | 181.2 | | | | 112.8 | | | | 116.4 | | | | 66.2 | |
Other | | | 2.0 | | | | 1.4 | | | | 12.7 | | | | 1.4 | |
| | | | | | | | | | | | |
|
Total | | $ | 419.8 | | | $ | 355.6 | | | $ | 352.9 | | | $ | 301.7 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
Year Ended September 30, | | 2013 | | 2012 | | 2011 | | 2010 |
(Millions of dollars) | | (estimate) | | | | | | |
AmeriGas Propane | | $ | 130.0 |
| | $ | 103.1 |
| | $ | 77.2 |
| | $ | 83.2 |
|
International Propane | | 70.0 |
| | 64.2 |
| | 65.4 |
| | 59.0 |
|
Gas Utility | | 111.0 |
| | 109.0 |
| | 91.3 |
| | 73.5 |
|
Midstream & Marketing | | 185.0 |
| | 60.4 |
| | 112.8 |
| | 116.4 |
|
Other | | 10.0 |
| | 6.5 |
| | 8.9 |
| | 20.8 |
|
Total | | $ | 506.0 |
| | $ | 343.2 |
| | $ | 355.6 |
| | $ | 352.9 |
|
Midstream & Marketing’s capital expenditures in Fiscal 2012, Fiscal 2011 and Fiscal 2010 principally reflect capital expenditures related to natural gas storage, and electric generation and Marcellus Shale projects. These Midstream & Marketing capital expenditures were financed in large part by capital contributions from UGI and cash from operations. The decline in InternationalEstimated AmeriGas Propane Fiscal 2013 capital expenditures ininclude $20.0 million related to Heritage integration activities. AmeriGas Propane Fiscal 2010 compared to Fiscal 2009 is principally due to lower expenditures for cylinders at Antargaz. The higher “other”2012 capital expenditures in Fiscal 2010 principally reflect capital improvements at UGI Corporation’s headquarters’ facility following a fire.
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Midstream & Marketing’s estimatedinclude $17.6 million of transition capital expenditures in Fiscal 2012, principally relating to the completionHeritage Propane integration activities.
In 2010, the Company announced plans to invest approximately $300 million over the next few years on infrastructure projects to support the development of natural gas in the Marcellus Shale region. This anticipated investment includes enhancementTo date the Company has invested or committed to invest more than half of its existing underground storage fields located in north-central Pennsylvania andthis amount. One major example is the construction of gas gathering facilities that would make locally produced gas available to Pennsylvania and interstate markets. TheCompany's recently announced $150 million expansion of the Auburn gathering system, which builds on a previous investment to move gas for Citrus Energy Appalachia, LLC. The 30-mile extension will link Marcellus production to the Transcontinental Gas Pipeline. The timing and extent of the Company’sCompany's investment in Marcellus infrastructure will depend on a number of factors including the timing of development of Marcellus gas production, market competition, any required regulatory approvals and construction schedules. The Company has a number of projects under development, including the previously announced Commonwealth Pipeline project.
Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2011.2012. 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 with non-affiliates under agreements existing as of September 30, 2011:2012:
| | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period | |
| | | | | | | | | Fiscal | | | Fiscal | | | | |
| | | | | | Fiscal | | | 2013 - | | | 2015 - | | | | |
(Millions of dollars) | | Total | | | 2012 | | | 2014 | | | 2016 | | | Thereafter | |
Long-term debt (a) | | $ | 2,157.7 | | | $ | 47.4 | | | $ | 196.5 | | | $ | 783.6 | | | $ | 1,130.2 | |
Interest on long-term fixed rate debt (b) | | | 975.4 | | | | 123.5 | | | | 233.7 | | | | 207.9 | | | | 410.3 | |
Operating leases | | | 277.9 | | | | 68.3 | | | | 103.9 | | | | 61.4 | | | | 44.3 | |
AmeriGas Propane supply contracts | | | 65.8 | | | | 65.8 | | | | — | | | | — | | | | — | |
International Propane supply contracts | | | 23.3 | | | | 23.3 | | | | — | | | | — | | | | — | |
Midstream & Marketing supply contracts | | | 280.2 | | | | 222.5 | | | | 57.7 | | | | — | | | | — | |
Gas Utility and Electric Utility supply, storage and transportation contracts | | | 529.4 | | | | 213.0 | | | | 179.6 | | | | 72.8 | | | | 64.0 | |
Derivative financial instruments (c) | | | 47.5 | | | | 40.4 | | | | 7.1 | | | | — | | | | — | |
Other purchase obligations (d) | | | 36.0 | | | | 36.0 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 4,393.2 | | | $ | 840.2 | | | $ | 778.5 | | | $ | 1,125.7 | | | $ | 1,648.8 | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
(Millions of dollars) | | Total | | Fiscal 2013 | | Fiscal 2014 - 2015 | | Fiscal 2016 - 2017 | | Thereafter |
Long-term debt (a) | | $ | 3,514.3 |
| | $ | 166.1 |
| | $ | 138.8 |
| | $ | 752.6 |
| | $ | 2,456.8 |
|
Interest on long-term fixed rate debt (b) | | 1,735.1 |
| | 228.7 |
| | 410.6 |
| | 356.0 |
| | 739.8 |
|
Operating leases | | 318.6 |
| | 77.4 |
| | 107.9 |
| | 64.7 |
| | 68.6 |
|
AmeriGas Propane supply contracts | | 319.3 |
| | 141.4 |
| | 174.7 |
| | 3.2 |
| | — |
|
International Propane supply contracts | | 571.2 |
| | 226.4 |
| | 286.8 |
| | 58.0 |
| | — |
|
Midstream & Marketing supply contracts | | 227.2 |
| | 171.1 |
| | 56.1 |
| | — |
| | — |
|
UGI Utilities supply, storage and transportation contracts | | 463.2 |
| | 173.9 |
| | 156.8 |
| | 69.8 |
| | 62.7 |
|
Derivative financial instruments (c) | | 91.5 |
| | 85.7 |
| | 5.8 |
| | — |
| | — |
|
Other purchase obligations (d) | | 34.8 |
| | 34.8 |
| | — |
| | — |
| | — |
|
Total | | $ | 7,275.2 |
| | $ | 1,305.5 |
| | $ | 1,337.5 |
| | $ | 1,304.3 |
| | $ | 3,327.9 |
|
| | |
(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, 20112012, amounts reflected in the Consolidated Balance Sheet (but excluding amounts associated with interest rate swaps). |
| |
(d) | | Includes material capital expenditure obligations. |
Other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 20112012, 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 to Consolidated Financial Statements); pension and other postretirement benefit liabilities recorded in accordance with accounting guidance relating to employee retirement plans (see Note 7 to Consolidated Financial Statements); and liabilities associated with executive compensation plans (see Note 13 to Consolidated Financial Statements). 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. We believe we will be required to make contributions to UGI Utilities’ pension plan (as further described below under “U.S. Pension Plans”Plan”) in Fiscal 20122013 of approximately $27.6$16.0 million. Contributions to the pension planUGI Pension Plan in years beyond Fiscal 20122013 will depend in large part on the impact of future returns and interest rates on pension plan assets. Certain of our operating lease arrangements, primarily vehicle leases with remaining lease terms of one to ten years, have residual value guarantees. Although such fair values at the end of the leases have historically exceeded the guaranteed amount, at September 30, 2011,2012, the maximum potential amount of future payments under lease guarantees assuming the leased equipment was deemed worthless was approximately $9.0$14 million.
Significant Acquisitions and Dispositions
On January 12, 2012 (the “Acquisition Date”), AmeriGas Partners completed the Heritage Acquisition for total consideration of approximately $2.6 billion comprising $1.5 billion in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of approximately $1.1 billion. The Heritage Acquisition was consummated pursuant to the Contribution Agreement, by and among AmeriGas Partners, ETP, Energy Transfer Partners GP, L.P., the general partner of ETP, and Heritage ETC, L.P. The acquired business conducts its propane operations in 41 states. According to LP-Gas Magazine rankings published on February 1, 2012, Heritage Propane was the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers in 2011. The Heritage Acquisition is consistent with our growth strategies, one of which is to grow our core business through acquisitions.
The cash portion of the Heritage Acquisition was financed by the issuance by AmeriGas Finance Corp. and AmeriGas Finance LLC, wholly owned finance subsidiaries of AmeriGas Partners, of $550 million principal amount of 6.75% Notes and $1.0 billion principal amount of 7.00% Notes. For further information on the 6.75% Notes and 7.00% Notes, see Note 5 to Consolidated Financial Statements.
The results of operations of Heritage Propane are included in the Consolidated Statements of Income since the Acquisition Date. For more information on the Heritage Acquisition, see Note 4 to Consolidated Financial Statements.
In addition, at September 30,October 2011, we are committed to invest an additional $8.5 million in a limited partnership that focuses on investmentsacquired Shell’s LPG distribution businesses in the alternative energy sector.
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Energy Services is evaluatingUnited Kingdom, Belgium, the feasibility of constructing natural gas pipelinesNetherlands, Luxembourg, Denmark, Finland, Norway and Sweden for €133.6 million ($179.0 million) in the Marcellus Shale gas production region of north-central Pennsylvania. In some instances, these pipeline projects involve potential partners who share in the development and marketing costs.
See “Subsequent Events” below regarding completed or pending acquisitions and their impact on our cash obligations.
Significant Dispositions and Acquisitions(see Note 4 to Consolidated Financial Statements).
On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned subsidiary, Atlantic Energy, to DCP Midstream Partners, L.P. for $49.0 million cash plus an amount for inventory and other working capital. Atlantic Energy owns and operates a 20 million gallon marine import and transshipment facility located in the port of Chesapeake, Virginia. The Company recorded a $36.5 million pre-tax gain on the sale which amount is included in “Otherother income, net”net, in the Fiscal 2010 Consolidated Statement of Income. The gain increased Fiscal 2010 net income attributable to UGI Corporation by $17.2 million or $0.16 per diluted share.share (see Note 4 to Consolidated Financial Statements).
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 revolving credit agreement borrowings. 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.
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.
Antargaz Competition Authority Matter
On July 21, 2009, Antargaz received a Statement of Objections (“Statement”) from France’s Autorité de la concurrence (“Competition Authority”) with respect to the investigation of Antargaz by the General Division of Competition, Consumption and Fraud Punishment. The Statement alleged that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. 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 is reflected in “Other income, net” on the Fiscal 2009 Consolidated Statement of Income. On December 17, 2010, the Competition Authority issued its decision dismissing all objections against Antargaz. The appeal period has expired without an appeal having been filed. As a result of the decision, during the three-month period ended December 31, 2010, the Company reversed its previously recorded nontaxable accrual for this matter which increased Fiscal 2011 net income by $9.4 million.
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U.S. Pension PlansPlan
In the U.S., we currently sponsor one defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). Effective December 31, 2010, UGI Utilities merged its then-existing two defined benefit pension plans. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans. The Antargaz plans’ assets and benefit obligations are not material. The Pension Plan, and the other U.S. pension plan that existed prior to the plan merger, are hereafter referred to as the “U.S. Pension Plans.”
The fair value of the U.S. Pension Plans’Plan's assets totaled $289.8$351.5 million and $287.9$289.7 million at September 30, 20112012 and 2010,2011, respectively. At September 30, 20112012 and 2010,2011, the underfunded positions of the U.S. Pension Plans,Plan, defined as the excess of the projected benefit obligations (“PBOs”) over the U.S. Pension Plans’Plan’s assets, were $167.0$192.1 million and $177.1$167.0 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 U.S. Pension PlansPlan during Fiscal 20122013 of approximately $27.6$16.0 million. Pre-tax pension cost associated with the U.S. Pension PlansPlan in Fiscal 20112012 was $13.9$15.3 million. Pre-tax pension cost associated with the U.S. Pension PlansPlan in Fiscal 20122013 is expected to be approximately $15.3$20.0 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. Through September 30, 2011,2012, we have recorded cumulative after-tax charges to UGI Corporation’s stockholders’ equity of $12.1$22.9 million and recorded regulatory assets totaling $154.1$188.2 million in order to reflect the funded status of our pension and other postretirement benefit plans. For a more detailed discussion of the U.S. Pension PlansPlan and our other postretirement benefit plans, see Note 7 to Consolidated Financial Statements.
Related Party Transactions
During Fiscal 2011,2012, Fiscal 20102011 and Fiscal 2009,2010, 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 its 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 Matters
Gas UtilityOn April 14, 2012, legislation enabling gas and electric utilities in Pennsylvania to seek surcharge recovery of eligible capital investment in distribution system infrastructure improvement projects became effective. The surcharge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC surcharge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures, for up to five percent of distribution rates. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff. Filings to implement a DSIC surcharge may be filed no earlier than January 2, 2013.
On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff's formal complaint, issued on June 11, 2012 ("PUC Staff Complaint"), pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage (the “Incident”). The PUC Staff Complaint had alleged that UGI Utilities had committed six violations of gas safety regulations and UGI Utilities' operating procedures related to its cast iron main replacement and gas odorant monitoring programs, and its emergency response to the Incident. As part of the Joint Settlement, UGI Utilities has agreed (i) to the assessment of a $0.4 million civil penalty; (ii) to accelerate the time frame for UGI Utilities, CPG, and PNG to replace the remainder of its cast-iron mains to 14 years, and (iii) to install odorant monitoring and injection equipment in its natural gas system at a number of supply points, but does not concede to having violated any regulation or operating procedure. Under the Joint Settlement, UGI Utilities, CPG and PNG have also agreed to not seek recovery of the related annual cost of capital return requirements through a DSIC for a period of 24 months but are permitted to retain the current 30-year timeframe for replacing the remainder of their bare steel mains. On October 31, 2012, the PUC administrative law judge issued an initial decision approving the settlement. The provisions of the Joint Settlement will become effective if the initial decision becomes final or if the PUC determines to review the initial decision and issues a final order approving the terms and conditions of the Joint Settlement without modification. The Company does not believe that the cost of complying with the requirements of the Joint Settlement will have a material impact on UGI Utilities' consolidated financial position, results of operations or cash flows.
On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 million annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. On August 11, 2011, the PUC approved the settlement agreement which resulted in an increase in annual base rate revenues of $8.0 million as well as $0.9 million in revenues per year for use in CPG’s Energy and Efficiency Conservation Program. The increase became effective August 30, 2011,2011. During Fiscal 2012, the PUC reversed its earlier decision related to the $0.9 million increase in revenues associated with the Energy and did not have a material effect on Fiscal 2011 results.Efficiency Conservation Program and required CPG to refund revenue it had collected for that program.
49
On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011, the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9 million. Compliance with the provisions of the PUC Order approving the transfer of the storage assets isdid not expected to have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.
On December 1, 2010, PNG filed an application with the PUC for expedited review and approval of the transfer of a 9 mile natural gas pipeline, related facilities, and right of way located in Mehoopany, Pennsylvania (the “Auburn Line”) to Energy Services. The PUC approved the transfer and in September 2011 the Auburn Line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the Auburn Line was $1.1 million.
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 increase in annual base operating revenue for PNG Gas and a $10.0 million increase in annual base operating revenue for CPG Gas. The increases became effective August 28, 2009.
Electric Utility
Prior to January 1, 2010, the terms and conditions under which Electric Utility 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. In accordance with the POLR Settlement, Electric Utility could increase its POLR rates up to certain limits through December 31, 2009. Beginning January 1, 2010, Electric Utility operates under a DS rate mechanism approved by the PUC that allows for full recovery of all DS costs incurred on and after January 1, 2010.
UGI Utilities Income Taxes
In 2010, U.S. federal tax legislation was enacted that allows taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of calendar 2011, when such property is placed in service before 2012. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers are also permitted to fully deduct such qualifying capital expenditures for Pennsylvania state corporate net income tax purposes. Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits from accelerated tax depreciation. UGI Utilities’ Fiscal 2011 effectiveand, to a lesser extent, Fiscal 2012 state tax rate reflectsrates reflect the beneficial effects of this greater state tax depreciation. The additional state and federal tax depreciation deductions described above reduce federal and state income taxes otherwise payable and increase UGI Utilities deferred income tax liabilities.
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Manufactured Gas Plants
UGI Utilities
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“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 (“PNG-COA”) with the DEP. 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 2013. 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, 2012 and 2011, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $15.0 million and $17.9 million.million, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.
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.
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 (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At September 30, 2011,2012, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas 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 OLPPropane
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 communicated the results of its research to DEC in January 2009 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.
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In connection with the Heritage Acquisition on January 12, 2012, a predecessor of Titan LLC is purportedly the beneficial holder of title with respect to three former MGPs discussed below. The Contribution Agreement provides for indemnification from ETP for certain expenses associated with remediation of these sites.
By letter dated September 30, 2010, the EPA notified Titan LLC that it may be a potentially responsible party (“PRP”) for cleanup costs associated with contamination at a former MGP in Claremont, New Hampshire. In June 2010, the Maryland Attorney General (“MAG”) identified Titan LLC as a PRP in connection with contamination at a former MGP in Chestertown, Maryland and requested that Titan LLC participate in characterization and remediation activities. Titan LLC has supplied the EPA and MAG with corporate and bankruptcy information for its predecessors to support its claim that it is not liable for any remediation costs at the sites. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.
In 1996, a predecessor company of Titan LLC performed an environmental assessment of its property in Bennington, Vermont and discovered that the site was a former MGP. At that time, Titan LLC’s predecessor informed the company that previously owned and operated the MGP of potential liability under CERCLA. Titan LLC has not received any requests to remediate or provide costs associated with the site. 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 matters referenced 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.
Subsequent Events
European LPG Acquisitions.On October 14, 2011, UGI, through subsidiaries, acquired Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden for approximately €130 million in cash, subject to working capital adjustments. The acquired businesses delivered a combined approximately 300 million gallons of LPG in 2010. The purchase price for these businesses was funded principally from existing cash at UGI and the return of cash capital contributions by Midstream & Marketing to UGI from borrowings under the Energy Services Credit Agreement. These cash capital contributions had previously been made by UGI to fund major Midstream & Marketing capital projects.
Proposed AmeriGas Acquisition of the Propane Operations of Energy Transfer Partners.On October 17, 2011, AmeriGas Partners announced that it had reached a definitive agreement to acquire the propane operations of Energy Transfer Partners, L.P. (“Energy Transfer”) for total consideration of approximately $2.9 billion, including $1.5 billion in cash, AmeriGas Partners Common Units valued at approximately $1.3 billion at the time of the execution of the agreement, and the assumption of $71 million in debt (the “Acquisition”). Energy Transfer conducts its propane operations in 41 states through its subsidiaries Heritage Operating, L.P. and Titan Energy Partners, L.P. (collectively, “Heritage Propane”). According to LP-Gas Magazine rankings, Heritage Propane is the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers. The acquisition of Heritage Propane is subject to customary closing conditions, including approval under the Hart-Scott-Rodino Act. AmeriGas Partners’ obligation to complete the Acquisition is also conditioned on it obtaining debt financing on certain agreed upon terms. In addition to new debt financing, the Partnership expects to increase the size of the AmeriGas 2011 Credit Agreement to at least $500 million upon closing of the transaction. The agreement contains termination rights for both parties. Under certain conditions, termination by AmeriGas Partners could result in the payment of a termination fee of up to $125 million. AmeriGas Partners expects to complete the Acquisition by March 31, 2012.
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.
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 as further described below. Antargaz hasOur International Propane operations have used over-the-counter derivative commodity instruments and may from time-to-time enter into other derivative contracts, similar to those used by the Partnership. Flaga has used and may use derivative commodity instrumentsPartnership, to reduce market risk associated with a portion of itstheir LPG purchases. Over-the-counter derivative commodity instruments used to hedge forecasted purchases of propane are generally settled at expiration of the contract.
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Gas Utility’sUtility's tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers.customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option 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’sUtility's PGC recovery mechanism.
Electric Utility’sUtility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, beginning January 1, 2010 there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations.
In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at September 30, 20112012, were not material.
Midstream & Marketing purchases financial transmission rights (“FTRs”)FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. In addition, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Although Midstream & Marketing’sMarketing's FTRs and NYMEX futures contracts associated with the purchase and later anticipated later sale of natural gas and propane are generally effective as economic hedges, they do not currently qualify for hedge accounting treatment.
In order to manage market price risk relating to substantially all of Midstream & Marketing’sMarketing's fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas and electricity futures contracts or enters into fixed-price supply arrangements. Midstream & Marketing also uses NYMEX and over the counterover-the-counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electricelectricity generation facilities. Midstream & Marketing’s exchange-traded natural gas and electricity futures contracts are traded on the NYMEX and have nominal credit risk. Although Midstream & Marketing’sMarketing's fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas or electricity would adversely impact Midstream & Marketing’sMarketing's results. In order to reduce this risk of supplier nonperformance, Midstream & Marketing has diversified its purchases across a number of suppliers. Midstream & Marketing has entered into and may continue to enter into fixed-price propane sales agreements for a portion of its propane sales.agreements. In order to manage the market price risk relating to substantially all of its fixed-price propane sales contracts for propane,agreements, Midstream & Marketing 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 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’sUGID's results.
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.
53
Our variable-rate debt includes bank loan borrowings and Antargaz’ and Flaga’s variable-rate term loans. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz and Flaga have effectively fixed the underlying euribor interest rates on their term loans through their scheduled maturity dates through the use of interest rate swaps. At September 30, 20112012, combined borrowings outstanding under these variable-rate debt agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate term loan debt, totaled $138.7$165.1 million. Excluding Antargaz’ and Flaga’s effectively fixed-rate term loan debt and based upon average borrowings outstanding under remaining variable-rate borrowings, an increase in short-term interest rates of 100 basis points (1%) would have increased our Fiscal 20112012 and Fiscal 20102011 interest expense by approximately $2.0$2.8 million and $1.3$2.0 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 $104.1$160.1 million and $94.7$104.1 million at September 30, 20112012 and 2010,2011, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $96.1$137.0 million and $104.8$96.1 million at September 30, 20112012 and 2010,2011, respectively.
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. 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 (“IRPAs”).
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 currency 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 on net investment hedges remain in accumulated other comprehensive income until such foreign operations are liquidated. At September 30, 2011, the fair value of2012, there were no unsettled net investment hedges was a gain of $1.1 million.outstanding. With respect to our net investments in our International Propane operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value at September 30, 20112012, by approximately $76.9$85.0 million, which amount would be reflected in other comprehensive income.
In addition, in order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar denominated LPG product purchases during the months of October through March through the use of forward foreign exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% — 30% of estimated dollar-denominated purchases to occur during the heating-season months of October to March.
In October 2011, the Company acquired certain European LPG businesses from Shell. In September 2011, in order to economically hedge the U.S. dollar amount of a substantial portion of the associated euro-denominated purchase price, we entered into foreign currency exchange contracts. These contracts are recorded at fair value with gains or losses recorded in other income (expense). At September 2011, we were hedging a total of €60 million of the euro-denominated purchase price. Losses recorded on acquisition purchase price hedge contracts through September 30, 2011 totaled $6.1 million.
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 large 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’counterparties' financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits.
Certain of theseour derivative instrument agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and option contracts generally require cash deposits in margin accounts. Declines in natural gas, LPG and electricity product costs can require our business units to post collateral with counterparties or make margin deposits to brokerage accounts. At September 30, 20112012 and 2010,2011, restricted cash in brokerage accounts totaled $3.0 million and $17.2 million, and $34.8 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, 20112012 and 2010.2011. The table also includes the changes in fair value of derivative instruments that would result if there were a 10% adverse change in (1) the market prices of commodity derivative instruments including the market prices of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges; (2) the three-month and one-month Euribor rates; and (3) the value of the euro versus the U.S. dollar. Gas Utility’s and Electric Utility’s derivative instruments other than gasoline futures and swap contracts are excluded from the table below because any associated net gains or losses are refundable to or recoverable from customers in accordance with Gas Utility and Electric Utility ratemaking.
| | | | | | | | |
| | Asset (Liability) | |
| | | | | | Change in | |
(Millions of dollars) | | Fair Value | | | Fair Value | |
| | | | | | | | |
September 30, 2011: | | | | | | | | |
Commodity price risk | | $ | (25.6 | ) | | $ | (35.3 | ) |
Interest rate risk | | | (44.4 | ) | | | (8.2 | ) |
Foreign currency exchange rate risk | | | 1.9 | | | | (16.5 | ) |
| | | | | | | | |
September 30, 2010: | | | | | | | | |
Commodity price risk | | $ | (37.2 | ) | | $ | (40.2 | ) |
Interest rate risk | | | (18.5 | ) | | | (3.7 | ) |
Foreign currency exchange rate risk | | | (2.2 | ) | | | (12.5 | ) |
|
| | | | | | | | |
| | Asset (Liability) |
(Millions of dollars) | | Fair Value | | Change in Fair Value |
September 30, 2012: | | | | |
Commodity price risk | | $ | (43.7 | ) | | $ | (35.9 | ) |
Interest rate risk | | (71.9 | ) | | (2.9 | ) |
Foreign currency exchange rate risk | | 1.8 |
| | (15.4 | ) |
| | | | |
September 30, 2011: | | | | |
Commodity price risk | | $ | (25.6 | ) | | $ | (35.3 | ) |
Interest rate risk | | (44.4 | ) | | (8.2 | ) |
Foreign currency exchange rate risk | | 1.9 |
| | (16.5 | ) |
Because substantially alla significant portion of our derivative instruments 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 GAAP 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 accountingAccounting policies and estimates discussed in this section are those that arewe consider to be the most importantcritical to the portrayalan understanding of the Company’sour financial conditionstatements because they involve significant judgments and results of operations.uncertainties. 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. Also, see Note 2 to Consolidated Financial Statements which discusses the significant accounting policies that we have selected from acceptable alternatives.
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.business. 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 GAAP, the Company establishes reserves for pending claimswhen a loss is considered probable and legal actions or environmental remediation obligations when it is probable thatreasonably estimable, we record a liability existsin the amount of our best estimate for the ultimate loss. When there is a range of possible loss with equal likelihood, liabilities recorded are based upon the low end of such range. The likelihood of a loss with respect to a particular contingency is often difficult to predict and determining a reasonable estimate of the loss or a range of possible loss may not be practicable based upon the information available and the amount or rangepotential effects of amounts can be reasonably estimated.future events and decisions by third parties that will determine the ultimate resolution of the contingency. 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.
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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, 2011,2012, our regulatory assets totaled $300.4 million.$338.4 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 goodwillsubject to amortization 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, 2011,2012, our net property, plant and equipment totaled $3,204.5$4,233.1 million and we recorded depreciation expense of $201.2$264.2 million during Fiscal 2011.2012. As of September 30, 2011,2012, our net intangible assets other than goodwillsubject to amortization totaled $147.8$521.0 million and we recorded amortization expense on intangible assets subject to amortization of $20.4$44.5 million during Fiscal 2011.2012.
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. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated if they have similar economic characteristics. Certain of the Company’s business unitsoperating segments 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 mustWe determine fair values for each of the reporting unit’sunits generally using an income approach unless market values are available. For purposes of the income approach, fair value using quoted market prices or, inis determined based upon the absencepresent value of quoted market prices, valuation techniques which use discounted estimates ofestimated future cash flows to be generated by the reporting unit. These cashdiscounted at an appropriate risk-adjusted rate. Cash flow estimates used to establish fair values involve management judgments based on a broad range of information and historical results. We use our internal forecasts to estimate future cash flows and include an estimate of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value and the carrying amount of the reporting unit's goodwill
exceeds the implied fair value of that goodwill. 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. The Company adopted new accounting guidance regarding goodwill impairment during Fiscal 2012 (see Note 3 to Consolidated Financial Statements) which permits us, in certain circumstances, to perform a qualitative approach to determine if it is more likely than not that the carrying value of a reporting unit is greater than its fair value. As of September 30, 2011,2012, our goodwill totaled $1,562.2 million.$2,818.3 million. We did not record any impairments of goodwill in Fiscal 2011,2012, Fiscal 2010 and2011 or Fiscal 2009. The Company will adopt new accounting guidance regarding goodwill impairment in Fiscal 2012 (see Note 3 to Consolidated Financial Statements)2010.
Pension Plan Assumptions. Pension plan assumptions are significant inputs to the actuarial models that measure pension benefit obligations and pension expense. The cost of providing benefits under the U.S. Pension PlansPlan 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 U.S. Pension PlansPlan 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 U.S. Pension PlansPlan assets of 50 basis points to a rate of 7.5%7.25% would result in an increase in pre-tax pension cost of approximately $1.6$1.8 million in Fiscal 2012.2013. A decrease in the discount rate of 50 basis points to a rate of 4.8%3.70% would result in an increase in pre-tax pension cost of approximately $2.8$3.2 million in Fiscal 2012.2013.
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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. Positions taken by an entity in its tax returns must satisfy a more-likely-than-not recognition threshold assuming the positions 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, 2011,2012, our net deferred tax liabilities totaled $664.3 million.$878.2 million.
Newly Adopted and Recently Issued Accounting Pronouncements
See Note 3 to Consolidated Financial Statements for a discussion of the effects of accounting guidance we adopted in Fiscal 20112012 as well as recently issued accounting guidance not yet adopted.
| | |
ITEM 7A. | | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
“Quantitative and Qualitative Disclosures About Market Risk” are contained in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Market Risk Disclosures” and are incorporated by reference.
57
| | |
ITEM 8. | | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Management’s Annual Report on Internal Control Over Financial Reporting and the financial statements and financial statement schedules referred to in the Index contained on page F-2 of this Report are incorporated herein by reference.
| | |
ITEM 9. | | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
None.
| | |
ITEM 9A. | | CONTROLS AND PROCEDURES |
| |
(a) | | The Company’sCompany's disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’sSEC's rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and PrincipalChief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company’sCompany's management, with the participation of the Company’sCompany's Chief Executive Officer and PrincipalChief Financial Officer, evaluated the effectiveness of the Company’sCompany's disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and PrincipalChief Financial Officer concluded that the Company’sCompany's disclosure controls and procedures, as of the end of the period covered by this Report, were effective at the reasonable assurance level. |
| |
(b) | | For “Management’s“Management's Annual Report on Internal Control over Financial Reporting” see Item 8 of this Report (which information is incorporated herein by reference). |
| |
(c) | | NoDuring the most recent fiscal quarter, other than changes resulting from the acquisition of Heritage Propane discussed below, no change in the Company’sCompany's internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’sCompany's internal control over financial reporting. |
On January 12, 2012, AmeriGas Partners acquired Heritage Propane. The Partnership is currently in the process of integrating Heritage Propane's operations, processes and internal controls. See Note 4 to Consolidated Financial Statements for additional information on the acquisition of Heritage Propane.
| | |
ITEM 9B. | | OTHER INFORMATION |
None.
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PART III:
ITEMS 10 THROUGH 14.
In accordance with General Instruction G(3), and except as set forth below, the information required by Items 10, 11, 12, 13 and 14 is incorporated in this Report by reference to the following portions of UGI’sUGI's Proxy Statement, which will be filed with the Securities and Exchange CommissionSEC by December 31, 2011.2012.
| | | | |
| | | | Captions of Proxy Statement |
| | Information | | Captions of Proxy Statement Incorporated by Reference |
Item 10. | | Directors, Executive Officers and Corporate Governance | | Election of Directors —- Nominees; Corporate Governance; Board Independence; Board Committees; Communications with the Board; Audit Committee; Securities Ownership of Management —- Section 16(a) —- Beneficial Ownership Reporting Compliance; Report of the Audit Committee of the Board of Directors |
| | | | |
| | The Code of Ethics for the Chief Executive Officer and Senior Financial Officers of UGI Corporation is available without charge on the Company’s website, www.ugicorp.com or by writing to Hugh J. Gallagher, Treasurer, UGI Corporation, P. O. Box 858, Valley Forge, PA 19482. | | |
| | | | |
Item 11. | | Executive Compensation | | Compensation of Directors; Report of the Compensation and Management Development Committee of the Board of Directors; Compensation Discussion and Analysis; Compensation of Executive Officers; Compensation Committee Interlocks and Insider Participation |
| | | | |
Item 12. | | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | | Securities Ownership of Certain Beneficial Owners; Securities Ownership of Management |
| | | | |
Item 13. | | Certain Relationships and Related Transactions, and Director Independence | | Election of Directors — Board Independence and Board Committees; Policy for Approval of Related Person Transactions |
| | | | |
Item 14. | | Principal Accounting Fees and Services | | Our Independent Registered Public
Accounting Firm |
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Equity Compensation Table
The following table sets forth information as of the end of Fiscal 20112012 with respect to compensation plans under which our equity securities are authorized for issuance.
| | | | | | | | | | | | |
| | | | | | | | | | Number of securities | |
| | Number of securities to be | | | Weighted average | | | remaining available for future | |
| | issued upon exercise of | | | exercise price of | | | issuance under equity | |
| | outstanding options, | | | outstanding options, | | | compensation plans | |
| | warrants and rights | | | warrants and rights | | | (excluding securities reflected | |
Plan category | | (a) | | | (b) | | | in column (a)) (c) | |
Equity compensation plans approved by security holders | | | 7,595,679 | (1) | | $ | 25.69 | | | | 2,618,351 | |
| | | | | | | | | | | | |
| | | 900,283 | (2) | | $ | 0 | | | | | |
| | | | | | | | | | | | |
Equity compensation plans not approved by security holders | | | 77,500 | (3) | | $ | 12.13 | | | | | |
| | | | | | | | | | | | |
Total | | | 8,573,462 | | | $ | 25.55 | (4) | | | | |
|
| | | | | | | | | | |
Plan category | | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | | Weighted average exercise price of outstanding options, warrants and rights (b) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) |
Equity compensation plans approved by security holders | | 8,036,772 |
| (1) | $ | 26.66 |
| | 1,436,672 |
|
| | 885,338 |
| (2) | $ | 0 |
| | |
Equity compensation plans not approved by security holders | | 21,000 |
| (3) | $ | 12.64 |
| | |
Total | | 8,943,110 |
| | $ | 26.62 |
| (4) | |
| | |
(1) | | Represents 7,595,6798,036,772 stock options under the 2000 Directors’Directors' Stock Incentive Plan and the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006. |
| |
(2) | | Represents 900,283885,338 phantom share units under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006. |
| |
(3) | | Column (a) represents 77,50021,000 stock options under the 2002 Non-Qualified Stock Option Plan. Under the 2002 Non-Qualified Stock Option Plan, the option exercise price is not less than 100% of the fair market value of the Company’sCompany's common stock on the date of grant. Generally, options become exercisable in three equal annual installments beginning on the first anniversary of the grant date. All options are non-transferable and generally exercisable only while the holder is employed by the Company or an affiliate, with exceptions for exercise following retirement, disability and death. Options are subject to adjustment in the event of recapitalization, stock splits, mergers and other similar corporate transactions affecting the Company’sCompany's common stock. |
| |
(4) | | Weighted-average exercise price of outstanding options; excludes phantom share units. |
The information concerning the Company’s executive officers required by Item 10 is set forth below.
EXECUTIVE OFFICERS
|
| | | | | | |
Name | | | Age | | | Position |
Lon R. Greenberg | | | 61 | 62 | | Chairman and Chief Executive Officer |
John L. Walsh | | | 56 | 57 | | President and Chief Operating Officer and Principal |
Kirk R. Oliver | | 54 | | Chief Financial Officer |
Davinder S. Athwal | | | 44 | 45 | | Vice President —- Accounting and Financial Control and Chief Risk Officer |
Eugene V.N. BissellJerry E. Sheridan | | | 58 | 47 | | President and Chief Executive Officer, AmeriGas Propane, Inc. |
Robert F. Beard | | | 46 | 47 | | President and Chief Executive Officer, UGI Utilities, Inc. |
Bradley C. Hall | | | 58 | 59 | | Vice President —- New Business Development |
Robert H. KnaussMonica M. Gaudiosi | | | 58 | 49 | | Vice President, and General Counsel and Assistant Secretary |
François Varagne | | | 56 | | | Chairman of the Board and Chief Executive Officer of Antargaz |
All officers except Mr. Varagne, are elected for a one-year term at the organizational meetings of the respective Boards of Directors held each year. Mr. Varagne was re-appointed as Chairman of the Board of Antargaz on April 1, 2010, for a term of five years. Mr. Varagne resigned effective October 12, 2011.
There are no family relationships between any of the officers or between any of the officers and any of the directors.
Lon R. Greenberg
Mr. Greenberg has been Chairman of the Board of Directors of UGI since 1996 and Chief Executive Officer since 1995. He was formerly President (1994 to 2005), Vice Chairman of the Board (1995 to 1996), and Senior Vice President —- Legal and Corporate Development (1989 to 1994). Mr. Greenberg also serves as a Director of UGI Utilities, Inc., AmeriGas Propane, Inc., Aqua America, Inc. and Ameriprise Financial, Inc. As previously announced, Mr. Greenberg will retire from his position as Chief Executive Officer of UGI in the spring of 2013 and will serve as Non-Executive Chairman of the Board of Directors following his retirement.
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John L. Walsh
Mr. Walsh is a Director and President and Chief Operating Officer of UGI Corporation (since April 2005). In addition, Mr. Walsh serves as Vice Chairman of AmeriGas Propane, Inc. (since 2005) and UGI Utilities, Inc. (since 2005). Previously, he also served as President and Chief Executive Officer of UGI Utilities, Inc. (2009 to 2011). Mr. Walsh was the Chief Executive of the Industrial and Special Products Division of the BOC Group plc (industrial gases), a position he assumed in 2001. He was also an Executive Director of BOC (2001 to 2005). He joined BOC in 1986 as Vice President-Special Gases and held various senior management positions in BOC, including President of Process Gas Solutions, North America (2000 to 2001) and President of BOC Process Plants (1996 to 2000). Mr. Walsh also serves as a Director of UGI Utilities, Inc. and AmeriGas Propane, Inc. As previously announced, Mr. Walsh will be named President and Chief Executive Officer of UGI upon Mr. Greenberg's retirement in the spring of 2013.
Kirk R. Oliver
Mr. Oliver is Chief Financial Officer of UGI (since October 2012). From December 2011 until September 2012, Mr. Oliver served as Senior Managing Director & Chief Operating Officer of InfraREIT Capital Partners, LLC, a partnership that invests in infrastructure assets, primarily electric transmission and gas pipeline assets. Prior to joining InfraREIT Capital, Mr. Oliver served as Senior Vice President and Chief Financial Officer of Allegheny Energy, Inc., an electric utility company, from 2008 to 2011, and as a Senior Executive at Hunt Power, LLC, a company that develops and invests in electric and gas utility projects, from 2007 to 2008. Mr. Oliver served in various positions at TXU Corp. (now Energy Future Holdings Corp.), an electricity distribution, generation and transmission company in Texas, from 1998 to 2006, including as Executive Vice President and Chief Financial Officer from 2004 to 2006, Senior Vice President, Finance from 2000 to 2003 and Vice President, Treasurer and Assistant Secretary from 1998 to 1999. Prior to joining TXU Corp., Mr. Oliver spent eleven years as an investment banker in the Global Power and Energy Group at Lehman Brothers and six years at Motorola Inc.
Davinder S. Athwal
Mr. Athwal is Vice President —- Accounting and Financial Control and Chief Risk Officer (since January 2009). He previously served as the Global Mergers & Acquisitions Controller of Nortel Networks, Inc., a global supplier of telecommunications equipment and solutions a position in which he served since 2007.from 2007 through 2008. Mr. Athwal served as Director, Global Revenue Governance for Nortel Networks, Inc. from 2006 through 2007. Mr. Athwal previously served in both accounting and risk management roles for IBM Corporation, a globally integrated innovation and technology company (2003 to 2006).
Eugene V.N. Bissell
Jerry E. Sheridan
Mr. BissellSheridan is President, Chief Executive Officer and a Director of AmeriGas Propane, Inc. (since July 2000), having served as Senior Vice President — Sales and Marketing (1999 to 2000) and Vice President — Sales and Operations (1995 to 1999)March 2012). Previously, he wasserved as Vice President — Distributors- Operations and Fabrication, BOC Gases (1995), having beenChief Operating Officer (2011 to 2012) and as Vice President — National Sales (1993- Finance and Chief Financial Officer (2005 to 1995)2011) of AmeriGas Propane, Inc. Mr. Sheridan served as President and RegionalChief Executive Officer (2003 to 2005) of Potters Industries, Inc., a global manufacturer of engineered glass materials and a wholly-owned subsidiary of PQ Corporation. In addition, Mr. Sheridan served as Executive Vice President (Southern Region) for Distributor(2003 to 2005) and Cylinder Gases Division, BOC Gases (1989as Vice President and Chief Financial Officer (1999 to 1993). From 1981 to 1987,2003) of PQ Corporation, a global producer of inorganic specialty chemicals. Mr. Bissell held various positions withSheridan also serves on the Company and its subsidiaries, including Director, Corporate Development. Mr. Bissell is a memberManagement Board of the BoardEngineered Materials Division of Directors of the National Propane Gas Association andJM Huber, a member of the Kalamazoo College Board of Trustees. Mr. Bissell is planning to retire in the Spring of 2012.privately held company (since 2012).
Robert F. Beard
Mr. Beard is President and Chief Executive Officer of UGI Utilities, Inc. (since September 2011). He previously served as Vice President —- Marketing, Rates and Gas Supply of UGI Utilities, Inc. (2010 to 2011) and Vice President —- Southern Region (2008 to 2010) of UGI Utilities, Inc. (2008 to 2010). From 2006 until 2008, Mr. Beard served as Vice President —- Operations and Engineering of PPL Gas Utilities Corporation and, from 2002 until 2006, he also served as Director —- Operations and Engineering of PPL Gas Utilities Corporation.
Bradley C. Hall
Mr. Hall is Vice President —- New Business Development (since October 1994). He also serves as President of UGI Enterprises, Inc. (since 1994) and UGI Energy Services, Inc. (since 1995). He joined the Company in 1982 and held various positions in UGI Utilities, Inc., including Vice President —- Marketing and Rates.
Robert H. Knauss
Mr. Knauss was electedMonica M. Gaudiosi
Ms. Gaudiosi is Vice President, General Counsel and Secretary (since April 2012). She also serves as Vice President and Secretary of AmeriGas Propane, Inc. and UGI Utilities, Inc. (since April 2012). Prior to joining UGI, Ms. Gaudiosi served as Senior Vice President and General Counsel (2007 to 2012) and Assistant Secretary on September 30, 2003. He previously served asSenior Vice President — Law and Associate General Counsel (2005 to 2007) of AmeriGas Propane, Inc. (1996Southern Union Company. Prior to 2003), and Group Counsel — Propane of UGI (1989 to 1996). He joined thejoining Southern Union Company in 1985. Previously, Mr. Knauss2005, Ms. Gaudiosi held various positions with General Electric Capital Corporation (1997 to 2005). Before joining General Electric Capital Corporation, Ms. Gaudiosi was an associate at the firmlaw firms of Ballard Spahr LLP in Philadelphia. Mr. Knauss is planningHunton & Williams (1994 to retire in the Spring1997) and Sutherland, Asbill & Brennan (1988 to 1994).
François Varagne
Mr. Varagne was Chairman of the Board and Chief Executive Officer of Antargaz through September 30, 2011. Mr. Varagne resigned effective October 12, 2011. Before joining Antargaz, Mr. Varagne was Chairman of the Board and Chief Executive Officer of VIA GTI, a common carrier in France (1998 to 2001). Prior to that, Mr. Varagne was Chairman of the Board and Chief Executive Officer of Brink’s France, a funds carrier (1997 to 1998).
61
PART IV:
| | |
ITEM 15. | | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
| |
(a) | | Documents filed as part of this report: |
Included under Item 8 are the following financial statements and supplementary data:
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of September 30, 20112012 and 20102011
Consolidated Statements of Income for the years ended September 30, 2012, 2011 2010 and 20092010
Consolidated Statements of Comprehensive Income for the years ended September 30, 2012, 2011 2010 and 20092010
Consolidated Statements of Cash Flows for the years ended September 30, 2012, 2011 2010 and 20092010
Consolidated Statements of Changes in Equity for the years ended September 30, 2012, 2011 2010 and 20092010
Notes to Consolidated Financial Statements
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(2) | | Financial Statement Schedules: |
I — Condensed Financial Information of Registrant (Parent Company)
II — Valuation and Qualifying Accounts for the years ended September 30, 2012, 2011 and 2010
We have omitted all other financial statement schedules because the required information is (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
1.1 | Underwriting Agreement, dated January 5, 2012, by and among the Partnership, the Issuers, AmeriGas Propane, Inc., AmeriGas Propane L.P., Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc., J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein | AmeriGas Partners, L.P. | Form 8-K (1/5/2012) | 1.1 |
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| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
1.2 | Underwriting Agreement, dated March 15, 2012, by and among the Partnership, AmeriGas Propane, Inc., AmeriGas Propane, L.P., Wells Fargo Securities, LLC, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and UBS Securities LLC, as representatives of the several underwriters named therein. | AmeriGas Partners, L.P. | Form 8-K (3/15/12) | 1.1 |
2.1 | Contribution and Redemption Agreement, dated October 15, 2011, by and among AmeriGas Partners, L.P., Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P. and Heritage ETC, L.P. | AmeriGas Partners, L.P. | Form 8-K (10/15/11) | 2.1 |
2.2 | Amendment No. 1, dated as of December 1, 2011, to the Contribution and Redemption Agreement, dated as of October 15, 2011, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P. | AmeriGas Partners, L.P. | Form 8-K (12/1/11) | 2.1 |
2.3 | Amendment No. 2, dated as of January 11, 2012, to the Contribution and Redemption Agreement, dated as of October 15, 2012, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P. | AmeriGas Partners, L.P. | Form 8-K (1/11/12) | 2.1 |
2.4 | Letter Agreement, dated as of January 11, 2012, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P. | AmeriGas Partners, L.P. | Form 8-K (1/11/12) | 2.1 |
3.1 | (Second) Amended and Restated Articles of Incorporation of the Company as amended through June 6, 2005 | UGI | Form 10-Q (6/30/05) | 3.1 |
3.2 | Bylaws of UGI as amended through September 28, 2004 | UGI | Form 8-K (9/28/04) | 3.2 |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
4.1 | Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of long-term debt not required to be filed pursuant to Item 601(b)(4) of Regulation S-K) | | | |
4.2 | The description of the Company's Common Stock contained in the Company's registration statement filed under the Securities Exchange Act of 1934, as amended | UGI | Form 8-B/A (4/17/96) | 3.(4) |
4.3 | UGI's (Second) Amended and Restated Articles of Incorporation and Bylaws referred to in 3.1 and 3.2 above | | | |
4.4 | Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of July 27, 2009 | AmeriGas Partners, L.P. | Form 10-Q (6/30/09) | 3.1 |
4.5 | Amendment No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of March 13, 2012. | AmeriGas Partners, L.P. | Form 8-K (3/14/12) | 3.1 |
4.6 | Indenture, dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee | AmeriGas Partners, L.P. | Form 10-Q (12/31/10) | 4.1 |
4.7 | First Supplemental Indenture, dated as of January 20, 2011, to Indenture dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee | AmeriGas Partners, L.P. | Form 8-K (1/19/11) | 4.1 |
4.8 | Second Supplemental Indenture, dated as of August 10, 2011, to Indenture dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee | AmeriGas Partners, L.P. | Form 8-K (8/10/11) | 4.1 |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
4.9 | Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994 | Utilities | Registration Statement No. 33-77514 (4/8/94) | 4(c) |
4.10 | Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association | Utilities | Form 8-K (9/12/06) | 4.2 |
4.11 | Indenture, dated as of January 12, 2012, among AmeriGas Finance Corp., AmeriGas Finance LLC, AmeriGas Partners, L.P., as guarantor, and U.S. Bank National Association, as trustee. | AmeriGas Partners, L.P. | Form 8-K (1/12/12) | 4.1 |
4.12 | First Supplemental Indenture, dated as of January 12, 2012, among AmeriGas Finance Corp., AmeriGas Finance LLC, AmeriGas Partners, L.P., as guarantor, and U.S. Bank National Association, as trustee. | AmeriGas Partners, L.P. | Form 8-K (1/12/12) | 4.2 |
4.13 | Form of Fixed Rate Medium-Term Note | Utilities | Form 8-K (8/26/94) | 4(i) |
4.14 | Form of Fixed Rate Series B Medium-Term Note | Utilities | Form 8-K (8/1/96) | 4(i) |
4.15 | Form of Floating Rate Series B Medium-Term Note | Utilities | Form 8-K (8/1/96) | 4(ii) |
4.16 | Officer's Certificate establishing Medium-Term Notes Series | Utilities | Form 8-K (8/26/94) | 4(iv) |
4.17 | Form of Officer's Certificate establishing Series B Medium-Term Notes under the Indenture | Utilities | Form 8-K (8/1/96) | 4(iv) |
4.18 | Form of Officers' Certificate establishing Series C Medium-Term Notes under the Indenture | Utilities | Form 8-K (5/21/02) | 4.2 |
4.19 | Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes | Utilities | Form 8-K (5/21/02) | 4.1 |
| I — | | Condensed Financial Information of Registrant (Parent Company) |
| II — | | Valuation and Qualifying Accounts for the years ended September 30, 2011, 2010 and 2009 |
|
| | | We have omitted all other financial statement schedules because the required information is (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes. |
| | | The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing): |
| | | | | | | | | | |
Incorporation by Reference | |
Exhibit No. | | Exhibit | | Registrant | | Filing | | Exhibit | |
| | | | | | | | | | |
2.1 | | Contribution and Redemption Agreement, dated October 15, 2011, by and among AmeriGas Partners, L.P., Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P. and Heritage ETC, L.P. | | AmeriGas Partners, L.P. | | Form 8-K (10/15/11) | | | 2.1 | |
| | | | | | | | | | |
3.1 | | (Second) Amended and Restated Articles of Incorporation of the Company as amended through June 6, 2005 | | UGI | | Form 10-Q (6/30/05) | | | 3.1 | |
62
| | | | | | | | | | |
Incorporation by Reference | |
Exhibit No. | | Exhibit | | Registrant | | Filing | | Exhibit | |
| | | | | | | | | | |
3.2 | | Bylaws of UGI as amended through September 28, 2004 | | UGI | | Form 8-K (9/28/04) | | | 3.2 | |
| | | | | | | | | | |
4 | | Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of long-term debt not required to be filed pursuant to Item 601(b)(4) of Regulation S-K) | | | | | | | | |
| | | | | | | | | | |
4.1 | | The description of the Company’s Common Stock contained in the Company’s registration statement filed under the Securities Exchange Act of 1934, as amended | | UGI | | Form 8-B/A (4/17/96) | | | 3.(4 | ) |
| | | | | | | | | | |
4.2 | | UGI’s (Second) Amended and Restated Articles of Incorporation and Bylaws referred to in 3.1 and 3.2 above | | | | | | | | |
| | | | | | | | | | |
4.3 | | Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of July 27, 2009 | | AmeriGas Partners, L.P. | | Form 10-Q (6/30/09) | | | 3.1 | |
| | | | | | | | | | |
4.4 | | Indenture, dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee | | AmeriGas Partners, L.P. | | Form 10-Q (12/31/10) | | | 4.1 | |
| | | | | | | | | | |
4.5 | | First Supplemental Indenture, dated as of January 20, 2011, to Indenture dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee | | AmeriGas Partners, L.P. | | Form 8-K (1/19/11) | | | 4.1 | |
| | | | | | | | | | |
4.6 | | Second Supplemental Indenture, dated as of August 10, 2011, to Indenture dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee | | AmeriGas Partners, L.P. | | Form 8-K (8/10/11) | | | 4.1 | |
| | | | | | | | | | |
4.7 | | Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994 | | Utilities | | Registration Statement No. 33-77514 (4/8/94) | | | 4(c | ) |
| | | | | | | | | | |
4.8 | | Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association | | Utilities | | Form 8-K (9/12/06) | | | 4.2 | |
| | | | | | | | | | |
4.9 | | Form of Fixed Rate Medium-Term Note | | Utilities | | Form 8-K (8/26/94) | | | 4(i | ) |
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4.10 | | Form of Fixed Rate Series B Medium-Term Note | | Utilities | | Form 8-K (8/1/96) | | | 4(i | ) |
| | | | | | | | | | |
4.11 | | Form of Floating Rate Series B Medium-Term Note | | Utilities | | Form 8-K (8/1/96) | | 4(ii | ) |
63
| | | | | | | | | | |
Incorporation by Reference | |
Exhibit No. | | Exhibit | | Registrant | | Filing | | Exhibit | |
| | | | | | | | | | |
4.12 | | Officer’s Certificate establishing Medium-Term Notes Series | | Utilities | | Form 8-K (8/26/94) | | 4(iv | ) |
| | | | | | | | | | |
4.13 | | Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture | | Utilities | | Form 8-K (8/1/96) | | 4(iv | ) |
| | | | | | | | | | |
4.14 | | Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture | | Utilities | | Form 8-K (5/21/02) | | | 4.2 | |
| | | | | | | | | | |
4.15 | | Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes | | Utilities | | Form 8-K (5/21/02) | | | 4.1 | |
| | | | | | | | | | |
10.1** | | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 | | UGI | | Form 8-K (2/27/07) | | | 10.1 | |
| | | | | | | | | | |
*10.2** | | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 — Terms and Conditions as amended and restated effective July 1, 2011 | | | | | | | | |
| | | | | | | | | | |
10.3** | | UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees effective December 6, 2005 | | UGI | | Form 10-K (9/30/06) | | | 10.66 | |
| | | | | | | | | | |
10.4** | | UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers effective May 20, 2008 | | UGI | | Form 10-Q (6/30/08) | | | 10.1 | |
| | | | | | | | | | |
10.5** | | UGI Corporation Amended and Restated Directors’ Deferred Compensation Plan as of January 1, 2005 | | UGI | | Form 10-K (9/30/10) | | | 10.5 | |
| | | | | | | | | | |
10.6** | | UGI Corporation 2000 Directors’ Stock Option Plan Amended and Restated as of May 24, 2005 | | UGI | | Form 10-K (9/30/06) | | | 10.13 | |
| | | | | | | | | | |
10.7** | | UGI Corporation 1997 Stock Option and Dividend Equivalent Plan Amended and Restated as of May 24, 2005 | | UGI | | Form 10-K (9/30/10) | | | 10.7 | |
| | | | | | | | | | |
10.8** | | UGI Corporation 2000 Stock Incentive Plan Amended and Restated as of May 24, 2005 | | UGI | | Form 10-K (9/30/06) | | | 10.14 | |
| | | | | | | | | | |
10.9** | | UGI Corporation 2009 Deferral Plan As Amended and Restated Effective June 1, 2010 | | UGI | | Form 10-Q (6/30/10) | | | 10.1 | |
| | | | | | | | | | |
10.10** | | UGI Corporation Senior Executive Employee Severance Plan as in effect as of January 1, 2008 | | UGI | | Form 10-Q (3/31/08) | | | 10.1 | |
| | | | | | | | | | |
10.11** | | UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective January 1, 2009 | | UGI | | Form 10-K (9/30/09) | | | 10.11 | |
| | | | | | | | | | |
10.12** | | Amendment 2009-1 to the UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan as Amended and Restated effective January 1, 2009 | | UGI | | Form 10-Q (12/31/09) | | | 10.1 | |
64
| | | | | | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
10.1** | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 | UGI | Form 8-K (2/27/07) | 10.1 |
10.2** | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 - Terms and Conditions as amended and restated effective July 30, 2012. | UGI | Form 10-K (9/30/11) | 10.2 |
10.3** | UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers effective May 20, 2008 | UGI | Form 10-Q (6/30/08) | 10.1 |
10.4** | UGI Corporation Amended and Restated Directors' Deferred Compensation Plan as of January 1, 2005 | UGI | Form 10-K (9/30/10) | 10.5 |
10.5** | UGI Corporation 2000 Directors' Stock Option Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.13 |
10.6** | UGI Corporation 1997 Stock Option and Dividend Equivalent Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/10) | 10.7 |
10.7** | UGI Corporation 2000 Stock Incentive Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.14 |
10.8** | UGI Corporation 2009 Deferral Plan As Amended and Restated Effective June 1, 2010 | UGI | Form 10-Q (6/30/10) | 10.1 |
10.9** | UGI Corporation Senior Executive Employee Severance Plan as in effect as of January 1, 2008 | UGI | Form 10-Q (3/31/08) | 10.1 |
10.10** | UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective January 1, 2009 | UGI | Form 10-K (9/30/09) | 10.11 |
10.11** | Amendment 2009-1 to the UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan as Amended and Restated effective January 1, 2009 | UGI | Form 10-Q (12/31/09) | 10.1 |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | | Exhibit | | Registrant | | Filing | | Exhibit | |
| | | | | | | | | | |
10.13*10.12** | | UGI Corporation 2009 Supplemental Executive Retirement Plan For New Employees as Amended and Restated as of October 1, 2010 | | UGI | | Form 10-Q (12/31/09) | | | 10.2 | |
| | | | | | | | | | |
10.14*10.13** | | UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006 | | UGI | | Form 10-K (9/30/07) | | | 10.8 | |
| | | | | | | | | | |
10.15*10.14** | | AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., as Amended and Restated effective January 1, 2005 | | AmeriGas Partners, L.P. | | Form 10-K (9/30/08) | | | 10.7 | |
| | | | | | | | | | |
10.16*10.15** | | AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective July 30, 2010 | | AmeriGas Partners, L.P. | | Form 8-K (7/30/10) | | | 10.2 | |
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10.17*10.16** | | AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective July 30, 2010 —- Terms and Conditions | | AmeriGas Partners, L.P. | | Form 10-K (9/30/10) | | | 10.10 | 10.1 |
10.16a** | AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. Performance Unit Grant Letter for Employees dated January 1, 2012. | AmeriGas Partners, L.P. | Form 10-Q (3/31/12) | 10.11 |
10.17** | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Mr. Grady dated January 17, 2012 | AmeriGas Partners, L.P. | Form 10-Q (3/31/12) | 10.9 |
10.18** | AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Phantom Unit Grant Letter for Mr. Grady dated as of January 17, 2012 | AmeriGas Partners, L.P. | Form 10-Q (3/31/12) | 10.7 |
10.19** | AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Performance Unit Grant Letter for Mr. Grady dated January 17, 2012 | AmeriGas Partners, L.P. | Form 10-Q (3/31/12) | 10.8 |
*10.20** | Form of UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for Ms. Monica M. Gaudiosi for the 2010-12 Performance Period, dated as of April 23, 2012 | | | |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
*10.21** | Form of UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for Ms. Monica M. Gaudiosi for the 2011-13 Performance Period, dated as of April 23, 2012 | | | |
10.18*10.22** | | AmeriGas Propane, Inc. Non-Qualified Deferred Compensation Plan, as Amended and Restated effective January 1, 20092012. | | AmeriGas Partners, L.P. | | Form 10-K (9/30/08)10-Q (3/31/12) | | | 10.44 | 10.5 |
| | | | | | | | | | |
10.19*10.23** | | Letter Agreement dated May 15, 2002 regarding severance arrangement for Mr. Varagne | | UGI | | Form 10-K (9/30/05) | | | 10.15 | |
| | | | | | | | | | |
10.20** | | AmeriGas Propane, Inc. Senior Executive Employee Severance Plan, as in effect January 1, 20082008. | | AmeriGas Partners, L.P. | | Form 10-K (9/30/09) | | 02) | 10.12 | |
| | | | | | | | | | |
10.21*10.24** | | AmeriGas Propane, Inc. Executive Employee Severance Plan, as in effect January 1, 2008 | | AmeriGas Partners, L.P. | | Form 10-K (9/30/08) | | | 10.4 | |
| | | | | | | | | | |
10.22*10.25** | | AmeriGas Propane, Inc. Supplemental Executive Retirement Plan, as Amended and Restated effective January 1, 2009 | | AmeriGas Partners, L.P. | | Form 10-Q (12/31/09) | | | 10.1 | |
| | | | | | | | | | |
10.23*10.26** | | AmeriGas Propane, Inc. Executive Annual Bonus Plan, effective as of October 1, 2006 | | AmeriGas Partners, L.P. | | Form 10-K (9/30/07) | | | 10.19 | |
| | | | | | | | | | |
10.24*10.27** | | Summary of Antargaz Supplemental Retirement Plans effective as of September 1, 2009 | | UGI | | Form 10-K (9/30/09) | | | 10.20 | |
| | | | | | | | | | |
10.28**10.25** | | UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for Non Employee Directors, dated January 7, 2011 | | | | | | | | |
| | | | | | | | | | |
10.26** | | UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for UGI Employees, dated January 1, 2009 | 9, 2012 | UGI | | Form 10-Q (3/31/09)12) | | | 10.8 | 10.16 |
| | | | | | | | | | |
10.29**10.27** | | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 1, 20119, 2012 | UGI | Form 10-Q (3/31/12) | | | | | | |
65
| | | | | | | | | | 10.10 |
Incorporation by Reference | |
Exhibit No. | | Exhibit | | Registrant | | Filing | | Exhibit | |
| | | | | | | | | | |
10.30**10.28** | | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 20112012 | UGI | Form 10-Q (3/31/12) | 10.11 |
| | | | |
| | | | | | | | | | |
*10.29**Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
10.31** | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for AmeriGas Employees, dated January 1, 20112012 | UGI | Form 10-Q (3/31/12) | | | | | | 10.12 |
| | | | | | | | | | |
10.32**10.30** | | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 20112012 | UGI | Form 10-Q (3/31/12) | | | | | | 10.13 |
| | | | | | | | | | |
10.33**10.31** | | UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Employees, dated January 1, 20112012 | UGI | Form 10-Q (3/31/12) | | | | | | 10.14 |
| | | | | | | | | | |
10.34**10.32** | | UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 20112012 | UGI | Form 10-Q (3/31/12) | | | | | | 10.15 |
| | | | | | | | | | |
10.35**10.33** | | UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Stock Option Grant Letter effective January 1, 20112012 | UGI | Form 10-K (9/30/11) | | | | | | 10.33 |
| | | | | | | | | | |
10.36**10.34** | | UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Performance Unit Grant Letter effective January 1, 20112012 | UGI | Form 10-K (9/30/11) | | | | | | |
| | | | | | | | | | 10.34 |
*10.35*10.37** | | Description of oral compensation arrangements for Messrs. Greenberg, Knauss, VaragneWalsh, Hall, and Walsh | | | | | Oliver and Ms. Gaudiosi | | | |
| | | | | | | | | | |
10.36*10.38** | | Description of oral compensation arrangement for Mr. BissellSheridan | | AmeriGas Partners, L.P. | | Form 10-K (9/30/11)12) | | | 10.26 | 10.29 |
| | | | | | | | | | |
10.37*10.39** | | AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., as amended and restated effective January 1, 2005, Restricted Unit Grant Letter dated as of December 31, 2009 | | AmeriGas Partners, L.P. | | Form 10-Q (3/31/10) | | | 10.2 |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
*10.40** | Summary of Director Compensation as of October 1, 2012 | | | |
10.41** | Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Messrs. Greenberg and Walsh | UGI | Form 10-Q (6/30/08) | 10.3 |
10.42** | Change in Control Agreement for Monica M. Gaudiosi dated as of April 23, 2012 | UGI | Form 10-Q (6/30/12) | 10.1 |
10.43** | Form of Confidentiality and Post-Employment Activities Agreement with AmeriGas Propane, Inc. for Mr. Bissell | AmeriGas Partners, L.P. | Form 10-Q (3/31/05) | 10.3 |
10.44** | Settlement Agreement dated October 12, 2011 among AGZ Holding, Antargaz and Mr. Varagne | UGI | Form 8-K (10/12/11) | 10.1 |
10.45 | Trademark License Agreement dated April 19, 1995 among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | UGI | Form 10-K (9/30/10) | 10.37 |
10.46 | Trademark License Agreement, dated April 19, 1995 among AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | AmeriGas Partners, L.P. | Form 10-Q (12/31/10) | 10.1 |
10.47 | Credit Agreement dated as of June 21, 2011, as amended through and including Amendment No. 4 thereto dated April 18, 2012, by and among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as a Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Lender (“Agent”), Wells Fargo Securities, LLC, as Sole Lead Arranger and Sole Book Manager and the financial institutions from time to time party thereto | AmeriGas Partners, L.P. | Form 10-K (9/30/12) | 10.39 |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
10.48 | Release of Liens and Termination of Security Documents dated as of November 6, 2006 by and among AmeriGas Propane, Inc., Petrolane Incorporated, AmeriGas Propane, L.P., AmeriGas Propane Parts & Service, Inc. and Wachovia Bank, National Association, as Collateral Agent for the Secured Creditors, pursuant to the Intercreditor and Agency Agreement dated as of April 19, 1995 | AmeriGas Partners, L.P. | Form 10-K (9/30/06) | 10.3 |
10.49 | Receivables Purchase Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 8 thereto dated April 22, 2010 and Amendment No. 9 thereto dated August 26, 2010, by and among UGI Energy Services, Inc., as servicer, Energy Services Funding Corporation, as seller, Market Street Funding, LLC, as issuer, and PNC Bank, National Association, as administrator | UGI | Form 10-K (9/30/11) | 10.47 |
10.50 | Amendment No. 10, dated as of April 21, 2011 to Receivables Purchase Agreement, dated as of November 30, 2001(as amended, supplemented or modified from time to time), by and among UGI Energy Services, Inc. as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator | UGI | Form 8-K (4/21/11) | |
10.51 | Amendment No. 11, dated as of April 19, 2012, to Receivables Purchase Agreement, dated as of November 30, 2001 (as amended, supplemented or modified from time to time), by and among UGI Energy Services, Inc., as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator | UGI | Form 8-K (4/19/12) | 10.1 |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
10.52 | Credit Agreement, dated as of May 25, 2011 among UGI Utilities, Inc., as borrower, and PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and RBS Citizens, N.A., as joint lead arrangers and joint bookrunners, and PNC Bank, National Association, Citizens Bank of Pennsylvania, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, The Bank of New York Mellon, and the other financial institutions from time to time parties thereto | Utilities | Form 8-K (5/25/11) | 10.1 |
10.53 | Purchase and Sale Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 3 thereto dated August 26, 2010, by and between UGI Energy Services, Inc. and Energy Services Funding Corporation | UGI | Form 10-K (9/30/10) | 10.47 |
10.54 | Credit Agreement, dated as of August 26, 2010, among UGI Energy Services, Inc., as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, PNC Bank, National Association, as syndication agent, and Wells Fargo Bank, National Association and Credit Suisse AG, Cayman Islands Branch, as co-documentation agents | UGI | Form 10-K (9/30/10) | 10.48 |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
10.55 | Senior Facilities Agreement dated March 16, 2011 by and among AGZ Holding, as Parent and Borrower, Antargaz, as Borrower, BNP Paribas, Caisse Régionale de Crédit Agricole Mutuel de Paris et d'Ile de France, Credit Lyonnais and Natixis, as Mandated Lead Arrangers and Bookrunners, Barclays Bank PLC, Banque Commerciale pour le Marché de l'Entreprise and ING Belgium SA, Succursale en France, as Mandated Lead Arrangers, Natixis, as Facility Agent and Security Agent, Banco Bilbao Vizcaya Argentaria, Crédit du Nord, HSBC France, Crédit Suisse International, Bred Banque Populaire and Banque Palatine, as Arrangers and the Financial Institutions named therein | UGI | Form 10-Q (3/31/11) | 10.1 |
10.56 | Pledge of Financial Instruments Account relating to Financial Instruments held by AGZ Holding in Antargaz, dated March 16, 2011, by and among AGZ Holding, as Pledgor, Natixis, as Security Agent and Bank Account Holder, and the Lenders, as Beneficiaries | UGI | Form 10-Q (3/31/11) | 10.2 |
10.57 | Pledge of Financial Instruments Account relating to Financial Instruments held by Antargaz in certain subsidiary companies, dated March 16, 2011, by and among Antargaz, as Pledgor, Natixis, as Security Agent and Bank Account Holder, and the Lenders, as Beneficiaries | UGI | Form 10-Q (3/31/11) | 10.3 |
10.58 | Master Agreement for Assignment of Receivables dated March 16, 2011 between AGZ Holding, as Assignor, Natixis, as Security Agent, and the Beneficiaries | UGI | Form 10-Q (3/31/11) | 10.4 |
10.59 | Master Agreement for Assignment of Receivables dated March 16, 2011 between Antargaz, as Assignor, Natixis, as Security Agent, and the Beneficiaries | UGI | Form 10-Q (3/31/11) | 10.5 |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
10.60 | First Demand Guarantee dated March 16, 2011 by UGI Corporation in favor of Natixis and the Lenders set forth in the Senior Facilities Agreement dated March 16, 2011 | UGI | Form 10-Q (3/31/11) | 10.6 |
10.61 | FSS Service Agreement No. 79028 dated March 29, 2012 between Columbia Gas Transmission, LLC and UGI Utilities, Inc. | Utilities | Form 10-Q (3/31/12) | 10.2 |
10.62 | Firm Storage and Delivery Service Agreement (Rate GSS) dated July 1, 1996 between Transcontinental Gas Pipe Line Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.8 |
10.63 | Service Agreement For Use Under Seller's GSS Rate Schedule dated July 9, 2012 between Transcontinental Gas Pipe Line Company, LLC and UGI Penn Natural Gas, Inc. | Utilities | Form 10-Q (6/30/12) | 10.1 |
10.64 | SST Service Agreement No. 79133 dated March 29, 2012 between Columbia Gas Transmission, LLC and UGI Utilities, Inc. | Utilities | Form 10-Q (3/31/12) | 10.1 |
10.65 | FTS-1 Service Agreement No. 46283 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 between Columbia Gulf Transmission Company and UGI Utilities, Inc. | Utilities | Form 10-Q (3/31/11) | 10.1 |
10.66 | FTS Service Agreement No. 46284 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004, between Columbia Transmission Corporation and UGI Utilities, Inc. | Utilities | Form 10-Q (3/31/11) | 10.2 |
10.67 | Amendment to FTS-1 Service Agreement No. 46283 and FTS Service Agreement No. 46284 each dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 dated November 1, 1993 | Utilities | Form 10-Q (3/31/11) | 10.3 |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
10.68 | Contingent Residential Support Agreement dated as of January 12, 2012, among Energy Transfer Partners, L.P., AmeriGas Finance LLC, AmeriGas Finance Corp., AmeriGas Partners, L.P., and for certain limited purposes only, UGI Corporation | AmeriGas Partners, L.P. | Form 8-K (1/11/12) | 10.1 |
10.69 | Unitholder Agreement, dated as of January 12, 2012, by and among Heritage ETC, L.P., AmeriGas Partners, L.P., and, for limited purposes, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., and Energy Transfer Equity, L.P. | AmeriGas Partners, L.P. | Form 8-K (1/11/12) | 10.2 |
14 | Code of Ethics for principal executive, financial and accounting officers | UGI | Form 10-K (9/30/03) | 14 |
*21 | Subsidiaries of the Registrant | | | |
*23 | Consent of PricewaterhouseCoopers LLP | | | |
*31.1 | Certification by the Chief Executive Officer relating to the Registrant's Report on Form 10-K for the fiscal year ended September 30, 2012 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | | |
*31.2 | Certification by the Chief Financial Officer relating to the Registrant's Report on Form 10-K for the fiscal year ended September 30, 2012 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | | |
*32 | Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant's Report on Form 10-K for the fiscal year ended September 30, 2012, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | | | |
*101.INS | XBRL.Instance | | | |
*101.SCH | XBRL Taxonomy Extension Schema | | | |
*101.CAL | XBRL Taxonomy Extension Calculation Linkbase | | | |
*101.DEF | XBRL Taxonomy Extension Definition Linkbase | | | |
|
| | | | | | |
Incorporation by Reference |
Exhibit No. | Exhibit | Registrant | Filing | Exhibit |
*101.LAB | XBRL Taxonomy Extension Labels Linkbase | | | |
10.38**101.PRE | | Summary of Director Compensation as of October 1, 2010 | | UGI | | Form 10-K (9/30/10) | | | 10.33 | |
| | | | | | | XBRL Taxonomy Extension Presentation Linkbase | | | |
10.39** | | Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Messrs. Greenberg, Knauss and Walsh | | UGI | | Form 10-Q (6/30/08) | | | 10.3 | |
| | | | | | | | | | |
10.40** | | Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Mr. Bissell | | AmeriGas Partners, L.P. | | Form 10-Q (6/30/08) | | | 10.1 | |
66
| | | | | | | | | | |
Incorporation by Reference | |
Exhibit No. | | Exhibit | | Registrant | | Filing | | Exhibit | |
| | | | | | | | | | |
10.41** | | Form of Confidentiality and Post-Employment Activities Agreement with AmeriGas Propane, Inc. for Mr. Bissell | | AmeriGas Partners, L.P. | | Form 10-Q (3/31/05) | | | 10.3 | |
| | | | | | | | | | |
10.42** | | Settlement Agreement dated October 12, 2011 among AGZ Holding, Antargaz and Mr. Varagne | | UGI | | Form 8-K (10/12/11) | | | 10.1 | |
| | | | | | | | | | |
10.43 | | Trademark License Agreement dated April 19, 1995 among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | | UGI | | Form 10-K (9/30/10) | | | 10.37 | |
| | | | | | | | | | |
10.44 | | Trademark License Agreement, dated April 19, 1995 among AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | | AmeriGas Partners, L.P. | | Form 10-Q (12/31/10) | | | 10.1 | |
| | | | | | | | | | |
10.45 | | Credit Agreement dated as of June 21, 2011 by and among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as a Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Lender (“Agent”), Wells Fargo Securities, LLC, as Sole Lead Arranger and Sole Book Manager and Wells Fargo Bank, National Association, Branch Banking and Trust Company, Citibank, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, Citizens Bank of Pennsylvania, The Bank of New York Mellon, Compass Bank, Manufacturers and Traders Trust Company, Sovereign Bank, TD Bank, N.A. and the other financial institutions from time to time party thereto | | AmeriGas Partners, L.P. | | Form 10-Q (6/30/11) | | | 10.2 | |
| | | | | | | | | | |
10.46 | | Release of Liens and Termination of Security Documents dated as of November 6, 2006 by and among AmeriGas Propane, Inc., Petrolane Incorporated, AmeriGas Propane, L.P., AmeriGas Propane Parts & Service, Inc. and Wachovia Bank, National Association, as Collateral Agent for the Secured Creditors, pursuant to the Intercreditor and Agency Agreement dated as of April 19, 1995 | | AmeriGas Partners, L.P. | | Form 10-K (9/30/06) | | | 10.3 | |
| | | | | | | | | | |
*10.47 | | Receivables Purchase Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 8 thereto dated April 22, 2010 and Amendment No. 9 thereto dated August 26, 2010, by and among UGI Energy Services, Inc., as servicer, Energy Services Funding Corporation, as seller, Market Street Funding, LLC, as issuer, and PNC Bank, National Association, as administrator | | | | | | | | |
67
| | | | | | | | | | |
Incorporation by Reference | |
Exhibit No. | | Exhibit | | Registrant | | Filing | | Exhibit | |
| | | | | | | | | | |
10.48 | | Amendment No. 10, dated as of April 21, 2011 to Receivables Purchase Agreement, dated as of November 30, 2001(as amended, supplemented or modified from time to time), by and among UGI Energy Services, Inc. as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator | | UGI | | Form 8-K (4/21/11) | | | 10.1 | |
| | | | | | | | | | |
10.49 | | Credit Agreement, dated as of May 25, 2011 among UGI Utilities, Inc., as borrower, and PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and RBS Citizens, N.A., as joint lead arrangers and joint bookrunners, and PNC Bank, National Association, Citizens Bank of Pennsylvania, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, The Bank of New York Mellon, and the other financial institutions from time to time parties thereto | | Utilities | | Form 8-K (5/25/11) | | | 10.1 | |
| | | | | | | | | | |
10.50 | | Purchase and Sale Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 3 thereto dated August 26, 2010, by and between UGI Energy Services, Inc. and Energy Services Funding Corporation | | UGI | | Form 10-K (9/30/10) | | | 10.47 | |
| | | | | | | | | | |
10.51 | | Credit Agreement, dated as of August 26, 2010, among UGI Energy Services, Inc., as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, PNC Bank, National Association, as syndication agent, and Wells Fargo Bank, National Association and Credit Suisse AG, Cayman Islands Branch, as co-documentation agents | | UGI | | Form 10-K (9/30/10) | | | 10.48 | |
| | | | | | | | | | |
10.52 | | Senior Facilities Agreement dated March 16, 2011 by and among AGZ Holding, as Parent and Borrower, Antargaz, as Borrower, BNP Paribas, Caisse Régionale de Crédit Agricole Mutuel de Paris et d’Ile de France, Credit Lyonnais and Natixis, as Mandated Lead Arrangers and Bookrunners, Barclays Bank PLC, Banque Commerciale pour le Marché de l’Entreprise and ING Belgium SA, Succursale en France, as Mandated Lead Arrangers, Natixis, as Facility Agent and Security Agent, Banco Bilbao Vizcaya Argentaria, Crédit du Nord, HSBC France, Crédit Suisse International, Bred Banque Populaire and Banque Palatine, as Arrangers and the Financial Institutions named therein | | UGI | | Form 10-Q (3/31/11) | | | 10.1 | |
68
| | | | | | | | | | |
Incorporation by Reference | |
Exhibit No. | | Exhibit | | Registrant | | Filing | | Exhibit | |
| | | | | | | | | | |
10.53 | | Pledge of Financial Instruments Account relating to Financial Instruments held by AGZ Holding in Antargaz, dated March 16, 2011, by and among AGZ Holding, as Pledgor, Natixis, as Security Agent and Bank Account Holder, and the Lenders, as Beneficiaries | | UGI | | Form 10-Q (3/31/11) | | | 10.2 | |
| | | | | | | | | | |
10.54 | | Pledge of Financial Instruments Account relating to Financial Instruments held by Antargaz in certain subsidiary companies, dated March 16, 2011, by and among Antargaz, as Pledgor, Natixis, as Security Agent and Bank Account Holder, and the Lenders, as Beneficiaries | | UGI | | Form 10-Q (3/31/11) | | | 10.3 | |
| | | | | | | | | | |
10.55 | | Master Agreement for Assignment of Receivables dated March 16, 2011 between AGZ Holding, as Assignor, Natixis, as Security Agent, and the Beneficiaries | | UGI | | Form 10-Q (3/31/11) | | | 10.4 | |
| | | | | | | | | | |
10.56 | | Master Agreement for Assignment of Receivables dated March 16, 2011 between Antargaz, as Assignor, Natixis, as Security Agent, and the Beneficiaries | | UGI | | Form 10-Q (3/31/11) | | | 10.5 | |
| | | | | | | | | | |
10.57 | | First Demand Guarantee dated March 16, 2011 by UGI Corporation in favor of Natixis and the Lenders set forth in the Senior Facilities Agreement dated March 16, 2011 | | UGI | | Form 10-Q (3/31/11) | | | 10.6 | |
| | | | | | | | | | |
10.58 | | Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, Inc. effective as of May 1, 2007 | | Utilities | | Form 10-Q (6/30/10) | | | 10.1 | |
| | | | | | | | | | |
10.59 | | Amendment No. 1 dated November 1, 2004, to the Service Agreement (Rate FSS) dated as of November 1, 1989 between Utilities and Columbia, as modified pursuant to the orders of the Federal Energy Regulatory Commission at Docket No. RS92-5-000 reported at Columbia Gas Transmission Corp., 64 FERC ¶61,060 (1993), order on rehearing, 64 FERC ¶61,365 (1993) | | UGI | | Form 10-K (9/30/10) | | | 10.60 | |
| | | | | | | | | | |
10.60 | | Firm Storage and Delivery Service Agreement (Rate GSS) dated July 1, 1996 between Transcontinental Gas Pipe Line Corporation and PG Energy | | Utilities | | Form 8-K (8/24/06) | | | 10.8 | |
| | | | | | | | | | |
10.61 | | SST Service Agreement No. 79133 dated November 1, 2004 between Columbia Gas Transmission Corporation and UGI Utilities, Inc. | | Utilities | | Form 10-Q (6/30/10) | | | 10.2 | |
| | | | | | | | | | |
10.62 | | FTS-1 Service Agreement No. 46283 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 between Columbia Gulf Transmission Company and UGI Utilities, Inc. | | Utilities | | Form 10-Q (3/31/11) | | | 10.1 | |
69
| | | | | | | | | | |
Incorporation by Reference | |
Exhibit No. | | Exhibit | | Registrant | | Filing | | Exhibit | |
| | | | | | | | | | |
10.63 | | FTS Service Agreement No. 46284 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004, between Columbia Transmission Corporation and UGI Utilities, Inc. | | Utilities | | Form 10-Q (3/31/11) | | | 10.2 | |
| | | | | | | | | | |
10.64 | | Amendment to FTS-1 Service Agreement No. 46283 and FTS Service Agreement No. 46284 each dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 dated November 1, 1993 | | Utilities | | Form 10-Q (3/31/11) | | | 10.3 | |
| | | | | | | | | | |
14 | | Code of Ethics for principal executive, financial and accounting officers | | UGI | | Form 10-K (9/30/03) | | | 14 | |
| | | | | | | | | | |
*21 | | Subsidiaries of the Registrant | | | | | | | | |
| | | | | | | | | | |
*23 | | Consent of PricewaterhouseCoopers LLP | | | | | | | | |
| | | | | | | | | | |
*31.1 | | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | | | | | | | |
| | | | | | | | | | |
*31.2 | | Certification by the Principal Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | | | | | | | |
| | | | | | | | | | |
*32 | | Certification by the Chief Executive Officer and the Principal Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | | | | | | | | |
| | | | | | | | | | |
*101.INS*** | | XBRL.Instance | | | | | | | | |
| | | | | | | | | | |
*101.SCH*** | | XBRL Taxonomy Extension Schema | | | | | | | | |
| | | | | | | | | | |
*101.CAL*** | | XBRL Taxonomy Extension Calculation Linkbase | | | | | | | | |
| | | | | | | | | | |
*101.DEF*** | | XBRL Taxonomy Extension Definition Linkbase | | | | | | | | |
| | | | | | | | | | |
*101.LAB*** | | XBRL Taxonomy Extension Labels Linkbase | | | | | | | | |
| | | | | | | | | | |
*101.PRE*** | | XBRL Taxonomy Extension Presentation Linkbase | | | | | | | | |
| |
** | | As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement. |
|
*** | | XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information. |
70
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | | |
| | | |
| | UGI CORPORATION
| |
Date: | November 21, 2011 20, 2012 | By: | /s/ John L. Walsh | Kirk R. Oliver |
| | John L. Walsh | |
| | President and Kirk R. Oliver Chief OperatingFinancial Officer
(Principal Financial Officer) | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 21, 2011,20, 2012, by the following persons on behalf of the Registrant in the capacities indicated.
|
| | | | |
Signature | | | | Title |
| | | | |
/s/ Lon R. Greenberg Lon R. Greenberg | | | | Chairman and Chief Executive Officer
(Principal Executive Officer) and Director |
Lon R. Greenberg | |
| | |
/s/ Kirk R. Oliver | | Chief Financial Officer (Principal Financial Officer) |
Kirk R. Oliver | |
| | |
/s/ John L. Walsh John L. Walsh | | | | President and Chief Operating Officer
(Principal (Principal Operating and Financial Officer) and Director |
John L. Walsh | |
| | | | |
/s/ Davinder S. Athwal Davinder S. Athwal | | | | Vice President — Accounting and Financial Control, Chief Risk Officer (Principal Accounting Officer) |
Davinder S. Athwal | |
| | | | |
/s/ Stephen D. Ban Stephen D. Ban | | | | Director |
Stephen D. Ban | |
| | | | |
/s/ Richard W. Gochnauer Richard W. Gochnauer | | | | Director |
Richard W. Gochnauer | |
| | | | |
/s/ Frank S. Hermance Frank S. Hermance | | | | Director |
Frank S. Hermance | |
| | | | |
/s/ Ernest E. Jones Ernest E. Jones | | | | Director |
Ernest E. Jones | |
| | | | |
| | | | Director |
Anne Pol | |
| | | | |
/s/ M. Shawn Puccio M. Shawn Puccio | | | | Director |
| | | | |
/s/ Marvin O. SchlangerMarvin O. Schlanger | | | | Director |
| | | | |
/s/ Roger B. VincentRoger B. Vincent | | | | Director |
71
EXHIBIT INDEX
| | | | |
Exhibit No. | | Description |
| 10.2 | | | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 — Terms and Conditions as amended and restated effective July 1, 2011 |
| | M. Shawn Puccio | | |
| 10.25 | | | UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for Non Employee Directors, dated January 7, 2011 |
| | | | |
| 10.27/s/ Marvin O. Schlanger | | | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 1, 2011Director |
| | | Marvin O. Schlanger | |
| 10.28 | | | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2011 |
| | | | |
| 10.29 | | | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for AmeriGas Employees, dated January 1, 2011 |
| | | | |
| 10.30 | | | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Utilities Employees, dated January 1, 2011 |
| | | | |
| 10.31 | | | UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Employees, dated January 1, 2011 |
| | | | |
| 10.32 | | | UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2011 |
| | | | |
| 10.33 | | | UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Stock Option Grant Letter effective January 1, 2011 |
| | | | |
| 10.34 | | | UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Performance Unit Grant Letter effective January 1, 2011 |
| | | | |
| 10.35 | | | Description of oral compensation arrangements for Messrs. Greenberg, Knauss, Varagne and Walsh |
| | | | |
72
| | | | |
Exhibit No. | | Description |
| 10.47 | | | Receivables Purchase Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 8 thereto dated April 22, 2010 and Amendment No. 9 thereto dated August 26, 2010, by and among UGI Energy Services, Inc., as servicer, Energy Services Funding Corporation, as seller, Market Street Funding, LLC, as issuer, and PNC Bank, National Association, as administrator |
| | | | |
| 21 | | | Subsidiaries of the Registrant |
| | | | |
| 23 | | | Consent of PricewaterhouseCoopers LLP |
| | | | |
| 31.1 | | | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
| | | | |
| 31.2 | | | Certification by the Principal Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
| | | | |
| 32 | | | Certification by the Chief Executive Officer and the Principal Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
| | | | |
101.INS* | | XBRL.Instance |
| | | | |
101.SCH* | | XBRL Taxonomy Extension Schema |
| | | | |
101.CAL* | | XBRL Taxonomy Extension Calculation Linkbase |
| | | | |
101.DEF* | | XBRL Taxonomy Extension Definition Linkbase |
| | | | |
101.LAB* | | XBRL Taxonomy Extension Labels Linkbase |
| | | | |
101.PRE* | | XBRL Taxonomy Extension Presentation Linkbase |
| | |
*/s/ Roger B. Vincent | | XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information.Director |
Roger B. Vincent | |
73
UGI CORPORATION AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 20112012
UGI CORPORATION
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
|
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| | Pages | |
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| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | F-10 to F-58 | |
| | | | |
Financial Statement Schedules: | | | | |
| | | | |
For the years ended September 30, 2012, 2011 2010 and 2009: | | | 2010: | |
| | | | |
| | | |
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We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
F-2
Report of Management
Financial Statements
The Company’s consolidated financial statements and other financial information contained in this Annual Report are prepared by management, which is responsible for their fairness, integrity and objectivity. The consolidated financial statements and related information were prepared in accordance with accounting principles generally accepted in the United States of America and include amounts that are based on management’s best judgments and estimates.
The Audit Committee of the Board of Directors is composed of three members, none of whom is an employee of the Company. This Committee is responsible for (i) overseeing the financial reporting process and the adequacy of internal control and (ii) monitoring the independence and performance of the Company’s independent registered public accounting firm and internal auditors. The Committee is also responsible for maintaining direct channels of communication among the Board of Directors, management, and both the independent registered public accounting firm and the internal auditors.
PricewaterhouseCoopers LLP, our independent registered public accounting firm, is engaged to perform audits of our consolidated financial statements. These audits are performed in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our independent registered public accounting firm was given unrestricted access to all financial records and related data, including minutes of all meetings of the Board of Directors and committees of the Board. The Company believes that all representations made to the independent registered public accounting firm during their audits were valid and appropriate.
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, of the Company’s internal control over financial reporting, using the criteria in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”).
Internal control over financial reporting refers to the process, designed under the supervision and participation of management including our Chief Executive Officer and our Chief Financial Officer, to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes policies and procedures that, among other things, provide reasonable assurance that assets are safeguarded and that transactions are executed in accordance with management’s authorization and are properly recorded to permit the preparation of reliable financial information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changing conditions, or the degree of compliance with the policies or procedures may deteriorate.
Based on its assessment, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2011,2012, based on the COSO Framework. PricewaterhouseCoopers LLP, our independent registered public accounting firm, audited the effectiveness of the Company’s internal control over financial reporting as of September 30, 2011,2012, as stated in their report, which appears herein.
/s/ Lon R. Greenberg
Chief Executive Officer
/s/ John L. Walsh
Kirk R. Oliver
Chief Financial Officer
/s/ Davinder S. Athwal
Chief Accounting Officer
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of UGI Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of changes in equity and of cash flows present fairly, in all material respects, the financial position of UGI Corporation and its subsidiaries at September 30, 20112012 and 2010,2011, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 20112012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15 (a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2011,2012, based on criteria established in Internal Control —- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers
LLP
Philadelphia, Pennsylvania
November 21, 201120, 2012
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
| | | | | | | | |
| | September 30, | |
| | 2011 | | | 2010 | |
ASSETS | | | | | | | | |
Current assets | | | | | | | | |
Cash and cash equivalents | | $ | 238.5 | | | $ | 260.7 | |
Restricted cash | | | 17.2 | | | | 34.8 | |
Accounts receivable (less allowances for doubtful accounts of $36.8 and $34.6, respectively) | | | 546.7 | | | | 467.8 | |
Accrued utility revenues | | | 14.8 | | | | 14.0 | |
Inventories | | | 363.0 | | | | 314.0 | |
Deferred income taxes | | | 44.9 | | | | 32.6 | |
Income taxes recoverable | | | 19.2 | | | | 20.1 | |
Utility regulatory assets | | | 8.6 | | | | 26.1 | |
Derivative financial instruments | | | 10.2 | | | | 11.3 | |
Prepaid expenses and other current assets | | | 43.0 | | | | 38.7 | |
| | | | | | |
Total current assets | | | 1,306.1 | | | | 1,220.1 | |
| | | | | | | | |
Property, plant and equipment | | | | | | | | |
Utilities | | | 2,201.0 | | | | 2,129.3 | |
Non-utility | | | 3,083.5 | | | | 2,840.4 | |
| | | | | | |
| | | 5,284.5 | | | | 4,969.7 | |
Accumulated depreciation and amortization | | | (2,080.0 | ) | | | (1,929.5 | ) |
| | | | | | |
Net property, plant, and equipment | | | 3,204.5 | | | | 3,040.2 | |
| | | | | | | | |
Goodwill | | | 1,562.2 | | | | 1,562.7 | |
Intangible assets, net | | | 147.8 | | | | 150.1 | |
Other assets | | | 442.7 | | | | 401.2 | |
| | | | | | |
Total assets | | $ | 6,663.3 | | | $ | 6,374.3 | |
| | | | | | |
| | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | |
Current liabilities | | | | | | | | |
Current maturities of long-term debt | | $ | 47.4 | | | $ | 573.6 | |
Bank loans | | | 138.7 | | | | 200.4 | |
Accounts payable | | | 399.6 | | | | 372.6 | |
Employee compensation and benefits accrued | | | 73.9 | | | | 86.3 | |
Deposits and advances | | | 161.5 | | | | 165.3 | |
Derivative financial instruments | | | 49.7 | | | | 58.0 | |
Other current liabilities | | | 207.1 | | | | 218.5 | |
| | | | | | |
Total current liabilities | | | 1,077.9 | | | | 1,674.7 | |
| | | | | | | | |
Debt and other liabilities | | | | | | | | |
Long-term debt | | | 2,110.3 | | | | 1,432.2 | |
Deferred income taxes | | | 709.2 | | | | 601.4 | |
Deferred investment tax credits | | | 5.0 | | | | 5.3 | |
Other noncurrent liabilities | | | 569.8 | | | | 599.1 | |
| | | | | | |
Total liabilities | | | 4,472.2 | | | | 4,312.7 | |
| | | | | | | | |
Commitments and contingencies (note 15) | | | | | | | | |
| | | | | | | | |
Equity: | | | | | | | | |
UGI Corporation stockholders’ equity: | | | | | | | | |
UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,507,094 and 115,400,294 shares, respectively) | | | 937.4 | | | | 906.1 | |
Retained earnings | | | 1,085.8 | | | | 966.7 | |
Accumulated other comprehensive loss | | | (17.7 | ) | | | (10.1 | ) |
Treasury stock, at cost | | | (27.8 | ) | | | (38.2 | ) |
| | | | | | |
Total UGI Corporation stockholders’ equity | | | 1,977.7 | | | | 1,824.5 | |
Noncontrolling interests, principally in AmeriGas Partners | | | 213.4 | | | | 237.1 | |
| | | | | | |
Total equity | | | 2,191.1 | | | | 2,061.6 | |
| | | | | | |
Total liabilities and equity | | $ | 6,663.3 | | | $ | 6,374.3 | |
| | | | | | |
|
| | | | | | | |
| September 30, |
| 2012 | | 2011 |
ASSETS | | | |
Current assets | | | |
Cash and cash equivalents | $ | 319.9 |
| | $ | 238.5 |
|
Restricted cash | 3.0 |
| | 17.2 |
|
Accounts receivable (less allowances for doubtful accounts of $36.1 and $36.8, respectively) | 632.6 |
| | 546.7 |
|
Accrued utility revenues | 16.9 |
| | 14.8 |
|
Inventories | 356.9 |
| | 363.0 |
|
Deferred income taxes | 56.8 |
| | 44.9 |
|
Income taxes recoverable | 32.2 |
| | 19.2 |
|
Utility regulatory assets | 6.5 |
| | 8.6 |
|
Derivative financial instruments | 13.2 |
| | 10.2 |
|
Prepaid expenses and other current assets | 66.5 |
| | 43.0 |
|
Total current assets | 1,504.5 |
| | 1,306.1 |
|
Property, plant and equipment | | | |
Utilities | 2,295.7 |
| | 2,201.0 |
|
Non-utility | 4,223.4 |
| | 3,083.5 |
|
| 6,519.1 |
| | 5,284.5 |
|
Accumulated depreciation and amortization | (2,286.0 | ) | | (2,080.0 | ) |
Net property, plant, and equipment | 4,233.1 |
| | 3,204.5 |
|
Goodwill | 2,818.3 |
| | 1,562.2 |
|
Intangible assets, net | 658.2 |
| | 147.8 |
|
Other assets | 495.6 |
| | 442.7 |
|
Total assets | $ | 9,709.7 |
| | $ | 6,663.3 |
|
LIABILITIES AND EQUITY | | | |
Current liabilities | | | |
Current maturities of long-term debt | $ | 166.7 |
| | $ | 47.4 |
|
Bank loans | 165.1 |
| | 138.7 |
|
Accounts payable | 411.3 |
| | 399.6 |
|
Employee compensation and benefits accrued | 91.1 |
| | 73.9 |
|
Deposits and advances | 252.8 |
| | 161.5 |
|
Derivative financial instruments | 100.9 |
| | 49.7 |
|
Accrued interest | 72.7 |
| | 27.9 |
|
Other current liabilities | 226.4 |
| | 179.2 |
|
Total current liabilities | 1,487.0 |
| | 1,077.9 |
|
Debt and other liabilities | | | |
Long-term debt | 3,347.6 |
| | 2,110.3 |
|
Deferred income taxes | 935.0 |
| | 709.2 |
|
Deferred investment tax credits | 4.6 |
| | 5.0 |
|
Other noncurrent liabilities | 616.7 |
| | 569.8 |
|
Total liabilities | 6,390.9 |
| | 4,472.2 |
|
Commitments and contingencies (Note 15) |
| |
|
Equity: | | | |
UGI Corporation stockholders’ equity: | | | |
UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,624,594 and 115,507,094 shares, respectively) | 1,157.7 |
| | 937.4 |
|
Retained earnings | 1,166.1 |
| | 1,085.8 |
|
Accumulated other comprehensive loss | (62.0 | ) | | (17.7 | ) |
Treasury stock, at cost | (28.7 | ) | | (27.8 | ) |
Total UGI Corporation stockholders’ equity | 2,233.1 |
| | 1,977.7 |
|
Noncontrolling interests, principally in AmeriGas Partners | 1,085.7 |
| | 213.4 |
|
Total equity | 3,318.8 |
| | 2,191.1 |
|
Total liabilities and equity | $ | 9,709.7 |
| | $ | 6,663.3 |
|
See accompanying notes to consolidated financial statements.
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
| | | | | | | | | | | | |
| | Year Ended September 30, | |
| | 2011 | | | 2010 | | | 2009 | |
Revenues | | | | | | | | | | | | |
Utilities | | $ | 1,135.5 | | | $ | 1,167.7 | | | $ | 1,379.5 | |
Non-utility and other | | | 4,955.8 | | | | 4,423.7 | | | | 4,358.3 | |
| | | | | | | | | |
| | | 6,091.3 | | | | 5,591.4 | | | | 5,737.8 | |
| | | | | | | | | |
Costs and Expenses | | | | | | | | | | | | |
Cost of sales (excluding depreciation shown below): | | | | | | | | | | | | |
Utilities | | | 678.5 | | | | 730.5 | | | | 944.8 | |
Non-utility and other | | | 3,332.4 | | | | 2,853.5 | | | | 2,725.8 | |
Operating and administrative expenses | | | 1,266.4 | | | | 1,177.4 | | | | 1,220.0 | |
Utility taxes other than income taxes | | | 16.6 | | | | 18.6 | | | | 16.9 | |
Depreciation | | | 201.2 | | | | 187.6 | | | | 180.2 | |
Amortization | | | 26.7 | | | | 22.6 | | | | 20.7 | |
Other income, net | | | (46.5 | ) | | | (58.0 | ) | | | (55.9 | ) |
| | | | | | | | | |
| | | 5,475.3 | | | | 4,932.2 | | | | 5,052.5 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Operating income | | | 616.0 | | | | 659.2 | | | | 685.3 | |
Loss from equity investees | | | (0.9 | ) | | | (2.1 | ) | | | (3.1 | ) |
Loss on extinguishments of debt | | | (38.1 | ) | | | — | | | | — | |
Interest expense | | | (138.0 | ) | | | (133.8 | ) | | | (141.1 | ) |
| | | | | | | | | |
Income before income taxes | | | 439.0 | | | | 523.3 | | | | 541.1 | |
Income taxes | | | (130.8 | ) | | | (167.6 | ) | | | (159.1 | ) |
| | | | | | | | | |
Net income | | | 308.2 | | | | 355.7 | | | | 382.0 | |
Less: net income attributable to noncontrolling interests, principally in AmeriGas Partners | | | (75.3 | ) | | | (94.7 | ) | | | (123.5 | ) |
| | | | | | | | | |
Net income attributable to UGI Corporation | | $ | 232.9 | | | $ | 261.0 | | | $ | 258.5 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Earnings per common share attributable to UGI Corporation stockholders: | | | | | | | | | | | | |
Basic | | $ | 2.09 | | | $ | 2.38 | | | $ | 2.38 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Diluted | | $ | 2.06 | | | $ | 2.36 | | | $ | 2.36 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Average common shares outstanding (thousands): | | | | | | | | | | | | |
Basic | | | 111,674 | | | | 109,588 | | | | 108,523 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Diluted | | | 112,944 | | | | 110,511 | | | | 109,339 | |
| | | | | | | | | |
|
| | | | | | | | | | | |
| Year Ended September 30, |
| 2012 | | 2011 | | 2010 |
Revenues | | | | | |
Utilities | $ | 882.5 |
| | $ | 1,135.5 |
| | $ | 1,167.7 |
|
Non-utility | 5,636.7 |
| | 4,955.8 |
| | 4,423.7 |
|
| 6,519.2 |
| | 6,091.3 |
| | 5,591.4 |
|
Costs and Expenses | | | | | |
Cost of sales (excluding depreciation shown below): | | | | | |
Utilities | 459.1 |
| | 678.5 |
| | 730.5 |
|
Non-utility | 3,652.1 |
| | 3,332.4 |
| | 2,853.5 |
|
Operating and administrative expenses | 1,591.7 |
| | 1,266.4 |
| | 1,177.4 |
|
Utility taxes other than income taxes | 17.3 |
| | 16.6 |
| | 18.6 |
|
Depreciation | 264.2 |
| | 201.2 |
| | 187.6 |
|
Amortization | 51.8 |
| | 26.7 |
| | 22.6 |
|
Other income, net | (38.3 | ) | | (46.5 | ) | | (58.0 | ) |
| 5,997.9 |
| | 5,475.3 |
| | 4,932.2 |
|
Operating income | 521.3 |
| | 616.0 |
| | 659.2 |
|
Loss from equity investees | (0.3 | ) | | (0.9 | ) | | (2.1 | ) |
Loss on extinguishments of debt | (13.3 | ) | | (38.1 | ) | | — |
|
Interest expense | (221.5 | ) | | (138.0 | ) | | (133.8 | ) |
Income before income taxes | 286.2 |
| | 439.0 |
| | 523.3 |
|
Income taxes | (99.6 | ) | | (130.8 | ) | | (167.6 | ) |
Net income | 186.6 |
| | 308.2 |
| | 355.7 |
|
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners | 12.8 |
| | (75.3 | ) | | (94.7 | ) |
Net income attributable to UGI Corporation | $ | 199.4 |
| | $ | 232.9 |
| | $ | 261.0 |
|
Earnings per common share attributable to UGI Corporation stockholders: | | | | | |
Basic | $ | 1.77 |
| | $ | 2.09 |
| | $ | 2.38 |
|
Diluted | $ | 1.76 |
| | $ | 2.06 |
| | $ | 2.36 |
|
Average common shares outstanding (thousands): | | | | | |
Basic | 112,581 |
| | 111,674 |
| | 109,588 |
|
Diluted | 113,432 |
| | 112,944 |
| | 110,511 |
|
See accompanying notes to consolidated financial statements.
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of dollars)
| | | | | | | | | | | | |
| | Year Ended September 30, | |
| | 2011 | | | 2010 | | | 2009 | |
|
Net income | | $ | 308.2 | | | $ | 355.7 | | | $ | 382.0 | |
Net losses on derivative instruments (net of tax of $(15.4), $(29.2) and $82.1, respectively) | | | (10.8 | ) | | | (16.8 | ) | | | (204.1 | ) |
Reclassifications of net losses on derivative instruments (net of tax of $(20.4), $(25.3) and $(78.6), respectively) | | | 11.8 | | | | 22.9 | | | | 225.0 | |
Foreign currency translation adjustments (net of tax of $4.5, $7.9 and $(8.4), respectively) | | | (14.0 | ) | | | (39.4 | ) | | | 29.5 | |
Foreign currency gains and losses on long-term intra-company transactions (net of tax of $0.4) | | | (0.8 | ) | | | — | | | | — | |
Benefit plans (net of tax of $(0.1), $12.7 and $31.1, respectively) | | | 0.1 | | | | (18.7 | ) | | | (44.4 | ) |
Reclassification of benefit plans actuarial losses and prior service costs (net of tax of $(0.4), $(2.9) and $(1.6), respectively) to net income | | | 0.6 | | | | 4.2 | | | | 2.3 | |
Reclassification of pension plans actuarial losses and prior service costs (net of tax of $(59.1)) to regulatory assets | | | — | | | | 83.3 | | | | — | |
| | | | | | | | | |
Comprehensive income | | | 295.1 | | | | 391.2 | | | | 390.3 | |
|
Less: comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners | | | (69.8 | ) | | | (101.4 | ) | | | (155.5 | ) |
| | | | | | | | | |
Comprehensive income attributable to UGI Corporation | | $ | 225.3 | | | $ | 289.8 | | | $ | 234.8 | |
| | | | | | | | | |
|
| | | | | | | | | | | |
| Year Ended September 30, |
| 2012 | | 2011 | | 2010 |
Net income | $ | 186.6 |
| | $ | 308.2 |
| | $ | 355.7 |
|
Net losses on derivative instruments (net of tax of $44.8, $(15.4) and $(29.2), respectively) | (127.1 | ) | | (10.8 | ) | | (16.8 | ) |
Reclassifications of net losses on derivative instruments (net of tax of $(36.9), $(20.4) and $(25.3), respectively) | 87.9 |
| | 11.8 |
| | 22.9 |
|
Foreign currency translation adjustments (net of tax of $2.8, $4.5 and $7.9, respectively) | (20.6 | ) | | (14.0 | ) | | (39.4 | ) |
Foreign currency gains and losses on long-term intra-company transactions (net of tax of $0.7, $0.4 and $0.0, respectively) | (1.7 | ) | | (0.8 | ) | | — |
|
Benefit plans (net of tax of $6.0, $(0.1) and $12.7, respectively) | (11.5 | ) | | 0.1 |
| | (18.7 | ) |
Reclassifications of benefit plans actuarial losses and prior service costs to net income (net of tax of $(0.5), $(0.4) and $(2.9), respectively) | 0.7 |
| | 0.6 |
| | 4.2 |
|
Reclassifications of pension plans actuarial losses and prior service costs to regulatory assets (net of tax of $(59.1)) | — |
| | — |
| | 83.3 |
|
Comprehensive income | 114.3 |
| | 295.1 |
| | 391.2 |
|
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners | 38.9 |
| | (69.8 | ) | | (101.4 | ) |
Comprehensive income attributable to UGI Corporation | $ | 153.2 |
| | $ | 225.3 |
| | $ | 289.8 |
|
See accompanying notes to consolidated financial statements.
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
| | | | | | | | | | | | |
| | Year Ended September 30, | |
| | 2011 | | | 2010 | | | 2009 | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | | | | | |
Net income | | $ | 308.2 | | | $ | 355.7 | | | $ | 382.0 | |
Reconcile to net cash provided by operating activities: | | | | | | | | | | | | |
Depreciation and amortization | | | 227.9 | | | | 210.2 | | | | 200.9 | |
Gains on sales of LPG storage facilities | | | — | | | | (36.5 | ) | | | (39.9 | ) |
Deferred income taxes, net | | | 82.7 | | | | 62.6 | | | | 26.8 | |
Provision for uncollectible accounts | | | 20.0 | | | | 27.1 | | | | 34.1 | |
Stock-based compensation expense | | | 15.6 | | | | 13.2 | | | | 11.4 | |
Net change in realized gains and losses deferred as cash flow hedges | | | 12.2 | | | | 23.8 | | | | (21.0 | ) |
Loss on extinguishments of debt | | | 38.1 | | | | — | | | | — | |
Other, net | | | (7.1 | ) | | | 7.7 | | | | 17.4 | |
Net change in: | | | | | | | | | | | | |
Accounts receivable and accrued utility revenues | | | (66.0 | ) | | | (94.6 | ) | | | 79.5 | |
Inventories | | | (40.7 | ) | | | 34.3 | | | | 67.0 | |
Utility deferred fuel costs, net of changes in unsettled derivatives | | | 12.8 | | | | (18.5 | ) | | | 10.3 | |
Accounts payable | | | 19.2 | | | | 47.1 | | | | (146.1 | ) |
Other current assets | | | (1.9 | ) | | | (9.4 | ) | | | 30.3 | |
Other current liabilities | | | (66.3 | ) | | | (23.9 | ) | | | 12.3 | |
| | | | | | | | | |
Net cash provided by operating activities | | | 554.7 | | | | 598.8 | | | | 665.0 | |
| | | | | | | | | |
| | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | | | | | |
Expenditures for property, plant and equipment | | | (360.7 | ) | | | (347.3 | ) | | | (301.7 | ) |
Acquisitions of businesses, net of cash acquired | | | (52.5 | ) | | | (83.0 | ) | | | (322.6 | ) |
Net proceeds from sale of Partnership LPG storage facility | | | — | | | | — | | | | 42.4 | |
Net proceeds from sale of Atlantic Energy, LLC | | | — | | | | 66.6 | | | | — | |
Decrease (increase) in restricted cash | | | 17.6 | | | | (27.8 | ) | | | 63.3 | |
Other, net | | | (19.8 | ) | | | (7.8 | ) | | | (1.3 | ) |
| | | | | | | | | |
Net cash used by investing activities | | | (415.4 | ) | | | (399.3 | ) | | | (519.9 | ) |
| | | | | | | | | |
| | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | | | | | |
Dividends on UGI Common Stock | | | (113.8 | ) | | | (98.6 | ) | | | (85.1 | ) |
Distributions on AmeriGas Partners publicly held Common Units | | | (93.7 | ) | | | (89.1 | ) | | | (90.4 | ) |
Issuances of debt | | | 1,480.6 | | | | — | | | | 118.0 | |
Repayments of debt | | | (1,383.6 | ) | | | (94.8 | ) | | | (82.2 | ) |
Receivables Facility net borrowings | | | 2.2 | | | | — | | | | — | |
(Decrease) increase in bank loans | | | (74.6 | ) | | | 37.9 | | | | 13.1 | |
Issuances of UGI Common Stock | | | 27.3 | | | | 27.5 | | | | 10.8 | |
Other | | | 3.5 | | | | 3.5 | | | | 1.2 | |
| | | | | | | | | |
Net cash used by financing activities | | | (152.1 | ) | | | (213.6 | ) | | | (114.6 | ) |
| | | | | | | | | |
| | | | | | | | | | | | |
EFFECT OF EXCHANGE RATE CHANGES ON CASH | | | (9.4 | ) | | | (5.3 | ) | | | 4.4 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Cash and cash equivalents (decrease) increase | | $ | (22.2 | ) | | $ | (19.4 | ) | | $ | 34.9 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Cash and cash equivalents: | | | | | | | | | | | | |
End of year | | $ | 238.5 | | | $ | 260.7 | | | $ | 280.1 | |
Beginning of year | | | 260.7 | | | | 280.1 | | | | 245.2 | |
| | | | | | | | | |
(Decrease) increase | | $ | (22.2 | ) | | $ | (19.4 | ) | | $ | 34.9 | |
| | | | | | | | | |
| | | | | | | | | | | | |
SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | | | | | | | |
Cash paid for: | | | | | | | | | | | | |
Interest | | $ | 135.0 | | | $ | 130.5 | | | $ | 136.3 | |
Income taxes | | $ | 48.6 | | | $ | 128.5 | | | $ | 130.2 | |
|
| | | | | | | | | | | |
| Year Ended September 30, |
| 2012 | | 2011 | | 2010 |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | |
Net income | $ | 186.6 |
| | $ | 308.2 |
| | $ | 355.7 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
Depreciation and amortization | 316.0 |
| | 227.9 |
| | 210.2 |
|
Gain on sales of Atlantic Energy, LLC | — |
| | — |
| | (36.5 | ) |
Deferred income taxes, net | 82.9 |
| | 82.7 |
| | 62.6 |
|
Provision for uncollectible accounts | 26.5 |
| | 20.0 |
| | 27.1 |
|
Stock-based compensation expense | 14.5 |
| | 15.6 |
| | 13.2 |
|
Net change in realized gains and losses deferred as cash flow hedges | (6.6 | ) | | 12.2 |
| | 23.8 |
|
Loss on extinguishments of debt | 13.3 |
| | 38.1 |
| | — |
|
Other, net | (10.7 | ) | | (7.1 | ) | | 7.7 |
|
Net change in: | | | | | |
Accounts receivable and accrued utility revenues | 65.5 |
| | (66.0 | ) | | (94.6 | ) |
Inventories | 89.2 |
| | (40.7 | ) | | 34.3 |
|
Utility deferred fuel costs, net of changes in unsettled derivatives | (1.7 | ) | | 12.8 |
| | (18.5 | ) |
Accounts payable | (78.7 | ) | | 19.2 |
| | 47.1 |
|
Other current assets | (12.5 | ) | | (1.9 | ) | | (9.4 | ) |
Other current liabilities | 23.4 |
| | (66.3 | ) | | (23.9 | ) |
Net cash provided by operating activities | 707.7 |
| | 554.7 |
| | 598.8 |
|
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | |
Expenditures for property, plant and equipment | (339.4 | ) | | (360.7 | ) | | (347.3 | ) |
Acquisitions of businesses, net of cash acquired | (1,580.5 | ) | | (52.5 | ) | | (83.0 | ) |
Net proceeds from sale of Atlantic Energy, LLC | — |
| | — |
| | 66.6 |
|
Decrease (increase) in restricted cash | 14.2 |
| | 17.6 |
| | (27.8 | ) |
Other, net | 1.2 |
| | (19.8 | ) | | (7.8 | ) |
Net cash used by investing activities | (1,904.5 | ) | | (415.4 | ) | | (399.3 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | |
Dividends on UGI Common Stock | (119.1 | ) | | (113.8 | ) | | (98.6 | ) |
Distributions on AmeriGas Partners publicly held Common Units | (181.7 | ) | | (93.7 | ) | | (89.1 | ) |
Issuances of debt | 1,550.2 |
| | 1,480.6 |
| | — |
|
Repayments of debt | (299.9 | ) | | (1,383.6 | ) | | (94.8 | ) |
Receivables Facility net (repayments) borrowings | (14.3 | ) | | 2.2 |
| | — |
|
Increase (decrease) in bank loans | 41.7 |
| | (74.6 | ) | | 37.9 |
|
Issuances of UGI Common Stock | 23.2 |
| | 27.3 |
| | 27.5 |
|
Issuances of AmeriGas Partners Common Units | 276.6 |
| | — |
| | — |
|
Other | 1.8 |
| | 3.5 |
| | 3.5 |
|
Net cash provided (used) by financing activities | 1,278.5 |
| | (152.1 | ) | | (213.6 | ) |
EFFECT OF EXCHANGE RATE CHANGES ON CASH | (0.3 | ) | | (9.4 | ) | | (5.3 | ) |
Cash and cash equivalents increase (decrease) | $ | 81.4 |
| | $ | (22.2 | ) | | $ | (19.4 | ) |
Cash and cash equivalents: | | | | | |
End of year | $ | 319.9 |
| | $ | 238.5 |
| | $ | 260.7 |
|
Beginning of year | 238.5 |
| | 260.7 |
| | 280.1 |
|
Increase (decrease) | $ | 81.4 |
| | $ | (22.2 | ) | | $ | (19.4 | ) |
SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | |
Cash paid for: | | | | | |
Interest | $ | 168.8 |
| | $ | 135.0 |
| | $ | 130.5 |
|
Income taxes | $ | 33.3 |
| | $ | 48.6 |
| | $ | 128.5 |
|
See accompanying notes to consolidated financial statements.
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions of dollars, except per share amounts)
| | | | | | | | | | | | |
| | Year Ended September 30, | |
| | 2011 | | | 2010 | | | 2009 | |
Common stock, without par value | | | | | | | | | | | | |
Balance, beginning of year | | $ | 906.1 | | | $ | 875.6 | | | $ | 858.3 | |
Common Stock issued: | | | | | | | | | | | | |
Employee and director plans | | | 14.7 | | | | 14.4 | | | | 2.9 | |
Dividend reinvestment plan | | | 2.2 | | | | 1.7 | | | | 1.6 | |
Excess tax benefits realized on equity-based compensation | | | 3.8 | | | | 4.2 | | | | 2.9 | |
Stock-based compensation expense | | | 10.6 | | | | 10.2 | | | | 9.9 | |
| | | | | | | | | |
Balance, end of year | | $ | 937.4 | | | $ | 906.1 | | | $ | 875.6 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Retained earnings | | | | | | | | | | | | |
Balance, beginning of year | | $ | 966.7 | | | $ | 804.3 | | | $ | 630.9 | |
Net income attributable to UGI Corporation | | | 232.9 | | | | 261.0 | | | | 258.5 | |
Cash dividends on Common Stock ($1.02, $0.90 and $0.785 per share, respectively) | | | (113.8 | ) | | | (98.6 | ) | | | (85.1 | ) |
| | | | | | | | | |
Balance, end of year | | $ | 1,085.8 | | | $ | 966.7 | | | $ | 804.3 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Accumulated other comprehensive income (loss) | | | | | | | | | | | | |
Balance, beginning of year | | $ | (10.1 | ) | | $ | (38.9 | ) | | $ | (15.2 | ) |
Net losses on derivative instruments, net of tax | | | (23.4 | ) | | | (37.8 | ) | | | (127.3 | ) |
Reclassification of net losses on derivative instruments, net of tax | | | 29.9 | | | | 37.2 | | | | 116.2 | |
Benefit plans, principally actuarial gains (losses), net of tax | | | 0.1 | | | | (18.7 | ) | | | (44.4 | ) |
Reclassification of benefit plans actuarial losses and prior service costs, net of tax, to net income | | | 0.6 | | | | 4.2 | | | | 2.3 | |
Reclassifications of pension plans actuarial losses and prior service cost, net of tax, to regulatory assets | | | — | | | | 83.3 | | | | — | |
Foreign currency losses on long-term intra-company transacations | | | (0.8 | ) | | | — | | | | — | |
Foreign currency translation adjustments, net of tax | | | (14.0 | ) | | | (39.4 | ) | | | 29.5 | |
| | | | | | | | | |
Balance, end of year | | $ | (17.7 | ) | | $ | (10.1 | ) | | $ | (38.9 | ) |
| | | | | | | | | |
| | | | | | | | | | | | |
Treasury stock | | | | | | | | | | | | |
Balance, beginning of year | | $ | (38.2 | ) | | $ | (49.6 | ) | | $ | (56.3 | ) |
Common Stock issued: | | | | | | | | | | | | |
Employee and director plans | | | 9.7 | | | | 10.6 | | | | 5.9 | |
Dividend reinvestment plan | | | 0.7 | | | | 0.8 | | | | 0.8 | |
| | | | | | | | | |
Balance, end of year | | $ | (27.8 | ) | | $ | (38.2 | ) | | $ | (49.6 | ) |
| | | | | | | | | |
| | | | | | | | | | | | |
Total UGI Corporation stockholders’ equity | | $ | 1,977.7 | | | $ | 1,824.5 | | | $ | 1,591.4 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Noncontrolling interests | | | | | | | | | | | | |
Balance, beginning of year | | $ | 237.1 | | | $ | 225.4 | | | $ | 159.2 | |
Net income attributable to noncontrolling interests, principally in AmeriGas Partners | | | 75.3 | | | | 94.7 | | | | 123.5 | |
Net gains (losses) on derivative instruments | | | 12.6 | | | | 21.0 | | | | (76.8 | ) |
Reclassification of net (gains) losses on derivative instruments | | | (18.1 | ) | | | (14.3 | ) | | | 108.8 | |
Dividends and distributions | | | (94.0 | ) | | | (89.1 | ) | | | (91.7 | ) |
Other | | | 0.5 | | | | (0.6 | ) | | | 2.4 | |
| | | | | | | | | |
Balance, end of year | | $ | 213.4 | | | $ | 237.1 | | | $ | 225.4 | |
| | | | | | | | | |
| | | | | | | | | | | | |
Total equity | | $ | 2,191.1 | | | $ | 2,061.6 | | | $ | 1,816.8 | |
| | | | | | | | | |
|
| | | | | | | | | | | |
| Year Ended September 30, |
| 2012 | | 2011 | | 2010 |
Common stock, without par value | | | | | |
Balance, beginning of year | $ | 937.4 |
| | $ | 906.1 |
| | $ | 875.6 |
|
Common Stock issued: | | | | | |
Employee and director plans | 13.6 |
| | 14.7 |
| | 14.4 |
|
Dividend reinvestment plan | 2.2 |
| | 2.2 |
| | 1.7 |
|
Excess tax benefits realized on equity-based compensation | 1.8 |
| | 3.8 |
| | 4.2 |
|
Stock-based compensation expense | 8.3 |
| | 10.6 |
| | 10.2 |
|
Adjustments to reflect change in ownership of AmeriGas Partners, net of tax | 194.4 |
| | — |
| | — |
|
Balance, end of year | $ | 1,157.7 |
| | $ | 937.4 |
| | $ | 906.1 |
|
Retained earnings | | | | | |
Balance, beginning of year | $ | 1,085.8 |
| | $ | 966.7 |
| | $ | 804.3 |
|
Net income attributable to UGI Corporation | 199.4 |
| | 232.9 |
| | 261.0 |
|
Cash dividends on Common Stock ($1.06, $1.02 and $0.90 per share, respectively) | (119.1 | ) | | (113.8 | ) | | (98.6 | ) |
Balance, end of year | $ | 1,166.1 |
| | $ | 1,085.8 |
| | $ | 966.7 |
|
Accumulated other comprehensive income (loss) | | | | | |
Balance, beginning of year | $ | (17.7 | ) | | $ | (10.1 | ) | | $ | (38.9 | ) |
Net losses on derivative instruments, net of tax | (67.3 | ) | | (23.4 | ) | | (37.8 | ) |
Reclassification of net losses on derivative instruments, net of tax | 54.2 |
| | 29.9 |
| | 37.2 |
|
Benefit plans, principally actuarial (losses) gains, net of tax | (11.5 | ) | | 0.1 |
| | (18.7 | ) |
Reclassification of benefit plans actuarial losses and prior service costs, net of tax, to net income | 0.7 |
| | 0.6 |
| | 4.2 |
|
Reclassifications of pension plans actuarial losses and prior service cost, net of tax, to regulatory assets | — |
| | — |
| | 83.3 |
|
Adjustments to reflect change in ownership of AmeriGas Partners, net of tax | 1.9 |
| | — |
| | — |
|
Foreign currency losses on long-term intra-company transactions, net of tax | (1.7 | ) | | (0.8 | ) | | — |
|
Foreign currency translation adjustments, net of tax | (20.6 | ) | | (14.0 | ) | | (39.4 | ) |
Balance, end of year | $ | (62.0 | ) | | $ | (17.7 | ) | | $ | (10.1 | ) |
Treasury stock | | | | | |
Balance, beginning of year | $ | (27.8 | ) | | $ | (38.2 | ) | | $ | (49.6 | ) |
Common Stock issued: | | | | | |
Employee and director plans | 6.4 |
| | 9.7 |
| | 10.6 |
|
Dividend reinvestment plan | 0.9 |
| | 0.7 |
| | 0.8 |
|
Reacquired common stock - employee and director plans | (8.2 | ) | | — |
| | — |
|
Balance, end of year | $ | (28.7 | ) | | $ | (27.8 | ) | | $ | (38.2 | ) |
Total UGI Corporation stockholders’ equity | $ | 2,233.1 |
| | $ | 1,977.7 |
| | $ | 1,824.5 |
|
Noncontrolling interests | | | | | |
Balance, beginning of year | $ | 213.4 |
| | $ | 237.1 |
| | $ | 225.4 |
|
Net (loss) income attributable to noncontrolling interests, principally in AmeriGas Partners | (12.8 | ) | | 75.3 |
| | 94.7 |
|
Net (losses) gains on derivative instruments | (59.8 | ) | | 12.6 |
| | 21.0 |
|
Reclassification of net losses (gains) on derivative instruments | 33.7 |
| | (18.1 | ) | | (14.3 | ) |
Dividends and distributions | (182.1 | ) | | (94.0 | ) | | (89.1 | ) |
AmeriGas Partners Common Unit public offering | 276.6 |
| | — |
| | — |
|
AmeriGas Partners Common Units issued for Heritage Acquisition | 1,132.6 |
| | — |
| | — |
|
Adjustments to reflect change in ownership of AmeriGas Partners | (321.4 | ) | | — |
| | — |
|
Other | 5.5 |
| | 0.5 |
| | (0.6 | ) |
Balance, end of year | $ | 1,085.7 |
| | $ | 213.4 |
| | $ | 237.1 |
|
Total equity | $ | 3,318.8 |
| | $ | 2,191.1 |
| | $ | 2,061.6 |
|
See accompanying notes to consolidated financial statements.
F-9
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Index to Notes
Note 1 — Nature of Operations
Note 2 — Significant Accounting Policies
Note 3 — Accounting Changes
Note 4 — Acquisitions and Dispositions
Note 5 — Debt
Note 6 — Income Taxes
Note 7 — Employee Retirement Plans
Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters
Note 9 — Inventories
Note 10 — Property, Plant and Equipment
Note 11 — Goodwill and Intangible Assets
Note 12 — Series Preferred Stock
Note 13 — Common Stock and Equity-Based Compensation
Note 14 — Partnership Distributions and Common Unit Offering
Note 15 — Commitments and Contingencies
Note 16 — Fair Value Measurements
Note 17 — Disclosures About Derivative Instruments and Hedging Activities
Note 18 — Energy Services Accounts Receivable Securitization Facility
Note 19 — Other Income, Net
Note 20 — Quarterly Data (unaudited)
Note 21 — Segment Information
Note 22 — Subsequent Events
Note 1 — Nature of Operations
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes and markets energy products and related services. In the United States, we (1) are the general partner and own and operate (1)limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; (3) own all or a portion of electricity generation facilities; and (4) own and operate an energy marketing, midstream infrastructure, storage and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”
We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”), a publicly traded limited partnership, and its principal operating subsidiaries,subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”) and, prioras a result of the January 12, 2012, acquisition of Heritage Propane from Energy Transfer Partners, L.P. ("ETP"), AmeriGas OLP's principal operating subsidiary, Heritage Operating, L.P. ("HOLP"). In addition, from January 12, 2012, through the date of its merger with and into AmeriGas OLP in August 2012, we also conducted business through AmeriGas OLP's operating subsidiary, Titan Propane LLC ("Titan LLC") which was also acquired on January 12, 2012, from ETP (see Note 4 for additional information about the acquisition of Heritage Propane). AmeriGas OLP, HOLP and Titan LLC (prior to its October 1, 2010 merger with and into AmeriGas OLP), are referred to herein as the "Operating Partnerships." AmeriGas Partners, AmeriGas OLP AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (together with AmeriGas OLP, the “Operating Partnership”). AmeriGas Partners and AmeriGas OLPHOLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30, 2011,2012, the General Partner held a 1% general partner interest and 42.8%25.3% limited partner interest in AmeriGas Partners, and held an effective 44.4%27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,20923,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 56.2%73.7% interest in AmeriGas Partners comprises 32,433,08739,477,103 Common Units held by the general public and 29,567,362 Common Units held by ETP as limited partner interests.a result of the acquisition of Heritage Propane.
Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries, conducts (1) conducts an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“Antargaz”); (2) conducts an LPG distribution business in central, northern and eastern Europe (“Flaga”); (3) an LPG distribution business in the United Kingdom ("AvantiGas"); and (3) conducts(4) an LPG distribution business in the Nantong region of China. We refer to our foreign LPG operations collectively as “International Propane.”
Enterprises, through UGI Energy Services, Inc. (“Energy Services”) and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage, natural gas gathering and energy services business primarily in the Mid-Atlantic region of the
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
United States. In addition, Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electric generation facilities located in Pennsylvania. TheThese businesses of Energy Services and its subsidiaries, including UGID, are referred to herein collectively as “Midstream & Marketing.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries.
F-10
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary, UGI Utilities, Inc. (“UGI Utilities”), and its subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.”" UGI Gas, PNG Gas and CPG Gas are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”
Note 2 — Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
Certain prior-year amounts have been reclassified to conform to the current-year presentation.
Principles of Consolidation
The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the general public’s and ETP's interests in the Partnership, and other parties’outside ownership interests in other consolidated but less than 100% owned subsidiaries, as noncontrolling interests. We eliminate all significant intercompany accounts and transactions when we consolidate. Investments in business entitiesEntities in which we do not have control but have significant influence over operating orand financial policies are accounted for underby the equity method of accounting and our proportionate share of income or loss is recorded in loss from equity investees on the Consolidated Statements of Income.method. Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2011.2012. Investments in business entities that are not publicly traded and in which we hold less than 20% of voting rights are accounted for using the cost method. Such investments are recorded in other assets and totaled $72.4$80.0 and $68.8$72.4 at September 30, 20112012 and 2010,2011, respectively.
On January 29, 2009, Flaga purchased for cash consideration the 50% equity interest in Zentraleuropa LPG Holdings GmbH (“ZLH”) it did not already own from its joint-venture partner, Progas GmbH & Co. KG. As a result, the operations of ZLH are consolidated with those of the Company beginning in January 2009.
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980 related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulator.
For additional information regarding the effects of rate regulation on our utility operations, see Note 8.
F-11
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Fair Value Measurements
We apply fair value measurements to certain assets and liabilities, principally our commodity, foreign currency and interest rate derivative instruments. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements require that we assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.
We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:
Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Instruments categorized in Level 1 consist of our exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and non exchange-traded electricity forward contracts whose underlying is identical to an exchange-traded contract.
Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over the counter commodity price swap and option contracts, interest rate swaps and interest rate protection agreements, foreign currency forward contracts, financial transmission rights (“FTRs”) and non exchange-traded electricity forward contracts that do not qualify for Level 1.
Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 20112012 or 2010.2011.
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. See Note 16 for additional information on fair value measurements.
Derivative Instruments
We account for derivative instruments and hedging activities in accordance with guidance provided by the FASB which requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.
A substantial portion of our derivative financial instruments are designated and qualify as cash flow hedges or net investment hedges. In addition, gains and losses on certain derivative financial instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities in accordance with FASB guidance regarding accounting for rate-regulated entities. For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Certain of our derivative financial instruments, although generally effective as economic hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments, other than net investment hedges, are included in cash flows from operating activities. Cash flows from net investment hedges are included in cash flows from investing activities.
F-12
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and related supplemental information required by GAAP, see Note 17.
Foreign Currency Translation
Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income.
Revenue Recognition
Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing records revenues when energy products are delivered or services are provided to customers. Revenues from the sale of appliances and equipment are recognized at the later of sale or installation. Revenues from repair or maintenance services are recognized upon completion of services.
UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service and commodities rendered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective.
We present revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.
LPG Delivery Expenses
Expenses associated with the delivery of LPG to customers of the Partnership and our International Propane operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as operating and administrative expenses on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and International Propane delivery vehicles is classified in depreciation on the Consolidated Statements of Income.
Income Taxes
AmeriGas Partners and the Operating PartnershipPartnerships are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. The Operating PartnershipPartnerships have subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation.
Gas Utility and Electric Utility record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. They also record a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. Investment tax credits associated with Midstream & Marketing’s qualifying solar energy property under the Emergency Economic Stabilization Act of 2008 are reflected in income tax expense when such property is placed in service.
F-13
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. For Fiscal 2012, Fiscal 2011 and Fiscal 2010, interest (income) expense of $(0.1), $0.2 and Fiscal 2009, interest expense (income) of $0.2, $(0.2) and $(0.4)$(0.2), respectively, was recognized in income taxes on the Consolidated Statements of Income.
Earnings Per Common Share
Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2012, Fiscal 2011 and Fiscal 2010:
UGI Corporation and Fiscal 2009:Subsidiaries
| | | | | | | | | | | | |
(Thousands of shares) | | 2011(a) | | | 2010 | | | 2009(a) | |
Average common shares outstanding for basic computation | | | 111,674 | | | | 109,588 | | | | 108,523 | |
Incremental shares issuable for stock options and common stock awards | | | 1,270 | | | | 923 | | | | 816 | |
| | | | | | | | | |
Average common shares outstanding for diluted computation | | | 112,944 | | | | 110,511 | | | | 109,339 | |
| | | | | | | | | |
Notes to Consolidated Financial Statements(Millions of dollars and euros, except per share amounts and where indicated otherwise)
|
| | | | | | | | | |
(Thousands of shares) | | 2012 (a) | | 2011(a) | | 2010 |
Average common shares outstanding for basic computation | | 112,581 |
| | 111,674 |
| | 109,588 |
|
Incremental shares issuable for stock options and common stock awards | | 851 |
| | 1,270 |
| | 923 |
|
Average common shares outstanding for diluted computation | | 113,432 |
| | 112,944 |
| | 110,511 |
|
| | |
(a) | | For Fiscal 20112012 and Fiscal 2009,2011, there were approximately 3,70081 shares and 2,8003,700 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share because their effect was antidilutive. |
Comprehensive Income
Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally results from gains and losses on derivative instruments qualifying as cash flow hedges, actuarial gains and losses on postretirement benefit plans and foreign currency translation adjustments.adjustments and foreign currency long-term intra-company transactions. Other comprehensive income in Fiscal 2010 also includes the reclassification of $83.3$83.3 of actuarial losses associated with a UGI Utilities’ pension plan to regulatory assets and deferred income taxes as a result of an August 2010 PUC order regarding regulatory treatment of such pension plan’s funded status (see Note 8).
The components of AOCI at September 30, 20112012 and 20102011 follow:
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Foreign | | | | |
| | | | | | Derivative | | | Currency | | | | |
| | Postretirement | | | Instruments Net | | | Translation | | | | |
| | Benefit Plans | | | Losses | | | Adjustments | | | Total | |
Balance, September 30, 2011 | | $ | (12.1 | ) | | $ | (47.6 | ) | | $ | 42.0 | | | $ | (17.7 | ) |
Balance, September 30, 2010 | | $ | (12.8 | ) | | $ | (54.1 | ) | | $ | 56.8 | | | $ | (10.1 | ) |
|
| | | | | | | | | | | | | | | |
| Postretirement Benefit Plans | | Derivative Instruments Net Losses | | Foreign Currency Translation Adjustments | | Total |
Balance, September 30, 2012 | $ | (22.9 | ) | | $ | (58.8 | ) | | $ | 19.7 |
| | $ | (62.0 | ) |
Balance, September 30, 2011 | $ | (12.1 | ) | | $ | (47.6 | ) | | $ | 42.0 |
| | $ | (17.7 | ) |
Cash and Cash Equivalents
All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.
Restricted Cash
Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.
Inventories
Our inventories are stated at the lower of cost or market. We determine cost using an average cost method for natural gas, propane and other LPG; specific identification for appliances; and the first-in, first-out (“FIFO”) method for all other inventories.
F-14
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.
We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives ranging from 15 to 40 years for buildings and improvements; 7 to 40 years for storage and customer tanks and cylinders; 25 to 35 years for electricity generation facilities; and 2 to 12 years for vehicles, equipment and office furniture and fixtures. Costs to install Partnership and Antargaz-owned tanks, net of amounts billed to customers, are capitalized and amortized over the estimated period of benefit not exceeding ten years.
We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.3%2.2% in Fiscal 2012, 2.3% in Fiscal 2011 and 2.5% in Fiscal 2010 and 2.4% in Fiscal 2009.. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.6%2.4% in Fiscal 2012, 2.6% in Fiscal 2011 and 2.6% in Fiscal 2010 and 2.9% in Fiscal 2009.. When Utilities retire depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.
No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
Goodwill and Intangible Assets
In accordance with GAAP relating to goodwill and other intangibles,intangible assets, we amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. Goodwill and otherWe review identifiable intangible assets subject to amortization for impairment whenever events or changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset. Intangible assets with indefinite lives are not amortized but are subjecttested annually for impairment and written down to testsfair value as required.
We do not amortize goodwill, but test it at least annually for impairment at least annually.the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value and the carrying amount of the reporting unit's goodwill exceeds the implied fair value of that goodwill. We determine fair values for each of our reporting units generally using discounted cash flows to establish fair values unless market values are available. The Company adopted new accounting guidance regarding goodwill impairment during Fiscal 2012 which permits us, in certain circumstances, to perform impairment testsa qualitative approach to determine if it is more frequentlylikely than annually if events or circumstances indicatenot that the carrying value of goodwill or intangible assets with indefinite lives might be impaired. When performing our impairment tests, we use quoted market prices or, in the absence of quoted market prices, discounted estimates of future cash flows. a reporting unit is greater than its fair value (see Note 3).
No provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2012, Fiscal 2011 or Fiscal 2010 or Fiscal 2009.
. No amortization expense is included in cost of sales in the Consolidated Statements of Income. For further information, seeIncome (see Note 11.11).
Impairment of Long-Lived Assets
We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No material provisions for impairments were recorded during Fiscal 2012, Fiscal 2011 or Fiscal 2010 or.
Deferred Debt Issuance Costs
Included in other assets on our Consolidated Balance Sheets are net deferred debt issuance costs of $46.6 and $30.7 at September 30, 2012 and 2011, respectively. We are amortizing these costs over the terms of the related debt. The increase in deferred debt issuance costs during Fiscal 2009.2012 largely resulted from the Partnership's issuance of debt to fund the acquisition of Heritage Propane (see Notes 4 and 5).
Refundable Tank and Cylinder Deposits
Included in “Otherother noncurrent liabilities”liabilities on our Consolidated Balance Sheets are customer paid deposits on Antargaz owned tanks and cylinders of $204.4$205.1 and $211.8$204.4 at September 30, 20112012 and 2010,2011, respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.
Environmental Matters
We are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.
F-15
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can reasonably be estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-yearfive-year average of such prudently incurred remediation costs, and CPG Gas and PNG Gas are currently gettingreceiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. For further information, see Note 15.
Employee Retirement Plans
We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 7).
Equity-Based Compensation
All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units”), isare measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as a liability or as equity in our Consolidated Balance Sheets. Equity-based compensation costs associated with the portion of Unit awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with the portion of Unit awards classified as liabilities are measured based upon their estimated fair value at the grant date and remeasured as of the end of each period.
We have calculated a tax windfall pool using the shortcut method. We record deferred tax assets for awards that we expect will result in deductions on our income tax returns based on the amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return are recorded in Common Stock (if the tax benefit exceeds the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeds the tax benefit and no tax windfall pool exists from previous awards).
For additional information on our equity-based compensation plans and related disclosures, see Note 13.
Note 3 — Accounting Changes
Adoption of New Accounting Standards
Presentation of Comprehensive Income.Indefinite-Lived Intangible Asset Impairment.In June 2011,July 2012, the FASB issued Accounting Standards Update (“ASU”) 2011-05, “Presentation of Comprehensive Income,” which revises the manner in which entities present comprehensive income in their financial statements.guidance on testing indefinite-lived intangible assets, other than goodwill, for impairment. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) Topic 220 and requirespermits entities to report componentsfirst assess qualitative factors to determine whether it is more likely than not that the fair value of comprehensive income in either (1) a continuous statementan indefinite-lived intangible asset is less than its carrying amount. If the entity determines on the basis of comprehensive income or (2) two separate but consecutive statements. ASU 2011-05qualitative factors that the fair value of the indefinite-lived intangible asset is not more likely than not impaired, the entity would not need to calculate the value of the asset. The new guidance does not changerevise the items that must be reported in other comprehensive income. Additionally, reclassification adjustments between net income and comprehensive income must be shown on the face of the financial statements. On October 21, 2011, the FASB decided to propose a deferral of the new requirement to present reclassification adjustments on the face of the income statement. The change in presentation is effectivetest indefinite-lived intangible assets annually for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011 with full retrospective application required. Early adoption is permitted. We applied the new provisions of the guidance effective September 30, 2011, (except for the presentation of reclassification adjustments on the face of the statement of net income), and report the components of comprehensive income in two separate but consecutive statements as permitted by the new guidance.
F-16
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Transfers of Financial Assets.Effective October 1, 2010, the Company adopted new guidance regarding accounting for transfers of financial assets. Among other things,impairment. In addition, the new guidance eliminatesdoes not amend the concept of Qualified Special Purpose Entities (“QSPEs”). It also amends previous derecognition guidance. The adoption ofrequirement to test these assets for impairment between annual tests if there is a change in events or circumstances. We adopted the new accounting guidance changed the Company’s accounting prospectively for sales of undivided interests in accounts receivable to the commercial paper conduit of a major bank under the Energy Services Receivables Facility. Effective October 1, 2010, trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet. Also effective October 1, 2010, the Company records interest expense on amounts owed to the commercial paper conduit. Prior to October 1, 2010, losses on sales of accounts receivable to the commercial paper conduit were reflected in other income, net. Additionally, effective October 1, 2010 borrowings and repayments associated with the Energy Services Receivables Facility are reflected in cash flows from financing activities. Previously, such transactions were reflected in cash flows from operating activities. For further information, see Note 18.
Business Combinations.Effective October 1, 2009, we adopted new guidance on accounting for business combinations. The new guidance applies to all transactions or other events in which an entity obtains control of one or more businesses. The new guidance establishes, among other things, principles and requirements for how the acquirer (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in a business combination or gain from a bargain purchase; and (3) determines what information with respect to a business combination should be disclosed. The new guidance applies prospectively to business combinations for which the acquisition date is on or after October 1, 2009. Among the more significant changes in accounting for acquisitions are (1) transaction costs are generally expensed (rather than being included as costsfourth quarter of the acquisition); (2) contingencies, including contingent consideration, are generally recorded at fair value with subsequent adjustments recognized in operations (rather than as adjustments to the purchase price); and (3) decreases in valuation allowances on acquired deferred tax assets are recognized in operations (rather than as decreases in goodwill). The new guidance did not have a material impact on our Fiscal 2010 financial statements.2012.
New Accounting Standards Not Yet Adopted
Goodwill Impairment.In September 2011, the FASB issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. The more-likely-than-not threshold is deemed as having a likelihood of more than 50 percent. Previous guidance required an entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance,
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirements to test goodwill annually for impairment. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted. We will adoptadopted the new guidance infor Fiscal 2012.
Fair Value Measurements.In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurementsnew guidance on fair value measurements and Disclosure Requirements in U.S. GAAP and IFRS.”related disclosure requirements. The amendments in ASU 2011-04 resultnew guidance results in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders’ equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance isbecame effective for our interim period ending March 31, 2012, and is required to be applied prospectively. We doThe adoption of this accounting guidance did not expect it will have a material impact on our resultsfinancial statements.
New Accounting Standard Not Yet Adopted
Disclosures about Offsetting Assets and Liabilities. In December 2011, the FASB issued new accounting guidance regarding disclosures about offsetting assets and liabilities. The new guidance requires an entity to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The amendments will enhance disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with other GAAP or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 (Fiscal 2014), and interim periods within those annual periods. We are currently evaluating the impact of the new guidance on our future disclosures.
Note 4 — Acquisitions & Dispositions
On January 12, 2012 (the “Acquisition Date”), AmeriGas Partners completed the acquisition of Heritage Propane from ETP for total consideration of $2,598.2, comprising $1,465.6 in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of $1,132.6 (the “Heritage Acquisition”). The Acquisition Date cash consideration for the Heritage Acquisition was subject to purchase price adjustments based on working capital, cash and the amount of indebtedness of Heritage Propane (“Working Capital Adjustment”) and certain excess cash proceeds resulting from ETP's sale of HOLP's former cylinder exchange business (“HPX”). In April 2012, AmeriGas Partners paid $25.5 of additional cash consideration as a result of the Working Capital Adjustment and in June 2012, AmeriGas Partners received $18.9 in cash representing the excess cash proceeds from the sale of HPX. The Heritage Acquisition was consummated pursuant to a Contribution and Redemption Agreement dated October 15, 2011, as amended (the “Contribution Agreement”), by and among AmeriGas Partners, ETP, Energy Transfer Partners GP, L.P., the general partner of ETP (“ETP GP”), and Heritage ETC, L.P. (the “Contributor”). The acquired business conducted its propane operations or financial condition.in 41 states through HOLP and Titan LLC. According to LP-Gas Magazine rankings published on February 1, 2012, Heritage Propane was the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers in 2011. The Heritage Acquisition is consistent with our growth strategies, one of which is to grow our core business through acquisitions.
F-17
Pursuant to the Contribution Agreement, the Contributor contributed to AmeriGas Partners a 99.999% limited partner interest in HOLP; a 100% membership interest in Heritage Operating GP, LLC, a Delaware limited liability company and a holder of a 0.001% general partner interest in HOLP; a 99.99% limited partner interest in Titan Energy Partners, L.P., a Delaware limited partnership and the sole member of Titan LLC; and a 100% membership interest in Titan Energy GP, L.L.C., a Delaware limited liability company and holder of a 0.01% general partner interest in Titan Energy Partners, L.P. As a result of the Heritage Acquisition, the General Partner, in order to maintain its general partner interests in AmeriGas Partners and AmeriGas OLP, contributed 934,327 Common Units to the Partnership having a fair value of $41.7. These Common Units were subsequently cancelled.
The cash portion of the Heritage Acquisition was financed by the issuance by AmeriGas Finance Corp. and AmeriGas Finance LLC, wholly owned finance subsidiaries of AmeriGas Partners (the “Issuers”), of $550 principal amount of 6.75% Senior Notes due May 2020 (the “6.75% Notes”) and $1,000 principal amount of 7.00% Senior Notes due May 2022 (the “7.00% Notes”). For further information on the 6.75% Notes and the 7.00% Notes, see Note 5.
The Consolidated Balance Sheet at September 30, 2012, reflects the final allocation of the purchase price to the assets acquired and liabilities assumed for the Heritage Propane business combination. The purchase price paid comprises AmeriGas Partners Common Units issued having a fair value of $1,132.6, and total cash consideration of $1,472.2 including cash acquired of $60.7. The fair value of the AmeriGas Partners Common Units issued to ETP was based on the closing price on the Acquisition Date
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 4 — Acquisitions & Dispositionssubject to a discount to reflect certain contractual transfer restrictions for a period of approximately twelve months. The purchase price allocation is as follows:
|
| | | |
Assets acquired: | |
Current assets | $ | 301.4 |
|
Property, plant & equipment | 890.2 |
|
Customer relationships (estimated useful life of 15 years) | 418.9 |
|
Trademarks and tradenames | 91.1 |
|
Goodwill | 1,217.7 |
|
Other assets | 9.9 |
|
Total assets acquired | $ | 2,929.2 |
|
| |
Liabilities assumed: | |
Current liabilities | $ | (238.1 | ) |
Long-term debt | (62.9 | ) |
Other noncurrent liabilities | (23.4 | ) |
Total liabilities assumed | $ | (324.4 | ) |
Total | $ | 2,604.8 |
|
Goodwill associated with the Heritage Acquisition principally results from synergies expected from combining the operations and from assembled workforce. The tax effects of such goodwill will be realized over a fifteen-year period. We allocated the purchase price of the acquisition to identifiable intangible assets based on estimated fair values. Tradenames and trademarks were valued using the relief from royalty method and customer relationships were valued using a discounted cash flow method. The relief from royalty method estimates our theoretical royalty savings from ownership of the tradenames and trademarks. Key assumptions used in this method include discount rates, royalty rates, growth rates and sales projections and are the assumptions most sensitive and susceptible to change as they require significant management judgment. The key assumptions used in the customer relationship discounted cash flow method include discount rates, growth rates and cash flow projections and are the assumptions most sensitive and susceptible to change as they require significant management judgment. We allocated the purchase price of the acquisition to property, plant and equipment based on estimated fair values primarily using replacement cost and market value methods.
Transaction expenses associated with the Heritage Acquisition, which are included in operating and administrative expenses in the Consolidated Statement of Income, totaled $5.3 for Fiscal 2012. The results of operations of Heritage Propane are included in the Consolidated Statements of Income since the Acquisition Date. As a result of achieving planned strategic operating and marketing milestones, it is impracticable to determine the impact of the Heritage Propane operations on the revenues and earnings of the Company.
The following presents unaudited pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred on October 1, 2010:
|
| | | | | | | | |
| | Fiscal 2012 | | Fiscal 2011 |
Revenues | | $ | 7,010.9 |
| | $ | 7,522.0 |
|
Net income attributable to UGI Corporation | | $ | 197.6 |
| | $ | 223.5 |
|
Earnings per common share attributable to UGI Corporation stockholders: | | | | |
Basic | | $ | 1.76 |
| | $ | 2.00 |
|
Diluted | | $ | 1.74 |
| | $ | 1.98 |
|
The unaudited pro forma results of operations reflect Heritage Propane’s historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The unaudited pro forma consolidated results of operations are not necessarily indicative of the results that would have occurred had the Heritage Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
In accordance with the Contribution Agreement, ETP and the Partnership entered into a transition services agreement and ETP, HPX and the Partnership also entered into a transition services agreement (collectively, the “TSA”) whereby each party may be a provider and receiver of certain services to the other. The principal services include general business continuity, information technology, accounting, tax and administrative services. Services under the TSA will be provided through the expiration of the term relating to each service or until such time as mutually agreed by the parties. Amounts associated with such services were not material.
In October 2011, we acquired Shell’s LPG distribution businesses in (1) Belgium, the Netherlands, Luxembourg through Antargaz; (2) Denmark, Finland, Norway and Sweden through Flaga; and (3) the United Kingdom through UGI Midlands Limited (a second-tier subsidiary of Enterprises), for €133.6 ($179.0) in cash ("Shell Transaction"). Also during Fiscal 2012, AmeriGas OLP acquired a number of smaller domestic retail propane distribution businesses for $13.5 in cash. During Fiscal 2011, AmeriGas OLP acquired a number of domestic retail propane distribution businesses for $34.0$34.0 in cash, and Flaga acquired a propane distribution business in Poland for total cash consideration of approximately $19.0.$19.0. During Fiscal 2010, AmeriGas OLP acquired a number of domestic retail propane distribution businesses for $34.3$34.3 in cash, and our International Propane operations acquired propane distribution businesses in Denmark, Hungary and Switzerland, and an additional 46% interest in our retail business in China, for total cash consideration of $48.7. During Fiscal 2009, AmeriGas OLP, in addition to the acquisition of the assets of CPP described below, acquired several retail propane distribution businesses for total cash consideration of $17.9 and Flaga acquired the 50% of ZLH it did not already own for $18.2.$48.7.
On October 1, 2008, UGI Utilities acquired all of the outstanding stock of PPL Gas Utilities Corporation (now CPG), the natural gas distribution utility of PPL Corporation (“PPL”), for cash consideration of $267.6 plus estimated working capital of $35.4 (the “CPG Acquisition”). Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary, Penn Fuel Propane, LLC (now named UGI Central Penn Propane, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas OLP. 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 at closing with a combination of $120 cash contributed by UGI on September 25, 2008, proceeds from the issuance on October 1, 2008 of $108 principal amount of 6.375% Senior Notes due 2013 and approximately $75.0 of UGI Utilities’ credit agreement borrowings. AmeriGas OLP funded its acquisition of the assets of CPP with AmeriGas OLP credit agreement borrowings, and UGI Utilities used the $33.6 cash proceeds from the sale of the assets of CPP to AmeriGas OLP to reduce its revolving credit agreement borrowings.
The assets and liabilities resulting from the CPG Acquisition which reflect the final purchase price allocation are included in our Consolidated Balance Sheets at September 30, 2011 and 2010. Pursuant to the CPG Acquisition purchase agreement, the purchase price was subject to adjustment for the difference between the estimated working capital of $35.4 and the actual working capital as of the closing date agreed to by both UGI Utilities and PPL. During Fiscal 2009, UGI Utilities and PPL reached an agreement on the working capital adjustment pursuant to which PPL paid UGI Utilities $9.7 in cash, including interest.
The purchase price of the CPG Acquisition, including transaction fees and expenses and incurred liabilities totaling approximately $2.9, was allocated to the assets acquired and liabilities assumed as follows:
| | | | |
|
Current assets less current liabilities | | $ | 22.7 | |
Property, plant and equipment | | | 236.1 | |
Goodwill | | | 36.8 | |
Utility regulatory assets | | | 22.5 | |
Other assets | | | 12.5 | |
Noncurrent liabilities | | | (34.4 | ) |
| | | |
Total | | $ | 296.2 | |
| | | |
The goodwill above is primarily the result of synergies between the acquired businesses and our existing utility and propane businesses. Substantially all of the goodwill is deductible for income tax purposes over a fifteen-year period. The operating results of CPG and CPP are included in our consolidated results beginning October 1, 2008.
On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned subsidiary Atlantic Energy, LLC (“Atlantic Energy”) to DCP Midstream Partners, L.P. for $49.0$49.0 in cash plus an amount for inventory and other working capital. Atlantic Energy owns and operates a 20 million gallon marine import and transshipment facility located in the port of Chesapeake, Virginia. The Company recorded a $36.5$36.5 pre-tax gain on the sale which amount is included in “Otherother income, net”net in the Fiscal 2010 Consolidated Statement of Income. The gain increased Fiscal 2010 net income attributable to UGI Corporation by $17.2 or $0.16 per diluted share.$17.2. Atlantic Energy’s income from operations was not material in Fiscal 2010 and 2009.2010.
On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated above-ground LPG storage facility located on leased property in California. The Partnership recorded a $39.9 pre-tax gain on the sale which amount is included in “Other income, net” in the Fiscal 2009 Consolidated Statement
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 5 — Debt
Long-term debt comprises the following at September 30:
| | | | | | | | |
| | 2011 | | | 2010 | |
AmeriGas Propane: | | | | | | | | |
AmeriGas Partners Senior Notes: | | | | | | | | |
6.50%, due May 2021 | | $ | 470.0 | | | $ | — | |
6.25%, due August 2019 | | | 450.0 | | | | — | |
8.875%, due May 2011 | | | — | | | | 14.7 | |
7.25%, due May 2015 | | | — | | | | 415.0 | |
7.125%, due May 2016 | | | — | | | | 350.0 | |
Other | | | 13.5 | | | | 11.7 | |
| | | | | | |
Total AmeriGas Propane | | | 933.5 | | | | 791.4 | |
| | | | | | |
International Propane: | | | | | | | | |
Antargaz 2011 Senior Facilities term loan, due through March 2016 | | | 508.7 | | | | — | |
Antargaz Senior Facilities term loan, due March 2011 | | | — | | | | 518.1 | |
Flaga term loan, due through September 2016 | | | 53.5 | | | | — | |
Flaga term loan, due through September 2011 | | | — | | | | 32.7 | |
Flaga term loan, due through June 2014 | | | 5.6 | | | | 7.6 | |
Other | | | 3.5 | | | | 2.7 | |
| | | | | | |
Total International Propane | | | 571.3 | | | | 561.1 | |
| | | | | | |
UGI Utilities: | | | | | | | | |
Senior Notes: | | | | | | | | |
6.375%, due September 2013 | | | 108.0 | | | | 108.0 | |
5.75%, due September 2016 | | | 175.0 | | | | 175.0 | |
6.21%, due September 2036 | | | 100.0 | | | | 100.0 | |
Medium- Term Notes: | | | | | | | | |
5.53%, due September 2012 | | | 40.0 | | | | 40.0 | |
5.37%, due August 2013 | | | 25.0 | | | | 25.0 | |
5.16%, due May 2015 | | | 20.0 | | | | 20.0 | |
7.37%, due October 2015 | | | 22.0 | | | | 22.0 | |
5.64%, due December 2015 | | | 50.0 | | | | 50.0 | |
6.17%, due June 2017 | | | 20.0 | | | | 20.0 | |
7.25%, due November 2017 | | | 20.0 | | | | 20.0 | |
5.67%, due January 2018 | | | 20.0 | | | | 20.0 | |
6.50%, due August 2033 | | | 20.0 | | | | 20.0 | |
6.13%, due October 2034 | | | 20.0 | | | | 20.0 | |
| | | | | | |
Total UGI Utilities | | | 640.0 | | | | 640.0 | |
| | | | | | |
|
Other | | | 12.9 | | | | 13.3 | |
| | | | | | |
|
Total long-term debt | | | 2,157.7 | | | | 2,005.8 | |
|
Less: current maturities | | | (47.4 | ) | | | (573.6 | ) |
| | | | | | |
Total long-term debt due after one year | | $ | 2,110.3 | | | $ | 1,432.2 | |
| | | | | | |
F-19
|
| | | | | | | |
| 2012 | | 2011 |
AmeriGas Propane: | | | |
AmeriGas Partners Senior Notes: | | | |
7.00%, due May 2022 | $ | 980.8 |
| | $ | — |
|
6.75%, due May 2020 | 550.0 |
| | — |
|
6.50%, due May 2021 | 270.0 |
| | 470.0 |
|
6.25%, due August 2019 | 450.0 |
| | 450.0 |
|
HOLP Senior Secured Notes | 55.6 |
| | — |
|
Other | 21.6 |
| | 13.5 |
|
Total AmeriGas Propane | 2,328.0 |
| | 933.5 |
|
International Propane: | | | |
Antargaz 2011 Senior Facilities term loan, due through March 2016 | 488.7 |
| | 508.7 |
|
Flaga term loan, due through September 2016 | 51.4 |
| | 53.5 |
|
Flaga term loan, due October 2016 | 24.6 |
| | — |
|
Flaga term loan, due through June 2014 | 3.6 |
| | 5.6 |
|
Other | 5.6 |
| | 3.5 |
|
Total International Propane | 573.9 |
| | 571.3 |
|
UGI Utilities: | | | |
Senior Notes: | | | |
6.375%, due September 2013 | 108.0 |
| | 108.0 |
|
5.75%, due September 2016 | 175.0 |
| | 175.0 |
|
6.21%, due September 2036 | 100.0 |
| | 100.0 |
|
Medium- Term Notes: | | | |
5.53%, due September 2012 | — |
| | 40.0 |
|
5.37%, due August 2013 | 25.0 |
| | 25.0 |
|
5.16%, due May 2015 | 20.0 |
| | 20.0 |
|
7.37%, due October 2015 | 22.0 |
| | 22.0 |
|
5.64%, due December 2015 | 50.0 |
| | 50.0 |
|
6.17%, due June 2017 | 20.0 |
| | 20.0 |
|
7.25%, due November 2017 | 20.0 |
| | 20.0 |
|
5.67%, due January 2018 | 20.0 |
| | 20.0 |
|
6.50%, due August 2033 | 20.0 |
| | 20.0 |
|
6.13%, due October 2034 | 20.0 |
| | 20.0 |
|
Total UGI Utilities | 600.0 |
| | 640.0 |
|
Other | 12.4 |
| | 12.9 |
|
Total long-term debt | 3,514.3 |
| | 2,157.7 |
|
Less: current maturities | (166.7 | ) | | (47.4 | ) |
Total long-term debt due after one year | $ | 3,347.6 |
| | $ | 2,110.3 |
|
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Scheduled principal repayments of long-term debt due in fiscal years 20122013 to 20162017 follow:
| | | | | | | | | | | | | | | | | | | | |
| | 2012 | | | 2013 | | | 2014 | | | 2015 | | | 2016 | |
AmeriGas Propane | | $ | 4.8 | | | $ | 3.1 | | | $ | 2.4 | | | $ | 2.0 | | | $ | 1.1 | |
UGI Utilities | | | 40.0 | | | | 133.0 | | | | — | | | | 20.0 | | | | 247.0 | |
International Propane | | | 2.1 | | | | 3.2 | | | | 53.7 | | | | 46.5 | | | | 465.9 | |
Other | | | 0.5 | | | | 0.6 | | | | 0.5 | | | | 0.5 | | | | 0.6 | |
| | | | | | | | | | | | | | | |
Total | | $ | 47.4 | | | $ | 139.9 | | | $ | 56.6 | | | $ | 69.0 | | | $ | 714.6 | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
AmeriGas Propane | $ | 30.0 |
| | $ | 10.9 |
| | $ | 8.9 |
| | $ | 6.5 |
| | $ | 4.6 |
|
UGI Utilities | 133.0 |
| | — |
| | 20.0 |
| | 247.0 |
| | 20.0 |
|
International Propane | 2.5 |
| | 52.9 |
| | 45.0 |
| | 448.2 |
| | 25.1 |
|
Other | 0.6 |
| | 0.6 |
| | 0.5 |
| | 0.6 |
| | 0.6 |
|
Total | $ | 166.1 |
| | $ | 64.4 |
| | $ | 74.4 |
| | $ | 702.3 |
| | $ | 50.3 |
|
AmeriGas Propane
In order to finance the cash portion of the Heritage Acquisition, on January 12, 2012, the “Issuers” issued $550 principal amount of 6.75% Notes due May 2020 and $1,000 principal amount of 7.00% Notes due May 2022. The 6.75% Notes and the 7.00% Notes are fully and unconditionally guaranteed on a senior unsecured basis by AmeriGas Partners. The Issuers have the right to redeem the 6.75% Notes, in whole or in part, at any time on or after May 20, 2016, and to redeem the 7.00% Notes, in whole or in part, at any time on or after May 20, 2017, subject to certain restrictions. A premium applies to redemptions of the 6.75% Notes and 7.00% Notes through May 2018 and May 2020, respectively. On or prior to May 20, 2015, the Issuers may also redeem, at a premium and subject to certain restrictions, up to 35% of each of the 6.75% Notes and the 7.00% Notes with the proceeds of an AmeriGas Partners registered public equity offering. The 6.75% Notes and the 7.00% Notes and the guarantees rank equal in right of payment with all of AmeriGas Partners’ existing Senior Notes. In connection with the Heritage Acquisition, AmeriGas Partners, AmeriGas Finance Corp., AmeriGas Finance LLC and UGI entered into a Contingent Residual Support Agreement ("CRSA") with ETP pursuant to which ETP will provide contingent, residual support of $1,500 of debt ("Supported Debt" as defined in the CRSA).
On March 28, 2012, AmeriGas Partners announced that holders of approximately $383.5 in aggregate principal amount of outstanding 6.50% Senior Notes due May 2021 (the “6.50% Notes”), representing approximately 82% of the total $470 principal amount outstanding, had validly tendered their notes in connection with the Partnership’s March 14, 2012, offer to purchase for cash up to $200 of the 6.50% Notes. Tendered 6.50% Notes in the amount of $200 were redeemed on March 28, 2012, at an effective price of 105% using an approximate proration factor of 52.3% of total notes tendered. During June 2012, AmeriGas Partners repurchased approximately $19.2 aggregate principal amount of outstanding 7.00% Notes. The Partnership recorded a net loss of $13.3 on these extinguishments of debt which amount is reflected on the Fiscal 2012 Consolidated Statement of Income under the caption loss on extinguishments of debt. The net loss reduced net income attributable to UGI Corporation by $2.2 during Fiscal 2012.
In January 2011, AmeriGas Partners issued $470$470 principal amount of 6.50% Senior Notes due May 2021 (the “6.50% Senior Notes”). The proceeds from the issuance of the 6.50% Senior Notes were used in February 2011 to repay AmeriGas Partners’ $415$415 principal amount of its 7.25% Senior Notes due May 2015 pursuant to a tender offer and subsequent redemption. In addition, in February 2011, AmeriGas Partners redeemed the outstanding $14.6$14.6 principal amount of its 8.875% Senior Notes due May 2011.2011. The Partnership incurred a loss of $18.8$18.8 on these extinguishments of debt which amount is reflected on the Fiscal 2011 Consolidated Statement of Income under the caption “Lossloss on extinguishments of debt.” The This loss reduced net income attributable to UGI Corporation by $5.2$5.2 during Fiscal 2011.
In August 2011, AmeriGas Partners issued $450$450 principal amount of 6.25% Senior Notes due August 2019 (the “6.25%“6.25% Senior Notes”). The proceeds from the issuance of the 6.25% Senior Notes were used to repay AmeriGas Partners’ $350$350 principal amount of its AmeriGas Partners 7.125% Senior Notes due May 2016 pursuant to a tender offer and subsequent redemption. The Partnership incurred a loss of $19.3$19.3 on this extinguishment of debt which amount is also reflected on the Fiscal 2011 Consolidated Statement of Income under the caption “Lossloss on extinguishments of debt.” This loss reduced net income attributable to UGI Corporation by $5.2$5.2 during Fiscal 2011.
The 6.50% and 6.25% Senior Notes generally may be redeemed at our option (pursuant to a tender offer). A redemption premium applies through May 2019 (with respect to the 6.50% Notes) and through August 2017 (with(with respect to the 6.25% Notes). In addition, in the event that AmeriGas Partners completes a registered public offering of Common Units, the Partnership may, at its option, redeem up to 35% of the outstanding 6.50% Notes (through May 2014)20, 2014) or 35% of the outstanding 6.25% Notes (through August 2014)20, 2014), each at a premium. AmeriGas Partners may, under certain circumstances involving excess sales proceeds from the disposition of assets not reinvested in the business or a change of control, be required to offer to prepay its 6.50% and 6.25% Senior Notes.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
As a result of the Heritage Acquisition, the Partnership's total long-term debt at September 30, 2012, includes $62.5 of Heritage Propane long-term debt including $55.6 of HOLP Senior Secured Notes (including unamortized premium of $4.4). The face interest rates on the HOLP Notes range from 7.26% to 8.87% with an effective interest rate of 6.75%. The HOLP Senior Secured Notes are collateralized by HOLP's receivables, contracts, equipment, inventory, general intangibles, cash and HOLP capital stock.
In June 2011, AmeriGas OLP entered into an unsecured revolving credit agreement (the “AmeriGas 2011 Credit Agreement”) with a group of banks providing for borrowings up to $325$325 (including a $100$100 sublimit for letters of credit). Concurrently with entering intoDuring Fiscal 2012, the AmeriGas 2011 Credit Agreement AmeriGas OLP terminatedwas amended to, among other things, increase the total amount available to $525, extend its then-existing $200 revolving credit agreement datedexpiration date to October 2016, and amend certain financial covenants as a result of November 6, 2006 and its $75 credit agreement dated as of April 17, 2009 (the “2009 AmeriGas Supplemental Credit Agreement”).the Heritage Acquisition. The AmeriGas 2011 Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a two-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas 2011 Credit Agreement, plus a margin. The margin on base rate borrowings (which ranges from 0.75% to 1.75%), Eurodollar Rate borrowings (which ranges from 1.75% to 2.75%), and the AmeriGas 2011 Credit Agreement facility fee rate (which ranges from 0.30% to 0.50%) are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”), each as defined in the AmeriGas 2011 Credit Agreement.
At September 30, 20112012 and 2010,2011, there were $95.5$49.9 and $91$95.5 of borrowings outstanding under the AmeriGas 2011 Credit Agreement, and predecessor credit agreements, respectively, which amounts are reflected as bank loans on the Consolidated Balance Sheets. The weighted-average interest rates on the AmeriGas 2011 AmeriGas Credit Agreement and predecessor credit agreements borrowings at September 30, 20112012 and 20102011, were 2.29%2.72% and 1.31%2.29%, respectively. IssuedAt September 30, 2012 and 2011, issued and outstanding letters of credit, which reduce available borrowings under the AmeriGas 2011 AmeriGas Credit Agreement, totaled $47.9and predecessor credit agreements, totaled $35.7 at September 30, 2011 and 2010.$35.7, respectively.
Restrictive Covenants.The 6.50% and 6.25%AmeriGas Partners Senior Notes of AmeriGas Partners restrict the ability of the Partnership and AmeriGas OLP to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets. Under the 6.50% and 6.25%AmeriGas Partners Senior NoteNotes Indentures, AmeriGas Partners is generally permitted to make cash distributions equal to available cash,Available Cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. At September 30, 2011,2012, these restrictions did not limit the amount of Available Cash. See Note 14 for definition of Available Cash included in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. (“Partnership Agreement”).
F-20
UGI CorporationThe HOLP Senior Secured Notes contain restrictive covenants including the maintenance of financial covenants and Subsidiaries
Noteslimitations on the disposition of assets, changes in ownership, additional indebtedness, restrictive payments and the creation of liens. The financial covenants require HOLP to Consolidated Financial Statements
(Millionsmaintain a ratio of dollarscombined Funded Indebtedness to combined EBITDA (as defined) below certain thresholds and euros, except per share amounts and where indicated otherwise)to maintain a minimum ratio of combined EBITDA to combined Interest Expense (as defined).
The AmeriGas 2011 Credit Agreement restricts the incurrence of additional indebtedness and also restrict certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas 2011 Credit Agreement requires that Thethe Partnership and AmeriGas OLP maintain ratios of total indebtedness to EBITDA, as defined, below certain thresholds. In addition, the Partnership must maintain a minimum ratio of EBITDA to interest expense, as defined, as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result, the Partnership and AmeriGas OLP are permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter.
International Propane
In March 2011, Antargaz entered into a new five-yearfive-year Senior Facilities Agreement with a consortium of banks (“2011 Senior Facilities Agreement”) consisting of a €380€380 variable-rate term loan and a €40 revolving€40 credit facility. The proceeds from the new2011 Senior Facilities Agreement term loan were used to repay Antargaz’ then-existing Senior Facilities Agreement term loan due March 2011.
Scheduled maturities under the term loan are €38€38 due May 2014, €34.2€34.2 due May 2015, and €307.8€307.8 due March 2016. Borrowings under the 2011 Senior Facilities Agreement bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the 2011 Senior Facilities Agreement. There were no amounts outstanding under the 2011 Senior Facilities Agreement revolving credit facility at September 30, 2011.2012 or 2011. The margin on the term loan and revolving credit facility borrowings (which ranges from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the 2011 Senior Facilities Agreement. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of 3.71% through the date of the term loan’s final maturity in March 2016. At September 30, 2011,2012, the effective interest rate on Antargaz’ term loan was 4.66%. The 2011 Senior Facilities Agreement is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivables.
In orderDecember 2011, Flaga entered into a €19.1 euro-based variable-rate term loan agreement. Proceeds from the term loan were used, in large part, to minimizefund Flaga’s October 2011 acquisition of Shell’s LPG propane businesses in Finland, Norway, Sweden and Denmark. The term loan matures in October 2016 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 1.175% to 2.525% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios. Flaga has effectively fixed the euribor component of the interest marginrate on its Senior Facilities Agreement borrowings, in September 2010 Antargaz borrowed €50 ($68.2), the total amount available under its revolving credit facility, which amount remained outstandingthis term loan at 1.79% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2010. This amount2012, was repaid in October 2010.4.35%.
In September 2011, Flaga entered into a €40€40 euro-based variable-rate term loan of which €26.7€26.7 matures in August 2016 and €13.3€13.3 matures in September 2016. This2016. A portion of the proceeds from the loan were used to repay its €24.0 euro-based variable-rate term loan which matured during Fiscal 2011. The €40 euro-based term loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin. The margin on such borrowings ranges from 1.58%0.23% to 3.93%2.55% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios. Flaga has effectively fixed the euribor component of its interest rate on this term loan through September 2016 at 2.68% by entering into interest rate swap agreements. The effective interest rates on thisFlaga's term loanloans at September 30, 2012 and 2011, was were 5.18% and 4.76%. At , respectively.
As of September 30, 2010, Flaga had a €24.0 euro-based variable-rate term loan which matured during Fiscal 2011. Flaga had effectively fixed the euribor component of its interest rate on this term loan through September 2012 and 2011 at 3.91% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2010 was 4.21%.
, Flaga also has a euro-based variable-rate term loan which had outstanding principal balances of €4.2 ($5.6)€2.8 ($3.6) and €5.6 ($7.6) as of September 30, 2011 and 2010,€4.2 ($5.6), respectively. This term loan matures in June 2014 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 2.625% to 3.50% and is based upon certain equity, return on assets and debt to EBITDA ratios as determined on a UGI consolidated basis. Semi-annual principal payments of €0.7€0.7 are due on December 31 and June 30 each year through June 2014. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 2.16% by entering into an interest rate swap agreement. TheAs of September 30, 2012 and 2011, the effective interest ratesrate on this term loan at was 5.04%.
At September 30, 2011 and 2010 were 5.04% and 5.03%2012, respectively.
During Fiscal 2011, in order to increase Flaga’s borrowing capacity, Flaga entered into several agreements to increase or extend maturities of its working capital facilities.
F-21
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
At September 30, 2011, Flaga GmbH has threetwo principal working capital facilities (the “Flaga Credit Agreements”) comprising (1) a €46€46 multi-currency working capital facility which includes an uncommitted €6€6 overdraft facility (the “2011 Multi-currency“Multi-Currency Working Capital Facility”) and (2) twoa euro-denominated working capital facilitiesfacility that provideprovides for borrowings and issuances of guarantees totaling €12 million€12 (the “Euro Working Capital Facilities”Facility”). The 2011 Multi-currency Working Capital Facility replaced two previously existing multi-currency working capital facilities which expired in September 2011 (the “Predecessor Multi-currency Facilities”). The 2011 Multi-currencyMulti-Currency Working Capital Facility expires in September 2014 and the Euro Working Capital Facilities expireFacility expires in March 2012.September 2013. At September 30, 20112012 and 2010,2011, there was €4.3 ($5.7)were €11.9 ($15.3) and €9.8 ($13.4)€12.3 ($16.5) of borrowings outstanding under the 2011 Multi-currency Working Capital Facility and the Predecessor Multi-currency Facilities, respectively, and €8.0 ($10.7) and €7.9 ($10.8) of borrowings outstanding under the Euro Working Capital Facilities, respectively.Flaga Credit Agreements. These amounts are reflected as bank loans on the Consolidated Balance Sheets.
Borrowings under the 2011 Multi-currency Working Capital Facility and Euro Working Capital FacilitiesFlaga Credit Agreements generally bear interest at market rates (a daily euro-based rate or three-month euribor rates) plus a margin. The weighted-average interest raterates on the 2011 Multi-currency Working Capital Facility and Euro Working Capital FacilitiesFlaga Credit Agreements borrowings at September 30, 2012 and 2011, was 3.39%. The weighted-average interest rate on the predecessor multi-currency facilitieswere 2.31% and the Euro Facilities at September 30, 2010 was 2.91%.3.39%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under these facilities,the Flaga Credit Agreements, totaled €12.1 ($16.2)€19.2 ($24.7) and €5.4 ($7.4)€12.1 ($16.2) at September 30, 20112012 and 2010,2011, respectively.
Restrictive Covenants and Guarantees.The 2011 Senior Facilities Agreement restricts the ability of Antargaz to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires Antargaz to maintain a ratio of net debt to EBITDA on a French generally accepted accounting basis, as defined in the agreement, that shall not exceed 3.50 to 1.00.1.00. Under this agreement, Antargaz is generally permitted to make restricted payments, such as dividends if no event of default exists or would exist upon payment of such restricted payment. UGI has guaranteed up to €100€100 of payments under the 2011 Senior Facilities Agreement.
The Flaga term loans, working capital facilities and interest rate swap agreements are guaranteed by UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending banks may accelerate repayment of the debt.
UGI Utilities
On May 25, 2011, UGI Utilities entered intohas an unsecured revolving credit agreement (the “UGI Utilities 2011 Credit Agreement”) with a group of banks providing for borrowings up to $300$300 (including a $100$100 sublimit for letters of credit) which expires in May 2012 but may be extended to October 2015 if UGI Utilities satisfies certain requirements relating to approval by the PUC. Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350 revolving credit agreement dated as of August 11, 2006.2015. Under the UGI Utilities 2011 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based upon the credit ratings of certain indebtedness of UGI Utilities. UGI Utilities hashad $9.2 of borrowings outstanding under the UGI Utilities 2011 Credit Agreement
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
at September 30, 2012 which amount is reflected in bank loans on the Consolidated Balance Sheet. UGI Utilities had no borrowings outstanding under the UGI Utilities 2011 Credit Agreement at September 30, 2011. UGI Utilities had borrowings outstanding under its credit agreements, which we classify as bank loans, totaling $17 at September 30, 2010. The weighted-average interest ratesrate on UGI Utilities’ revolving credit agreementsUtilities 2011 Credit Agreement borrowings at September 30, 20102012 was 3.25%1.21%. Issued and outstanding letters of credit, which reduce available borrowings under the UGI Utilities 2011 Credit Agreement, totaled $2.0$2.0 at September 30, 2011.2012 and 2011.
Restrictive Covenants.UGI Utilities 2011 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.1.00.
Energy Services
Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $170$170 (including a $50$50 sublimit for letters of credit) which expires in August 2013. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries. In addition, Energy Services may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not exceed 2.00 to 1.00.1.00. There were $10$85 and $10 of borrowings outstanding under the Energy Services Credit Agreement at September 30, 2011. There were no borrowings outstanding under2012 and 2011, respectively. These amounts are reflected as bank loans on the Energy Services Credit Agreement at September 30, 2010.
F-22
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)Balance Sheets.
Borrowings under the Energy Services Credit Agreement bear interest at either (i) a rate derived from LIBOR (the “LIBO Rate”) plus 3.0% for each Eurodollar Revolving Loan (as defined in the Energy Services Credit Agreement) or (ii) the Alternate Base Rate plus 2.0%. The Alternate Base Rate (as defined in the Energy Services Credit Agreement) is generally the greater of (a) the Agent Bank’s prime rate, (b) the federal funds rate plus 0.50% and (c) the one-month LIBO Rate plus 1.0%. The weighted-average interest rate on the Energy Services Credit Agreement borrowings at September 30, 2012 and 2011, was 3.25%. The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services.
Restrictive Covenants.The Energy Services Credit Agreement restricts the ability of Energy Services to dispose of assets, effect certain consolidations or mergers, incur indebtedness and guaranty obligations, create liens, make acquisitions or investments, make certain dividend or other distributions and make any material changes to the nature of its businesses. In addition, the Energy Services Credit Agreement requires Energy Services to not exceed a ratio of Consolidated Total Indebtedness, as defined, to Consolidated EBITDA, as defined; a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense, as defined; a maximum ratio of Consolidated Total Indebtedness to Consolidated Total Capitalization, as defined, at any time when Consolidated Total Indebtedness is greater than $250;$250; and a minimum Consolidated Net Worth, as defined, of $150.$150.
Energy Services also has a $200$200 receivables securitization facility (see Note 18).
Restricted Net Assets
At September 30, 2011,2012, the amount of net assets of UGI’s consolidated subsidiaries that was restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $1,700.$1,400.
Note 6 — Income Taxes
Income before income taxes comprises the following:
| | | | | | | | | | | | |
| | 2011 | | | 2010 | | | 2009 | |
Domestic | | $ | 388.8 | | | $ | 448.8 | | | $ | 431.7 | |
Foreign | | | 50.2 | | | | 74.5 | | | | 109.4 | |
| | | | | | | | | |
Total income before income taxes | | $ | 439.0 | | | $ | 523.3 | | | $ | 541.1 | |
| | | | | | | | | |
|
| | | | | | | | | | | |
| 2012 | | 2011 | | 2010 |
Domestic | $ | 227.3 |
| | $ | 388.8 |
| | $ | 448.8 |
|
Foreign | 58.9 |
| | 50.2 |
| | 74.5 |
|
Total income before income taxes | $ | 286.2 |
| | $ | 439.0 |
| | $ | 523.3 |
|
The provisions for income taxes consist of the following:
| | | | | | | | | | | | |
| | 2011 | | | 2010 | | | 2009 | |
Current expense: | | | | | | | | | | | | |
Federal | | $ | 24.4 | | | $ | 60.5 | | | $ | 69.6 | |
State | | | 14.5 | | | | 20.4 | | | | 21.6 | |
Foreign | | | 15.0 | | | | 25.8 | | | | 41.1 | |
Investment tax credit | | | (5.8 | ) | | | (1.7 | ) | | | — | |
| | | | | | | | | |
Total current expense | | | 48.1 | | | | 105.0 | | | | 132.3 | |
Deferred expense (benefit): | | | | | | | | | | | | |
Federal | | | 79.3 | | | | 54.5 | | | | 27.6 | |
State | | | 2.4 | | | | 6.4 | | | | (1.1 | ) |
Foreign | | | 1.4 | | | | 2.1 | | | | 0.7 | |
Investment tax credit amortization | | | (0.4 | ) | | | (0.4 | ) | | | (0.4 | ) |
| | | | | | | | | |
Total deferred expense | | | 82.7 | | | | 62.6 | | | | 26.8 | |
| | | | | | | | | |
Total income tax expense | | $ | 130.8 | | | $ | 167.6 | | | $ | 159.1 | |
| | | | | | | | | |
Federal income taxes for Fiscal 2010 and Fiscal 2009 are net of foreign tax credits of $2.1 and $34.9, respectively.
F-23
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
|
| | | | | | | | | | | |
| 2012 | | 2011 | | 2010 |
Current expense (benefit): | | | | | |
Federal | $ | (10.4 | ) | | $ | 24.4 |
| | $ | 60.5 |
|
State | 11.2 |
| | 14.5 |
| | 20.4 |
|
Foreign | 18.8 |
| | 15.0 |
| | 25.8 |
|
Investment tax credit | (2.9 | ) | | (5.8 | ) | | (1.7 | ) |
Total current expense | 16.7 |
| | 48.1 |
| | 105.0 |
|
Deferred expense (benefit): | | | | | |
Federal | 76.2 |
| | 79.3 |
| | 54.5 |
|
State | 5.2 |
| | 2.4 |
| | 6.4 |
|
Foreign | 1.8 |
| | 1.4 |
| | 2.1 |
|
Investment tax credit amortization | (0.3 | ) | | (0.4 | ) | | (0.4 | ) |
Total deferred expense | 82.9 |
| | 82.7 |
| | 62.6 |
|
Total income tax expense | $ | 99.6 |
| | $ | 130.8 |
| | $ | 167.6 |
|
Federal income taxes for Fiscal 2012 and Fiscal 2010 are net of foreign tax credits of $5.2 and $2.1, respectively.
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:
| | | | | | | | | | | | |
| | 2011 | | | 2010 | | | 2009 | |
U.S. federal statutory tax rate | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % |
Difference in tax rate due to: | | | | | | | | | | | | |
Noncontrolling interests not subject to tax | | | (6.0 | ) | | | (6.4 | ) | | | (8.0 | ) |
State income taxes, net of federal benefit | | | 2.2 | | | | 3.5 | | | | 2.5 | |
Effects of international operations | | | (0.6 | ) | | | (0.6 | ) | | | (0.3 | ) |
Other, net | | | (0.8 | ) | | | 0.5 | | | | 0.2 | |
| | | | | | | | | |
Effective tax rate | | | 29.8 | % | | | 32.0 | % | | | 29.4 | % |
| | | | | | | | | |
|
| | | | | | | | |
| 2012 | | 2011 | | 2010 |
U.S. federal statutory tax rate | 35.0 | % | | 35.0 | % | | 35.0 | % |
Difference in tax rate due to: | | | | | |
Noncontrolling interests not subject to tax | 1.3 |
| | (6.0 | ) | | (6.4 | ) |
State income taxes, net of federal benefit | 3.8 |
| | 2.2 |
| | 3.5 |
|
Valuation allowance adjustments | (1.6 | ) | | — |
| | (0.2 | ) |
Effects of foreign operations | (3.6 | ) | | (0.6 | ) | | (0.6 | ) |
Other, net | (0.1 | ) | | (0.8 | ) | | 0.7 |
|
Effective tax rate | 34.8 | % | | 29.8 | % | | 32.0 | % |
The effects of foreign operations in the table above for Fiscal 2012 reflects the impact of tax efficient structuring of certain of our international operations and, as a result of the Shell Transaction, also reflects a greater proportion of pretax income in countries in which the statutory income tax rate is less than the U.S. statutory tax rate. The tax restructuring of certain of our international operations also permitted us to reduce our foreign tax credit valuation allowance by $4.6 during Fiscal 2012 which is included as valuation allowance adjustments in the table above.
Earnings of the Company's foreign subsidiaries are generally subject to U.S. taxation upon repatriation to the U.S. and the Company's tax provision reflects the related incremental U.S. tax except for certain foreign subsidiaries whose unremitted earnings are considered to be indefinitely reinvested. Because of the availability of U.S. foreign tax credits, it is likely no U.S. tax would be due if such earnings were repatriated.
Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2012, Fiscal 2011 and Fiscal 2010, the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $3.2, $7.9 and $2.5, respectively. The state tax flow through amounts in Fiscal 2012 and Fiscal 2011 reflect the impact of 2010 U.S. Federal tax legislation that allowed taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of calendar 2011, when such property is placed in service before 2012. This legislation was also permitted for Pennsylvania state corporate income tax purposes.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Deferred tax liabilities (assets) comprise the following at September 30:
| | | | | | | | |
| | 2011 | | | 2010 | |
Excess book basis over tax basis of property, plant and equipment | | $ | 490.4 | | | $ | 414.9 | |
Investment in AmeriGas Partners | | | 172.7 | | | | 170.9 | |
Intangible assets and goodwill | | | 52.1 | | | | 51.0 | |
Utility regulatory assets | | | 124.7 | | | | 127.4 | |
Foreign currency translation adjustment | | | 8.5 | | | | 12.9 | |
Other | | | 7.2 | | | | 8.6 | |
| | | | | | |
Gross deferred tax liabilities | | | 855.6 | | | | 785.7 | |
| | | | | | | | |
Pension plan liabilities | | | (62.8 | ) | | | (76.1 | ) |
Employee-related benefits | | | (42.7 | ) | | | (42.4 | ) |
Operating loss carryforwards | | | (31.8 | ) | | | (25.5 | ) |
Foreign tax credit carryforwards | | | (60.1 | ) | | | (61.3 | ) |
Utility regulatory liabilities | | | (12.4 | ) | | | (13.5 | ) |
Derivative financial instruments | | | (30.5 | ) | | | (34.8 | ) |
Other | | | (32.9 | ) | | | (41.7 | ) |
| | | | | | |
Gross deferred tax assets | | | (273.2 | ) | | | (295.3 | ) |
|
Deferred tax assets valuation allowance | | | 81.9 | | | | 78.4 | |
| | | | | | |
Net deferred tax liabilities | | $ | 664.3 | | | $ | 568.8 | |
| | | | | | |
|
| | | | | | | |
| 2012 | | 2011 |
Excess book basis over tax basis of property, plant and equipment | $ | 582.0 |
| | $ | 490.4 |
|
Investment in AmeriGas Partners | 293.2 |
| | 172.7 |
|
Intangible assets and goodwill | 61.2 |
| | 52.1 |
|
Utility regulatory assets | 140.4 |
| | 124.7 |
|
Foreign currency translation adjustment | 3.6 |
| | 8.5 |
|
Other | 6.8 |
| | 7.2 |
|
Gross deferred tax liabilities | 1,087.2 |
| | 855.6 |
|
| | | |
Pension plan liabilities | (72.7 | ) | | (62.8 | ) |
Employee-related benefits | (43.0 | ) | | (42.7 | ) |
Operating loss carryforwards | (38.0 | ) | | (31.8 | ) |
Foreign tax credit carryforwards | (55.5 | ) | | (60.1 | ) |
Utility regulatory liabilities | (11.8 | ) | | (12.4 | ) |
Derivative financial instruments | (37.7 | ) | | (30.5 | ) |
Other | (31.9 | ) | | (32.9 | ) |
Gross deferred tax assets | (290.6 | ) | | (273.2 | ) |
Deferred tax assets valuation allowance | 81.6 |
| | 81.9 |
|
Net deferred tax liabilities | $ | 878.2 |
| | $ | 664.3 |
|
At September 30, 2011,2012, foreign net operating loss carryforwards principally relating to Flaga and certain operations of Antargaz totaled $46.0$50.2 and $5.5,$5.3, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $177.9$213.3 and expire through 2031.2032. We also have operating loss carryforwards of $7.4$18.6 for certain operations of AmeriGas Propane that expire through 2031.2032. At September 30, 2011,2012, deferred tax assets relating to operating loss carryforwards include $10.6$12.1 for Flaga, $1.9$1.8 for Antargaz, $1.0$0.9 for UGI International Holdings BV, $2.7$5.2 for AmeriGas Propane and $15.6$17.9 for certain other subsidiaries. A valuation allowance of $15.6$17.2 has been provided for deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries because, on a state reportable basis, it is more likely than not that these assets will expire unused. A valuation allowance of $6.2$1.0 was provided for certain acquisition loss carryforwards for certain operations of AmeriGas Propane because it is more likely than not that these assets will expire unused. A valuation allowance of $7.9 was also provided for deferred tax assets related to certain operations of Antargaz, Flaga and UGI International Holdings BV. Operating activities and tax deductions related to the exercise of non-qualified stock options contributed to the state net operating losses disclosed above. We first recognize the utilization of state net operating losses from operations (which exclude the impact of tax deductions for exercises of non-qualified stock options) to reduce income tax expense. Then, to the extent state net operating loss carryforwards, if realized, relate to non-qualified stock option deductions, the resulting benefits will be credited to UGI Corporation stockholders’ equity.
We have foreign tax credit carryforwards of approximately $60.1$55.5 expiring through 2022 resulting from the actual and planned repatriation of Antargaz’ accumulated earnings since acquisition which are includable in U.S. taxable income. Because we expect that these credits will expire unused, a valuation allowance has been provided for the entire foreign tax credit carryforward amount. The valuation allowance for all deferred tax assets increaseddecreased by $3.5$0.3 in Fiscal 20112012 due primarilyto a decrease in unusable foreign tax credits of $4.6 partially offset by adjustments to unusable net operating losses obtained in connection with overseas acquisitions of $3.2 and$1.7, an increase in unusable state operating losses of $1.5 partially offset by a decrease$1.6, and unusable net operating losses in the foreign tax credit carryforwardsconnection with an AmeriGas Propane acquisition of $1.2.
F-24
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)$1.0.
We conduct business and file tax returns in the U.S., numerous states, local jurisdictions and in France and certain central and easternother European countries. Our U.S. federal income tax returns are settled through the 20082009 tax year, and our French tax returns are settled through the 2008 tax year, our Belgian tax returns are settled through 2007 and our Netherlands tax year.returns are settled through 2004. Our Austrian tax returns are settled through 20072008 and our other central and eastern European tax returns are effectively settled for various years from 20042005 to 2009. UGI Corporation’s federal income tax return for Fiscal 2009 is currently under audit. Although it is not possible to predict with certainty the timing of the conclusion of the pending U.S. federal tax audit in progress, we anticipate that the Internal Revenue Service’s (“IRS’s”) audit of our Fiscal 2009 U.S. federal income tax return may be completed during Fiscal 2012.2010. State and other income tax returns in the U.S. are generally subject to examination for a period of three to five years after the filing of the respective returns.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
As of September 30, 2011,2012, we have unrecognized income tax benefits totaling $6.5$3.1 including related accrued interest of $0.2.$0.2. If these unrecognized tax benefits were subsequently recognized, $1.6$1.9 would be recorded as a benefit to income taxes on the consolidated statementConsolidated Statement of incomeIncome and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. Included in the balance at September 30, 20112012, are $4.8$1.1 of tax positions for which the deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, the disallowance of the current deduction would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The amount of reasonably possibleThere are no expected changes in unrecognized tax benefits and related interest in the next twelve months is a net reduction of approximately $4.2.months.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
| | | | |
|
Balance at September 30, 2008 | | $ | 4.9 | |
Additions for tax positions of the current year | | | 0.5 | |
Additions for tax positions of prior years | | | 0.3 | |
Reductions as a result of tax positions taken in prior years | | | (1.2 | ) |
Settlements with tax authorities | | | (2.2 | ) |
| | | |
Balance at September 30, 2009 | | | 2.3 | |
Additions for tax positions of the current year | | | 4.3 | |
Reductions as a result of tax positions taken in prior years | | | (0.2 | ) |
Settlements with tax authorities | | | (1.0 | ) |
| | | |
Balance at September 30, 2010 | | | 5.4 | |
Additions for tax positions of the current year | | | 0.4 | |
Additions for tax positions of prior years | | | 1.0 | |
Settlements with tax authorities | | | (0.5 | ) |
| | | |
Balance at September 30, 2011 | | $ | 6.3 | |
| | | |
Beginning with the tax year ended September 30, 2009, the Company received IRS consent to change its tax method of accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility and Electric Utility assets. The filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30.2 which were used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 Pennsylvania income tax return also produced a $43.4 state net operating loss (“NOL”) carryforward. Under current Pennsylvania state income tax law, the NOL can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. As of September 30, 2011, a state net operating loss carryforward of $29.3 remains. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded. The Company’s determination of what constitutes a capital cost versus ordinary expense as it relates to the new tax method will likely be reviewed upon audit by the IRS and may be subject to subsequent adjustment. Accordingly, the status of this tax return position is uncertain at this time. In accordance with accounting guidance regarding uncertain tax positions, during Fiscal 2011 and Fiscal 2010, the Company added $1.2 and $3.9 including interest to its liability for unrecognized tax benefits related to this tax method. However, because this tax matter relates only to the timing of tax deductibility, we have recorded an offsetting deferred tax asset of an equal amount. For further information on the regulatory impact of this change, see Note 8.F-25
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
In 2010, U.S. federal tax legislation was enacted that allows taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010 through the end of calendar 2011, when such property is placed in service before 2012. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers are also permitted to fully deduct such qualifying capital expenditures for Pennsylvania state corporate net income tax purposes. Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits from accelerated tax depreciation. UGI Utilities’ Fiscal 2011 effective tax rate reflects the beneficial effects of this greater state tax depreciation. |
| | | |
Balance at September 30, 2009 | $ | 2.3 |
|
Additions for tax positions of the current year | 4.3 |
|
Reductions as a result of tax positions taken in prior years | (0.2 | ) |
Settlements with tax authorities | (1.0 | ) |
Balance at September 30, 2010 | 5.4 |
|
Additions for tax positions of the current year | 0.4 |
|
Additions for tax positions of prior years | 1.0 |
|
Settlements with tax authorities | (0.5 | ) |
Balance at September 30, 2011 | 6.3 |
|
Additions for tax positions of the current year | 0.5 |
|
Additions for tax positions of prior years | 0.6 |
|
Settlements with tax authorities | (4.5 | ) |
Balance at September 30, 2012 | $ | 2.9 |
|
Note 7 — Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans.In the U.S., we currently sponsor one defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“subsidiaries. Effective December 31, 2010, we merged our then-existing two U.S. defined benefit pension plans covering these employees ("U.S. Pension Plan”Plans Merger"). The Company's two U.S. pension plans prior to the Pension Plans Merger, and the single U.S. pension plan after the Pension Plans Merger, are hereafter referred to as the "U.S. Pension Plan."
We also provide postretirement health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all domestic active and retired employees. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the Antargaz plans, such amounts are not material.
Effective December 31, 2010, UGI Utilities merged its then-existing two defined benefit pension plans (“Utilities Pension Plan Merger”). As a result of the Utilities Pension Plan Merger and in accordance with GAAP relating to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010, which decreased other noncurrent liabilities by $46.7; decreased associated regulatory assets by $43.1; and increased pre-tax other comprehensive income by $3.6. The Pension Plan, and the other U.S. pension plan that existed prior to the Utilities Pension Plan Merger, are hereafter referred to as the “U.S. Pension Plans.”
F-26
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the U.S. Pension PlansPlan and the Antargaz pension plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 20112012 and 2010.2011. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation.
| | | | | | | | | | | | | | | | |
| | Pension | | | Other Postretirement | |
| | Benefits | | | Benefits | |
| | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Change in benefit obligations: | | | | | | | | | | | | | | | | |
Benefit obligations — beginning of year | | $ | 471.8 | | | $ | 428.9 | | | $ | 22.9 | | | $ | 21.4 | |
Service cost | | | 8.8 | | | | 8.7 | | | | 0.4 | | | | 0.4 | |
Interest cost | | | 24.1 | | | | 23.5 | | | | 1.1 | | | | 1.1 | |
Actuarial (gain) loss | | | (22.0 | ) | | | 32.2 | | | | (2.4 | ) | | | 1.6 | |
Plan amendments | | | — | | | | — | | | | (0.1 | ) | | | — | |
Plan settlements | | | — | | | | (2.7 | ) | | | — | | | | — | |
Foreign currency | | | (0.1 | ) | | | (0.5 | ) | | | — | | | | (0.2 | ) |
Benefits paid | | | (19.7 | ) | | | (18.3 | ) | | | (1.4 | ) | | | (1.4 | ) |
| | | | | | | | | | | | |
Benefit obligations — end of year | | $ | 462.9 | | | $ | 471.8 | | | $ | 20.5 | | | $ | 22.9 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Change in plan assets: | | | | | | | | | | | | | | | | |
Fair value of plan assets — beginning of year | | $ | 287.9 | | | $ | 279.8 | | | $ | 10.0 | | | $ | 9.7 | |
Actual gain on plan assets | | | 2.6 | | | | 25.9 | | | | 0.1 | | | | 0.7 | |
Foreign currency | | | — | | | | (0.2 | ) | | | — | | | | — | |
Employer contributions | | | 19.2 | | | | 3.4 | | | | 1.1 | | | | 1.0 | |
Settlement payments | | | — | | | | (2.7 | ) | | | — | | | | — | |
Benefits paid | | | (19.7 | ) | | | (18.3 | ) | | | (1.4 | ) | | | (1.4 | ) |
| | | | | | | | | | | | |
Fair value of plan assets — end of year | | $ | 290.0 | | | $ | 287.9 | | | $ | 9.8 | | | $ | 10.0 | |
| | | | | | | | | | | | |
Funded status of the plans — end of year | | $ | (172.9 | ) | | $ | (183.9 | ) | | $ | (10.7 | ) | | $ | (12.9 | ) |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
(Liabilities) recorded in the balance sheet: | | | | | | | | | | | | | | | | |
Unfunded liabilities — included in other current liabilities | | $ | (27.6 | ) | | $ | (20.3 | ) | | $ | — | | | $ | — | |
Unfunded liabilities — included in other noncurrent liabilities | | | (145.3 | ) | | | (163.6 | ) | | | (10.7 | ) | | | (12.9 | ) |
| | | | | | | | | | | | |
Net amount recognized | | $ | (172.9 | ) | | $ | (183.9 | ) | | $ | (10.7 | ) | | $ | (12.9 | ) |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): | | | | | | | | | | | | | | | | |
Prior service (credit) cost | | $ | (0.2 | ) | | $ | (0.4 | ) | | $ | (0.1 | ) | | $ | 0.1 | |
Net actuarial loss (gain) | | | 13.6 | | | | 13.8 | | | | (0.8 | ) | | | 0.1 | |
| | | | | | | | | | | | |
Total | | $ | 13.4 | | | $ | 13.4 | | | $ | (0.9 | ) | | $ | 0.2 | |
| | | | | | | | | | | | |
Amounts recorded in regulatory assets and liabilities (pre-tax): | | | | | | | | | | | | | | | | |
Prior service cost (credit) | | $ | 1.8 | | | $ | 0.3 | | | $ | (3.2 | ) | | $ | (3.4 | ) |
Net actuarial loss | | | 146.9 | | | | 155.6 | | | | 6.3 | | | | 5.9 | |
| | | | | | | | | | | | |
Total | | $ | 148.7 | | | $ | 155.9 | | | $ | 3.1 | | | $ | 2.5 | |
| | | | | | | | | | | | |
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
|
| | | | | | | | | | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
| 2012 | | 2011 | | 2012 | | 2011 |
Change in benefit obligations: | | | | | | | |
Benefit obligations — beginning of year | $ | 462.9 |
| | $ | 471.8 |
| | $ | 20.5 |
| | $ | 22.9 |
|
Service cost | 9.3 |
| | 8.8 |
| | 0.4 |
| | 0.4 |
|
Interest cost | 25.1 |
| | 24.1 |
| | 1.1 |
| | 1.1 |
|
Actuarial loss (gain) | 82.4 |
| | (22.0 | ) | | 3.2 |
| | (2.4 | ) |
Plan amendments | 0.1 |
| | — |
| | 1.0 |
| | (0.1 | ) |
Acquisitions | 14.6 |
| | — |
| | — |
| | — |
|
Foreign currency | (0.7 | ) | | (0.1 | ) | | (0.1 | ) | | — |
|
Benefits paid | (20.3 | ) | | (19.7 | ) | | (1.4 | ) | | (1.4 | ) |
Benefit obligations — end of year | $ | 573.4 |
| | $ | 462.9 |
| | $ | 24.7 |
| | $ | 20.5 |
|
| | | | | | | |
Change in plan assets: | | | | | | | |
Fair value of plan assets — beginning of year | $ | 290.0 |
| | $ | 287.9 |
| | $ | 9.8 |
| | $ | 10.0 |
|
Actual gain on plan assets | 51.2 |
| | 2.6 |
| | 1.7 |
| | 0.1 |
|
Foreign currency | (0.5 | ) | | — |
| | — |
| | — |
|
Employer contributions | 32.2 |
| | 19.2 |
| | 1.1 |
| | 1.1 |
|
Acquisitions | 17.3 |
| | — |
| | — |
| | — |
|
Benefits paid | (20.3 | ) | | (19.7 | ) | | (1.4 | ) | | (1.4 | ) |
Fair value of plan assets — end of year | $ | 369.9 |
| | $ | 290.0 |
| | $ | 11.2 |
| | $ | 9.8 |
|
Funded status of the plans — end of year | $ | (203.5 | ) | | $ | (172.9 | ) | | $ | (13.5 | ) | | $ | (10.7 | ) |
| | | | | | | |
(Liabilities) recorded in the balance sheet: | | | | | | | |
Unfunded liabilities — included in other current liabilities | $ | (15.8 | ) | | $ | (27.6 | ) | | $ | (0.6 | ) | | $ | (0.6 | ) |
Unfunded liabilities — included in other noncurrent liabilities | (187.7 | ) | | (145.3 | ) | | (12.9 | ) | | (10.1 | ) |
Net amount recognized | $ | (203.5 | ) | | $ | (172.9 | ) | | $ | (13.5 | ) | | $ | (10.7 | ) |
| | | | | | | |
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): | | | | | | | |
Prior service credit | $ | (0.1 | ) | | $ | (0.2 | ) | | $ | (0.1 | ) | | $ | (0.1 | ) |
Net actuarial loss (gain) | 25.3 |
| | 13.6 |
| | 0.4 |
| | (0.8 | ) |
Total | $ | 25.2 |
| | $ | 13.4 |
| | $ | 0.3 |
| | $ | (0.9 | ) |
| | | | | | | |
Amounts recorded in regulatory assets and liabilities (pre-tax): | | | | | | | |
Prior service cost (credit) | $ | 1.5 |
| | $ | 1.8 |
| | $ | (2.8 | ) | | $ | (3.2 | ) |
Net actuarial loss | 184.5 |
| | 146.9 |
| | 5.8 |
| | 6.3 |
|
Total | $ | 186.0 |
| | $ | 148.7 |
| | $ | 3.0 |
| | $ | 3.1 |
|
In Fiscal 2012,2013, we estimate that we will amortize approximately $8.8$15.4 of net actuarial losses and $0.2$(0.1) of prior service credits from UGI stockholders’ equity and regulatory assets into retiree benefit cost.
F-27
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Actuarial assumptions for our domestic plans are described below. Assumptions for the Antargaz plans are based upon market conditions in France. The discount rates at September 30 are used to measure the year-end benefit obligations and the earnings effects for the subsequent year. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the plans’ benefit
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
payments. The expected rate of return on assets assumption is based on the current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plans | | | Other Postretirement Benefits | |
| | 2011(a) | | | 2010 | | | 2009 | | | 2008 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
Weighted-average assumptions: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Discount rate | | | 5.3 | % | | | 5.0 | % | | | 5.5 | % | | | 6.8 | % | | | 5.3 | % | | | 5.0 | % | | | 5.5 | % | | | 6.8 | % |
Expected return on plan assets | | | 8.0 | % | | | 8.5 | % | | | 8.5 | % | | | 8.5 | % | | | 5.5 | % | | | 5.5 | % | | | 5.5 | % | | | 5.5 | % |
Rate of increase in salary levels | | | 3.5 | % | | | 3.8 | % | | | 3.8 | % | | | 3.8 | % | | | 3.5 | % | | | 3.8 | % | | | 3.8 | % | | | 3.8 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Plan | | Other Postretirement Benefits |
| 2012 | | 2011 (a) | | 2010 | | 2009 | | 2012 | | 2011 | | 2010 | | 2009 |
Weighted-average assumptions: | | | | | | | | | | | | | | | |
Discount rate | 4.20 | % | | 5.30 | % | | 5.00 | % | | 5.50 | % | | 4.20 | % | | 5.30 | % | | 5.00 | % | | 5.50 | % |
Expected return on plan assets | 7.75 | % | | 8.00 | % | | 8.50 | % | | 8.50 | % | | 5.20 | % | | 5.50 | % | | 5.50 | % | | 5.50 | % |
Rate of increase in salary levels | 3.25 | % | | 3.50 | % | | 3.75 | % | | 3.75 | % | | 3.25 | % | | 3.50 | % | | 3.75 | % | | 3.75 | % |
______________
| | |
(a) | | The discount raterates used during Fiscal 2011 to calculate pension expense was a ratewere rates of 5.0% through December 31, 2010 (the date of the Utilities PlanU.S. Pension Plans Merger) and 5.5% for the remainder of Fiscal 2011. |
The ABOABOs for the U. S.U.S. Pension Plans was $415.0Plan were $496.4 and $417.8$415.0 as of September 30, 20112012 and 2010,2011, respectively.
Net periodic pension expense and other postretirement benefit costs includecost includes the following components:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | | Other Postretirement Benefits | |
| | 2011 | | | 2010 | | | 2009 | | | 2011 | | | 2010 | | | 2009 | |
Service cost | | $ | 8.8 | | | $ | 8.7 | | | $ | 7.1 | | | $ | 0.4 | | | $ | 0.4 | | | $ | 0.3 | |
Interest cost | | | 24.1 | | | | 23.5 | | | | 23.3 | | | | 1.1 | | | | 1.1 | | | | 1.2 | |
Expected return on assets | | | (25.8 | ) | | | (25.8 | ) | | | (25.7 | ) | | | (0.5 | ) | | | (0.5 | ) | | | (0.6 | ) |
Curtailment gain | | | — | | | | — | | | | — | | | | (3.2 | ) | | | — | | | | — | |
Settlement loss | | | — | | | | 1.0 | | | | 1.8 | | | | — | | | | — | | | | — | |
Amortization of: | | | | | | | | | | | | | | | | | | | | | | | | |
Transition obligation | | | — | | | | — | | | | — | | | | — | | | | — | | | | 0.2 | |
Prior service cost (benefit) | | | 0.2 | | | | — | | | | — | | | | (0.7 | ) | | | (0.4 | ) | | | (0.4 | ) |
Actuarial loss (gain) | | | 7.5 | | | | 5.9 | | | | 3.8 | | | | 0.4 | | | | 0.1 | | | | (0.1 | ) |
| | | | | | | | | | | | | | | | | | |
Net benefit cost (income) | | | 14.8 | | | | 13.3 | | | | 10.3 | | | | (2.5 | ) | | | 0.7 | | | | 0.6 | |
Change in associated regulatory liabilities | | | — | | | | — | | | | — | | | | 3.1 | | | | 3.1 | | | | 3.3 | |
| | | | | | | | | | | | | | | | | | |
Net benefit cost after change in regulatory liabilities | | $ | 14.8 | | | $ | 13.3 | | | $ | 10.3 | | | $ | 0.6 | | | $ | 3.8 | | | $ | 3.9 | |
| | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
| 2012 | | 2011 | | 2010 | | 2012 | | 2011 | | 2010 |
Service cost | $ | 9.3 |
| | $ | 8.8 |
| | $ | 8.7 |
| | $ | 0.4 |
| | $ | 0.4 |
| | $ | 0.4 |
|
Interest cost | 25.1 |
| | 24.1 |
| | 23.5 |
| | 1.1 |
| | 1.1 |
| | 1.1 |
|
Expected return on assets | (26.2 | ) | | (25.8 | ) | | (25.8 | ) | | (0.5 | ) | | (0.5 | ) | | (0.5 | ) |
Curtailment gain | — |
| | — |
| | — |
| | — |
| | (3.2 | ) | | — |
|
Settlement loss | — |
| | — |
| | 1.0 |
| | — |
| | — |
| | — |
|
Amortization of: | | | | | | | | | | | |
Prior service cost (benefit) | 0.2 |
| | 0.2 |
| | — |
| | (0.3 | ) | | (0.7 | ) | | (0.4 | ) |
Actuarial loss | 8.4 |
| | 7.5 |
| | 5.9 |
| | 0.3 |
| | 0.4 |
| | 0.1 |
|
Net benefit cost (income) | 16.8 |
| | 14.8 |
| | 13.3 |
| | 1.0 |
| | (2.5 | ) | | 0.7 |
|
Change in associated regulatory liabilities | — |
| | — |
| | — |
| | 3.2 |
| | 3.1 |
| | 3.1 |
|
Net benefit cost after change in regulatory liabilities | $ | 16.8 |
| | $ | 14.8 |
| | $ | 13.3 |
| | $ | 4.2 |
| | $ | 0.6 |
| | $ | 3.8 |
|
U.S. Pension Plans’Plan's assets are held in trust. It is our general policy to fund amounts for pensionU.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2012, Fiscal 2011 and Fiscal 2010, we made cash contributions to the U.S. Pension PlansPlan of $18.7$31.2, $18.7 and $3.4,$3.4, respectively. We did not make any contributions to the U.S. Pension Plans in Fiscal 2009. In conjunction with the settlement of obligations under a subsidiary retirement benefit plan, Antargaz made a settlement payment of €4.1 ($5.7) during Fiscal 2009. We believe that in Fiscal 20122013 we will be required to make contributions to the U.S. Pension PlansPlan totaling approximately $27.6.$16.
UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under GAAP. The difference between such amounts and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. The required contributions to the VEBA during Fiscal 20122013 are not expected to be material.
F-28
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Expected payments for pension benefits and for other postretirement welfare benefits are as follows:
| | | | | | | | |
| | | | | | Other | |
| | Pension | | | Postretirement | |
| | Benefits | | | Benefits | |
Fiscal 2012 | | $ | 20.7 | | | $ | 2.0 | |
Fiscal 2013 | | | 21.7 | | | | 2.0 | |
Fiscal 2014 | | | 23.0 | | | | 2.0 | |
Fiscal 2015 | | | 24.3 | | | | 2.0 | |
Fiscal 2016 | | | 26.0 | | | | 2.0 | |
Fiscal 2017 - 2021 | | | 148.5 | | | | 9.9 | |
|
| | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
Fiscal 2013 | $ | 22.3 |
| | $ | 1.9 |
|
Fiscal 2014 | 23.3 |
| | 1.9 |
|
Fiscal 2015 | 24.6 |
| | 1.9 |
|
Fiscal 2016 | 27.4 |
| | 1.9 |
|
Fiscal 2017 | 28.0 |
| | 1.8 |
|
Fiscal 2018 - 2022 | 158.0 |
| | 8.7 |
|
The assumed domestic health care cost trend rates are 7.5%7.0% for Fiscal 2012,2013, decreasing to 5.0% in Fiscal 2017. A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 20112012 other postretirement benefit cost or September 30, 20112012, other postretirement benefit ABO.
We also sponsor unfunded and non-qualified supplemental executive retirement plans. At September 30, 20112012 and 2010,2011, the PBOs of these plans were $25.6$29.5 and $23.9,$25.6, respectively. We recorded net costs for these plans of $3.0$3.0 in Fiscal 2011, $2.62012, $3.0 in Fiscal 20102011 and $3.1$2.6 in Fiscal 2009.2010. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $7.6$11.0 and $4.7$7.6 at September 30, 20112012 and 2010,2011, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.7$0.7 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2012.2013.
U.S. Pension PlansPlan and VEBA Assets.The assets of the U.S. Pension PlansPlan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the U.S. Pension PlansPlan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly-traded diversified equity and fixed income mutual funds and UGI Common Stock.
F-29
The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows:
U.S. Pension Plan
|
| | | | | | | | | | |
| Actual | | Target Asset Allocation | | Permitted Range |
| 2012 | | 2011 | | |
Equity investments: | | | | | | | |
Domestic | 53.5 | % | | 49.4 | % | | 52.5 | % | | 40.0% - 65.0% |
International | 10.5 | % | | 10.7 | % | | 12.5 | % | | 7.5% - 17.5% |
Total | 64.0 | % | | 60.1 | % | | 65.0 | % | | 60.0% - 70.0% |
Fixed income funds & cash equivalents | 36.0 | % | | 39.9 | % | | 35.0 | % | | 30.0% - 40.0% |
Total | 100.0 | % | | 100.0 | % | | 100.0 | % | | |
VEBA
|
| | | | | | | | | | |
| Actual | | Target Asset Allocation | | Permitted Range |
| 2012 | | 2011 | | |
Domestic equity investments | 68.5 | % | | 62.2 | % | | 65.0 | % | | 60.0% - 70.0% |
Fixed income funds & cash equivalents | 31.5 | % | | 37.8 | % | | 35.0 | % | | 30.0% - 40.0% |
Total | 100.0 | % | | 100.0 | % | | 100.0 | % | | |
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The targets, target ranges and actual allocations for the U.S. Pension Plans’ and VEBA trust assets at September 30 are as follows:
U.S. Pension Plans
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Target | | | | |
| | Actual | | | Asset | | | Permitted | |
| | 2011 | | | 2010 | | | Allocation | | | Range | |
Equity investments: | | | | | | | | | | | | | | | | |
Domestic | | | 49.4 | % | | | 56.1 | % | | | 52.5 | % | | | 40.0% - 65.0 | % |
International | | | 10.7 | % | | | 12.2 | % | | | 12.5 | % | | | 7.5% - 17.5 | % |
| | | | | | | | | | | | | |
Total | | | 60.1 | % | | | 68.3 | % | | | 65.0 | % | | | 60.0% - 70.0 | % |
Fixed income funds & cash equivalents | | | 39.9 | % | | | 31.7 | % | | | 35.0 | % | | | 30.0% - 40.0 | % |
| | | | | | | | | | | | | |
Total | | | 100.0 | % | | | 100.0 | % | | | 100.0 | % | | | | |
| | | | | | | | | | | | | |
VEBA
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Target | | | | |
| | Actual | | | Asset | | | Permitted | |
| | 2011 | | | 2010 | | | Allocation | | | Range | |
| | | | | | | | | | | | | | | | |
Domestic equity investments | | | 62.2 | % | | | 65.0 | % | | | 65.0 | % | | | 60.0% - 70.0 | % |
|
Fixed income funds & cash equivalents | | | 37.8 | % | | | 35.0 | % | | | 35.0 | % | | | 30.0% - 40.0 | % |
| | | | | | | | | | | | | |
Total | | | 100.0 | % | | | 100.0 | % | | | 100.0 | % | | | | |
| | | | | | | | | | | | | |
Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds. Investments in international equity mutual funds are indexed to various Morgan Stanley Composite indices. The fixed income investments comprise investments designed to match the duration of the Barclays Capital Aggregate Bond Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 7.6%7.5% and 8.3%7.6% of U.S. Pension PlansPlan assets at September 30, 20112012 and 2010,2011, respectively. At September 30, 2011,2012, there were no significant concentrations of risk (defined as greater than 10% of the fair value of total assets) associated with any individual company, industry sector or international geographic region.
GAAP establishes a hierarchy that prioritizes fair value measurements based upon the inputs and valuation techniques used to measure fair value. This fair value hierarchy groups assets into three levels, as described in Note 2. We maximize the use of observable inputs and minimize the use of unobservable inputs when determining fair value. The fair values of U.S. Pension PlansPlan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee.
F-30
The fair values of the U.S. Pension Plan and VEBA trust assets at September 30, 2012 and 2011, by asset class are as follows:
|
| | | | | | | | | | | | | | | |
| U.S. Pension Plan |
| Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Unobservable Inputs (Level 3) | | Total |
September 30, 2012: | | | | | | | |
Equity investments: | | | | | | | |
Domestic | $ | 188.2 |
| | $ | — |
| | $ | — |
| | $ | 188.2 |
|
International | 36.9 |
| | — |
| | — |
| | 36.9 |
|
Fixed income | 123.3 |
| | — |
| | — |
| | 123.3 |
|
Cash equivalents | — |
| | 3.1 |
| | — |
| | 3.1 |
|
Total | $ | 348.4 |
| | $ | 3.1 |
| | $ | — |
| | $ | 351.5 |
|
| | | | | | | |
September 30, 2011: | | | | | | | |
Equity investments: | | | | | | | |
Domestic | $ | 143.1 |
| | $ | — |
| | $ | — |
| | $ | 143.1 |
|
International | 31.0 |
| | — |
| | — |
| | 31.0 |
|
Fixed income | 113.6 |
| | — |
| | — |
| | 113.6 |
|
Cash equivalents | — |
| | 2.0 |
| | — |
| | 2.0 |
|
Total | $ | 287.7 |
| | $ | 2.0 |
| | $ | — |
| | $ | 289.7 |
|
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The fair values of the U.S. Pension Plans’ and VEBA trust assets at September 30, 2011 and 2010 by asset class are as follows: | | | | | | | | | | | | | | | | | |
| | Pension Plans | | | | | | | | | | |
| | Quoted Prices | | | | | | | | VEBA |
| | in Active | | Significant | | | | | | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Unobservable Inputs (Level 3) | | Total |
| | Markets for | | Other | | | | | | |
| | Identical Assets | | Observable | | Unobservable | | | | |
| | and Liabilities | | Inputs | | Inputs | | | | |
September 30, 2012: | | | | | | | | |
Domestic equity | | $ | 7.7 |
| | $ | — |
| | $ | — |
| | $ | 7.7 |
|
Fixed income | | 3.4 |
| | — |
| | — |
| | 3.4 |
|
Cash equivalents | | — |
| | 0.1 |
| | — |
| | 0.1 |
|
Total | | $ | 11.1 |
| | $ | 0.1 |
| | $ | — |
| | $ | 11.2 |
|
| | (Level 1) | | (Level 2) | | (Level 3) | | Total | | | | | | | | |
September 30, 2011: | | | | | | | | |
Equity investments: | | |
Domestic | | $ | 143.1 | | $ | — | | $ | — | | $ | 143.1 | | |
International | | 31.0 | | — | | — | | 31.0 | | |
Domestic equity | | $ | 6.1 |
| | $ | — |
| | $ | — |
| | $ | 6.1 |
|
Fixed income | | 113.6 | | — | | — | | 113.6 | | 3.3 |
| | — |
| | — |
| | 3.3 |
|
Cash equivalents | | — | | 2.0 | | — | | 2.0 | | — |
| | 0.4 |
| | — |
| | 0.4 |
|
| | | | | | | | | | |
Total | | $ | 287.7 | | $ | 2.0 | | $ | — | | $ | 289.7 | | $ | 9.4 |
| | $ | 0.4 |
| | $ | — |
| | $ | 9.8 |
|
| | | | | | | | | | |
| | |
September 30, 2010: | | |
Equity investments: | | |
Domestic | | $ | 161.5 | | $ | — | | $ | — | | $ | 161.5 | | |
International | | 35.2 | | — | | — | | 35.2 | | |
Fixed income | | 88.9 | | — | | — | | 88.9 | | |
Cash equivalents | | — | | 2.3 | | — | | 2.3 | | |
| | | | | | | | | | |
Total | | $ | 285.6 | | $ | 2.3 | | $ | — | | $ | 287.9 | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | VEBA | |
| | Quoted Prices | | | | | | | | | | |
| | in Active | | | Significant | | | | | | | |
| | Markets for | | | Other | | | | | | | |
| | Identical Assets | | | Observable | | | Unobservable | | | | |
| | and Liabilities | | | Inputs | | | Inputs | | | | |
| | (Level 1) | | | (Level 2) | | | (Level 3) | | | Total | |
September 30, 2011: | | | | | | | | | | | | | | | | |
Domestic equity | | $ | 6.1 | | | $ | — | | | $ | — | | | $ | 6.1 | |
Fixed income | | | 3.3 | | | | — | | | | — | | | | 3.3 | |
Cash equivalents | | | — | | | | 0.4 | | | | — | | | | 0.4 | |
| | | | | | | | | | | | |
Total | | $ | 9.4 | | | $ | 0.4 | | | $ | — | | | $ | 9.8 | |
| | | | | | | | | | | | |
|
September 30, 2010: | | | | | | | | | | | | | | | | |
Domestic equity | | $ | 6.5 | | | $ | — | | | $ | — | | | $ | 6.5 | |
Fixed income | | | 3.0 | | | | — | | | | — | | | | 3.0 | |
Cash equivalents | | | — | | | | 0.5 | | | | — | | | | 0.5 | |
| | | | | | | | | | | | |
Total | | $ | 9.5 | | | $ | 0.5 | | | $ | — | | | $ | 10.0 | |
| | | | | | | | | | | | |
The expected long-term rates of return on U.S. Pension Plans’Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.
F-31
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Defined Contribution Plans.We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans totaled $10.4$13.7 in Fiscal 2011, $9.82012, $10.4 in Fiscal 20102011 and $10.1$9.8 in Fiscal 2009.2010.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters
The following regulatory assets and liabilities associated with Utilities are included in our accompanying balance sheets at September 30:
| | | | | | | | |
| | 2011 | | | 2010 | |
Regulatory assets: | | | | | | | | |
Income taxes recoverable | | $ | 97.9 | | | $ | 82.5 | |
Underfunded pension and postretirement plans | | | 150.7 | | | | 159.2 | |
Environmental costs | | | 19.5 | | | | 22.6 | |
Deferred fuel and power costs | | | 12.2 | | | | 36.6 | |
Removal costs, net | | | 12.3 | | | | 13.0 | |
Other | | | 7.8 | | | | 5.8 | |
| | | | | | |
Total regulatory assets | | $ | 300.4 | | | $ | 319.7 | |
| | | | | | |
| | | | | | | | |
Regulatory liabilities: | | | | | | | | |
Postretirement benefits | | $ | 11.5 | | | $ | 10.5 | |
Environmental overcollections | | | 4.7 | | | | 7.2 | |
Deferred fuel and power refunds | | | 6.6 | | | | 8.3 | |
State tax benefits — distribution system repairs | | | 6.3 | | | | 6.7 | |
Other | | | 0.7 | | | | — | |
| | | | | | |
Total regulatory liabilities | | $ | 29.8 | | | $ | 32.7 | |
| | | | | | |
|
| | | | | | | |
| 2012 | | 2011 |
Regulatory assets: | | | |
Income taxes recoverable | $ | 103.2 |
| | $ | 97.9 |
|
Underfunded pension and postretirement plans | 188.2 |
| | 150.7 |
|
Environmental costs | 16.8 |
| | 19.5 |
|
Deferred fuel and power costs | 11.6 |
| | 12.2 |
|
Removal costs, net | 12.7 |
| | 12.3 |
|
Other | 5.9 |
| | 7.8 |
|
Total regulatory assets | $ | 338.4 |
| | $ | 300.4 |
|
| | | |
Regulatory liabilities: | | | |
Postretirement benefits | $ | 13.1 |
| | $ | 11.5 |
|
Environmental overcollections | 2.9 |
| | 4.7 |
|
Deferred fuel and power refunds | 4.4 |
| | 6.6 |
|
State tax benefits — distribution system repairs | 7.4 |
| | 6.3 |
|
Other | 0.5 |
| | 0.7 |
|
Total regulatory liabilities | $ | 28.3 |
| | $ | 29.8 |
|
Income taxes recoverable.This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 50 years.
Underfunded pension and other postretirement plans.This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and other postretirement benefits which isare probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants.
Environmental costs.Environmental costs representsrepresent amounts actually spent by UGI Gas to clean up sites in Pennsylvania as well as the portion of estimated probable future environmental remediation and investigation costs principally at manufactured gas plant (“MGP”) sites that CPG Gas and PNG Gas expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 15). UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites. PNG Gas and CPG Gas are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2011,2012, the period over which PNG Gas and CPG Gas expect to recover these costs will depend upon future remediation activity.
F-32
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Deferred fuel and power — costs and refunds.Gas Utility’s tariffs and, commencing January 1, 2010, Electric Utility’s default service (“DS”) tariffs (as further described below under “Electric Utility DS Rates”), contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and DS rates in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.
Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm-residential,firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
financial instruments are included in deferred fuel costs or refunds. Net unrealized lossesgains (losses) on such contracts at September 30, 20112012 and 20102011 were $3.1$5.3 and $1.4,$(3.1), respectively.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities. At September 30, 20112012 and 2010,2011, the fair values of Electric Utility’s electricity supply contracts were losses of $8.7$9.2 and $19.7,$8.7, respectively, which amounts are reflected in current derivative financial instruments and other noncurrent liabilities on the Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.
In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power costs or deferred fuel and power refunds. At September 30, 20112012 and 2010,2011, such gains or losses were not material.
Removal costs, net.This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. At September 30, 2011,2012, UGI Utilities expects to recover these costs over periods of 1 to 5 years.years.
Postretirement benefits.Gas Utility and Electric Utility are recovering ongoing postretirement benefit costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI Gas and Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above.
Environmental overcollections.This regulatory liability represents the difference between amounts recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms of a consent order agreement between CPG and the Pennsylvania Department of Environmental Protection to remediate certain gas plant sites.
State income tax benefits — distribution system repairs.As previously described in Note 6, the Company received IRS consent to change its tax method of accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of these repair and maintenance expensescosts associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.
Other.Other regulatory assets comprise a number of items including, among others, deferred postretirement costs, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2011,2012, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.years.
UGI Utilities’ regulatory liabilities relating to postretirement benefits, environmental overcollections and state tax benefits — distribution system repairs are included in “Otherother noncurrent liabilities”liabilities on the Consolidated Balance Sheets. UGI Utilities does not recover a rate of return on its regulatory assets.
F-33
Other Regulatory Matters
Distribution System Improvement Charge Legislation. On April 14, 2012, legislation enabling gas and electric utilities in Pennsylvania to seek surcharge recovery of eligible capital investment in distribution system infrastructure improvement projects became effective. The surcharge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC surcharge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures, for up to five percent of distribution rates. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff. Filings to implement a DSIC surcharge may be filed no earlier than January 2, 2013.
Allentown, Pennsylvania Natural Gas Incident. On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Other Regulatory MattersEnforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff's formal complaint, issued on June 11, 2012 ("PUC Staff Complaint)", pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage (the “Incident”). The PUC Staff Complaint had alleged that UGI Utilities had committed six violations of gas safety regulations and UGI Utilities' operating procedures related to its cast iron main replacement and gas odorant monitoring programs, and its emergency response to the Incident. As part of the Joint Settlement, UGI Utilities has agreed (i) to the assessment of a $0.4 civil penalty; (ii) to accelerate the time frame for UGI Utilities, CPG, and PNG to replace the remainder of its cast iron mains to 14 years, and (iii) to install odorant monitoring and injection equipment in its natural gas system at a number of supply points, but does not concede to having violated any regulation or operating procedure. Under the Joint Settlement, UGI Utilities, CPG and PNG have also agreed to not seek recovery of the related annual cost of capital return requirements through a DSIC for a period of 24 months but are permitted to retain the current 30-year timeframe for replacing the remainder of their bare steel mains. On October 31, 2012, the PUC administrative law judge issued an initial decision approving the settlement. The provisions of the Joint Settlement will become effective if the initial decision becomes final or if the PUC determines to review the initial decision and issues a final order approving the terms and conditions of the Joint Settlement without modification. The Company does not believe that the cost of complying with the requirements of the Joint Settlement will have a material impact on UGI Utilities' consolidated financial position, results of operations or cash flows.
PNG and CPG Base Rate Filings.Filing. On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5$16.5 annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. On August 11, 2011, the PUC approved the settlement agreement which resulted in an increase in annual base rate revenues of $8.0$8.0 as well as $0.9$0.9 in revenues per year for use in CPG’s Energy and Efficiency Conservation Program. The increase became effective August 30, 2011 and did not have a material effect on2011. During Fiscal 2011 results.
On January 28, 2009, PNG and CPG filed separate requests2012, the PUC reversed its earlier decision related to the $0.9 increase in revenue associated with the PUC to increase base operating revenues by $38.1 annually for PNGEnergy and $19.6 annually forEfficiency Conservation Program and required CPG to fund system improvements and operations necessary to maintain safe and reliable natural gas service and energy assistancerefund revenue it had collected 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 increase in annual base operating revenue for PNG Gas and a $10.0 increase in annual base operating revenue for CPG Gas. The increases became effective August 28, 2009 and did not have a material effect on Fiscal 2009 results.that program.
Electric Utility DS Rates.Rates. Beginning January 1, 2010, Electric Utility operates under a DS rate mechanism approved by the PUC that allows for full recovery of all DS costs incurred on and after January 1, 2010. Prior to January 1, 2010, the terms and conditions under which Electric Utility provided provider of last resort (“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.. In accordance with the POLR Settlement, Electric Utility could increase its POLR rates up to certain limits through December 31, 2009. Beginning January 1, 2010, Electric Utility operates under a DS rate mechanism approved by the PUC that allows for full recovery of all DS costs incurred on and after January 1, 2010.
Transfers of Assets.On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011, the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9.$10.9. Compliance with the provisions of the PUC Order approving the transfer of the storage assets isdid not expected to have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-yearone-year firm storage service agreement with UGI Storage Company.
On December 1, 2010, PNG filed an application with the PUC for expedited review and approval of the transfer of a 9.0 mile9-mile natural gas pipeline, related facilities, and right of way located in Mehoopany, Pennsylvania (the “Auburn Line”) to Energy Services. The PUC approved the transfer and in September 2011 the Auburn Line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the Auburn Line was $1.1.$1.1.
Note 9 — Inventories
Inventories comprise the following at September 30:
| | | | | | | | |
| | 2011 | | | 2010 | |
Non-utility LPG and natural gas | | $ | 222.2 | | | $ | 157.9 | |
Gas Utility natural gas | | | 95.6 | | | | 111.5 | |
Materials, supplies and other | | | 45.2 | | | | 44.6 | |
| | | | | | |
Total inventories | | $ | 363.0 | | | $ | 314.0 | |
| | | | | | |
F-34
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 9 — Inventories
Inventories comprise the following at September 30:
|
| | | | | | | |
| 2012 | | 2011 |
Non-utility LPG and natural gas | $ | 240.7 |
| | $ | 222.2 |
|
Gas Utility natural gas | 57.7 |
| | 95.6 |
|
Materials, supplies and other | 58.5 |
| | 45.2 |
|
Total inventories | $ | 356.9 |
| | $ | 363.0 |
|
At September 30, 2011,2012, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013. Pursuant to these and predecessor SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above. The carrying values of gas storage inventories released under the SCAAs to non-affiliates at September 30, 20112012 and 20102011 comprising 3.93.8 billion cubic feet (“bcf”) and 8.03.9 bcf of natural gas was $19.0$11.4 and $41.9,$19.0, respectively. Effective November 1, 2012, UGI Utilities entered into two new SCAAs having terms of three years.
Note 10 — Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:
| | | | | | | | |
| | 2011 | | | 2010 | |
Utilities: | | | | | | | | |
Distribution | | $ | 1,951.9 | | | $ | 1,866.0 | |
Transmission | | | 83.4 | | | | 78.2 | |
General and other, including work in process | | | 165.7 | | | | 185.1 | |
| | | | | | |
Total Utilities | | | 2,201.0 | | | | 2,129.3 | |
| | | | | | |
|
Non-utility: | | | | | | | | |
Land | | | 98.5 | | | | 94.1 | |
Buildings and improvements | | | 214.8 | | | | 206.4 | |
Transportation equipment | | | 112.6 | | | | 111.3 | |
Equipment, primarily cylinders and tanks | | | 2,127.6 | | | | 2,020.3 | |
Electric generation | | | 230.0 | | | | 97.9 | |
Other, including work in process | | | 300.0 | | | | 310.4 | |
| | | | | | |
Total non-utility | | | 3,083.5 | | | | 2,840.4 | |
| | | | | | |
Total property, plant and equipment | | $ | 5,284.5 | | | $ | 4,969.7 | |
| | | | | | |
|
| | | | | | | |
| 2012 | | 2011 |
Utilities: | | | |
Distribution | $ | 2,047.8 |
| | $ | 1,951.9 |
|
Transmission | 85.4 |
| | 83.4 |
|
General and other, including work in process | 162.5 |
| | 165.7 |
|
Total Utilities | 2,295.7 |
| | 2,201.0 |
|
| | | |
Non-utility: | | | |
Land | 175.0 |
| | 98.5 |
|
Buildings and improvements | 283.3 |
| | 214.8 |
|
Transportation equipment | 246.5 |
| | 112.6 |
|
Equipment, primarily cylinders and tanks | 3,041.1 |
| | 2,127.6 |
|
Electric generation | 254.3 |
| | 230.0 |
|
Other, including work in process | 223.2 |
| | 300.0 |
|
Total non-utility | 4,223.4 |
| | 3,083.5 |
|
Total property, plant and equipment | $ | 6,519.1 |
| | $ | 5,284.5 |
|
Note 11 — Goodwill and Intangible Assets
Goodwill and other intangible assets comprise the following at September 30:
| | | | | | | | |
| | 2011 | | | 2010 | |
Goodwill (not subject to amortization) | | $ | 1,562.2 | | | $ | 1,562.7 | |
| | | | | | |
|
Other intangible assets: | | | | | | | | |
Customer relationships, noncompete agreements and other | | $ | 232.1 | | | $ | 215.4 | |
Trademark (not subject to amortization) | | | 47.9 | | | | 46.3 | |
| | | | | | |
Gross carrying amount | | | 280.0 | | | | 261.7 | |
Accumulated amortization | | | (132.2 | ) | | | (111.6 | ) |
| | | | | | |
Net carrying amount | | $ | 147.8 | | | $ | 150.1 | |
| | | | | | |
F-35
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
|
| | | | | | | |
| 2012 | | 2011 |
Goodwill (not subject to amortization) | $ | 2,818.3 |
| | $ | 1,562.2 |
|
Intangible assets: | | | |
Customer relationships, noncompete agreements and other | $ | 691.9 |
| | $ | 232.1 |
|
Trademarks and tradenames (not subject to amortization) | 137.2 |
| | 47.9 |
|
Gross carrying amount | 829.1 |
| | 280.0 |
|
Accumulated amortization | (170.9 | ) | | (132.2 | ) |
Intangible assets, net | $ | 658.2 |
| | $ | 147.8 |
|
Changes in the carrying amount of goodwill are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | AmeriGas | | | Gas | | | Midstream & | | | International Propane | | | Corporate & | | | | |
| | Propane | | | Utility | | | Marketing | | | Antargaz | | | Other | | | Other & Elims. | | | Total | |
Balance September 30, 2009 | | $ | 670.1 | | | $ | 180.1 | | | $ | 11.8 | | | $ | 646.9 | | | $ | 70.4 | | | $ | 3.0 | | | $ | 1,582.3 | |
Goodwill acquired | | | 12.9 | | | | — | | | | — | | | | — | | | | 20.6 | | | | — | | | | 33.5 | |
Purchase accounting adjustments | | | 0.1 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 0.1 | |
Dispositions | | | — | | | | — | | | | (9.0 | ) | | | — | | | | — | | | | 4.0 | | | | (5.0 | ) |
Foreign currency translation | | | — | | | | — | | | | — | | | | (44.2 | ) | | | (4.0 | ) | | | — | | | | (48.2 | ) |
| | | | | | | | | | | | | | | | | | | | | |
Balance September 30, 2010 | | | 683.1 | | | | 180.1 | | | | 2.8 | | | | 602.7 | | | | 87.0 | | | | 7.0 | | | | 1,562.7 | |
Goodwill acquired | | | 13.1 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 13.1 | |
Purchase accounting adjustments | | | 0.1 | | | | 2.0 | | | | — | | | | — | | | | (3.2 | ) | | | — | | | | (1.0 | ) |
Foreign currency translation | | | — | | | | — | | | | — | | | | (10.9 | ) | | | (1.6 | ) | | | — | | | | (12.6 | ) |
| | | | | | | | | | | | | | | | | | | | | |
Balance September 30, 2011 | | $ | 696.3 | | | $ | 182.1 | | | $ | 2.8 | | | $ | 591.8 | | | $ | 82.2 | | | $ | 7.0 | | | $ | 1,562.2 | |
| | | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | International Propane | | | | |
| AmeriGas Propane | | Gas Utility | | Energy Services | | Antargaz | | Flaga & Other | | Corporate & Other | | Total |
Balance September 30, 2010 | $ | 683.1 |
| | $ | 180.1 |
| | $ | 2.8 |
| | $ | 602.7 |
| | $ | 87.0 |
| | $ | 7.0 |
| | $ | 1,562.7 |
|
Goodwill acquired | 13.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 13.1 |
|
Purchase accounting adjustments | 0.1 |
| | 2.0 |
| | — |
| | — |
| | (3.2 | ) | | — |
| | (1.1 | ) |
Foreign currency translation | — |
| | — |
| | — |
| | (10.9 | ) | | (1.6 | ) | | — |
| | (12.5 | ) |
Balance September 30, 2011 | 696.3 |
| | 182.1 |
| | 2.8 |
| | 591.8 |
| | 82.2 |
| | 7.0 |
| | 1,562.2 |
|
Goodwill acquired | 1,223.1 |
| | — |
| | — |
| | 46.4 |
| | 13.7 |
| | — |
| | 1,283.2 |
|
Purchase accounting adjustments | (0.2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (0.2 | ) |
Foreign currency translation | — |
| | — |
| | — |
| | (26.2 | ) | | (0.7 | ) | | — |
| | (26.9 | ) |
Balance September 30, 2012 | $ | 1,919.2 |
| | $ | 182.1 |
| | $ | 2.8 |
| | $ | 612.0 |
| | $ | 95.2 |
| | $ | 7.0 |
| | $ | 2,818.3 |
|
We amortize customer relationships and noncompete agreement intangibles over their estimated periods of benefit which do not exceed 15 years. Amortization expense of intangible assets was $20.4$44.5 in Fiscal 2011, $19.92012, $20.4 in Fiscal 20102011 and $18.4$19.9 in Fiscal 2009.2010. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 20122013 — $20.1;$51.8; Fiscal 20132014 — $19.5;$50.5; Fiscal 20142015 — $18.6;$47.4; Fiscal 20152016 — $16.6;$41.3; Fiscal 20162017 — $10.3.$35.0. There were no accumulated impairment losses at September 30, 2011.2012.
Note 12 — Series Preferred Stock
UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of UGI Series Preferred Stock outstanding at September 30, 20112012 or 2010.2011.
UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. At September 30, 20112012 and 2010,2011, there were no shares of UGI Utilities Series Preferred Stock outstanding.
Note 13 — Common Stock and Equity-Based Compensation
UGI Common Stock share activity for Fiscal 2009, Fiscal 2010 and Fiscal 2011 follows:
| | | | | | | | | | | | |
| | Issued | | | Treasury | | | Outstanding | |
Balance, September 30, 2008 | | | 115,247,694 | | | | (7,386,732 | ) | | | 107,860,962 | |
| | | | | | | | | |
Issued: | | | | | | | | | | | | |
Employee and director plans | | | 13,600 | | | | 776,074 | | | | 789,674 | |
Dividend reinvestment plan | | | — | | | | 96,071 | | | | 96,071 | |
| | | | | | | | | |
Balance, September 30, 2009 | | | 115,261,294 | | | | (6,514,587 | ) | | | 108,746,707 | |
| | | | | | | | | |
Issued: | | | | | | | | | | | | |
Employee and director plans | | | 139,000 | | | | 1,390,207 | | | | 1,529,207 | |
Dividend reinvestment plan | | | — | | | | 97,673 | | | | 97,673 | |
| | | | | | | | | |
Balance, September 30, 2010 | | | 115,400,294 | | | | (5,026,707 | ) | | | 110,373,587 | |
| | | | | | | | | |
Issued: | | | | | | | | | | | | |
Employee and director plans | | | 106,800 | | | | 1,263,065 | | | | 1,369,865 | |
Dividend reinvestment plan | | | — | | | | 92,570 | | | | 92,570 | |
| | | | | | | | | |
Balance, September 30, 2011 | | | 115,507,094 | | | | (3,671,072 | ) | | | 111,836,022 | |
| | | | | | | | | |
F-36
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 13 — Common Stock and Equity-Based Compensation
UGI Common Stock share activity for Fiscal 2010, Fiscal 2011 and Fiscal 2012 follows:
|
| | | | | | | | |
| Issued | | Treasury | | Outstanding |
Balance, September 30, 2009 | 115,261,294 |
| | (6,514,587 | ) | | 108,746,707 |
|
Issued: | | | | | |
Employee and director plans | 139,000 |
| | 1,390,207 |
| | 1,529,207 |
|
Dividend reinvestment plan | — |
| | 97,673 |
| | 97,673 |
|
Balance, September 30, 2010 | 115,400,294 |
| | (5,026,707 | ) | | 110,373,587 |
|
Issued: | | | | | |
Employee and director plans | 106,800 |
| | 1,263,065 |
| | 1,369,865 |
|
Dividend reinvestment plan | — |
| | 92,570 |
| | 92,570 |
|
Balance, September 30, 2011 | 115,507,094 |
| | (3,671,072 | ) | | 111,836,022 |
|
Issued: | | | | | |
Employee and director plans | 117,500 |
| | 824,925 |
| | 942,425 |
|
Dividend reinvestment plan | — |
| | 104,994 |
| | 104,994 |
|
Shares reacquired - employee and director plans | — |
| | (263,020 | ) | | (263,020 | ) |
Balance, September 30, 2012 | 115,624,594 |
| | (3,004,173 | ) | | 112,620,421 |
|
As a result of the January 2012 issuance of 29,567,362 AmeriGas Partners Common Units to ETP in conjunction with the Heritage Acquisition and related General Partner Common Unit transactions (see Note 4), and the March 2012 issuance of 7,000,000 AmeriGas Partners Common Units pursuant to AmeriGas Partners’ public offering (see Note 14), the Company recorded a $196.3 increase in UGI Corporation stockholders’ equity (which amount is net of deferred income taxes) and an associated $321.4 pre-tax decrease in noncontrolling interests equity.
Equity-Based Compensation
The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $15.6 ($10.3$14.5 ($8.7 after-tax), $13.2 ($8.7$15.6 ($10.3 after-tax) and $17.6 ($11.4$13.2 ($8.7 after-tax) in Fiscal 2011,2012, Fiscal 20102011 and Fiscal 2009,2010, respectively.
UGI Equity-Based Compensation Plans and Awards.Under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “OECP”), we may grant options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”) and other equity-based awards to key employees and non-employee directors. The exercise price for options may not be less than the fair market value on the grant date. Awards granted under the OECP may vest immediately or ratably over a period of years, and stock options can be exercised no later than ten years from the grant date.date. In addition, the OECP provides that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
Under the OECP, awards representing up to 15,000,000 shares of UGI Common Stock may be granted. The maximum number of shares that may be issued pursuant to grants other than stock options or SARs is 3,200,000.3,200,000. Dividend equivalents on UGI Unit awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are accumulated in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of Common Stock and cash. UGI Unit awards granted to Antargaz employees are settled in shares of Common Stock. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions. It is our practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit awards. We do not expect to repurchase shares on the market for such purposes during Fiscal 2012.
UGI Stock Option Awards2013.Stock option transactions Beginning during Fiscal 2012, options granted under the OECP may be net exercised whereby shares equal to the option price and predecessor plans for Fiscal 2009, Fiscal 2010 and Fiscal 2011 follow:grantee's minimum applicable payroll tax withholding are withheld from the number
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | Weighted | |
| | | | | | Weighted | | | Total | | | Average | |
| | | | | | Average | | | Intrinsic | | | Contract Term | |
| | Shares | | | Option Price | | | Value | | | (Years) | |
Shares under option — September 30, 2008 | | | 6,652,245 | | | $ | 21.71 | | | $ | 30.9 | | | | 6.6 | |
| | | | | | | | | | | | |
Granted | | | 1,411,200 | | | $ | 24.65 | | | | | | | | | |
Cancelled | | | (87,334 | ) | | $ | 25.81 | | | | | | | | | |
Exercised | | | (474,618 | ) | | $ | 13.30 | | | $ | 6.0 | | | | | |
| | | | | | | | | | | | | |
Shares under option — September 30, 2009 | | | 7,501,493 | | | $ | 22.74 | | | $ | 23.2 | | | | 6.4 | |
| | | | | | | | | | | | |
Granted | | | 1,394,300 | | | $ | 24.37 | | | | | | | | | |
Cancelled | | | (62,501 | ) | | $ | 25.12 | | | | | | | | | |
Exercised | | | (1,276,247 | ) | | $ | 18.09 | | | $ | 11.7 | | | | | |
| | | | | | | | | | | | | |
Shares under option — September 30, 2010 | | | 7,557,045 | | | $ | 23.81 | | | $ | 36.2 | | | | 6.5 | |
| | | | | | | | | | | | |
Granted | | | 1,443,558 | | | $ | 31.55 | | | | | | | | | |
Cancelled | | | (235,437 | ) | | $ | 27.79 | | | | | | | | | |
Exercised | | | (1,091,987 | ) | | $ | 20.95 | | | $ | 11.4 | | | | | |
| | | | | | | | | | | | | |
Shares under option — September 30, 2011 | | | 7,673,179 | | | $ | 25.55 | | | $ | 15.1 | | | | 6.2 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Options exercisable — September 30, 2009 | | | 4,744,054 | | | $ | 21.00 | | | | | | | | | |
Options exercisable — September 30, 2010 | | | 4,706,376 | | | $ | 22.99 | | | | | | | | | |
Options exercisable — September 30, 2011 | | | 4,879,784 | | | $ | 24.15 | | | $ | 12.7 | | | | 5.2 | |
| | | | | | | | | | | | |
Non-vested options — September 30, 2011 | | | 2,793,395 | | | $ | 27.99 | | | $ | 2.4 | | | | 8.0 | |
| | | | | | | | | | | | |
F-37
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
of shares payable ("net exercise"). We record shares withheld under option net exercises as shares reacquired.
UGI Stock Option Awards. Stock option transactions under the OECP and predecessor plans for Fiscal 2010, Fiscal 2011 and Fiscal 2012 follow:
|
| | | | | | | | | | | | |
| Shares | | Weighted Average Option Price | | Total Intrinsic Value | | Weighted Average Contract Term (Years) |
Shares under option — September 30, 2009 | 7,501,493 |
| | $ | 22.74 |
| | $ | 23.2 |
| | 6.4 |
Granted | 1,394,300 |
| | $ | 24.37 |
| | | | |
Cancelled | (62,501 | ) | | $ | 25.12 |
| | | | |
Exercised | (1,276,247 | ) | | $ | 18.09 |
| | $ | 11.7 |
| | |
Shares under option — September 30, 2010 | 7,557,045 |
| | $ | 23.81 |
| | $ | 36.2 |
| | 6.5 |
Granted | 1,443,558 |
| | $ | 31.55 |
| | | | |
Cancelled | (235,437 | ) | | $ | 27.79 |
| | | | |
Exercised | (1,091,987 | ) | | $ | 20.95 |
| | $ | 11.4 |
| | |
Shares under option — September 30, 2011 | 7,673,179 |
| | $ | 25.55 |
| | $ | 15.1 |
| | 6.2 |
Granted | 1,508,050 |
| | $ | 29.26 |
| | | | |
Cancelled | (321,600 | ) | | $ | 27.74 |
| | | | |
Exercised | (801,857 | ) | | $ | 20.93 |
| | $ | 7.2 |
| | |
Shares under option — September 30, 2012 | 8,057,772 |
| | $ | 26.62 |
| | $ | 41.4 |
| | 6.1 |
Options exercisable — September 30, 2010 | 4,706,376 |
| | $ | 22.99 |
| | | | |
Options exercisable — September 30, 2011 | 4,879,784 |
| | $ | 24.15 |
| | | | |
Options exercisable — September 30, 2012 | 5,317,698 |
| | $ | 25.32 |
| | $ | 34.2 |
| | 5.0 |
Non-vested options — September 30, 2012 | 2,740,074 |
| | $ | 29.13 |
| | $ | 7.2 |
| | 8.3 |
Cash received from stock option exercises and associated tax benefits were $22.9$16.8 and $3.8, $23.1$2.3, $22.9 and $4.3,$3.8, and $6.3$23.1 and $2.2$4.3 in Fiscal 2011,2012, Fiscal 20102011 and Fiscal 2009,2010, respectively. As of September 30, 2011,2012, there was $3.6$4.2 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 2.12 years.
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2011:2012:
| | | | | | | | | | | | | | | | |
| | Range of exercise prices | |
| | Under | | | $20.00 - | | | $25.01 - | | | Over | |
| | $20.00 | | | $25.00 | | | $30.00 | | | $30.00 | |
Options outstanding at September 30, 2011: | | | | | | | | | | | | | | | | |
Number of options | | | 336,300 | | | | 3,539,727 | | | | 2,456,694 | | | | 1,340,458 | |
Weighted average remaining contractual life (in years) | | | 1.9 | | | | 6.0 | | | | 5.7 | | | | 8.7 | |
Weighted average exercise price | | $ | 15.42 | | | $ | 23.05 | | | $ | 27.24 | | | $ | 31.59 | |
| | | | | | | | | | | | | | | | |
Options exercisable at September 30, 2011: | | | | | | | | | | | | | | | | |
Number of options | | | 336,300 | | | | 2,351,093 | | | | 2,124,391 | | | | 68,000 | |
Weighted average exercise price | | $ | 15.42 | | | $ | 22.44 | | | $ | 27.19 | | | $ | 31.74 | |
|
| | | | | | | | | | | | | | | |
| Range of exercise prices |
| Under $20.00 | | $20.00 - $25.00 | | $25.01 - $30.00 | | Over $30.00 |
Options outstanding at September 30, 2012: | | | | | | | |
Number of options | 162,300 |
| | 2,996,470 |
| | 3,529,044 |
| | 1,369,958 |
|
Weighted average remaining contractual life (in years) | 1.5 |
| | 5.3 |
| | 6.3 |
| | 7.8 |
|
Weighted average exercise price | $ | 16.92 |
| | $ | 23.29 |
| | $ | 27.99 |
| | $ | 31.53 |
|
Options exercisable at September 30, 2012: | | | | | | | |
Number of options | 162,300 |
| | 2,546,170 |
| | 2,164,909 |
| | 444,319 |
|
Weighted average exercise price | $ | 16.92 |
| | $ | 23.12 |
| | $ | 27.26 |
| | $ | 31.60 |
|
UGI Stock Option Fair Value Information.The per share weighted-average fair value of stock options granted under our option plans was $5.40$4.31 in Fiscal 2011, $4.492012, $5.40 in Fiscal 20102011 and $4.13$4.49 in Fiscal 2009.2010. These amounts were determined using a Black-Scholes option pricing model which values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments and the risk-free interest rate over the expected life of the option.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The expected life of option awards represents the period of time during which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on historical UGI dividend rates. The risk free interest rate is based on U.S. Treasury bonds with terms comparable to the options in effect on the date of grant.
The assumptions we used for valuing option grants during Fiscal 2011,2012, Fiscal 20102011 and Fiscal 20092010 are as follows:
| | | | | | | | | | | | |
| | 2011 | | | 2010 | | | 2009 | |
Expected life of option | | 5.75 years | | 5.75 years | | 5.75 years |
Weighted average volatility | | | 24.3 | % | | | 24.0 | % | | | 23.7 | % |
Weighted average dividend yield | | | 3.4 | % | | | 3.3 | % | | | 3.0 | % |
| | | | | | | | | | | | |
Expected volatility | | | 23.8% - 24.3 | % | | | 24.0 | % | | | 20.3% - 23.7 | % |
Expected dividend yield | | | 3.1% - 3.4 | % | | | 3.3% - 3.4 | % | | | 2.9% - 3.2 | % |
Risk free rate | | | 1.2% - 2.4 | % | | | 1.7% - 3.1 | % | | | 1.7% - 3.0 | % |
|
| | | | | |
| 2012 | | 2011 | | 2010 |
Expected life of option | 5.75 years | | 5.75 years | | 5.75 years |
Weighted average volatility | 24.7% | | 24.3% | | 24.0% |
Weighted average dividend yield | 3.5% | | 3.4% | | 3.3% |
Expected volatility | 24.7% | | 23.8% - 24.3% | | 24.0% |
Expected dividend yield | 3.3% - 3.7% | | 3.1% - 3.4% | | 3.3% - 3.4% |
Risk free rate | 0.8% - 1.1% | | 1.2% - 2.4% | | 1.7% - 3.1% |
UGI Unit Awards.UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of UGI Performance Units ultimately paid at the end of the performance period (generally three-years)three years) may be higher or lower than the target amount, or even zero, based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to companies in the Standard & Poor’s Utilities Index for grants prior to January 1, 2011 and the Russell Midcap Utility Index (excluding telecommunication companies) for grants on or after January 1, 2011 (“UGI comparator group”). Based on the TSR percentile rank, grantees may receive 0% to 200% of the target award granted. If UGI’s TSR ranks below the 40th percentile compared to the UGI comparator group, the employee will not be paid. At the 40th percentile, the employee will be paid an award equal to 50% of the target award; at the 50th percentile, 100%; and at the 100th percentile, 200%. The actual amount of the award is interpolated between these percentile rankings. Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.
The fair value of UGI Stock Units on the grant date is equal to the market price of UGI Stock on the grant date. Under GAAP, UGI Performance Units are equity awards with a market-based condition which, if settled in shares, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of UGI Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award is accounted for as equity and the fair value of the award over the target, as well as all dividend equivalents, is accounted for as a liability. The expected term of the UGI Performance Unit awards is three years based on the performance period. Expected volatility is based on the historical volatility of UGI Common Stock over a three-year period. The risk-free interest rate is based on the yields on U.S. Treasury bonds at the time of grant. Volatility for all companies in the UGI comparator group is based on historical volatility.
F-38
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following table summarizes the weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs:
| | | | | | | | | | | | |
| | Grants Awarded in Fiscal | |
| | 2011 | | | 2010 | | | 2009 | |
Risk free rate | | | 1.0 | % | | | 1.7 | % | | | 1.0 | % |
Expected life | | 3 years | | | 3 years | | | 3 years | |
Expected volatility | | | 27.6 | % | | | 28.0 | % | | | 27.1 | % |
Dividend yield | | | 3.2 | % | | | 3.3 | % | | | 3.2 | % |
|
| | | | | | | | |
| Grants Awarded in Fiscal |
| 2012 | | 2011 | | 2010 |
Risk free rate | 0.4 | % | | 1.0 | % | | 1.7 | % |
Expected life | 3 years |
| | 3 years |
| | 3 years |
|
Expected volatility | 22.2 | % | | 27.6 | % | | 28.0 | % |
Dividend yield | 3.5 | % | | 3.2 | % | | 3.3 | % |
The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $35.19$27.25 for Units granted in Fiscal 2011, $22.512012, $35.19 for Units granted in Fiscal 20102011 and $27.91$22.51 for Units granted in Fiscal 2009.2010.
The following table summarizes UGI Unit award activity for Fiscal 2011:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Total | | | Vested | | | Non-Vested | |
| | | | | | Weighted | | | | | | | Weighted | | | | | | | Weighted | |
| | | | | | Average | | | | | | | Average | | | | | | | Average | |
| | Number of | | | Grant Date | | | Number of | | | Grant Date | | | Number of | | | Grant Date | |
| | UGI | | | Fair Value | | | UGI | | | Fair Value | | | UGI | | | Fair Value | |
| | Units | | | (per Unit) | | | Units | | | (per Unit) | | | Units | | | (per Unit) | |
September 30, 2010 | | | 930,493 | | | $ | 22.99 | | | | 570,835 | | | $ | 21.27 | | | | 359,658 | | | $ | 25.71 | |
UGI Performance Units: | | | | | | | | | | | | | | | | | | | | | | | | |
Granted | | | 223,525 | | | $ | 35.19 | | | | — | | | $ | — | | | | 223,525 | | | $ | 35.19 | |
Forfeited | | | (77,906 | ) | | $ | 30.18 | | | | — | | | $ | — | | | | (77,906 | ) | | $ | 30.18 | |
Vested | | | — | | | $ | — | | | | 198,749 | | | $ | 28.84 | | | | (198,749 | ) | | $ | 28.84 | |
Unit awards paid | | | (185,374 | ) | | $ | 30.17 | | | | (185,374 | ) | | $ | 30.17 | | | | — | | | $ | — | |
Performance criteria not met | | | — | | | $ | — | | | | — | | | $ | — | | | | — | | | $ | — | |
UGI Stock Units: | | | | | | | | | | | | | | | | | | | | | | | | |
Granted(a) | | | 61,945 | | | $ | 33.31 | | | | — | | | $ | — | | | | 61,945 | | | $ | 33.31 | |
Forfeited | | | (30,600 | ) | | $ | 34.88 | | | | — | | | $ | — | | | | (30,600 | ) | | $ | 34.88 | |
Vested | | | — | | | $ | — | | | | 36,545 | | | $ | 30.54 | | | | (36,545 | ) | | $ | 30.54 | |
Unit awards paid | | | (21,800 | ) | | $ | 26.37 | | | | (21,800 | ) | | $ | 26.37 | | | | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | |
September 30, 2011 | | | 900,283 | | | $ | 24.13 | | | | 598,955 | | | $ | 21.41 | | | | 301,328 | | | $ | 29.56 | |
| | | | | | | | | | | | | | | | | | |
| | |
(a) | | Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2010 and Fiscal 2009 were 27,060 and 52,767, respectively. |
F-39
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following table summarizes UGI Unit award activity for Fiscal 2012:
|
| | | | | | | | | | | | | | | | | | | | |
| Total | | Vested | | Non-Vested |
| Number of UGI Units | | Weighted Average Grant Date Fair Value (per Unit) | | Number of UGI Units | | Weighted Average Grant Date Fair Value (per Unit) | | Number of UGI Units | | Weighted Average Grant Date Fair Value (per Unit) |
September 30, 2011 | 900,283 |
| | $ | 24.13 |
| | 598,955 |
| | $ | 21.41 |
| | 301,328 |
| | $ | 29.56 |
|
UGI Performance Units: | | | | | | | | | | | |
Granted | 197,400 |
| | $ | 27.25 |
| | 33,518 |
| | $ | 29.16 |
| | 163,882 |
| | $ | 26.86 |
|
Forfeited | (51,411 | ) | | $ | 27.94 |
| | — |
| | $ | — |
| | (51,411 | ) | | $ | 27.94 |
|
Vested | — |
| | $ | — |
| | 110,083 |
| | $ | 29.04 |
| | (110,083 | ) | | $ | 29.04 |
|
Performance criteria not met | (170,481 | ) | | $ | 27.82 |
| | (170,481 | ) | | $ | 27.82 |
| | — |
| | $ | — |
|
UGI Stock Units: | | | | | | | | | | | |
Granted (a) | 42,445 |
| | $ | 29.69 |
| | 40,945 |
| | $ | 29.53 |
| | 1,500 |
| | $ | 34.06 |
|
Vested | — |
| | $ | — |
| | — |
| | $ | — |
| | — |
| | $ | — |
|
Unit awards paid | (32,898 | ) | | $ | 26.17 |
| | (32,898 | ) | | $ | 26.17 |
| | — |
| | $ | — |
|
September 30, 2012 | 885,338 |
| | $ | 24.09 |
| | 580,122 |
| | $ | 21.72 |
| | 305,216 |
| | $ | 28.59 |
|
| |
(a) | Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2011 and Fiscal 2010 were 61,945 and 27,060, respectively. |
During Fiscal 2011,2012, Fiscal 20102011 and Fiscal 2009,2010, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:
| | | | | | | | | | | | |
| | 2011 | | | 2010 | | | 2009 | �� |
UGI Performance Unit awards: | | | | | | | | | | | | |
Number of original awards granted | | | 197,917 | | | | 193,983 | | | | 163,450 | |
Fiscal year granted | | | 2008 | | | | 2007 | | | | 2006 | |
Payment of awards: | | | | | | | | | | | | |
Shares of UGI Common Stock issued | | | 142,494 | | | | 123,169 | | | | 117,847 | |
Cash paid | | $ | 7.5 | | | $ | 2.6 | | | $ | 3.1 | |
|
UGI Stock Unit awards: | | | | | | | | | | | | |
Number of original awards granted | | | 22,400 | | | | — | | | | 88,449 | |
Payment of awards: | | | | | | | | | | | | |
Shares of UGI Common Stock issued | | | 17,545 | | | | — | | | | 58,376 | |
Cash paid | | $ | 0.2 | | | $ | — | | | $ | 0.8 | |
|
| | | | | | | | | | | |
| 2012 | | 2011 | | 2010 |
UGI Performance Unit awards: | | | | | |
Number of original awards granted | 210,750 |
| | 197,917 |
| | 193,983 |
|
Fiscal year granted | 2009 |
| | 2008 |
| | 2007 |
|
Payment of awards: | | | | | |
Shares of UGI Common Stock issued | — |
| | 142,494 |
| | 123,169 |
|
Cash paid | $ | — |
| | $ | 7.5 |
| | $ | 2.6 |
|
| | | | | |
UGI Stock Unit awards: | | | | | |
Number of original awards granted | 32,898 |
| | 22,400 |
| | — |
|
Payment of awards: | | | | | |
Shares of UGI Common Stock issued | 21,757 |
| | 17,545 |
| | — |
|
Cash paid | $ | 0.2 |
| | $ | 0.2 |
| | $ | — |
|
During Fiscal 2011,2012, Fiscal 20102011 and Fiscal 2009,2010, we granted UGI Unit awards representing 239,845, 285,470 231,710 and 269,017231,710 shares, respectively, having weighted-average grant date fair values per Unit of $34.78, $22.69$27.68, $34.78 and $27.26,$22.69, respectively.
As of September 30, 2011,2012, there was a total of approximately $6.6$5.2 of unrecognized compensation cost associated with 900,283885,338 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.9 years. The total fair values of UGI Units that vested during Fiscal 2011,2012, Fiscal 20102011 and Fiscal 20092010 were $6.8, $5.0$3.6, $6.8 and $7.6,$5.0, respectively. As of September 30, 20112012 and 2010,2011, total liabilities of $6.0$5.0 and $8.7,$6.0, respectively, associated with UGI Unit awards are reflected in “Employeeemployee compensation and benefits accrued”accrued and “Otherother noncurrent liabilities”liabilities in the Consolidated Balance Sheets.
At September 30, 2011, 2,618,3512012, 1,436,672 shares of Common Stock were available for future grants under the OECP, of which up to 1,437,2971,436,672 may be issued pursuant to future grants other than stock options or SARs.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
AmeriGas Partners Equity-Based Compensation Plans and Awards.Under the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. (“2010 Propane Plan”), the General Partner may award to employees and non-employee directors grants of CommonAmeriGas Partners Units performance units,(comprising “AmeriGas Stock Units” and “AmeriGas Performance Units”), options, phantom units, unit appreciation rights and other Common Unit-based awards. The 2010 Propane Plan succeeded the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan (“2000 Propane Plan”) which expired on December 31, 2009, and replaced the AmeriGas Propane, Inc. Discretionary Long-Term Incentive Plan for Non-Executive Key Employees (“Nonexecutive Propane Plan”). The total aggregate number of Common Units that may be issued under the 2010 Propane Plan is 2,800,000.2,800,000. The exercise price for options may not be less than the fair market value on the date of grant. Awards granted under the 2010 Propane Plan may vest immediately or ratably over a period of years, and options can be exercised no later than ten years from the grant date.date. In addition, the 2010 Propane Plan provides that Common Unit-based awards may also provide for the crediting of Common Unit distribution equivalents to participants’ accounts.
The 2010 Propane Plan succeeded the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan (“2000 Propane Plan”) which expired on December 31, 2009, and replaced the AmeriGas Propane, Inc. Discretionary Long-Term Incentive Plan for Non-Executive Key Employees (“Nonexecutive Propane Plan”). Under the 2000 Propane Plan, the General Partner could award to key employees the right to receive Common Units (comprising performance units), or cash equivalent to the fair market value of such Common Units. In addition, the 2000 Propane Plan authorizes the crediting of Common Unit distribution equivalents to participants’ accounts. Under the Nonexecutive Propane Plan, the General Partner could grant awards to key employees who did not participate in the 2000 Propane Plan. Generally, awards under the Nonexecutive Propane Plan vest at the end of a three-year period and are paid in Common Units and cash. No additional grants will be made under the 2000 Propane Plan and the Nonexecutive Propane Plan.
Recipients of performance unit awards under the 2010 Propane Plan and the 2000 Propane Plan (“AmeriGas Performance Units”)Unit awards are awarded a target number of AmeriGas Performance Units. The number of AmeriGas Performance Units ultimately paid at the end of the performance period (generally three years)years ) may be higher or lower than the target amountnumber based upon AmeriGas Partners’ Total Unitholder Return (“TUR”) percentile rank relative to entities in a peer group. Percentile rankings and payout percentages are generally the same as those used for the UGI Performance Unit awards. Any Common Unit distribution equivalents earned are paid in cash. Generally, except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed by the General Partner. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
F-40
UGI CorporationAs a result of the Heritage Acquisition, certain Heritage Propane employees were awarded AmeriGas Performance Units, AmeriGas Stock Units (in the form of phantom units), or a combination of AmeriGas Performance Units and Subsidiaries
NotesAmeriGas Stock Units. The terms of the Performance Unit awards granted to Consolidated Financial Statements
(MillionsHeritage Propane employees are generally the same as those described above. The AmeriGas Stock Units awards granted to Heritage employees vest in tranches with certain awards beginning to vest in January 2013 through January 2016. Certain of dollars and euros, except per share amounts and where indicated otherwise)the AmeriGas Stock Unit awards provide for accelerated vesting under certain conditions. Under certain conditions all or a portion of these awards could be forfeited. The AmeriGas Stock Unit awards granted to Heritage Propane employees provide for the crediting of distribution equivalents to participants' accounts.
Under GAAP, AmeriGas Performance Units are equity awards with a market-based condition which, if settled in Common Units, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of AmeriGas Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award and the award above the target, if any, which will be paid in Common Units, is accounted for as equity and the fair value of all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability. The expected term of the AmeriGas Performance Unit awards is three years based on the performance period. Expected volatility is based on the historical volatility of Common Units over a three-year period. The risk-free interest rate is based on the rates on U.S. Treasury bonds at the time of grant. Volatility for all limited partnerships in the peer group is based on historical volatility.
The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards and related compensation costs:
| | | | | | | | | | | | |
| | Grants Awarded in Fiscal | |
| | 2011 | | | 2010 | | | 2009 | |
Risk-free rate | | | 1.0 | % | | | 1.7 | % | | | 1.0 | % |
Expected life | | 3 years | | | 3 years | | | 3 years | |
Expected volatility | | | 34.6 | % | | | 35.0 | % | | | 32.0 | % |
Dividend yield | | | 5.8 | % | | | 6.8 | % | | | 9.1 | % |
|
| | | | | | | | |
| Grants Awarded in Fiscal |
| 2012 | | 2011 | | 2010 |
Risk-free rate | 0.4 | % | | 1.0 | % | | 1.7 | % |
Expected life | 3 years |
| | 3 years |
| | 3 years |
|
Expected volatility | 23.0 | % | | 34.6 | % | | 35.0 | % |
Dividend yield | 6.4 | % | | 5.8 | % | | 6.8 | % |
The General Partner granted awards under the 2010 Propane Plan representing 248,818, 49,287 57,750 and 60,20057,750 Common Units in Fiscal 2011,2012, Fiscal 20102011 and Fiscal 2009,2010, respectively, having weighted-average grant date fair values per Common Unit subject to award of $53.19, $41.39$43.22, $53.19 and $31.94,$41.39, respectively. At September 30, 2011, 2,747,2632012, 2,517,419 Common Units were available for future award grants under the 2010 Propane Plan.
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2011:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Total | | | Vested | | | Non-Vested | |
| | Number of | | | | | | | Number of | | | | | | | Number of | | | | |
| | AmeriGas | | | | | | | AmeriGas | | | | | | | AmeriGas | | | | |
| | Partners | | | Weighted | | | Partners | | | Weighted | | | Partners | | | Weighted | |
| | Common | | | Average | | | Common | | | Average | | | Common | | | Average | |
| | Units | | | Grant Date | | | Units | | | Grant Date | | | Units | | | Grant Date | |
| | Subject | | | Fair Value | | | Subject | | | Fair Value | | | Subject | | | Fair Value | |
| | to Award | | | (per Unit) | | | to Award | | | (per Unit) | | | to Award | | | (per Unit) | |
September 30, 2010 | | | 146,600 | | | $ | 37.05 | | | | 53,851 | | | $ | 37.14 | | | | 92,749 | | | $ | 37.00 | |
Granted | | | 49,287 | | | $ | 53.19 | | | | — | | | $ | — | | | | 49,287 | | | $ | 53.19 | |
Forfeited | | | (2,967 | ) | | $ | 35.41 | | | | — | | | $ | — | | | | (2,967 | ) | | $ | 35.41 | |
Vested | | | — | | | $ | — | | | | 46,351 | | | $ | 39.88 | | | | (46,351 | ) | | $ | 39.88 | |
Awards paid | | | (37,564 | ) | | $ | 38.75 | | | | (37,564 | ) | | $ | 38.75 | | | | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | |
September 30, 2011 | | | 155,356 | | | $ | 41.79 | | | | 62,638 | | | $ | 38.20 | | | | 92,718 | | | $ | 44.22 | |
| | | | | | | | | | | | | | | | | | |
F-41
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2012:
|
| | | | | | | | | | | | | | | | | | | | |
| Total | | Vested | | Non-Vested |
| Number of AmeriGas Partners Common Units Subject to Award | | Weighted Average Grant Date Fair Value (per Unit) | | Number of AmeriGas Partners Common Units Subject to Award | | Weighted Average Grant Date Fair Value (per Unit) | | Number of AmeriGas Partners Common Units Subject to Award | | Weighted Average Grant Date Fair Value (per Unit) |
September 30, 2011 | 155,356 |
| | $ | 41.79 |
| | 62,638 |
| | $ | 38.20 |
| | 92,718 |
| | $ | 44.22 |
|
AmeriGas Performance Units: |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Granted | 55,150 |
| | $ | 48.28 |
| | 8,665 |
| | $ | 48.28 |
| | 46,485 |
| | $ | 48.28 |
|
Forfeited | (15,068 | ) | | $ | 50.37 |
| | — |
| | $ | — |
| | (15,068 | ) | | $ | 50.37 |
|
Vested | — |
| | $ | — |
| | 36,833 |
| | $ | 39.28 |
| | (36,833 | ) | | $ | 39.28 |
|
Performance criteria not met | (48,633 | ) | | $ | 32.17 |
| | (48,633 | ) | | $ | 32.17 |
| | — |
| | $ | — |
|
AmeriGas Stock Units: | | | | | | | | | | | |
Granted | 193,668 |
| | $ | 41.77 |
| | 66,244 |
| | $ | 41.81 |
| | 127,424 |
| | $ | 41.76 |
|
Forfeited | (10,360 | ) | | $ | 41.42 |
| | — |
| | $ | — |
| | (10,360 | ) | | $ | 41.42 |
|
Vested | — |
| | $ | — |
| | 6,050 |
| | $ | 35.05 |
| | (6,050 | ) | | $ | 35.05 |
|
Awards paid | (66,146 | ) | | $ | 40.72 |
| | (66,146 | ) | | $ | 40.72 |
| | — |
| | $ | — |
|
September 30, 2012 | 263,967 |
| | $ | 44.70 |
| | 65,651 |
| | $ | 45.42 |
| | 198,316 |
| | $ | 44.47 |
|
During Fiscal 2011,2012, Fiscal 20102011 and Fiscal 2009,2010, the Partnership paid AmeriGas Common Unit-based awards in Common Units and cash as follows:
| | | | | | | | | | | | |
| | 2011 | | | 2010 | | | 2009 | |
Number of Common Units subject to original Awards granted | | | 41,064 | | | | 49,650 | | | | 38,350 | |
Fiscal year granted | | | 2008 | | | | 2007 | | | | 2006 | |
Payment of Awards: | | | | | | | | | | | | |
AmeriGas Partners Common Units issued | | | 35,787 | | | | 42,121 | | | | 36,437 | |
Cash paid | | $ | 1.2 | | | $ | 1.2 | | | $ | 0.9 | |
|
| | | | | | | | | | | |
| 2012 (a) | | 2011 | | 2010 |
Number of Common Units subject to original awards granted | 60,200 |
| | 41,064 |
| | 49,650 |
|
Fiscal year granted | 2009 |
| | 2008 |
| | 2007 |
|
Payment of awards: | | | | | |
AmeriGas Partners Common Units issued | 3,500 |
| | 35,787 |
| | 42,121 |
|
Cash paid | $ | 0.1 |
| | $ | 1.2 |
| | $ | 1.2 |
|
(a) In addition, 40,516 AmeriGas Stock Units, and $0.9 in cash, were paid to Heritage Propane employees associated with awards granted in Fiscal 2012.
As of September 30, 2011,2012, there was a total of approximately $2.6$3.0 of unrecognized compensation cost associated with 155,356263,967 Common Units subject to award that is expected to be recognized over a weighted-average period of 1.82.0 years. The total fair value of Common Unit-based awards that vested during Fiscal 2011,2012, Fiscal 20102011 and Fiscal 20092010 was $2.0, $2.0$5.1, $2.0 and $1.6,$2.0, respectively. As of September 30, 20112012 and 2010,2011, total liabilities of $1.2$1.1 and $1.3$1.2 associated with Common Unit-based awards are reflected in “Employeeemployee compensation and benefits accrued”accrued and “Otherother noncurrent liabilities”liabilities in the Consolidated Balance Sheets.
Note 14 — Partnership Distributions and Common Unit Offering
The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash for such quarter.quarter. Available Cash generally means:
| |
1. | | all cash on hand at the end of such quarter, |
| |
2. | | plus all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter, |
| |
3. | | less the amount of cash reserves established by the General Partner in its reasonable discretion. |
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the next four quarters.
Distributions of Available Cash are made 98% to limited partners and 2% to the General Partner (representing a 1% General Partner interest in AmeriGas Partners and 1.01% interest in AmeriGas OLP) until Available Cash exceeds the Minimum Quarterly Distribution of $0.55$0.55 and the First Target Distribution of $0.055$0.055 per Common Unit (or a total of $0.605$0.605 per Common Unit). When Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner will receive a greater percentage of the total Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common Unit to limited partners exceeds $0.605.$0.605.
During Fiscal 2011,2012, Fiscal 20102011 and Fiscal 2009,2010, the Partnership made quarterly distributions to Common Unitholders in excess of $0.605$0.605 per limited partner unit. As a result, the General Partner has received a greater percentage of the total Partnership distribution than its aggregate 2% general partner interest in AmeriGas OLP and AmeriGas Partners. The total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $9.0$19.7 in Fiscal 2011, $6.92012, $9.0 in Fiscal 20102011 and $8.5$6.9 in Fiscal 2009.2010. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2011,2012, Fiscal 20102011 and Fiscal 20092010 of $5.0, $3.0$13.0, $5.0 and $4.5,$3.0, respectively.
On July 27, 2009,In March 2012, AmeriGas Partners sold 7,000,000 Common Units in an underwritten public offering at a public offering price of $41.25 per unit. The net proceeds of the public offering totaling $276.6 and the associated capital contributions from the General Partner’s BoardPartner totaling $2.8 were used to redeem $200 of Directors approved6.50% Senior Notes pursuant to a distribution of $0.84 per Common Unit payable on August 18, 2009tender offer, to unitholders of record on August 10, 2009. This distribution included the regular quarterly distribution of $0.67 per Common Unitreduce bank loan borrowings and $0.17 per Common Unit reflecting a distribution of a portion of the proceeds from the Partnership’s November 2008 sale of its California storage facility.for general partnership purposes.
F-42
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 15 — Commitments and Contingencies
Commitments
We lease various buildings and other facilities and vehicles, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $69.8$77.9 in Fiscal 2011, $70.62012, $69.8 in Fiscal 20102011 and $70.1$70.6 in Fiscal 2009.2010.
Minimum future payments under operating leases with non-affiliates that have initial or remaining noncancelable terms in excess of one year are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | After | |
| | 2012 | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2016 | |
AmeriGas Propane | | $ | 53.8 | | | $ | 45.3 | | | $ | 37.2 | | | $ | 29.3 | | | $ | 21.1 | | | $ | 40.4 | |
UGI Utilities | | | 4.8 | | | | 4.3 | | | | 3.1 | | | | 2.3 | | | | 2.1 | | | | 2.2 | |
International Propane | | | 7.1 | | | | 5.5 | | | | 4.0 | | | | 2.4 | | | | 2.3 | | | | 1.3 | |
Other | | | 2.6 | | | | 2.7 | | | | 1.9 | | | | 1.2 | | | | 0.6 | | | | 0.4 | |
| | | | | | | | | | | | | | | | | | |
Total | | $ | 68.3 | | | $ | 57.8 | | | $ | 46.2 | | | $ | 35.2 | | | $ | 26.1 | | | $ | 44.3 | |
| | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | After 2017 |
AmeriGas Propane | $ | 62.0 |
| | $ | 48.8 |
| | $ | 39.4 |
| | $ | 30.3 |
| | $ | 23.1 |
| | $ | 63.9 |
|
UGI Utilities | 5.4 |
| | 4.3 |
| | 3.4 |
| | 3.1 |
| | 1.8 |
| | 2.3 |
|
International Propane | 8.0 |
| | 5.6 |
| | 3.4 |
| | 2.6 |
| | 2.4 |
| | 2.3 |
|
Other | 2.0 |
| | 1.7 |
| | 1.3 |
| | 1.1 |
| | 0.3 |
| | 0.1 |
|
Total | $ | 77.4 |
| | $ | 60.4 |
| | $ | 47.5 |
| | $ | 37.1 |
| | $ | 27.6 |
| | $ | 68.6 |
|
Our businesses enter into contracts of varying lengths and terms to meet their supply, pipeline transportation, storage, capacity and energy needs. Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation and natural gas storage services, which Gas Utility may terminate at various dates through Fiscal 2022. Gas Utility’s costs associated with transportation and storage capacity agreements are included in its annual PGC filings with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices. Electric Utility purchases its electricity needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2014. Midstream & Marketing enters into fixed-price contracts with suppliers to purchase natural gas and electricity to meet its sales commitments. Generally, these contracts have terms of less than two years. The Partnership enters into fixed-price and variable-pricedvariable-price contracts to purchase a portion of its supply requirements. These contracts generallycurrently have terms of less than one year.that do not exceed four years. International Propane enters into variable-priced contracts to purchase a portion of its supply requirements that generallycurrently do not exceed one year.four years.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following table presents contractual obligations with non-affiliates under Gas Utility, Electric Utility, Midstream & Marketing, AmeriGas Propane and International Propane supply, storage and service contracts existing at September 30, 2011:2012:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | After | |
| | 2012 | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2016 | |
Gas Utility and Electric Utility supply, storage and transportation contracts | | $ | 213.0 | | | $ | 103.3 | | | $ | 76.2 | | | $ | 47.8 | | | $ | 25.0 | | | $ | 64.0 | |
Midstream & Marketing supply contracts | | | 222.5 | | | | 54.1 | | | | 3.6 | | | | — | | | | — | | | | — | |
AmeriGas Propane supply contracts | | | 65.8 | | | | — | | | | — | | | | — | | | | — | | | | — | |
International Propane supply contracts | | | 23.3 | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | |
Total | | $ | 524.6 | | | $ | 157.4 | | | $ | 79.8 | | | $ | 47.8 | | | $ | 25.0 | | | $ | 64.0 | |
| | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | After 2017 |
UGI Utilities supply, storage and transportation contracts | $ | 173.9 |
| | $ | 95.0 |
| | $ | 61.8 |
| | $ | 43.3 |
| | $ | 26.5 |
| | $ | 62.7 |
|
Midstream & Marketing supply contracts | 171.1 |
| | 51.4 |
| | 4.7 |
| | — |
| | — |
| | — |
|
AmeriGas Propane supply contracts | 141.4 |
| | 87.0 |
| | 87.7 |
| | 3.2 |
| | — |
| | — |
|
International Propane supply contracts | 226.4 |
| | 143.4 |
| | 143.4 |
| | 58.0 |
| | — |
| | — |
|
Total | $ | 712.8 |
| | $ | 376.8 |
| | $ | 297.6 |
| | $ | 104.5 |
| | $ | 26.5 |
| | $ | 62.7 |
|
The Partnership and International Propane also enter into other contracts to purchase LPG to meet supply requirements. Generally, these contracts are one-one- to three-yearthree-year agreements subject to annual price and quantity adjustments.
In addition, we have committed to invest upon request a total of up to an additional $8.5 in a limited partnership that focuses on investments in the alternative energy sector.
F-43
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)Contingencies
Contingencies
Environmental Matters
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“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 (“PNG-COA”) with the DEP. 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$1.8 and $1.1,$1.1, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. 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, 20112012 and 2010,2011, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $17.9$15.0 and $21.4,$17.9, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.
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.
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 (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-yearfive-year average of such prudently incurred remediation costs and (2) CPG Gas and PNG Gas are currently gettingreceiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At September 30, 2011,2012, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas 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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
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.
South Carolina Electric & Gas Company v. UGI Utilities, Inc.On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 in remediation costs and paid $26 in third-party claims relating to the site and estimates that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14. Trial took place in March 2009 and the court’s decision is pending.
F-44
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Frontier Communications Company v. UGI Utilities, Inc. et al.In April 2003, Citizens Communications Company, now known as Frontier Communications Company (“Frontier”), served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that they are responsible for an equitable share of any clean up costs Frontier would be required to pay to the City. Frontier alleged that through ownership and control of a subsidiary, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to Frontier’s claims. On October 19, 2010, the magistrate judge recommended the Court grant UGI Utilities’ motion. On November 19, 2010, the Court affirmed the recommended decision of the magistrate judge granting summary judgment in favor of UGI Utilities. On July 1, 2011, Frontier appealed the Court’s decision to the United States Court of Appeals for the First Circuit.
Sag Harbor, New York Matter.Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3$2.3 and expects to spend another $11$11 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10.$10. KeySpan believeshas indicated that the cost could be as high as $20.$20. There have been no recent developments or facts indicating thatin this will have a material impact to our results of operations or financial condition.matter.
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc.On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies. The Northeast Companies alleged that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites in Waterbury, CT (“Waterbury North”)Omaha, Nebraska. After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s decision in favor of UGI Utilities. A second phase of the trial took place in August 2011 to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The District Court’s decision is pending. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25.
Omaha, Nebraska.By letter dated October 20, 2011, the City of Omaha (“City”) and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities’ predecessor is identified as an owner and operator of the site. The City of Omaha and MUD hashave requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up of this site.costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska, and issued an information request to UGI Utilities. UGI Utilities is reviewingresponded to the EPA’s information request on January 17, 2012, and will cooperateis cooperating with its investigation. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.
AmeriGas OLP Saranac Lake.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 communicated the results of its research to DEC in January 2009 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.
HOLP San Bernardino. In July 2001, HOLP acquired a company that had previously received a request for information from the EPA regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred prior to the construction of the facility acquired by HOLP, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”). No follow-up correspondence has been received from the EPA on the matter since HOLP’s acquisition of the predecessor company in 2001. Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on our financial condition or results of operations.
Titan LLC Claremont, Chestertown and Bennington. In connection with the Heritage Acquisition on January 12, 2012, a predecessor of Titan LLC is purportedly the beneficial holder of title with respect to three former MGPs discussed below. The Contribution Agreement provides for indemnification from ETP for certain expenses associated with remediation of these sites.
Claremont, New Hampshire and Chestertown, Maryland. By letter dated September 30, 2010, the EPA notified Titan LLC that it may be a potentially responsible party (“PRP”) for cleanup costs associated with contamination at a former MGP in Claremont, New Hampshire. In June 2010, the Maryland Attorney General (“MAG”) identified Titan LLC as a PRP in connection with contamination at a former MGP in Chestertown, Maryland, and requested that Titan LLC participate in characterization and remediation activities. Titan LLC has supplied the EPA and MAG with corporate and bankruptcy information for its predecessors to support its claim that it is not liable for any remediation costs at the sites. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.
Bennington, Vermont. In 1996, a predecessor company of Titan LLC performed an environmental assessment of its property in Bennington, Vermont and discovered that the site was a former MGP. At that time, Titan LLC’s predecessor informed the company that previously owned and operated the MGP of potential liability under CERCLA. Titan LLC has not received any requests to remediate or provide costs associated with the site. Because of the preliminary nature of available environmental
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
information, the ultimate amount of expected clean up costs cannot be reasonably estimated.
Other Matters
AmeriGas Cylinder Investigations.Investigation.On or about October 21, 2009, the General Partner received a notice that the Offices of the District Attorneys of Santa Clara, Sonoma, Ventura, San Joaquin and Fresno Counties and the City Attorney of San Diego (the “District Attorneys”) have commenced an investigation into AmeriGas OLP’sOLP's cylinder labeling and filling practices in California andas a result of the Partnership's decision in 2008 to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds. At that time, the District Attorneys issued an administrative subpoena seeking documents and information relating to thesethose practices. We have responded to the administrative subpoena. On or about July 20, 2011, the General Partner received a second subpoena from the District Attorneys. The subpoena seekssought additional information and documents regarding AmeriGas OLP’sOLP's cylinder exchange program and allegeswe responded to that subpoena. In connection with this matter, the District Attorneys have alleged potential violations of California’s Unfair Competition Law.California's antitrust laws, California's slack-fill law, and California's principal false advertising statute. We reviewed and respondedbelieve we have strong defenses to the subpoena and will continue to cooperate with the District Attorneys.
F-45
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)these allegations.
Federal Trade Commission Investigation of Propane Grill Cylinder Filling Practices.On or about November 4, 2011, the General Partner received notice that the Federal Trade Commission (“FTC”) is conducting an antitrust and consumer protection investigation into certain practices of the Partnership whichthat relate to the filling of portable propane grill cylinders. Based upon the limited amount of information available at this time,On February 2, 2012, the Partnership believesreceived a Civil Investigative Demand from the investigation concerns, in whole or in part,FTC that requests documents and information concerning, among other things, (i) the Partnership’s decision, in 2008, to reduce the volume of propane in the grill cylinders it sells to consumers from 17 pounds to 15 pounds. pounds and (ii) cross-filling, related service arrangements and communications regarding the foregoing with competitors. The Partnership believes that it will have good defenses to any claims that may result from this investigation. Because of the limited information available at this time, weWe are not able to assess the financial impact this investigation or any related claims may have on the Partnership.
Swiger, et al. v. UGI/AmeriGas, Inc.et al.Purported Class Action Lawsuit. In 1996, a fire occurred at the residence of2005, Samuel and Brenda Swiger (the “Swigers”) when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, resulting from the defendants’ alleged failure to install underground propane lines at depths required by applicable safety standards. On December 14, 2010, AmeriGas OLP and its affiliates entered into a settlement agreement with the class. On August 12, 2011, the Circuit Court of Monongalia County entered a final order, dismissing all claims against AmeriGas.
In 2005, the Swigers also filed what purports to be a class action lawsuit in the Circuit Court of Harrison County, West Virginia, against UGI, an insurance subsidiary of UGI, certain officers of UGI and the General Partner, and their insurance carriers and insurance adjusters. In the Harrison Countythis lawsuit, the Swigers are seeking compensatory and punitive damages on behalf of the putative class for alleged violations of the West Virginia Insurance Unfair Trade Practice Act, negligence, intentional misconduct, and civil conspiracy. The Swigers have also requested that the Court rule that insurance coverage exists under the policies issued by the defendant insurance companies for damages sustained by the members of the class in the Monongalia County lawsuit. The Circuit Court of Harrison County has not certified the class in the Harrison County lawsuit at this time and, in October 2008, stayed thatthe lawsuit pending resolution of thea separate, but related, class action lawsuit filed against AmeriGas OLP in Monongalia County.County, which was settled in Fiscal 2011. We believe we have good defenses to the claims in this action.
BP America Production Company v. Amerigas Propane, L.P.On July 15, 2011, BP America Production Company (“BP”) filed a complaint against AmeriGas Propane, L.P.OLP in the District Court of Denver County, Colorado, alleging, among other things, breach of contract and breach of the covenant of good faith and fair dealing relating to amounts billed for certain goods and services provided to BP since 2005 (the “Services”). The Services relate to the installation of propane-fueled equipment and appliances, and the supply of propane, to approximately 400 residential customers at the request of and for the account of BP. The complaint seeks an unspecified amount of direct, indirect, consequential, special and compensatory damages, including attorneys’ fees, costs and interest and other appropriate relief. It also seeks an accounting to determine the amount of the alleged overcharges related to the Services. We have substantially completed our investigation of this matter and, based upon the results of that investigation, we believe we have good defenses to the claims set forth in the complaint and the amount of loss will not have a material impact on our results of operations and financial condition.
Antargaz Competition Authority Matter.On July 21, 2009, Antargaz received a Statement of Objections (“Statement”) from France’sFrance's Autorité de la concurrence (“Competition Authority”) with respect to the investigation of Antargaz by the General Division of Competition, Consumption and Fraud Punishment. The Statement alleged that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. 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 (€7.1) related to this matter which is reflected in “Other income, net” on the Fiscal 2009 Consolidated Statement of Income. On December 17, 2010, the Competition Authority issued its decision dismissing all objections against Antargaz. The appeal period has expired without an appeal having beenbeing filed. As a result of the decision, during the three-month period ended December 31, 2010, the Company reversed its previously recorded nontaxable accrual for this matter which increased Fiscal 2011 net income by $9.4.$9.4.
F-46
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
We cannot predict the final results of any of the environmental or other pending claims or legal 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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
results and cash flows. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. We believe, after consultation with counsel, the final outcome of such other matters will not have a material effect on our consolidated financial position, results of operations or cash flows.
Note 16 — Fair Value Measurements
Derivative Financial Instruments
The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of September 30, 20112012 and 2010:2011:
| | | | | | | | | | | | | | | | |
| | Asset (Liability) | |
| | Quoted Prices | | | | | | | | | | |
| | in Active | | | Significant | | | | | | | |
| | Markets for | | | Other | | | | | | | |
| | Identical Assets | | | Observable | | | Unobservable | | | | |
| | and Liabilities | | | Inputs | | | Inputs | | | | |
| | (Level 1) | | | (Level 2) | | | (Level 3) | | | Total | |
September 30, 2011: | | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | | |
Derivative financial instruments: | | | | | | | | | | | | | | | | |
Commodity contracts | | $ | 3.5 | | | $ | 3.3 | | | $ | — | | | $ | 6.8 | |
Foreign currency contracts | | $ | — | | | $ | 5.3 | | | $ | — | | | $ | 5.3 | |
Liabilities: | | | | | | | | | | | | | | | | |
Derivative financial instruments: | | | | | | | | | | | | | | | | |
Commodity contracts | | $ | (28.1 | ) | | $ | (16.1 | ) | | $ | — | | | $ | (44.2 | ) |
Foreign currency contracts | | $ | — | | | $ | (3.3 | ) | | $ | — | | | $ | (3.3 | ) |
Interest rate contracts | | $ | — | | | $ | (44.4 | ) | | $ | — | | | $ | (44.4 | ) |
| | | | | | | | | | | | | | | | |
September 30, 2010: | | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | | |
Derivative financial instruments: | | | | | | | | | | | | | | | | |
Commodity contracts | | $ | 1.1 | | | $ | 10.7 | | | $ | — | | | $ | 11.8 | |
Foreign currency contracts | | $ | — | | | $ | 0.8 | | | $ | — | | | $ | 0.8 | |
Liabilities: | | | | | | | | | | | | | | | | |
Derivative financial instruments: | | | | | | | | | | | | | | | | |
Commodity contracts | | $ | (49.4 | ) | | $ | (20.3 | ) | | $ | — | | | $ | (69.7 | ) |
Foreign currency contracts | | $ | — | | | $ | (2.9 | ) | | $ | — | | | $ | (2.9 | ) |
Interest rate contracts | | $ | — | | | $ | (18.5 | ) | | $ | — | | | $ | (18.5 | ) |
F-47
UGI Corporation and Subsidiaries
|
| | | | | | | | | | | | | | | |
| Asset (Liability) |
| Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Unobservable Inputs (Level 3) | | Total |
September 30, 2012: | | | | | | | |
Assets: | | | | | | | |
Derivative financial instruments: | | | | | | | |
Commodity contracts | $ | 8.6 |
| | $ | 4.5 |
| | $ | — |
| | $ | 13.1 |
|
Foreign currency contracts | $ | — |
| | $ | 1.8 |
| | $ | — |
| | $ | 1.8 |
|
Liabilities: | | | | | | | |
Derivative financial instruments: | | | | | | | |
Commodity contracts | $ | (7.8 | ) | | $ | (53.2 | ) | | $ | — |
| | $ | (61.0 | ) |
Interest rate contracts | $ | — |
| | $ | (71.9 | ) | | $ | — |
| | $ | (71.9 | ) |
| | | | | | | |
September 30, 2011: | | | | | | | |
Assets: | | | | | | | |
Derivative financial instruments: | | | | | | | |
Commodity contracts | $ | 3.5 |
| | $ | 3.3 |
| | $ | — |
| | $ | 6.8 |
|
Foreign currency contracts | $ | — |
| | $ | 5.3 |
| | $ | — |
| | $ | 5.3 |
|
Liabilities: | | | | | | | |
Derivative financial instruments: | | | | | | | |
Commodity contracts | $ | (28.1 | ) | | $ | (16.1 | ) | | $ | — |
| | $ | (44.2 | ) |
Foreign currency contracts | $ | — |
| | $ | (3.3 | ) | | $ | — |
| | $ | (3.3 | ) |
Interest rate contracts | $ | — |
| | $ | (44.4 | ) | | $ | — |
| | $ | (44.4 | ) |
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The fair values of our Level 1 exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The remainder of our derivative financial instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. There were no transfers between Level 1 and Level 2 during the periods presented.
Other Financial Instruments
The carrying amounts of other financial instruments included in current assets and current liabilities (except for and current maturities of long-term debt) approximate their fair values because of their short-term nature. At September 30, 2012, the carrying
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
amount and estimated fair value of our long-term debt (including current maturities) were $3,514.3 and $3,787.6, respectively. At September 30, 2011, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $2,157.7$2,157.7 and $2,223.4, respectively. At September 30, 2010, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $2,005.8 and $2,144.7,$2,223.4, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt.debt (Level 2).
Financial instruments other than derivative financial instruments, such as our short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit our credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 17.
Note 17 — Disclosures About Derivative Instruments and Hedging Activities
We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments 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 risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our derivative instruments generally qualify as hedges under GAAP or are subject to regulatory rate recovery mechanisms, we expect that changes in the fair value of derivative instruments used to manage commodity, interest rate or currency exchange rate risk would be substantially offset by gains or losses on the associated anticipated transactions.
Commodity Price Risk
In order to manage market price risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane principally during the months of October through March, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units and our International Propane operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. In addition, from time to time, the Partnership enters into price swap agreements to reduce short-term commodity price volatility and to provide market price risk support to some of its wholesale customers. These agreementscustomers which are generally not designated as hedges for accounting purposes and the volumes of propane subject to these agreements were not material.purposes.
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 20112012 and 2010,2011, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 15.119.2 million dekatherms and 19.515.1 million dekatherms, respectively. At September 30, 2011,2012, the maximum period over which Gas Utility is hedging natural gas market price risk is 1312 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets in accordance with FASB’s guidance in ASC 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 8).
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