Adjusted Operating Margin | | ( Adjusted Pretax Contribution: For a reconciliation of Adjusted PTC to net income from continuing operations, see Note 12 — Segments included in Item 1. — Financial Statements of this Form 10-Q.
Adjusted EPS | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Reconciliation of Adjusted Earnings Per Share | | 2014 | | 2013 | | 2014 | | 2013 | | | 2014 | | 2013 | | 2014 | | 2013 | | Diluted earnings per share from continuing operations | | $ | 0.20 |
| | $ | 0.22 |
| | $ | 0.13 |
| | $ | 0.37 |
| | | $ | 0.67 |
| | $ | 0.23 |
| | $ | 0.81 |
| | $ | 0.61 |
| | Unrealized derivative (gains) losses (1) | | (0.02 | ) | | (0.05 | ) | | (0.03 | ) | | (0.03 | ) | | | 0.01 |
| | — |
| | (0.02 | ) | | (0.04 | ) | | Unrealized foreign currency transaction (gains) losses (2) | | — |
| | 0.04 |
| | 0.03 |
| | 0.05 |
| | | 0.06 |
| | (0.02 | ) | | 0.07 |
| | 0.04 |
| | Disposition/acquisition (gains) losses | | — |
| | (0.03 | ) | (3) | — |
| | (0.03 | ) | (4) | | (0.51 | ) | (3) | — |
| | (0.51 | ) | (4) | (0.03 | ) | (5) | Impairment losses | | 0.09 |
| (5) | — |
| | 0.26 |
| (6) | 0.05 |
| (7) | | 0.08 |
| (6) | 0.18 |
| (7) | 0.34 |
| (8) | 0.23 |
| (9) | Loss on extinguishment of debt | | 0.01 |
| (8) | 0.17 |
| (9) | 0.14 |
| (10 | ) | 0.21 |
| (11) | | 0.06 |
| (10) | — |
| | 0.20 |
| (11 | ) | 0.20 |
| (12) | Adjusted earnings per share | | $ | 0.28 |
| | $ | 0.35 |
| | $ | 0.53 |
| | $ | 0.62 |
| | | $ | 0.37 |
| | $ | 0.39 |
| | $ | 0.89 |
| | $ | 1.01 |
| |
_____________________________ | | (1) | Unrealized derivative (gains) losses were net of income tax per share of $(0.01)$0.00 and $(0.02)$(0.01) in the three months ended JuneSeptember 30, 2014 and 2013, and of $(0.01) and $(0.02)$(0.03) in the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively. |
| | (2) | Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.00$0.03 and $0.00$(0.01) in the three months ended JuneSeptember 30, 2014 and 2013, and of $0.01$0.04 and $0.01 in the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively. |
| | (3) | Amount primarily relates to the gain from the sale of the remaining 20%a noncontrolling interest in Cartagena for $20Masinloc of $283 million ($15283 million, or $0.02$0.39 per share, net of income tax per share of $0.01).$0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per |
share of $0.00), the tax benefit of $12 million ($0.02 per share) associated with the agreement executed in September 2014 to sell a noncontrolling interest in our Dominican Republic businesses, and the tax expense of $4 million ($0.01 per share) related to the Silver Ridge Power transaction. | | (4) | Amount primarily relates to the gain from the sale of a noncontrolling interest in Masinloc of $283 million ($283 million, or $0.39 per share, net of income tax per share of $0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per share of $0.00), the tax benefit of $12 million ($0.02 per share) associated with the agreement executed in September 2014 to sell a noncontrolling interest in our Dominican Republic businesses, and the tax expense of $4 million ($0.01 per share) related to the Silver Ridge Power transaction. |
| | (5) | Amount primarily relates to the gain from the sale of the remaining 20% interest in Cartagena forof $20 million ($1514 million, or $0.02 per share, net of income tax per share of $0.01), the gain from the sale of wind turbines for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00), the gain from the sale of Trinidad for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00) as well as the gain from the sale of Chengdu, an equity method investment in China forof $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00). |
| | (5)(6)
| Amount primarily relates to the assetother-than-temporary impairment of our equity method investment at EbuteEntek of $52$18 million ($3412 million, or $0.05$0.02 per share, net of income tax per share of $0.02) and$0.01), the asset impairment at NewfieldEbute of $11$15 million ($6 million, or $0.00 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our equity method investment at Silver Ridge of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02). |
| | (6)
| Amount primarily relates to the goodwill impairments at DPLER of $136 million ($92 million, or $0.13 per share, net of income tax per share of $0.06), at Buffalo Gap of $18 million ($1823 million, or $0.03 per share, net of income tax per sharenoncontrolling interest of $0.00)$1 million and asset impairments at Ebute of $52 million ($34 million, or $0.05 per share, net of income tax per share of $0.02)$(0.01)), at Newfieldand a tax benefit of $11$25 million ($6 million, or $0.000.03 per share, net of income tax per share of $0.00),share) associated with the previously recognized goodwill impairment at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our equity method investment at Silver Ridge of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02).DPLER. |
| | (7) | Amount primarily relates to other-than-temporary impairment of our equity method investment at Elsta of $122 million ($89 million, or $0.12 per share, net of income tax per share of $0.04). Amount also includes asset impairment at Beaver ValleyItabo (San Lorenzo) of $46$15 million ($346 million, or $0.05$0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02). |
| | (8) | Amount primarily relates to the loss on early retirementgoodwill impairments at DPLER of debt$136 million ($117 million, or $0.16 per share, net of income tax per share of $0.03), and at CorporateBuffalo Gap of $13$18 million ($18 million, or $0.03 per share, net of income tax per share of $0.00), and asset impairments at Ebute of $67 million ($57 million, or $0.08 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01), at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.01), and at Newfield of $11 million ($6 million, or $0.00 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00) as well as the other-than-temporary impairments of our equity method investment at Silver Ridge Power of $42 million ($28 million, or $0.04 per share, net of income tax per share of $0.02) and at Entek of $18 million ($12 million, or $0.02 per share, net of income tax per share of $0.01). |
| | (9) | Amount primarily relates to the loss on early retirementother-than-temporary impairment of debtour equity method investment at CorporateElsta in the Netherlands of $163$122 million ($12189 million, or $0.16$0.12 per share, net of income tax per share of $0.06)$0.04). Amount also includes the asset impairment at Beaver Valley of $46 million ($33 million, or $0.04 per share, net of income tax per share of $0.02), the asset impairment at Itabo (San Lorenzo) of $15 million ($6 million, or $0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as the goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02). |
| | (10) | Amount primarily relates to the loss on early retirement of debt at Corporatethe Parent Company of $145$43 million ($9925 million, or $0.14$0.03 per share, net of income tax per share of $0.06)$0.03), at UK wind projects of $18 million ($14 million, or $0.02 per share, net of income tax per share of $0.01) and at Gener of $6 million ($3 million, or $0.00 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00). |
| | (11) | Amount primarily relates to the loss on early retirement of debt at Corporatethe Parent Company of $188 million ($123 million, or $0.17 per share, net of income tax per share of $0.09), at UK wind projects of $18 million ($14 million, or $0.02 per share, net of income tax per share of $0.01) and at Gener of $8 million ($4 million, or $0.01 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00). |
| | (12) | Amount primarily relates to the loss on early retirement of debt at the Parent Company of $165 million ($123120 million, or $0.16 per share, net of income tax per share of $0.06) and at Masinloc of $43 million ($29 million, or $0.04 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01). |
Operating Margin and Adjusted PTC Analysis US SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our US SBU for the periods indicated: | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | | ($’s in millions) | Operating Margin | | $ | 144 |
| | $ | 147 |
| | $ | (3 | ) | | -2 | % | | $ | 278 |
| | $ | 292 |
| | $ | (14 | ) | | -5 | % | | $ | 222 |
| | $ | 206 |
| | $ | 16 |
| | 8 | % | | $ | 500 |
| | $ | 498 |
| | $ | 2 |
| | — | % | Noncontrolling Interests Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Derivatives Adjustment | | — |
| | (13 | ) | | | | | | 9 |
| | — |
| | | | | | 5 |
| | 2 |
| | | | | | 14 |
| | 2 |
| | | | | Adjusted Operating Margin | | $ | 144 |
| | $ | 134 |
| | $ | 10 |
| | 7 | % | | 287 |
| | 292 |
| | $ | (5 | ) | | -2 | % | | $ | 227 |
| | $ | 208 |
| | $ | 19 |
| | 9 | % | | 514 |
| | 500 |
| | $ | 14 |
| | 3 | % | Adjusted PTC | | $ | 80 |
| | $ | 63 |
| | $ | 17 |
| | 27 | % | | $ | 155 |
| | $ | 196 |
| | $ | (41 | ) | | 21 | % | | $ | 156 |
| | $ | 132 |
| | $ | 24 |
| | 18 | % | | $ | 311 |
| | $ | 328 |
| | $ | (17 | ) | | 5 | % |
Operating marginMargin for the three months ended JuneSeptember 30, 2014 decreased $3increased $16 million, or 2%8%. This performance was driven primarily by the following businessesbusiness and key operating drivers: DPL decreased $19 million, primarily due to a $15 million impact from unrealized mark-to-market gains on derivatives in 2013 that did not recur, combined with a decrease in sales volumes, partially offset by an increase in retail rates. This decrease was partially offset by:
US GenerationOhio increased by $14 million, primarily due to $8regulatory retail rate increases and reduced fuel and purchase power costs of $41 million, relating to the implementationpartially offset by decreased retail sales of the synchronous condensers to provide ancillary services in June 2013 at Southland, $3$25 million due to the completion of
the Tait energy storage project at DPL in September 2013,resulting from customer switching and an increase in market prices relating to production at Laurel Mountain of $2 million. mild weather.
Adjusted Operating Margin increased $1019 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.non-controlling interests within operating margin. Adjusted PTC increased $1724 million driven by a $3$5 million gain recognized from proceeds relatingat Buffalo Gap, due to a bankruptcy settlement at Laurel Mountain,an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest (See Note 1 — General and Summary of Significant Accounting Policies — Noncontrolling Interests included in Item 8. — Financial Statements and Supplementary Data in the Company's 2013 Form 10-K) as well as the increase of $1019 million in Adjusted Operating Margin described above.
Operating marginMargin for the sixnine months ended JuneSeptember 30, 2014 decreased $14increased $2 million, or 5%0.4%. This performance was driven primarily by the following businesses and key operating drivers: DPL decreased $48US Generation increased by $32 million, primarily due to $11 million from increased availability as a result of fewer outages at Hawaii, $7 million relating to the implementation of the synchronous condensers to provide ancillary services in June 2013 and lower fixed costs at Southland, $8 million at Laurel Mountain due to increased market prices, and $8 million due to the September 2013 completion of the Tait energy storage project; and
IPL in Indiana increased $4 million driven by higher wholesale and retail margin of $13 million, partially offset by higher fixed costs and depreciation of $9 million. These increases were partially offset by: DPL decreased $34 million, primarily due to decreases of $31 million attributable to outages and lower gas availability, which resulted in higher purchased power and related costs to supply higher demand from cold weather during the first quarter as well as outages and lower gains on unrealized derivativederivatives of $13 million in the second quarter. This decrease was The results above were partially offset by:
US Generation increased by $33 million, primarily due to $11 millionimprovements in Q3 resulting from increased availability as a resultretail rates and lower fuel costs of fewer outages at Hawaii, $11 million relating to the implementation of the synchronous condensers to provide ancillary services in June 2013 at Southland, $8 million at Laurel Mountain due to increased market prices relating to production, and $6 million due to the completion 2013 of the Tait energy storage project in September 2013.$16 million.
Adjusted Operating Margin decreased $5increased $14 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.non-controlling interests within operating margin. Adjusted PTC decreased $41$17 million driven by net gains of $53 million recognized as a result of the early termination of the PPA and coal supply contract at Beaver Valley during the first quarter of 2013, partially offset by an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest at Buffalo Gap and Armenia Wind of $10 million, settlements at Laurel Mountain of $6 million, as well as the decreaseincrease of $5$14 million in Adjusted Operating Margin described above. Andes SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Andes SBU for the periods indicated: | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | | ($’s in millions) | Operating Margin | | $ | 148 |
| | $ | 148 |
| | $ | — |
| | — | % | | $ | 239 |
| | $ | 282 |
| | $ | (43 | ) | | -15 | % | | $ | 212 |
| | $ | 134 |
| | $ | 78 |
| | 58 | % | | $ | 451 |
| | $ | 416 |
| | $ | 35 |
| | 8 | % | Noncontrolling Interests Adjustment | | 32 |
| | 34 |
| | | | | | 56 |
| | 71 |
| | | | | | 53 |
| | 29 |
| | | | | | 109 |
| | 100 |
| | | | | Derivatives Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 116 |
| | $ | 114 |
| | $ | 2 |
| | — | % | | $ | 183 |
| | $ | 211 |
| | $ | (28 | ) | | -13 | % | | $ | 159 |
| | $ | 105 |
| | $ | 54 |
| | 51 | % | | $ | 342 |
| | $ | 316 |
| | $ | 26 |
| | 8 | % | Adjusted PTC | | $ | 104 |
| | $ | 88 |
| | $ | 16 |
| | 18 | % | | $ | 157 |
| | $ | 169 |
| | $ | (12 | ) | | 7 | % | | $ | 120 |
| | $ | 109 |
| | $ | 11 |
| | 10 | % | | $ | 277 |
| | $ | 278 |
| | $ | (1 | ) | | — | % |
Including the neutralunfavorable impact of foreign currency translation and remeasurement of $3 million, operating margin for the three months ended JuneSeptember 30, 2014 remained flat.increased $78 million, or 58%. This performance was driven primarily by the following businesses and key operating drivers: Chivor in Colombia increased $55 million as higher inflows resulted in higher generation and spot sales of $44 million as well as higher rates of $6 million. Gener in Chile increased $30 million due to higher coal and diesel availability of $19 million, and favorable contract and spot prices of $10 million in the SIC market. This increase was offset by: Argentina increaseddecreased $6 million driven by higher rates of $17 million related to the Resolution 529 adjustment (retroactive from February 2014), offset by higher fixed costs of $9 million mainly caused by inflation, adjustments. This increase was offset by:
Gener in Chile decreased $4 million due to lower spot prices and lower margins on Energy Plus contracts at Termoandesgeneration of $8$7 million, and lower contract prices at Norgenerunfavorable foreign exchange rate impact of $5$4 million, partially offset by lower fixed costs from lower maintenancehigher rates of $8 million; and
Chivor in Colombia decreased $2$16 million from higher fixed costs related to the tunnel maintenance, partially offset by higher ancillary services and spot prices.Resolution 529 adjustment.
Adjusted Operating Margin increased $254 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.
Adjusted PTC increased $1611 million, driven by the increase of $254 million in Adjusted Operating Margin described above, partially offset by a non-recurring benefit of $20 million from FONINVEMEM III interest income on receivables in 2013 in Argentina and lower realized foreign currency lossesequity in earnings at Guacolda in Chile of $15 million in Chile.$12 million. Including the unfavorable impact of foreign currency translation and remeasurement of $3$7 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased $43increased $35 million, or 15%8%. This performance was driven primarily by the following businesses and key operating drivers:
Chivor in Colombia increased $52 million largely driven by significantly higher generation of $51 million resulting in higher spot and contract sales and ancillary services. This increase was offset by: Gener in Chile decreased $44$14 million, largely driven by lower availability in the first quarter due primarily to planned outages of $22 million, a reduction of $39$29 million from lower contract prices, spot prices in the SADI and lower Energy Plus margin and lower availability of $6 million; partially offset by the contribution of $10 million from Ventanas IV, which commenced operations in March 2013, and lower fixed costs from lower maintenance and salaries of $9 million;$10 million. Chivor in ColombiaArgentina decreased $3$4 million driven by higher fixed costs as described above and lower foreign currency exchange rates,of $25 million driven by higher inflation; partially offset by higher prices and AGC sales; and
Argentina increased $3 million driven by higher rates of $17$21 million as a result of the impact of Resolution 529, partially offset by higher fixed costs of $16 million driven by higher inflation adjustment.529.
Adjusted Operating Margin decreased $28increased $26 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina. Adjusted PTC decreased $12$1 million, driven by the decreaseincrease of $28$26 million in Adjusted Operating Margin described above, partiallyprimarily offset by higher equity earningsa non-recurring benefit in 2013 from the sale of a transmission line of Guacolda and lower realized foreign currency losses in Chile.FONINVEMEM III interest income on receivables as discussed above. Brazil SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Brazil SBU for the periods indicated: | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | | ($’s in millions) | Operating Margin | | $ | 270 |
| | $ | 313 |
| | $ | (43 | ) | | -14 | % | | $ | 591 |
| | $ | 516 |
| | $ | 75 |
| | 15 | % | | $ | 44 |
| | $ | 306 |
| | $ | (262 | ) | | -86 | % | | $ | 635 |
| | $ | 822 |
| | $ | (187 | ) | | -23 | % | Noncontrolling Interests Adjustment | | 188 |
| | 223 |
| | | | | | 423 |
| | 372 |
| | | | | | 29 |
| | 208 |
| | | | | | 453 |
| | 580 |
| | | | | Derivatives Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 82 |
| | $ | 90 |
| | $ | (8 | ) | | -9 | % | | $ | 168 |
| | $ | 144 |
| | $ | 24 |
| | 17 | % | | $ | 15 |
| | $ | 98 |
| | $ | (83 | ) | | -85 | % | | $ | 182 |
| | $ | 242 |
| | $ | (60 | ) | | -25 | % | Adjusted PTC | | $ | 115 |
| | $ | 78 |
| | $ | 37 |
| | 47 | % | | $ | 184 |
| | $ | 120 |
| | $ | 64 |
| | 53 | % | | $ | — |
| | $ | 84 |
| | $ | (84 | ) | | -100 | % | | $ | 184 |
| | $ | 204 |
| | $ | (20 | ) | | 10 | % |
Including the unfavorable impact of foreign currency translation of $23 million, operating marginOperating Margin for the three months ended JuneSeptember 30, 2014 decreased $43$262 million, or 14%86%. This performance was driven primarily by the following businesses and key operating drivers:
Uruguaiana decreased $39 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation volumes from a temporary restart of operations;
Tietê decreased $12$202 million, driven by unfavorable foreign exchange rates of $16 million anddue to lower hydrology which led to lower generation volumes of $40 million as a result of low water inflows, partially offset byand an increase in energy purchases at higher spot prices of $45 million; andprices; Eletropaulo decreased $5$29 million due to higher fixed costs of $53$39 million, including higher payroll and pension expense, as well as higher depreciation and unfavorable impact of foreign exchange, partially offset by $59$15 million of higher rates as a result of the July 20132014 tariff adjustmentadjustment; and volume. These decreases were partially offset by:
Sul increaseddecreased by $13$26 million driven by lower volume and higher volumes from warmer weather of $10 million.fixed costs. Adjusted Operating Margin decreased $883 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê. Adjusted PTC increasedecreased $3784 million, asdue to the decrease of $883 million in Adjusted Operating Margin as described above was offset by the reversal of a loss contingency related to interest expense of $47 million at Sul that is no longer considered probable.above.
Including the unfavorable impact of foreign currency translation of $83 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 increased $75decreased $187 million, or 15%23%. This performance was driven primarily by the following businesses and key operating drivers: Tietê increased $74decreased $129 million, driven by a net impact of $142 million related to higher sales in the spot market, partially offset by lower contracted volumes of energy sold to Eletropaulo, and unfavorable foreign exchange rates of $61 million; Eletropaulo increased $24 million, driven by higher tariffs and volume of $99 million, partially offset by unfavorable foreign exchange rates of $17 million and the net impact of $61 million of lower hydrology which led to lower generation and an increase in energy purchases at higher fixed costs of $56 million; and
Sul increased $23 million, due to higher volume of $35 million,prices, partially offset by higher fixed cost expensespot sales in first half of $3 million mainly related to services,2014 due to the stormy weather, and unfavorable foreign exchange rateslower contracted volumes of $5 million.
These increases were partially offset by:energy sold;
Uruguaiana decreased $46$48 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation in 2014 during the period of temporary restart of operations.operations; Eletropaulo decreased $5 million, driven by higher fixed costs and depreciation of $103 million and unfavorable foreign exchange rates of $16 million, partially offset by higher tariffs and volume of $114 million; and Sul decreased $3 million, due to higher fixed cost and depreciation expense of $14 million mainly driven by storm related maintenance costs, lower rates of $10 million due to the April 2013 tariff reset, and unfavorable foreign exchange rates of $4 million, partially offset by higher volume of $26 million. Adjusted Operating Margin increased $24decreased $60 million primarily due to the drivers discussed above, adjusted for the impact of noncontrollingnon-controlling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.
Adjusted PTC increased $64decreased $20 million, driven by the increasedecrease of the $24$60 million in Adjusted Operating Margin described above and higher interest rates and debt, partially offset by the reversal of a loss contingency resulting from a change in estimate related to interest expense of $47 million at Sul that is no longer considered probable, partially offset by higher interest expense, as a result of an increase in interest rates.probable. MCAC SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our MCAC SBU for the periods indicated: | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | | ($’s in millions) | Operating Margin | | $ | 146 |
| | $ | 149 |
| | $ | (3 | ) | | -2 | % | | $ | 235 |
| | $ | 254 |
| | $ | (19 | ) | | -7 | % | | $ | 176 |
| | $ | 143 |
| | $ | 33 |
| | 23 | % | | $ | 411 |
| | $ | 397 |
| | $ | 14 |
| | 4 | % | Noncontrolling Interests Adjustment | | 17 |
| | 12 |
| | | | | | 10 |
| | 31 |
| | | | | | 20 |
| | 14 |
| | | | | | 30 |
| | 45 |
| | | | | Derivatives Adjustment | | (3 | ) | | (1 | ) | | | | | | (2 | ) | | (1 | ) | | | | | | — |
| | — |
| | | | | | (2 | ) | | (1 | ) | | | | | Adjusted Operating Margin | | $ | 126 |
| | $ | 136 |
| | $ | (10 | ) | | -7 | % | | $ | 223 |
| | $ | 222 |
| | $ | 1 |
| | — | % | | $ | 156 |
| | $ | 129 |
| | $ | 27 |
| | 21 | % | | $ | 379 |
| | $ | 351 |
| | $ | 28 |
| | 8 | % | Adjusted PTC | | $ | 95 |
| | $ | 104 |
| | $ | (9 | ) | | -9 | % | | $ | 160 |
| | $ | 160 |
| | $ | — |
| | 0% |
| | $ | 124 |
| | $ | 96 |
| | $ | 28 |
| | 29 | % | | $ | 284 |
| | $ | 256 |
| | $ | 28 |
| | 11 | % |
Including the unfavorable impact of currency translation of $1 million, operating margin for the three months ended JuneSeptember 30, 2014 decreased $3increased $33 million, or 2%23%. This performance was driven primarily by the following businesses and key operating drivers: Dominican Republic increased $23 million, mainly related to the favorable impact of rates of $29 million due to lower fuel prices, higher PPA prices, and higher prices of gas sales to third parties; and Panama decreased $8increased $12 million, driven by the Esti tunnel settlement agreement received during the second quarter of 2013 of $31 million, partially offset by a compensation from the government of Panama of $16$13 million related to spot purchases driven by dry hydrological conditions, as well as lower fixed costs of $7 million; and El Salvador decreased $4 million, due primarily to higher energy losses and other fixed costs.
This decrease was partially offset by:
Dominican Republic increased $11 million, mainly related to higher sales due to higher generation of $15 million, as well as higher availability during Q2 2014 of $9 million, partially offset by lower volume of gas sales to third parties of $8 million and higher fuel prices of $5 million.conditions.
Adjusted Operating Margin decreaseincreased $10$27 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina, 50% of Itabo in the Dominican Republic, and a weighted average of 75% of its businesses in El Salvador. Adjusted PTC decreaseincreased $928 million, driven by the decreaseincrease of $1027 million in Adjusted Operating Margin as described above.
Including the unfavorable impact of currency translation of $2$4 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased $19increased $14 million, or 7%4%. This performance was driven primarily by the following businesses and key operating drivers: Dominican Republic increased $59 million, mainly related to lower fuel costs of $31 million and higher PPA prices of $12 million, higher availability of $20 million and related lower maintenance expenses of $8 million, partially offset by lower gas sales to third parties of $11 million. This increase was partially offset by: Panama decreased $39$27 million, driven by dry hydrological conditions, which resulted in lower generation and higher energy purchases of $45$51 million and the Esti tunnel settlement agreement received during 2013 of $31 million, partially offset by compensation from the government of Panama of $23$36 million related to spot purchases from dry hydrological conditions, as well as lower fixed and other costs during 2014 of $14$17 million; and El Salvador decreased $18$15 million, due primarily to a one-time unfavorable adjustment to unbilled revenue, as well as higher energy losses and other fixed costs. This decrease was partially offset by:
Dominican Republic increased $36 million, mainly related to higher availability of $17 million, lower maintenance and other costs of $7 million and higher PPA prices of $12 million.
Mexico increased $5 million, mainly driven by higher availability.
Adjusted Operating Margin increased $1$28 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina, 50% of Itabo in the Dominican Republic, and a weighted average of 75% of its businesses in El Salvador. Adjusted PTC remained flat,increased $28 million, driven by the increase of $1$28 million in Adjusted Operating Margin described above, partially offset by lower equity in earnings from the Trinidad business, which was sold in 2013.above.
EMEA SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our EMEA SBU for the periods indicated: | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | | ($’s in millions) | Operating Margin | | $ | 77 |
| | $ | 86 |
| | $ | (9 | ) | | -10 | % | | $ | 210 |
| | $ | 200 |
| | $ | 10 |
| | 5 | % | | $ | 94 |
| | $ | 85 |
| | $ | 9 |
| | 11 | % | | $ | 304 |
| | $ | 285 |
| | $ | 19 |
| | 7 | % | Noncontrolling Interests Adjustment | | 5 |
| | 5 |
| | | | | | 11 |
| | 11 |
| | | | | | 7 |
| | 6 |
| | | | | | 18 |
| | 17 |
| | | | | Derivatives Adjustment | | (4 | ) | | — |
| | | | | | (4 | ) | | — |
| | | | | | 4 |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 68 |
| | $ | 81 |
| | $ | (13 | ) | | -16 | % | | $ | 195 |
| | $ | 189 |
| | $ | 6 |
| | 3 | % | | $ | 91 |
| | $ | 79 |
| | $ | 12 |
| | 15 | % | | $ | 286 |
| | $ | 268 |
| | $ | 18 |
| | 7 | % | Adjusted PTC | | $ | 73 |
| | $ | 72 |
| | $ | 1 |
| | 1 | % | | $ | 188 |
| | $ | 168 |
| | $ | 20 |
| | 12 | % | | $ | 79 |
| | $ | 66 |
| | $ | 13 |
| | 20 | % | | $ | 267 |
| | $ | 234 |
| | $ | 33 |
| | 14 | % |
Including the neutral impact of foreign currency translation, operating marginOperating Margin for the three months ended JuneSeptember 30, 2014 decreasedincreased $9 million, or 10%11%. This performance was driven primarily by the following businesses and key operating drivers:
Jordan increased $8 million as the IPP4 Jordan plant commenced operations in July 2014; Maritza (Bulgaria)in Bulgaria increased $8 million, driven by better availability of $5 million related to timing of scheduled outages and lower depreciation of $3 million; and Ebute in Nigeria increased $6 million primarily due to fewer outages of $2 million and lower depreciation of $2 million. These increases were partially offset by: Kilroot in the United Kingdom (U.K.) decreased $12$17 million driven by lower availability related to higher scheduled outages. This decrease was partially offset by:
Kilroot (United Kingdom "U.K.") increased $5 million driven by higherdispatch and rates of $6 million, including income from energy price hedges, and strengthening of the British Pound, partially offset by higher outages of $2$14 million.
Adjusted Operating Margin decreaseincreased $1312 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives. Adjusted PTC increased $113 million, as a result of the decreaseincrease of $1312 million in Adjusted Operating Margin described aboveabove. Including the unfavorable impact of foreign currency translation of $1 million, operating margin for the nine months ended September 30, 2014 increased $19 million, or 7%. This performance was driven primarily by the following businesses and key operating drivers: Jordan increased $8 million as the IPP4 Jordan plant commenced operations in July 2014; Ebute increased $7 million due to fewer outages of $6 million and lower depreciation; Kazakhstan increased $6 million driven by higher generation volumes and rates of $19 million, partially offset by unfavorable foreign exchange impact of $8 million; and Wind businesses in the U.K. increased $4 million, driven by higher contributions from Sixpenny Wood, Yelvertoft and Drone Hill, which were sold in August 2014. These results were partially offset by: Kilroot decreased $10 million, driven by lower dispatch and higher outages of $19 million, partially offset by higher rates of $11 million, including income from energy price hedges, and favorable foreign exchange impact. Adjusted Operating Margin increased $18 million due to the drivers above adjusted for non-controlling interests and excluding unrealized gains and losses on derivatives. Adjusted PTC increased $33 million, driven primarily by the increase of $18 million in Adjusted Operating Margin, as well as a reversal of a liability of $18 million in Kazakhstan from the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES. Including the favorable impact of foreign currency translation of $1 million, operating margin for the six months ended June 30, 2014 increased $10 million, or 5%. This performance was driven primarily by the following businesses and key operating drivers:
Kilroot (U.K.) increased $6 million, driven by higher rates, including income from energy price hedges, favorable FX,AES, partially offset by lower dispatch and higher outages;
Wind businesses (U.K.) increased $4 million, driven primarily by new business generation from Sixpenny Wood and Yelvertoft which commenced commercial operation in July 2013 and higher generation from Drone Hill;
Kazakhstan increased $3 million driven by higher generation volumes and rates, partially offset by unfavorable foreign currency; and
Ballylumford (U.K.) increased $2 million, due to higher volumes, partially offset by higher fixed costs.
These results were partially offset by:
Maritza (Bulgaria) decreased $6 million, driven primarily by higher scheduled outages, partially offset by higher rates.
Adjusted Operating Margin increased $6 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $20 million, driven primarily by the increase of $6 million in Adjusted Operating Margin, as well as a reversal of a liability in Kazakhstan as described above, partially offset by lower equity in earnings from Turkey.
Asia SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Asia SBU for the periods indicated: | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | | ($’s in millions) | Operating Margin | | $ | 27 |
| | $ | 45 |
| | $ | (18 | ) | | -40 | % | | $ | 37 |
| | $ | 83 |
| | $ | (46 | ) | | -55 | % | | $ | 12 |
| | $ | 38 |
| | $ | (26 | ) | | -68 | % | | $ | 49 |
| | $ | 121 |
| | $ | (72 | ) | | -60 | % | Noncontrolling Interests Adjustment | | 1 |
| | 3 |
| | | | | | 1 |
| | 5 |
| | | | | | 9 |
| | 2 |
| | | | | | 10 |
| | 7 |
| | | | | Derivatives Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 26 |
| | $ | 42 |
| | $ | (16 | ) | | -38 | % | | $ | 36 |
| | $ | 78 |
| | $ | (42 | ) | | -54 | % | | $ | 3 |
| | $ | 36 |
| | $ | (33 | ) | | -92 | % | | $ | 39 |
| | $ | 114 |
| | $ | (75 | ) | | -66 | % | Adjusted PTC | | $ | 23 |
| | $ | 40 |
| | $ | (17 | ) | | -43 | % | | $ | 31 |
| | $ | 71 |
| | $ | (40 | ) | | 56 | % | | $ | 2 |
| | $ | 30 |
| | $ | (28 | ) | | -93 | % | | $ | 33 |
| | $ | 101 |
| | $ | (68 | ) | | 67 | % |
Operating margin for the three months ended JuneSeptember 30, 2014 decreased by $1826 million, or 40%68%. This performance was driven primarily by the following businesses and key operating drivers: Masinloc (Philippines)in the Philippines decreased by $17$23 million driven by lower plant availability and related maintenance of $14 million and the net impact of lower spot sales and lower price of spot purchases of $2$18 million; and Kelanitissa (Sri Lanka)in Sri Lanka decreased by $5$6 million driven by the step down in the contracted PPA price.price and higher outages and maintenance costs. Adjusted Operating Margin decreased by $16$33 million due to the drivers above adjusted for the impact of non-controlling interests. AES owns 92%51% of Masinloc after the sell-down in mid-July 2014, and 90% of Kelanitissa. In the comparative period in 2013, AES owned 92% of Masinloc. Adjusted PTC decreased by $17$28 million, driven by the decrease of $16$33 million in Adjusted Operating Margin described above.above, partially offset by the impact of lower proportional interest expense at Masinloc, and OPGC higher equity earnings. Operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased by $46$72 million, or 55%60%. This performance was driven primarily by the following businesses and key operating drivers: Masinloc (Philippines)in the Philippines decreased by $41$64 million, driven by $20$33 million due to lower plant availability, an unfavorable impact of $15 million resulting from the market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013, higher fixed costs of $5 million primarily due to maintenance, and net impact of higher contract demand at lower prices and lower spot sales and lower price of spot purchases of $5$4 million; and Kelanitissa (Sri Lanka)in Sri Lanka decreased by $10$16 million driven by the step down in the contracted PPA price. Adjusted Operating Margin decreased by $42$75 million due to the drivers above adjusted for the impact of non-controlling interests. AES owns 92%51% of Masinloc after the sell-down in mid-July 2014, and 90% of Kelanitissa. In the comparative period in 2013, AES owned 92% of Masinloc. Adjusted PTC decreased by $40$68 million, driven by the decrease of $42$75 million in Adjusted Operating Margin described above, partially offset by the impact of lower proportional interest expense at Masinloc due to a 2013 debt refinancing.and gains on foreign currency. Key Trends and Uncertainties During the remainder of 2014 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors, a combination of factors, (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1. — Business and Item 1A. — Risk Factors of the 2013 Form 10-K. Regulatory Ohio—As noted in Item 1. — Business - United States— US SBU — Dayton Power & Light Company of the 2013 Form 10-K, an order was issued by the Public Utilities Commission of Ohio ("PUCO") in September 2013 (the “ESP Order”), which states that DP&L’s next ESP begins January 1, 2014 and extends through May 31, 2017. On March 19, 2014, the PUCO issued a second entry on rehearing ("Entry on Rehearing") which changes some terms of the ESP order. The Entry on Rehearing shortens the time by which DP&L must divest its generation assets to no later than January 1, 2016 from May 31, 2017 in the ESP Order. The Entry on Rehearing also terminates the potential extension of the Service Stability Rider on April 30, 2017 instead of May 31, 2017. In addition, the Entry on Rehearing accelerates DP&L’s phase-in of the competitive bidding structure to 10% in 2014, 60% in 2015 and 100% in 2016, compared to 10% in 2014, 40% in 2015, 70% in 2016 and 100% in June 2017 in the ESP Order. Parties, including DP&L, have filed applications for rehearing on this Commission Order, which were granted in the PUCO’s third entry on rehearing on May 7, 2014. On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the deadline by which DP&L must divest its generation assets to January 1, 2017. The Ohio Consumer's Counsel has filed an application for rehearing on this Order, which was denied by the PUCO. On June 30, 2014, several intervening parties filed a joint motion to stay collection of the Service Stability Rider while appeals are pending. This motion to stay was denied by the PUCO. The Industrial Energy Users of Ohio and the Ohio Consumer's Counsel filed Notices of Appeal of various aspects of the ESP Order and Entries on Rehearing to the Ohio Supreme Court on August 29, 2014 and September 22, 2014, respectively. On September 19, 2014, DP&L filed a Notice of Cross-appeal of the accelerated phase-in of the competitive bidding structure.
In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets on or before May 31, 2017. DP&L amended its application on February 25, 2014 and again on May 23, 2014. On September 17, 2014, the PUCO issued a Finding and Order in which it approved of DP&L’s plan to separate its generation assets with minor modifications. Specifically, DP&L’s request to defer costs associated with the Ohio Valley Electric Corporation (OVEC) which are not currently being recovered through existing rates was denied, and DP&L was ordered to transfer environmental liabilities with the generation assets. See Item 1. - — Business -— United States SBU -— Dayton Power & Light Company of the 2013 Form 10-K for further details of the ESP order and the filing to separate generation. Philippines—In November and December 2013, the Philippines spot market witnessed an unprecedented price spike compared to historical levels. On March 11, 2014, Energy Regulatory Commission ("ERC") declared the market prices from this period void and ordered the market operator to recalculate the prices for all market participants for November and December 2013 billing months. The recalculation of prices based on the load weighted average prices for the first nine months of 2013 resulted in an unfavorable adjustment of approximately $15 million to Masinloc spot sales. The ERC’s review of the motions for reconsideration filed by market participants including Masinloc is on-going. A secondary price cap was established for May and June 2014 and has been extended to mid-August,December, as a temporary measure to mitigate spot price impacts in the market. AtAs of this time the measure is expected to apply temporarilyhas not had a material impact on our business in 2014, in which case the impact may not be material.Philippines. However, if similar measures are implemented on a permanent basis, the impact could be material. Dominican Republic— In August 2014, the Superintendence of Electricity (Sectoral Regulatory Body of the Electricity Sector), modified the rules for offering primary frequency regulation service, an ancillary service item. The former rules allocated the service to generators based on merit order and those which were the most flexible and could enter the system quickly generally satisfied the supply requirement. The new rule assigns a mandatory minimum margin to all generators which must be provided by own source or through bilateral contracts with other generators who can offer the service, and any additional supply requirement must be allocated using the merit order process. As the AES businesses, Andres and Los Mina, were lower in the merit order they received a majority of the allocation under the former rules. The lower allocation of this service to these units under the new rules will have an impact of lowering the margin from frequency regulation which will be partially offset by higher energy dispatch. Operational Sensitivity to Dry Hydrological Conditions
Our hydroelectric generation facilities are sensitive to changes in the weather, particularly the level of water inflows into generation facilities. Throughout 2013 and 2014, dry hydrological conditions in Brazil, Panama, Chile and Colombia have presented challenges for our businesses in these markets. Low rainfall and water inflows caused reservoir levels to be below historical levels, reduced generation output, and increased prices for electricity. If our hydroelectric generation facilities cannot generate sufficient energy to meet contractual arrangements, we may need to purchase energy to fulfill our obligations, which could have a material adverse impact on our results of operations. Some local forecasts suggest continued dry conditions for the remainder of 2014. Once rainfall and water inflows return to normal levels, high market prices and low generation could persist until reservoir levels are fully recovered. In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels, and manages an Energythere is a mechanism called MRE (Energy Reallocation MechanismMechanism) created to share hydrological risk across all generators. If the system of hydroelectric generation facilities generates less than the assured energy of the system, the shortfall is shared among generators, and depending on a generator's contract level, is fulfilled with spot market purchases. We expect the system operator in Brazil to pursue a more conservative reservoir management strategy going forward, including the dispatch of up to 16 GW of thermal generation capacity, which could result in lower dispatch of hydroelectric generation facilities and electricity prices higher than historicalat high levels. During the first and second quarters of 2014, AES Tietê benefited from lower contract levels and captured spot sales at favorable prices. However, AES Tietê has higher contract obligations in the second half of 2014 and may needhas needed to fulfill some of these obligations with spot purchases, so itthey will be sensitive to generation output and spot prices for electricity during this period. Finally, if dry conditions persist in Brazil throughout 2014 and into the next rainy season, from NovemberDecember 2014 to April 2015, there is a risk that the
government of Brazil could implement a rationing program in 2015, which could have a material adverse impact on our results of operations and cash flows. In Panama, dry hydrological conditions continue to reduce generation output from hydroelectric facilities and have increased spot prices for electricity. From March to June 2014, the government of Panama implemented certain energy saving measures designed to reduce demand for electricity during the peak hours by approximately 300 MW, which contributed to water savings in the key hydroelectric dams and lower spot prices. AES Panama has had to purchase energy on the spot market to fulfill its contract obligations when its generation output is below its contract levels, and we expect this trend to continue for the remainder of the year. As authorized on March 31, 2014, the government of Panama agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70MW reduction in contracted capacity for the period
2014-2016 by compensating AES Panama for spot purchases up to $40 million in 2014, $30 million in 2015 and $30 million in 2016. Compensation payments recognized through September 30, 2014 were $36 million, of which $12 million are pending to be collected. AES owns 49% of AES Panama. Additionally, as part of our strategy to reduce our reliance on hydrology, AES Panama acquired a 72MW power barge for $26 million, financed with non-recourse debt, in September 2014, which we expect to become operational in the first quarter of 2015. Taxes Chilean Tax Reform On April 1,September 29, 2014, the Chilean government sent to Congress a bill proposingenacted comprehensive tax reforms. The proposed reforms would introducewhich introduced significant changes which, among others, include an increase in theto corporate income tax rate from 20% to 25% over a periodrates, modification of 4 years, the introduction of “Greenshareholder level income tax beginning in 2017, and new “green taxes” primarily over CO2 emissions and from 2017 a shareholder level tax on accrued profits rather than on actual dividends. The potential new legislation is being debatedalso beginning in Congress and could be subject to2017. See Note 17 — Income Taxes in Part I. Item 1. — Financial Statements of this Form 10-Q for further modification in the next several months. Should the bill be approved, the financial impact could be material.information. Macroeconomic and Political During the past few years, economic conditions in some countries where our subsidiaries conduct business have deteriorated. Global economic conditions remain volatile and could have an adverse impact on our businesses in the event these recent trends continue. Argentina — In Argentina, economic conditions are deteriorating, as measured by indicators such as non-receding inflation, diminishing foreign reserves, the potential for continued devaluation of the local currency, and a decline in economic growth. Many of these economic conditions in conjunction with the restrictions to freely access the foreign exchange currency established by the Argentine Government since 2012, have contributed to the development of a limited parallel unofficial foreign exchange market that is less favorable than the official exchange. At JuneSeptember 30, 2014, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank. See Note 6 — Financing Receivables in Part I Item 1. — Financial Statements of this Form 10-Q for further information on the long-term receivables. Although our businesses in Argentina have been able to access foreign currency for parts, equipment and equipmentfuel purchases and debt payments when needed, a further weakening of the Argentine Peso and local economic activity could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to the Parent Company, and the value of our assets. Argentina defaulted on its public debt in 2001, when it stopped making payments on about $100 billion amid a deep economic crisis. In 2005 and 2010, Argentina restructured its defaulted bonds into new securities valued at about 33 cents on the dollar. Between the two transactions, 93% of the bondholders agreed to exchange their defaulted bonds for new bonds. The remaining 7% did not accept the restructured deal. Since then, a certain group of the “hold-out” bondholders have been in judicial proceedings with Argentina regarding payment. More recently, the United States District Court ruled that Argentina would need to make payment to such hold-out bondholders according to the original applicable terms. Despite intense negotiations with the hold-out bondholders through the U.S. District Court appointed Special Master, on July 30, 2014 the parties failed to reach a settlement agreement and consequently (as referred by S&P and Fitch ratings) Argentina fell into a selective default resulting from failure to make interest payments on its Discount Bonds maturing in December 2033. Argentina has expressed thatAlthough this situation remains unresolved, it will attempt to reach a satisfactory settlement agreement to unlock the current situation. This situation has not caused any significant changes that impact our current exposures other than those that are discussed above in regards to the macroeconomics within the country. Bulgaria—Our investments in Bulgaria rely on offtaker contracts with NEK, the state-owned electricity public supplier and energy trading company. Maritza, a lignite-fired generation facility, has experienced ongoing delays in the collection of outstanding receivables as a result of liquidity issues faced by NEK. In November 2013, Maritza and NEK signed a rescheduling agreement for the overdue receivables as of November 12, 2013. Under the terms of the agreement, NEK paid $70 million of the overdue receivables and agreed to pay the remaining receivables in 13 equal monthly installments beginning December 2013. NEK has made payments according to the schedule through JulySeptember 2014. As of JuneSeptember 30, 2014, Maritza had outstanding receivables of $226 million, representing $43$50 million of current receivables, $30$14 million of the rescheduled receivables not yet due, $85$74 million of receivables overdue by less than 90 days and $69$88 million of receivables overdue by more than 90 days. On July 31, 2014 Maritza entered into a tripartite agreement with NEK and Mini Maritza Iztok EAD
(MMI), our fuel supplier, which reduced Maritza's outstanding receivables from NEK by $17.3$17 million through an offset of payables due by Maritza to MMI. Additionally, NEK has agreed to four additional monthly installments totaling $27.6$28 million to be paid equally from August to November, 2014. Maritza has also received payments on outstanding receivables of $14.5 million subsequent to June 30, 2014 which were not under the tripartite agreement. Although Maritza continued to collect overdue receivables during the secondthird quarter of 2014 and thereafter, there continue to be risks associated with collections, which could result in a write-off of the remaining receivables and/or liquidity problems which could impact Maritza's ability to meet its obligations, if the situation around collections were to deteriorate significantly. In May and June 2014, Bulgaria’s State Energy and Water Regulatory Commission (SEWRC) issued decisions precluding the ability of NEK to pass-through to the regulated market certain costs incurred by NEK pursuant to the PPA with Maritza,
which could further impactimpacted NEK's liquidity and its ability to make payments under the PPA. SEWRC also instructed NEK and Maritza to begin negotiating amendments to the PPA, including taking one of Maritza’s units out of the PPA and reducing the price of the remaining unit’s output by 30%. It is unclear whether NEK will abide by its obligations underHowever, SEWRC confirmed that until such negotiations conclude, the PPA or objectis in full force and effect and NEK has not objected to Maritza's invoices going forward.invoices. Maritza has filed appeals and requests for suspension of these SEWRC decisions with the Supreme Administrative Court in Bulgaria.Bulgaria with the first hearing scheduled for the beginning of 2015. In addition, SEWRC announced that it has asked the Directorate-General for Competition of the European Commission (DG Comp) to review NEK's respective PPAs with Maritza and a separate generator pursuant to European state aid rules, and to suspend the PPAs pending the completion of that review. DG Comp has not contacted Maritza about the SEWRC's request to date. On July 24, 2014, the Government of Bulgaria formally resigned.resigned and the Caretaker Government was appointed by the President. Preliminary Parliamentary Elections are scheduled forwere held on October 5, 2014 to put2014. Eight political parties were elected and are currently discussing the formation of a new government in place. Installation of the new governmentwhich is expected to allow the negotiations to continue in a productive manner. Meanwhile the Caretaker Government requested and received the resignations of the former Chairman and two commissioners of the Regulator. The new leadership approved an end-consumer energy price increase of approximately 10% effective October 1, 2014, which is expected to slightly improve NEK's liquidity. The Caretaker Government also established an Energy Board, which is consultative body comprised of members who have an interest in the energy sector, with the objective to discuss and propose measures to be taken for stabilization of the energy sector. Maritza is a member of the Energy Board. As a result of any of the foregoing events (including failure by NEK to honor its obligations under the PPA for any reason), we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value (including, without limitation, the value of receivables listed above) and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. For further information about the risks associated with the Company's investment in Maritza, see the following items in the Company's 2013 Form 10-K: Item 1— Business - EMEA; Item 1A. — Risk Factors of the 2013 Form 10-K — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and Item 7: Management's Discussion & Analysis - Key Risks and Uncertainties.Uncertainties. See Note 8 — Debt included in Part I Item 1. — Financial Statements of this Form 10-Q for further information on current existing debt defaults. Further, Maritza is in litigation related to construction delays and related matters. For further information on the litigation see Part II Item 1. — Legal Proceedings. Maritza will take all actions necessary to protect its interests, whether through negotiated agreement with NEK or through enforcement of its rights under the PPA. In addition, if necessary, Maritza will defend the PPA in any assessment or proceeding that may be initiated by DG Comp in response to SEWRC's request. As such, as of JuneSeptember 30, 2014, we concluded there is no indicator of an impairment of the long-lived assets in Bulgaria for Maritza, which were $1.4$1.3 billion and total debt of $797$720 million, and Kavarna, which were $280$256 million and total debt of $190$176 million. Therefore, there is no reason to believemanagement believes the carrying amount of the asset group was notis recoverable as of JuneSeptember 30, 2014. Puerto Rico— Our subsidiary in Puerto Rico has a long-term PPA with the Puerto Rico Electric Power Authority (“PREPA”), a state-owned entity that supplies virtually all of the electric power consumed in the Commonwealth and generates, transmits and distributes electricity to 1.5 million customers. As a result of macroeconomic challenges in the country, including a seven-year recession, PREPA faces economic challenges including, but not limited to reliance on high cost fuel oil, decline in electricity sales, high customer power rates, high operating costs, past due accounts receivables from government institutions, and very low liquidity along with challenges obtaining financing due to the recent downgrades, and has struggled to honor its payment obligations to electricity generators on a timely basis. As a result, AES Puerto Rico's receivables balance has increased toas of September 30, 2014 is $95 million, outstanding as of June 30, 2014, of which $27$33 million is overdue and days sales outstanding from PREPA has deteriorated, which has caused our business to start to be delayed in our payments to suppliers. Subsequent to JuneSeptember 30, 2014, the overdue receivables of $27$30 million have been collected. In February 2014, all agencies downgraded the Commonwealth of Puerto Rico and it's public sector companies (PREPA included) to below investment grade. On June 28, 2014, the Governor of Puerto Rico signed into law the Recovery Act, which allows public corporations to adjust their debts in the interest of all creditors, and establishes procedures for the orderly enforcement. With the recent passing of the Recovery Act, the ratings were further reduced. S&PThe downgrade on PREPA has yet to lowerhad a direct impact on AES Puerto Rico's bonds, except for Moody's which rates the Commonwealth's rating butbonds above the state-owned corporation given AES Puerto Rico is expected to do so in the near term.lowest cost producer of electricity. We believe that AES Puerto Rico’s unique position as the lowest cost energy producer and cost-effective alternative for PREPA relative to fuel oil generated power, positions the business well and reduces the probability of negative impacts from a potential PREPA restructuring process. However there can be no assurance as to the final terms of any restructuring or potential impacts on AES Puerto Rico. If AES Puerto Rico fails to receive payment in accordance with the terms of the PPA with PREPA, its liquidity issues could worsen, which could further impact AES Puerto Rico's ability to meet its obligations. See Item 1A. — Risk Factors of the
2013 Form 10-K — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and "We have a significant amount of debt, a large percentage of which is secured, which could adversely affect our business and the ability to fulfill our obligations." As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. Our Puerto Rico business will take all actions necessary to protect its interests, whether through negotiated agreement with PREPA or through enforcement of its rights under the PPA. In October 2014, the Parent Company reached an agreement with an investor in AES Puerto Rico's preferred shares to retire the investment at a fixed redemption value of $52 million. The redemption is expected to be completed by the end of 2014. As the events pertaining to the Recovery Act continue to
unfold, we concluded that there is no indicator of an impairment of the long-lived assets in Puerto Rico, which were $620$635 million and total debt of $584 million, and there is no reason to believe$594 million. Therefore, management believes the carrying amount of the asset group was notis recoverable as of JuneSeptember 30, 2014. If global economic conditions deteriorate further, it could also affect the prices we receive for the electricity we generate or transmit. Utility regulators or parties to our generation contracts may seek to lower our prices based on prevailing market conditions pursuant to PPAs, concession agreements or other contracts as they come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual price or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses. Impairments
Goodwill — Since its annual goodwill impairment test in the fourth quarter of 2013, the Company has been monitoring three reporting units, DP&L, DPLER and Buffalo Gap, as “at risk.” A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. In the first quarter of 2014, the Company recognized a full goodwill impairment of $136 million at DPLER and a goodwill impairment of $18 million at Buffalo Gap. The Company continues to monitor the remaining goodwill of $10 million at Buffalo Gap and the $316 million goodwill at DP&L. It is possible that the Company may incur goodwill impairment at DP&L, Buffalo Gap or any other reporting unit in future periods if certain events, such as, adverse changes in their business or operating environments occur. Environmental The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts) and certain air emissions, such as SOsulfur dioxide (SO2), NOnitrogen oxides (NOx), particulate matter (PM)and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A. —- Risk Factors, “Our“Our businesses are subject to stringent environmental laws and regulations,,” “Our“Our businesses are subject to enforcement initiatives from environmental regulatory agencies,,” and “Regulators,“Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows”flows” set forth in the Company’s Form 10-K for the year ended December 31, 2013.2013. The following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in Item 1. —- Business —- Regulatory Matters —- Environmental and Land Use Regulations of the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 and in Item 2. —- Management's Discussion and Analysis of Financial Condition and Results of Operations —- Key Trends and Uncertainties —- Regulatory —- Environmental of the Company'sCompany’s Quarterly ReportReports on Form 10-Q for the fiscal quarterquarters ended March 31, 2014 and June 30, 2014. UpdateTax on Greenhouse GasCarbon and Other Emissions Regulationsin Chile
In September 2014, the government of Chile enacted a carbon tax of $5.00 per ton of CO2, as well as taxes on emissions of PM, SO2 and NOx. The United States Environmental Protection Agency (“EPA”) issued proposed rules establishing greenhouse gas (“GHG”) performance standardsamount of the annual tax on PM, SO2 and NOx depends on volume and geographic location of the emissions, among other factors. This tax will be paid annually for existing power plants under Clean Air Act Section 111(d) on June 2, 2014. Under the proposed rule, states would be judged against state-specific carbon dioxide emissions targetsin the previous year, beginning in 2020, with expected total U.S. power section2018 for emissions reductionin 2017. The financial impact to the Company of 30% from 2005 levels by 2030. The proposed rule requires states to submit
implementation plans to meet the standards set forth in the rule by June 30, 2016, with the possibility of one or two-year extensions under certain circumstances. The proposed rule will be subject to a public comment process during the course of this year, after which time EPA is expected to finalize it by President Obama’s June 1, 2015 deadline. Among other things, the Company's U.S.-based businessesthese taxes could be required to make efficiency improvements to existing facilities. However, it is too soon to determine what the rule, and the corresponding state implementation plans affecting the Company’s U.S.-based businesses, will require once they are finalized, whether they will survive judicial and other challenges, and if so, whether and when the rule and the corresponding state implementations plan would materially impact the Company’s business, operations or financial condition.
In addition,material in October 2013, the U.S. Supreme Court granted certiorari for several cases that address EPA’s authority to issue GHG Prevention of Significant Deterioration (“PSD”) permits under Section 165 of the CAA. In June 2014, the U.S. Supreme Court ruled that EPA had exceeded its statutory authority in issuing the so-called “Tailoring Rule” under Section 165 of the CAA by regulating all sources that emitted GHGs. However, the U.S. Supreme Court also held that EPA could impose GHG Best Achievable Control Technology (“BACT”) requirements for sources already required to implement under PSD for other pollutants. Therefore, if future modifications to the Company's U.S.-based businesses' sources require PSD review for other pollutants, it may also trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHG and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of the U.S. Supreme Court’s ruling and GHG BACT requirements applicable to the operation of the Company's U.S.-based businesses cannot be determined at this time as these businesses are not required to implement BACT until they construct a new major source or make a major modification of an existing major source. However, the cost of compliance could be material.
Update on MATS
As further discussed in Item 1. Business — United States Environmental and Land Use Regulations — MATS in the Company's Form 10-K for the year ended December 31, 2013, several lawsuits challenging the Mercury Air Toxics Standards (“MATS”) were filed and consolidated into a single proceeding before the United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”). On April 15, 2014, a three-judge panel of the D.C. Circuit denied the challenges. Twenty-three states and certain industry groups have petitioned the United States Supreme Court to review the decision. We currently cannot predict whether the petition will be granted.
On June 20, 2014, IPL contemporaneously filed a waiver request/alternative complaint with the Federal Energy Regulatory Commission ("FERC") requesting a waiver that will allow IPL to keep 216 MW of reliable capacity available at its Eagle Valley generating station from June 1, 2015 through April 15, 2016. Both of these filings request that the FERC either waive or reform certain requirements of the Midcontinent Independent System Operator, Inc. market tariff for failing to address the specific circumstances resulting from compliance with MATS.
Update on Cooling Water Intake Structures Standards
As further discussed in Item 1. Business — United States Environmental and Land Use Regulations — Water Discharges in the Company's Form 10-K for the year ended December 31, 2013, the Company’s facilities are subject to the U.S. Clean Water Act Section 316(b) rule issued by the EPA which seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the “Best Technology Available” (“BTA”) for cooling water intake structures. On May 19, 2014, the EPA announced its final standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other industrial facilities. These standards require subject facilities that utilize at least 25% of the withdrawn water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day to choose among seven BTA options to reduce fish impingement. In addition, facilities that withdraw at least 125 million gallons per day for cooling purposes must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. This decision process would include public input as part of permit renewal or permit modification. It is possible this process could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility are required to reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards for entrainment. It is not yet possible to predict the total impacts of this recent final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.periods.
Update on Environmental Wastewater Requirements As discussed in Item 1. Business - United States Environmental and Land Use Regulations - Water Discharges in the Company's Form 10-K for the year ended December 31, 2013, certainDP&L is appealing various aspects of the Company’s U.S.-based businesses are subject toa National Pollutant Discharge Elimination System (“NPDES”) permit for J.M. Stuart Station issued by the Ohio EPA. NPDES permits that regulate specific industrial waste waterwastewater and storm water discharges to the watersinto a water of the United States under the FederalU.S. Clean Water Act (“CWA”). In June 2014, the EPA alongAct. It is believed that compliance with the U.S. Army Corpspermit as written will require capital expenses that will be material to DP&L. The cost of Engineers issuedcompliance and the timing of such costs is uncertain and may vary considerably depending on a proposed rule definingcompliance plan that would need to be developed, the waterstype of capital projects that may be necessary, and the uncertainties that may arise in the likely event that permits and approvals from other governmental entities would likely be required to construct and operate any such capital project. DP&L has appealed various aspects of the United States. This rulemakingfinal permit to the Environmental Review Appeals Commission and a hearing has been scheduled for March 2015. The compliance schedule in the potentialfinal permit has been modified to impact all programs underaccommodate the CWA. Expansion of regulated waterways is possible based on initial reviewtiming of the proposal, which may impact several permitting programs. Although we cannot at this time determine the timing or impacthearing. The outcome of compliance with any new regulations, more stringent regulations could have a material impact on our operations and/or consolidated financial results.such appeal is uncertain. Update on the CSAPR
As furtherAlso as discussed in Item 1. 1. Business —- United States Environmental and Land Use Regulations — CAIR and CSAPR - Water Dischargesin the Company's Form 10-K for the year ended December 31, 2013, in responsethe Indiana Department of Environmental Management (“IDEM”) issued NPDES permits to the D.C. Circuit’s striking down muchIPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. These permits set new water quality-based levels of acceptable metal effluent water discharges for the EPA’s Clean Air Interstate Rule (“CAIR”)Petersburg and remanding itHarding Street facilities, as well as monitoring and other requirements designed to protect aquatic life, with full compliance with the new metal effluent limitations required by October 2015. IPL received an extension to the EPA, the EPA issued a new rule in July 2011 titled “Federal Implementation Planscompliance deadline through September 2017 for IPL’s Harding Street and Petersburg facilities through agreed orders with IDEM. IPL conducted studies to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, the CSAPR would have required significant reductions in SO2 and NOx emissions from covered sources, such as power plants, in certain states in which subsidiaries of the Company operate. Once fully implemented (originally planned for 2014), the rule would requiredetermine what operational changes and/or additional SO2 emission reductions of 73% and additional NOx reductions of 54% from 2005 levels. The CSAPR would be implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of new emissions allowances that the EPAequipment will create. The CSAPR contemplates limited interstate and intra-state trading of emissions allowances by covered sources. Initially, the EPA would issue emissions allowances to affected power plants based on state emissions budgets established by the EPA under the CSAPR. The future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time.
Upon petitions for review filed by many states, utilities and other affected parties, the D.C. Circuit vacated the CSAPR in August 2012 and required the EPA to continue administering CAIR pending the promulgation of a valid replacement to the CSAPR. Prior to this decision, the D.C. Circuit had granted a stay of the CSAPR. On April 29, 2014, the United States Supreme Court upheld the CSAPR, reversing the D.C. Circuit Court’s decision to vacate the CSAPR.
It is difficult to predict the steps that will follow this ruling. There remain numerous challenges to the CSAPR that must be addressed, some of which could again result in delay or invalidation of the CSAPR. On June 26, 2014, EPA filed a motion in the D.C. Circuit requesting that the court lift the stay of the CSAPR. EPA also requested that the court extend CSAPR’s compliance deadlines by three years, so that the Phase 1 emissions budgets that were to begin in 2012 would now apply starting in 2015, and the Phase 2 emissions that were to begin in 2014 would apply starting in 2017. The multiple parties to the litigation have filed oppositions to EPA’s motion to lift the stay and all parties have filed motions to govern further proceedings. If the D.C. Circuit grants EPA’s motion, the Company anticipates an increase in capital costs and other expenditures and operational restrictions that would be required to comply with the new limitations. On August 15, 2014, IPL announced its intent to file plans with the IURC to refuel Unit 7 at Harding Street from coal-fired to natural gas. This conversion is part of IPL's overall wastewater compliance plan for its power plants. On October 16, 2014, IPL filed its wastewater compliance plans with the IURC. IPL is seeking approval for a reinstated CSAPR. AtCertificate of Public Convenience and Necessity (CPCN) to install and operate wastewater treatment technologies at its Petersburg and Harding Street plants. If approved, IPL will invest $332 million in these projects to ensure compliance with the wastewater treatment requirements by 2017. IPL expects to recover through its environmental rate adjustment mechanism, operating or capital expenditures related to compliance with these NPDES permit requirements. Recovery of these costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding; however, there can be no assurances that IPL will be successful in that regard. In light of the uncertainties at this time, we cannot predict the impact that such rules would haveof these permit requirements on the Company; they could have a material impact on the Company's business,our consolidated results of operations, cash flows, or financial condition, and results of operations.
IPL Unit Retirement and Replacement Generation
As discussed in Item 1. Business — United States Environmental and Land Use Regulations — Unit Retirement and Replacement Generation in the Company's Form 10-K for the year ended December 31, 2013, in April 2013, IPL filed a petition and case-in-chief with the IURC seeking a CPCN to build a 550 MW to 725 MW combined cycle gas turbine (“CCGT”) at its Eagle Valley generating station and to refuel its Harding Street generating station Units 5 and 6 from coal to natural gas (about 100MW each). In May 2014, the IURC issued an order on the CPCN authorizing the refueling project and granting approval to build a 644 to 685 MW CCGT at a total budget of $649 million. The current estimated cost of these projects is $626 million. IPL was granted authority to accrue post in-service allowance for debt and equity funds used during construction and to defer the recognition of depreciation expense of the CCGT and refueling project until such time that we are allowed to collect both a return and depreciation expense on the CCGT and refueling project. The CCGTbut it is expected to be placed into service in April 2017, and the refueling project is expected to be completed in early 2016. The costs to build and operate the CCGT and for the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after the assets have been placed in service.material.
Capital Resources and Liquidity Overview As of JuneSeptember 30, 2014, the Company had unrestricted cash and cash equivalents of $1.51.7 billion, of which approximately $15229 million was held at the Parent Company and qualified holding companies, and approximatelycompanies. The Company had $424686 million was held in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $1.0 billion967 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.915.7 billion and $5.85.3 billion, respectively. Of the approximately $2.12.3 billion of our current non-recourse debt, $1.1$1.4 billion was presented as such because it is due in the next twelve months and $1.00.9 billion relates to debt considered in default due to covenant violations. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks. Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated
long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company’s only material un-hedged exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility and floating rate senior unsecured notes due 2019. On a consolidated basis, of the Company’s $15.915.7 billion of total non-recourse debt outstanding as of JuneSeptember 30, 2014, approximately $3.94.1 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate. In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At JuneSeptember 30, 2014, the Parent Company had provided outstanding financial and performance-related guarantees, indemnities or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $620 million$1.0 billion in aggregate (excluding those collateralized by letters of credit and other obligations discussed below). As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At JuneSeptember 30, 2014, we had $1 million in letters of credit outstanding, provided under our senior secured credit facility, and $10297 million in cash collateralized letters of credit outstanding outside of our senior secured credit facility. These letters of credit operate to guarantee performance relating to certain project development activities and business operations. During the quarter ended JuneSeptember 30, 2014, the Company paid letter of credit fees ranging from 0.2% to 2.5% per annum on the outstanding amounts. We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has
near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary. Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses. As of JuneSeptember 30, 2014, the Company had approximately $258246 million and $3924 million of accounts receivable related to certain of its generation businesses in Argentina and the Dominican Republic and its utility businesses in Brazil classified as “Noncurrent assets — other” and “Current assets — Accounts receivable,” respectively. The noncurrent portion primarily consists of accounts receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond JuneSeptember 30, 2014, or one year from the latest balance sheet date. The majority of Argentinian receivables have been converted into long-term financing for the construction of power plants. See Note 6 — Financing Receivables included in Part I Item 1. — Financial Statements of this Form 10-Q and Item 1. — Business — Regulatory Matters — Argentina included in the 2013 Form 10-K for further information. Consolidated Cash Flows During the sixnine months ended JuneSeptember 30, 2014,, cash and cash equivalents decreaseincreased $127$28 million to $1.5$1.7 billion. The decreaseincrease in cash and cash equivalents was due to $453 million1.2 billion of cash provided by operating activities, $391364 million of cash used
in investing activities, $250844 million of cash used in financing activities, an unfavorable effect of foreign currency exchange rates on cash of $1455 million and a $75 million decrease in cash of discontinued and held-for-sale businesses. Operating Activities — Net cash provided by operating activities decreased $732824 million to $453 million during the six months endedJune 30, 2014 compared to $1.2 billion during the sixnine months ended JuneSeptember 30, 2014 compared to $2 billion during the nine months endedSeptember 30, 2013. This performance was driven primarily by the following SBUs and key operating activities: Brazil — a decrease of $505 million primarily at Eletropaulo and Sul due to higher prices of energy purchases as well as higher taxes; MCAC — a decrease of $179 million at our generation businesses primarily due to higher working capital requirements; and EMEA — a decrease of $94 million primarily due to higher working capital requirements. OperatingNet cash flow forprovided by operating activities was $1.2 billion during the sixnine months ended JuneSeptember 30, 2014. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization, impairment expenses and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $1 billion in operating assets and liabilities. This net use of cash forwithin operating activities of $1 billion was primarily due to the following:
an increase of $316494 million in accounts receivable primarily related to higher sales at Eletropaulo, Sul and Alicura and lower collections at Maritza; an increase of $439 million in other assets primarily related to increased regulatory assets at Eletropaulo and Sul resulting from higher priced energy purchases recoverable through future tariffs; an increase of $312 million in accounts receivable primarily related to higher sales at Sul, Alicura and Gener, return of operations at Uruguaiana in March 2014 and lower collections at Maritza;
a decrease of $194 million in accounts payable and other current liabilities primarily at Eletropaulo relating to a decrease in regulatory liabilities; a decrease of $176239 million in net income tax and other tax payables primarily related to payments of income taxes exceeding accruals for the 2014 tax liability.liability; partially offset by
an increase of $319 million in other liabilities primarily related to an increase in regulatory liabilities at Eletropaulo and Sul partially offset by reduced pension contributions at IPL and payments for share-based compensation issuance tax and derivative termination at the Parent Company. Net cash provided by operating activities was $1.22.0 billion during the sixnine months ended JuneSeptember 30, 2013. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $310255 million in operating assets and liabilities. This net use of cash forwithin operating activities of $310$255 million was primarily due to: a decrease of $252$578 million in accounts payable and other current liabilities primarily at Eletropaulo and Sul due to lower costs and a decrease in regulatory liabilities and a decrease in value added taxes payables due to the lower tariff in 2013 andas well as at Uruguaiana primarily related to the extinguishment of a liability based on a favorable arbitration decision; an increase of $147$149 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo and Sul, resulting from higher priced energy purchases which are recoverable through future tariffs; partially offset bya decrease of $134$403 million in net income taxprepaid expenses and other tax payablescurrent assets primarily from payment of income taxes exceeding accrualsdue to a decrease in current regulatory assets, for the tax liability on 2013 income, partially offset by an accrualrecovery of indirect taxes in Brazil; partially offset by prior-period tariff cycle energy purchases and transportation costs at Eletropaulo and Sul; anda decrease of $191$135 million in accounts receivable primarily duerelated to lower tariffs in 2013 at Eletropaulo and higher collections combined with lower tariffs and reduced consumption at Sul, partially offset by lower collections at Maritza.
The net decrease of cash flows from operating activities of $732 million for the six months endedJune 30, 2014 compared to the six months endedJune 30, 2013 was primarily the result of the following:
Brazil — a decrease of $442 million primarily at Eletropaulo and Sul due to higher prices of energy purchases as well as higher taxes and interest on debt.
US — a decrease of $160 million primarily due to proceeds from the PPA termination at Beaver Valley in January 2013 and lower operating results and higher working capital requirements at DPL.
MCAC — a decrease of $154 million at our generation businesses primarily due to higher working capital requirements.
Investing Activities — Net cash used in investing activities was $391364 million during the sixnine months ended JuneSeptember 30, 2014 primarily attributable to the following: Capital expenditures of $908 million1.4 billion consisting of $536$789 million of growth capital expenditures and $372$600 million of maintenance and environmental capital expenditures. Growth capital expenditures primarily included amounts at Gener of $250$303 million, Eletropaulo of $83$125 million,Vietnam Mong Duong of $45$72 million, Jordan of $71 million, IPL of $61 million and Jordan $38Sul of $35 million. Maintenance and environmental capital expenditures primarily included amounts at IPL of $105$178 million, Eletropaulo of $42$73 million, Tietê of $40$64 million, Gener of $50 million, DPL of $48 million and DPLSul of $32 million.$41 million; Acquisitions, net of cash acquired of $728 million consisted of an acquisition at Gener in the second quarter for the remaining 50% interest in our equity investment in Guacolda, of which 50% less one share was subsequently sold during the same quarter. See Note 7 — Investment in and Advances to Affiliates in Item 1. — Financial Statements of this Form 10-Q for further information. These amounts wereinformation; partially offset by Proceeds from the sale of businesses of $890 million with$1.7 billion including $730 million at Gener related to the sale of 50% less one share of our interest in Guacolda, $443 million for the sale of 45% of our equity interest in Masinloc, $179 million related to the the sale of AES’ interest in Silver Ridge Power’s assets in Bulgaria, France, Greece, India and $160the United States and $156 million from the sale of our businessesbusiness in Cameroon,Cameroon; and
Decreases in restricted cash, debt service reserves and other assets of $162 million including amounts at the USParent Company of $66 million, Maritza of $44 million and India; and SalesAlto Maipo of short-term investments, net of purchases of $273 million primarily in Brazil.$37 million.
Net cash used in investing activities was $706 million1.3 billion during the sixnine months ended JuneSeptember 30, 2013. This was primarily attributable to the following: Capital expenditures of $866 million$1.3 billion consisting of $454$690 million of growth capital expenditures and $412$640 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Eletropaulo of $138$188 million, Gener of $81$166 million, Jordan of $54$95 million, Sul of $44$57 million, Sixpenny WoodDPL of $22$28 million, Mong Duong of $19$27 million, Yelvertoft of $20 million, Kribi of $17 million and YelvertoftAltai of $19$16 million. Maintenance and environmental capital expenditures included amounts at IPALCOIPL of $87$164 million, Eletropaulo of $72$103 million, DPL of $63 million, Gener of $47$61 million, DPLTietê of $46$53 million, Sul of $39$50 million, Altai of $21 million and Itabo of $15 million; Purchase of short-term investments, net of sales of $263 million including amounts at Eletropaulo of $212 million, Sul of $32 million and Tietê of $30$29 million; partially offset by Proceeds from the sale of business, net of cash sold of $135$167 million including $113 million for the sale of the Ukraine businesses, $31 million for the sale of our 10% equity interest in Trinidad and $24 million for the sale of our remaining interest in Cartagena.
Net cash used in investing activities decreased $315903 million to $391364 million during the sixnine months ended JuneSeptember 30, 2014 compared to net cash used in investing activities of $706 million1.3 billion during the sixnine months ended JuneSeptember 30, 2013. This net decrease was primarily due to an increase in proceeds from the sale of business, net of cash sold of $1.5 billion, a decrease in purchases of short-term investments, net of sales of $343212 million, partially offset by an increase in acquisitions of $725 million. Financing Activities — Net cash used in financing activities was $250844 million during the sixnine months ended JuneSeptember 30, 2014. This was primarily attributable to the following: Payments for financed capital expenditures of $312 million, primarily at Mong Duong with $272 million in payments to the contractors, which took place more than three months after the associated equipment was purchased or work performed;
Distributions to minority interests of $197 million primarily at Tietê with $109 million; and
Repayments of recourse and non-recourse debt of $3.03.7 billion including amounts at the Parent Company of $1.7$2 billion, Gener of $853$905 million, Tietê of $132 million, Maritza of $65 million, Shady Point of $52 million, Puerto Rico of $51 million and Puerto Rico$114 million related to the UK Wind sale; Distributions to noncontrolling interests of $42$377 million including amounts at Tietê of $188 million, Brasiliana Energia of $65 million, Gener of $35 million and Buffalo Gap of $33 million; Payments for financed capital expenditures of $360 million primarily at Mong Duong of $272 million; partially offset by Issuances of recourse and non-recourse debt of $3.23.8 billion, including new issuances at the Parent Company of $1.5 billion, Gener of $700 million, Mong Duong of $298 million, Eletropaulo of $253 million, Cochrane of $173 million, IPL of $130 million and Tietê of $129 million; and a draw down under construction loan facility at Mong Duong of $272 million. Net cash used in financing activities was $799635 million during the sixnine months ended JuneSeptember 30, 2013. This was primarily attributable to the following:
Payments for financed capital expenditures of $257 million, primarily at Mong Duong for payments to the contractors, which took place more than three months after the associated equipment was purchased or work performed;
Distributions to noncontrolling interests of $211 million included amounts at Tietê of $98 million, Brasiliana of $34 million, Buffalo Gap of $25 million, and Gener of $18 million;
Payments for financing fees of $127 million included amounts at Cochrane of $41 million, Eletropaulo of $25 million, and Mong Duong of $13 million; and
Repayments of recourse and non-recourse debt of $3.4$3.5 billion primarilyincluded amounts at the Parent Company of $1.2 billion, Masinloc of $546 million, DPL of $425 million, Tietê of $396 million, El Salvador of $301 million, IPL of $110 million, Warrior Run of $87$93 million, Puerto Rico of $52$65 million, Maritza of $57 million, Sonel of $46 million and Sul of $37$40 million; Payments for financed capital expenditures of $436 million, primarily at Mong Duong for payments to the contractors which took place more than three months after the associated equipment was purchased or work performed; Distributions to noncontrolling interests of $385 million included amounts at Tietê of $154 million, Brasiliana Energia of $96 million, Gener of $39 million and MaritzaBuffalo Gap of $29$19 million; Payments for financing fees of $148 million included amounts at Cochrane of $42 million, Eletropaulo of $25 million, Mong Duong of $20 million and the Parent Company of $17 million; partially offset by Issuances of recourse and non-recourse debt of $3.1$3.8 billion,, including amounts at the Parent Company for $750 million, DPL of $645 million, Masinloc of $500 million, Tietê of $496 million, Mong Duong of $339 million, El Salvador of $310 million, Mong Duong of $210 million, DPL of $200 million, IPL of $170 million, Sul of $150 million, Jordan of $138 million, Cochrane of $82$120 million,Warrior Run of $74 million and Kribi of $63 million; and Contributions from noncontrolling interests of $157 million including amounts at Mong Duong of $55 million, Alto Maipo of $50 million and JordanCochrane of $61$34 million. Net cash used in financing activities decreasedincreased $549209 million to $250844 million during the sixnine months ended JuneSeptember 30, 2014 compared to net cash used in financing activities of $799635 million during the sixnine months ended JuneSeptember 30, 2013. This net decreaseincrease was primarily due to a decreasean increase in the repayments of recourse and non-recourse debt of $363 million and an increase in the issuance of recourse and non-recourse debt of $102162 million.
Proportional Free Cash Flow (a non-GAAP measure) We define Proportional Free Cash Flow as cash flows from operating activities less maintenance capital expenditures (including non-recoverable environmental capital expenditures), adjusted for the estimated impact of noncontrolling interests. The proportionate share of cash flows and related adjustments attributable to noncontrolling interests in our subsidiaries comprise the proportional adjustment factor presented in the reconciliation below. We exclude environmental capital expenditures that are expected to be recovered through regulatory, contractual or other mechanisms. An example of recoverable environmental capital expenditures is IPL's investment in MATS-related environmental upgrades that are recovered through a tracker. See Item 1. Business— US SBU — IPALCO — Environmental Matters in the 2013 Form 10-K for details of these investments. The GAAP measure most comparable to proportional free cash flow is cash flows from operating activities. We believe that proportional free cash flow better reflects the underlying business performance of the Company, as it measures the cash generated by the business, after the funding of maintenance capital expenditures, that may be available for investing or repaying debt or other purposes. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly-owned by the Company. The presentation of free cash flow has material limitations. Proportional free cash flow should not be construed as an alternative to cash from operating activities, which is determined in accordance with GAAP. Proportional free cash flow does not represent our cash flow available for discretionary payments because it excludes certain payments that are required or to which we have committed, such as debt service requirements and dividend payments. Our definition of proportional free cash flow may not be comparable to similarly titled measures presented by other companies
| | | | Three months ended June 30, | | Six months ended June 30, | | Three months ended September 30, | | Nine months ended September 30, | | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 | | 2013 | | | (in millions) | | (in millions) | Calculation of Maintenance Capital Expenditures for Free Cash Flow Reconciliation Below: | | | | | | | | | | | | | | | | | Maintenance Capital Expenditures | | $ | 152 |
| | $ | 174 |
| | $ | 289 |
| | $ | 360 |
| | $ | 169 |
| | $ | 166 |
| | $ | 458 |
| | $ | 526 |
| Environmental Capital Expenditures | | 77 |
| | 42 |
| | 111 |
| | 73 |
| | 62 |
| | 72 |
| | 172 |
| | 145 |
| Growth Capital Expenditures | | 414 |
| | 354 |
| | 820 |
| | 690 |
| | 298 |
| | 405 |
| | 1,119 |
| | 1,095 |
| Total Capital Expenditures | | $ | 643 |
| | $ | 570 |
| | $ | 1,220 |
| | $ | 1,123 |
| | $ | 529 |
| | $ | 643 |
| | $ | 1,749 |
| | $ | 1,766 |
| Consolidated | | | | | | | | | | | | | | | | | Net cash provided by operating activities | | $ | 232 |
| | $ | 567 |
| | $ | 453 |
| | $ | 1,185 |
| | $ | 763 |
| | $ | 855 |
| | $ | 1,216 |
| | $ | 2,040 |
| Less: Maintenance Capital Expenditures, net of reinsurance proceeds | | 152 |
| | 174 |
| | 289 |
| | 360 |
| | 169 |
| | 166 |
| | 458 |
| | 526 |
| Less: Non-recoverable Environmental Capital Expenditures | | 25 |
| | 26 |
| | 36 |
| | 47 |
| | 16 |
| | 22 |
| | 52 |
| | 69 |
| Free Cash Flow | | $ | 55 |
| | $ | 367 |
| | $ | 128 |
| | $ | 778 |
| | $ | 578 |
| | $ | 667 |
| | $ | 706 |
| | $ | 1,445 |
| Reconciliation of Proportional Operating Cash Flow | | | | | | | | | | | | | | | | | Net cash provided by operating activities | | $ | 232 |
| | $ | 567 |
| | $ | 453 |
| | $ | 1,185 |
| | $ | 763 |
| | $ | 855 |
| | $ | 1,216 |
| | $ | 2,040 |
| Less: Proportional Adjustment Factor (1) | | 64 |
| | 263 |
| | 44 |
| | 367 |
| | 208 |
| | 327 |
| | 251 |
| | 694 |
| Proportional Operating Cash Flow | | $ | 168 |
| | $ | 304 |
| | $ | 409 |
| | $ | 818 |
| | $ | 555 |
| | $ | 528 |
| | $ | 965 |
| | $ | 1,346 |
| Proportional | | | | | | | | | | | | | | | | | Proportional Operating Cash Flow | | $ | 168 |
| | $ | 304 |
| | $ | 409 |
| | $ | 818 |
| | $ | 555 |
| | $ | 528 |
| | $ | 965 |
| | $ | 1,346 |
| Less: Proportional Maintenance Capital Expenditures, net of reinsurance proceeds (1) | | 102 |
| | 121 |
| | 206 |
| | 258 |
| | 116 |
| | 114 |
| | 322 |
| | 372 |
| Less: Proportional Non-recoverable Environmental Capital Expenditures (1) | | 19 |
| | 18 |
| | 27 |
| | 34 |
| | 12 |
| | 17 |
| | 39 |
| | 51 |
| Proportional Free Cash Flow | | $ | 47 |
| | $ | 165 |
| | $ | 176 |
| | $ | 526 |
| | $ | 427 |
| | $ | 397 |
| | $ | 604 |
| | $ | 923 |
|
(1) The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds), and proportional non-recoverable environmental capital expenditures are calculated by multiplying the percentage owned by non-controlling interests for each entity by its corresponding consolidated cash flow metric and adding up the resulting figures. For example, the Company owns approximately 70% of AES Gener, its subsidiary in Chile. Assuming a consolidated net cash flow from operating activities of $100 from AES Gener, the proportional adjustment factor for AES Gener would equal approximately $30 (or $100 x 30%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then adds these amounts together to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to non-controlling interests as a result of (a) non-cash items which impact income but not cash and (b) AES’ ownership interest in the subsidiary where such items occur. Proportional Free Cash Flow for the three months ended JuneSeptember 30, 2014 compared to the three months ended JuneSeptember 30, 2013 increased $30 million, driven by higher Proportional Operating Cash Flow and lower Proportional Non-recoverable Environmental Capital Expenditures. This performance was driven primarily by increases from the following SBUs and key operating drivers: US — driven by higher operating cash flow at the US Utilities driven by lower working capital requirements and higher earnings; and Brazil — driven by Sul due to higher collections, partially offset by higher energy purchases and higher tax payments. These increases were partially offset by decreases at:
Asia — driven by Masinloc due to lower earnings and higher working capital requirements; EMEA — driven by lower results for Wind entities driven by sale of UK Wind assets, sold in August 2014, and lower collections at Kavarna in Bulgaria as well as Kilroot in the U.K. driven by lower earnings; MCAC — driven by higher working capital requirements as a result of lower collections and timing of inventory in the Dominican Republic. Proportional Free Cash Flow for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 decreased $118$319 million, driven by lower Proportional Operating Cash Flow, partially offset by lower Proportional Maintenance and Non-recoverable Environmental Capital Expenditures. This performance was driven primarily by decreasesincreases from the following SBUs and key operating drivers: MCAC — due todriven by higher working capital requirements in the Dominican Republic;Republic and Panama; Brazil — driven by higher pricesprice of energy purchases as well asand higher taxes and interest on debt at Eletropaulo and Sul.Sul; and These decreases were partially offset by an increase at:
CorpEMEA — driven by lower interest payments.
Proportional Free Cash Flow for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 decreased $350 million, driven by lower Proportional Operating Cash Flow, partially offset by lower Proportional Maintenance Capital Expenditures. This performance was driven primarily by decreases from the following SBUs and key operating drivers:
Brazil — driven by higher prices of energy purchases as well as higher taxes and interest on debt at Eletropaulo and Sul;
MCAC — due to higher working capital requirements in the Dominican Republic; and
US — due to proceeds from the PPA termination at Beaver Valley in January 2013 and lower operating resultsmargins and higher working capital requirementsin the U.K. and lower collections at DPL, partially offset by lower proportional maintenance capital expenditures.Maritza and Kavarna in Bulgaria.
Parent Company Liquidity The following discussion of Parent Company Liquidity has been included because we believe it is a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company Liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to cash and cash equivalents which are determined in accordance with GAAP as a measure of liquidity. Cash and cash equivalents are disclosed in the condensed consolidated statements of cash flows. Parent Company Liquidity may differ from similarly titled measures used by other companies. The principal sources of liquidity at the Parent Company level are:
dividends and other distributions from our subsidiaries, including refinancing proceeds; proceeds from debt and equity financings at the Parent Company level, including availability under our credit facilities; and proceeds from asset sales. Cash requirements at the Parent Company level are primarily to fund: interest; principal repayments of debt; acquisitions; construction commitments; other equity commitments; common stock repurchases; taxes; Parent Company overhead and development costs; and dividends on common stock. The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents,” at the periods indicated as follows: | | Parent Company Liquidity | | June 30, 2014 | | December 31, 2013 | | September 30, 2014 | | December 31, 2013 | | | (in millions) | | (in millions) | Consolidated cash and cash equivalents | | $ | 1,515 |
| | $ | 1,642 |
| | $ | 1,670 |
| | $ | 1,642 |
| Less: Cash and cash equivalents at subsidiaries | | 1,500 |
| | 1,510 |
| | 1,441 |
| | 1,510 |
| Parent and qualified holding companies’ cash and cash equivalents | | 15 |
| | 132 |
| | 229 |
| | 132 |
| Commitments under Parent credit facilities | | 800 |
| | 800 |
| | 800 |
| | 800 |
| Less: Borrowings under the credit facilities | | (120 | ) | | — |
| | Less: Letters of credit under the credit facilities | | (1 | ) | | (1 | ) | | (1 | ) | | (1 | ) | Borrowings available under Parent credit facilities | | 679 |
| | 799 |
| | 799 |
| | 799 |
| Total Parent Company Liquidity | | $ | 694 |
| | $ | 931 |
| | $ | 1,028 |
| | $ | 931 |
|
The Company paid a dividend of $0.05 per share to its common stockholders during the three months ended JuneSeptember 30, 2014. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance we will be able to continue the payment of dividends. While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets (see Key Trends and Uncertainties and Global Economic Considerations in this Item 2), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured credit facility. See Item 1A. — Risk Factors “The, “The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.otherwise.” of the Company’s 2013 Form 10-K. Various debt instruments at the Parent Company level, including our senior secured credit facilities, contain certain restrictive covenants. The covenants provide for, among other items:
limitations on other indebtedness, liens, investments and guarantees; limitations on dividends, stock repurchases and other equity transactions; restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements; maintenance of certain financial ratios; and
financial and other reporting requirements. As of JuneSeptember 30, 2014, the Parent Company was in compliance with these covenants. Non-Recourse Debt While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:
reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default; triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary; causing us to record a loss in the event the lender forecloses on the assets; and triggering defaults in our outstanding debt at the Parent Company. For example, our senior secured credit facilities and outstanding debt securities at the Parent Company include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries. Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying condensed consolidated balance sheet amounts to $2.12.3 billion. The portion of current debt related to such defaults was $1.00.9 billion at JuneSeptember 30, 2014, all of which was non-recourse debt related to two subsidiaries — Maritza and Kavarna. None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’s corporate debt agreements as of JuneSeptember 30, 2014 in order for such defaults to trigger an event of default or permit acceleration under AES’s indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities. A material subsidiary is defined in the Company's senior secured revolving credit facility as any business that contributed 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of JuneSeptember 30, 2014, none of the defaults listed above individually or in the aggregate results in or is at risk of triggering a cross-default under the recourse debt of the Company.
Critical Accounting Policies and Estimates The condensed consolidated financial statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. The Company’s significant accounting policies are described in Note 1 — General and Summary of Significant Accounting Policies to the consolidated financial statements included in our 2013 Form 10-K. The Company’s critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2013 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that those policiesthese remain the Company’sas critical accounting policies as of and for the sixnine months ended JuneSeptember 30, 2014. During the third quarter of 2014, the following additional critical accounting estimate was employed with respect to the Company's sales of noncontrolling interests: Sales of Noncontrolling Interests The accounting for a sale of noncontrolling interests under the accounting standards depends on whether the sale is considered to be a sale of in-substance real estate (as opposed to an equity transaction), where the gain (loss) on sale would be recognized in earnings rather than within stockholders’ equity. If management's estimation process determines that there is no significant value beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest is recognized in earnings. However, if it is determined that significant value likely exists beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest would be recognized within stockholders’ equity. In-substance real estate is comprised of land plus improvements and integral equipment. The determination of whether property, plant and equipment is integral equipment is based on the significance of the costs to remove the equipment from its existing location (including the cost of repairing damage resulting from the removal), combined with the decrease in the fair value of the equipment as a result of those removal activities. When the combined total of removal costs and the decrease in fair value of the equipment exceeds 10% of the fair value of the equipment, the equipment is considered integral equipment. The accounting standards specifically identify power plants as an example of in-substance real estate. Where the consolidated entity in which noncontrolling interests have been sold contains in-substance real estate, management estimates the extent to which the total fair value of the assets of the entity is represented by the in-substance real estate and whether significant value exists beyond the in-substance real estate. This estimation considers all qualitative and quantitative factors relevant for each sale and, where appropriate, includes making quantitative estimates about the fair value of the entity and its identifiable assets and liabilities (including any favorable or unfavorable contracts) by analogy to the accounting standards on business combinations. As such, these estimates may require significant judgment and assumptions, similar to the critical accounting estimates previously disclosed in our 2013 Form 10-K for impairments and fair value. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Overview Regarding Market Risks Our generation and utility businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal and environmental credits. We operate in multiple countries and as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between
our functional currency, the U.S. Dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments. These disclosures set forth in this Item 3 are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 3. For further information regarding market risk, see Item 1A. — Risk Factors, Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations, Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance, and We may not be adequately hedged against our exposure to changes in commodity prices or interest rates of the 2013 Form 10-K. Commodity Price Risk Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term sales or under contract sales that leave an
un-hedged exposure on some of our capacity or through imperfect fuel pass-throughs. In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations and sharing or pass-through mechanisms. These businesses subject our operational results to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options. When hedging the output of our generation assets, we utilize contract strategies that lock in the spread per MWh between variable costs and the price at which the electricity can be sold. The portion of our sales and purchases that are not subject to such agreements or contracted businesses where indexation is not perfectly matched to business drivers will be exposed to commodity price risk. AES businesses will see changes in variable margin performance as global commodity prices shift. For the remainder of 2014, we project pretax earnings exposure on a 10% move in commodity prices would be approximately $5 million for natural gas, $5 million for oil and less than $5 million for coal. Our estimates exclude correlation of oil with coal or natural gas. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some of our businesses. Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Spot power prices, contract indexation provisions and generation costs can be directly or indirectly affected by movements in the price of natural gas, oil and coal. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. OffsetsExposures are not perfectly linear or symmetric. The sensitivities are affected by a number of local or indirect market factors. Examples of these factors include hydrology, local energy market supply/demand balances, regional fuel supply issues, regional competition, bidding strategies and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, certain power plants may limit downside exposure by reducing dispatch in low market environments. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices. In the US SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Additionally, at DPL, open access allows our retail customers to switch to alternative suppliers; falling energy prices may increase the rate at which our customers switch to alternative suppliers; DPL sells generation in excess of its retail demand under short-term sales. Given that natural gas-fired generators set power prices for many markets, higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during some periods. In the Andes SBU, our business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. In the central region, the contract sales generally cover the efficient generation from our coal-fired and hydroelectric assets. Any residual spot price risk will primarily be driven by the amount of hydrological inflows. In the case of low hydroelectric generation, spot price exposure is capped by the ability to dispatch our natural gas/diesel assets.assets which can be an expensive cap depending on fuel pricing at the time required. There is a small amount of coal generation in the northern region that is not covered by the portfolio of contract sales and therefore subject to spot price risk. In both regions, generators with oil or oil-linked fuel generally set power prices. In Colombia, we
operate under a short-term sales strategy and have commodity exposure to un-hedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel. In the Brazil SBU, the hydroelectric generating facility is covered by contract sales. Under normal hydrological volatility, spot price risk is mitigated through a regulated sharing mechanism across all hydroelectric generators in the country. Under drier conditions, the sharing mechanism may not be sufficient to cover the business' contract position, and therefore it may have to purchase power at spot prices driven by the cost of thermal generation. In the MCAC SBU, our businesses have commodity exposure on un-hedged volumes. Panama is largelyhighly contracted under a portfolio of fixed volume contract sales. To the extent hydrological inflows are greater than or less than the contract sales volume, the business will be sensitive to changes in spot power prices which may be driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices. Additionally, the contract levels do not always match our generation availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot market to satisfy contract obligations.
In the EMEA SBU, our Kilroot facility operates on a short-term sales strategy. To the extent that sales are un-hedged, the commodity risk at our Kilroot business is to the clean dark spread — the difference between electricity price and our coal-based variable dispatch cost including emissions. Natural gas-fired generators set power prices for many periods, so higher natural gas prices generally expand margins and higher coal or emissions prices reduce them. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods. At our Ballylumford facility, the regulator has the right to terminate the contract, which would impact our commodity exposure. Our operations in Turkey are sensitive to the spread between power and natural gas prices, both of which have historically demonstrated a relationship to oil. As a result of these relationships, falling oil prices could compress margins realized at the business. In the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume soldor shortfalls of generation relative to contract volumes settled in the spot market. Low oil prices may be a driver of margin compression since oil affects spot power sale prices. Foreign Exchange Rate Risk In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in the U.S. Dollar or currencies other than their own functional currencies. We have varying degrees of exposure to changes in the exchange rate between the U.S. Dollar and the following currencies: Argentine Peso, Brazilian Real, British Pound, Chilean Peso, Colombian Peso, Dominican Peso, Euro, Indian Rupee, KazakhstaniKazakhstan Tenge, Mexican Peso and Philippine Peso. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations. We have entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. The largest foreign exchange risks over a twelve-month forward-looking period are stemming from the following currencies: Argentine Peso, British Pound, Brazilian Real, Colombian Peso, Euro and Kazakhstan Tenge. As of JuneSeptember 30, 2014, assuming a 10% U.S. Dollar appreciation, adjusted pretax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro and Kazakhstan Tenge relative to the U.S. Dollar are projected to be reduced by approximately $5 million, $5 million, $5 million, $5 million, less than $5 million and $5 million respectively,for each currency for the remainder of 2014. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pretax earnings for 2014 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted pretax earnings exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility. Interest Rate Risks We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt, as well as interest rate swap, cap and floor and option agreements. Decisions on the fixed-floating debt ratio are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-
recoursenon-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Most of our interest rate risk is related to non-recourse financings at our businesses.
As of JuneSeptember 30, 2014, the portfolio’s pretax earnings exposure for the remainder of 2014 to a 100-basis-point increase in interest rates for our Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro, Kazakhstani Tenge and U.S. Dollar denominated debt would be approximately $10 million based on the impact of a one time, 100-basis-point upward shift in interest rates on interest expense for the debt denominated in these currencies. The amounts do not take into account the historical correlation between these interest rates. ITEM 4. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures The Company, under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”)CEO and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our
disclosure controls and procedures were effective as of JuneSeptember 30, 2014 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure. Changes in Internal Controls over Financial Reporting ThereOn May 14, 2013, The Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) issued an updated version of its Internal Control - Integrated Framework (the “2013 Framework”). Originally issued in 1992 (the “1992 Framework”), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. We have reviewed the 2013 Framework and integrated the changes into the Company’s internal controls over financial reporting. We expect that management’s assessment of the overall effectiveness of our internal controls over financial reporting for the year ending December 31,2014 will be based on the 2013 Framework and that the change will not be significant to our overall control structure over financial reporting.
As of September 30 2014, there were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II: OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of JuneSeptember 30, 2014. In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro (“FDC”) against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the FDC found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$1.511.53 billion ($685629 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off of EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo’s defenses in the execution suit. On appeal, the case was remanded to the FDC for further proceedings.proceedings to determine whether Eletropaulo is liable for the debt. In December 2012, the FDC issued a decision that Eletropaulo is liable for the debt. However, that decision was annulled on appeal and the case was remanded to the FDC for further proceedings. On remand at the FDC, the FDC has appointed an accounting expert who will issue a report on the amount of the alleged debt and the responsibility for its payment in light of the privatization. The parties will be entitled to take discovery and present arguments on the issues to be determined by the expert. The expert has been nominated by the FDC. If the FDC again finds Eletropaulo liable for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the FDC grants such request, Eletropaulo’s results of operations may be materially adversely affected and, in turn, the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the FDC against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of São Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1.51.6 million ($680656 thousand) as of JuneSeptember 30, 2014, or pay an indemnification amount of approximately R$15 million ($76 million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court’s decision, the case has been remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision. In January 2014, Eletropaulo informed the court that it intended to comply with the court’s decision by donating a green area inside a protection zone and restore watersheds, the aggregate cost of which is expected to be approximately R$1.51.6 million ($680656 thousand). Eletropaulo also requested that the court add the current owner of the land where the Associação facilities are located, Empresa Metropolitana de Águas e Energia S.A. (“EMAE”), as a party to the lawsuit and order EMAE to perform the demolition and reforestation aspects of the court’s decision. In July 2014, the court requested the Secretary of the Environment for the State of São Paulo to notify the court of its opinion regarding the acceptability of the green areas to be donated by Eletropaulo to the State of São Paulo. In December 2001, Gridco Ltd. ("Gridco") served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the shareholders agreement between Gridco, the Company, AES ODPL, Jyoti and the Central Electricity Supply Company of Orissa Ltd. ("CESCO"), an affiliate of the Company. In the arbitration, Gridco asserted that a comfort letter issued by the Company in connection with the Company's indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO's financial obligations to Gridco. Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. A majority of the tribunal later awarded the respondents, including the Company, some of their costs relating to the arbitration. Gridco filed challenges of the tribunal's awards with the local Indian court. Gridco's challenge of the costs award has been dismissed by the court, but its challenge of the liability award
remains pending. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified Eletropaulo that it had commenced an inquiry into the BNDES financings provided to AES Elpa and AES Transgás, the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo, and the quality of service provided by Eletropaulo to its customers. The MPF requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FCSP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. The lawsuit remains before the FCSP, but the FCSP has suspended the lawsuit pending a decision on MPF's interlocutory appeal. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts. Pursuant to their environmental audit, AES Sul and AES Florestal discovered 200 barrels of solid creosote waste and other contaminants at a pole factory that AES Florestal had been operating. The conclusion of the audit was that a prior operator of the pole factory, Companhia Estadual de Energia (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. On their initiative, AES Sul and AES Florestal communicated with Brazilian authorities and CEEE about the adoption of containment and remediation measures. In March 2008, the State Attorney of the State of Rio Grande do Sul, Brazil filed a public civil action against AES Sul, AES Florestal and CEEE seeking an order requiring the companies to recover the contaminated area located on the grounds of the pole factory and an indemnity payment (approximately R$6 million ($32 million)) to the State’s Environmental Fund. In October 2011, the State Attorney Office filed a request for an injunction ordering the defendant companies to remediatecontain and remove the contaminated areacontamination immediately. The court granted injunctive relief on October 18, 2011, but determined only that defendant CEEE was required to proceed with the remediationremoval work. In May 2012, CEEE began the remediationremoval work in compliance with the injunction. The remediationremoval costs are estimated to be approximately R$60 million ($2725 million) and the work is ongoing.was completed in February 2014. In parallel with the removal activities, a court-appointed expert investigation took place, which was concluded in May 2014. The parties have until November 2014 to present their response to the report of the court-appointed expert. The case is in the evidentiary stage awaiting the production of the court’s expert opinion on several matters, including which of the parties had utilized the products found in the area. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. In January 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. (“Este”)) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court’s decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity’s appeal remains pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) in Brazil initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Estado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF sought an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous
obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserted that if it was determined that AESU was responsible for the termination of the GSA, AESU was liable for TGM’s alleged losses, including losses under the TA. In April 2011, the arbitrations were consolidated into a single proceeding. The hearing on liability issues took place in December 2011. In May 2013, the arbitral Tribunal issued a liability award in AESU's favor. YPF thereafter challenged the
award in Argentine court. In June 2014, at AESU's request, a Uruguayan court temporarily enjoined YPF from pursuing its action in the Argentine court, pending a final determination by the Uruguayan court on whether YPF is entitled to challenge the liability award in the Argentine court. It is unclear whether YPF will complyhas not complied with the temporary injunction.injunction to date. In August 2014, a Uruguayan appellate court issued a decision declaring that only the Uruguayan courts have jurisdiction to review awards in the arbitration and that the Tribunal must disregard litigation outside of Uruguay when deciding issues in the arbitration. In October 2014, an Argentine appellate court issued a decision purporting to suspend the arbitration, and later issued an order threatening sanctions against violations of its decision. Given the competing decisions of the Uruguayan and Argentine courts, the Tribunal has suspended the damages phase of the arbitration until February 2, 2015, at which time the Tribunal will consider whether to lift the suspension. In the arbitration,meantime, the Tribunal has asked the parties are submitting their respective evidence on damages. The final evidentiary hearing on damages will take place on November 6-7, 2014.to remove any alleged obstacles to the progress of the arbitration. AESU believes it has meritorious claims and defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.
In April 2009, the Antimonopoly Agency in Kazakhstan initiated an investigation of certain power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”). The Antimonopoly Agency determined that the Hydros had abused their market position and charged monopolistically high prices for power from January-February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million)648 thousand) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($2 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of the Hydros. In the course of criminal proceedings, the financial police expanded the periods at issue to the entirety of 2009 for UK HPP and from January-October 2009 for Shulbinsk HPP, and sought increased damages of KZT 1.2 billion ($76 million) from UK HPP and KZT 1.3 billion ($7 million) from Shulbinsk HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts. In October 2009, AES Mérida III, S. de R.L. de C.V. (AES Mérida), one of our businesses in Mexico, initiated arbitration against its fuel supplier and electricity offtaker, Comisión Federal de Electricidad (“CFE”), seeking a declaration that CFE breached the parties’ power purchase agreement (“PPA”) by supplying gas that did not comply with the PPA’s specifications. Alternatively, AES Mérida requested a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputed the claims. Although it did not assert counterclaims, in its closing brief CFE asserted that it is entitled to a partial refund of the capacity charge payments that it made for power generated with the out-of-specification gas. In July 2012, the arbitral Tribunal issued an award in AES Mérida’s favor. In December 2012, CFE initiated an action in Mexican court seeking to nullify the award. AES Mérida opposed the request and asserted a counterclaim to confirm the award. In February 2014, the court rejected CFE's claims and granted AES Mérida's request to confirm the award. CFE has appealed the court's decision. AES Mérida believes it has meritorious grounds to defeat that action; however, there can be no assurances that it will be successful. In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the Clean Air Act (“CAA”) Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard. In November 2009, April 2010, December 2010, April 2011, June 2011, August 2011, and November 2011, and October 2014, substantially similar personal injury lawsuits were filed by a total of 4950 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit, the plaintiffs allege that the coal combustion byproductsby-products of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The Company is not able to estimate damages, if any, at this time. The AES defendants moved for partial dismissal of both the November 2009 and April
2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. In November 2011, the AES defendants again moved for partial dismissal of those amended complaints, and in both lawsuits, the Superior Court dismissed the plaintiffs' claims for future medical monitoring expenses but declined to dismiss their claims under Dominican Republic Law 64-00. The AES defendants filed an answer to the November 2009 lawsuit in June 2012. The Superior Court has stayed the remaining six lawsuits as well as any subsequently filed similar lawsuits. The Superior Court hasbetween April 2010 and November 2011, and may also ordered that, forstay the present,October 2014 lawsuit. Presently, discovery will proceedis proceeding only in the November 2009 lawsuit and will be limited toon causation
and exposure issues. The AES defendants believe they have meritorious defenses and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts. On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns a 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million. The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units, allegedly because of the purported characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor’s claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately €240 million ($327304 million) in the arbitration, plus interest and costs. The evidentiary hearing took place on November 27-December 6, 2013, and January 6-17, 2014. Closing arguments were heard on May 21-22, 2014. The parties are awaiting the Tribunal's award. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. On February 11, 2011, Eletropaulo received a notice of violation from São Paulo State’s Environmental Authorities for allegedly destroying 0.32119 hectares of native vegetation at the Conservation Park of Serra do Mar (“Park”), without previous authorization or license. The notice of violation asserted a fine of approximately R$1 million ($454410 thousand) and the suspension of Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities (“São Paulo EA”), Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the notice of violation or reduce the fine. In December 2011, the São Paulo EA declined to vacate the notice of violation but recognized the possibility of 40% reduction inof the fine if Eletropaulo agrees to recover the affected area with additional vegetation. Eletropaulo has not appealed the decision and is now discussing the terms of a possible settlement with the São Paulo EA, including a plan to recover the affected area by primarily planting additional trees. In March 2012, the State of São Paulo Prosecutor’s Office of São Bernardo do Campo initiated a Civil Proceeding to review the compliance by Eletropaulo with the terms of any possible settlement. Eletropaulo has had several meetings and field inspections to settle the details of the recovery project. Eletropaulo was informed by the Park Administrator that the area where the recovery project was to be located was no longer available. The Park Administrator subsequently approved a new area for the recovery project. Eletropaulo is currently awaiting the draft of the agreement by the environmental agency, and expects to proceed with the recovery project after reaching agreement with the environmental agency. In February 2011, a consumer protection group, S.O.S. Consumidores (“SOSC”), filed a lawsuit in the State of São Paulo Federal Court against the Brazilian Regulatory Agency (“ANEEL”), Eletropaulo and all other distribution companies in the State of São Paulo, claiming that the distribution companies had overcharged customers for electricity. SOSC asserted that the distribution companies’ tariffs had been incorrectly calculated by ANEEL, and that the tariffs were required to be corrected from the effective dates of the relevant concession contracts. SOSC asserted that ANEEL erred in May 2010, when the agency corrected the alleged error going forward but declared that the tariff calculations made in the past were correct. Eletropaulo opposed the lawsuit on the ground that it had not wrongfully collected amounts from its customers, as its tariffs had been calculated in accordance with the concession contract with the Federal Government and ANEEL’s rules. Subsequently, the lawsuit was transferred to the Federal Court of Belo Horizonte ("FCBH"), which was presiding over similar lawsuits against other distribution companies and ANEEL. In January 2014, the FCBH dismissed the lawsuit against Eletropaulo and the other distribution companies. Incompanies ("January 2014 Decision"). An appeal was filed in May 2014, SOSC appealedbut that decision.appeal was unsuccessful. The January 2014 Decision has become final and unappealable. SOSC's lawsuit will continue against ANEEL. If SOSC ultimately
prevails against the agency, it is possible that SOSC may file a new lawsuit against Eletropaulo seeking refunds. Eletropaulo estimates that its liability to customers could be approximately R$855 million ($388 million). Eletropaulo believes it has meritorious defenses and willwould vigorously defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.any such lawsuit. In June 2011, the São Paulo Municipal Tax Authority (the “Municipality”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking to collect services tax (“ISS”) that allegedly had not been paid on revenues for services rendered by Eletropaulo. Eletropaulo challenged the assessments on the ground that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$2.82.86 billion ($1.271.17 billion) as estimated by Eletropaulo. Eletropaulo has appealed to the Second Instance Administrative Court. No tax is due while the appeal is pending. Eletropaulo believes it has
meritorious defenses to the assessments and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. In January 2012, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê paid PIS and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê challenged the assessment on the ground that the tax rate was set in the applicable legislation. In April 2013, the First Instance Administrative Court determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable for unpaid taxes, interest and penalties totaling approximately R$844854 million ($383350 million) as estimated by AES Tietê. AES Tietê has filed an appeal to the Second Instance Administrative Court. No tax is due while the appeal is pending. AES Tietê believes it has meritorious defenses to the claim and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. In August 2012, Fondo Patrimonial de las Empresas Reformadas (“FONPER”) (the Dominican instrumentality that holds the Dominican Republic’s shares in Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”)) filed a criminal complaint against certain current and former employees of AES. The criminal proceedings include a related civil component initiated against Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NCI”) (the AES affiliate that manages Itabo). FONPER asserts claims relating to the alleged mismanagement of Itabo and seeks approximately $270 million in damages. The Dominican District Attorney (“DA”) has admitted the criminal complaint and is investigating the allegations set forth therein. In September 2012, one of the individual defendants responded to the criminal complaint, denying the charges and seeking an immediate dismissal of same. In April 2013, the DA requested that the Dominican Camara de Cuentas ("Camara") perform an audit of the allegations in the criminal complaint. The audit is ongoing and the Camara has not issued its report to date. Further, in August 2012, Coastal and NCI initiated an international arbitration proceeding against FONPER and the Dominican Republic, seeking a declaration that Coastal and NCI have acted both lawfully and in accordance with the relevant contracts with FONPER and the Dominican Republic in relation to the management of Itabo. Coastal and NCI also seek a declaration that the criminal complaint is a breach of the relevant contracts between the parties, including the obligation to arbitrate disputes. Coastal and NCI further seek damages from FONPER and the Dominican Republic resulting from their breach of contract. FONPER and the Dominican Republic have denied the claims and challenged the jurisdiction of the arbitral Tribunal. The Tribunal has not yet established the procedural schedule for the arbitration.arbitration, but has not yet scheduled the final evidentiary hearing. The AES defendants believe they have meritorious claims and defenses, which they will assert vigorously; however, there can be no assuranceassurances that they will be successful in their efforts. In April 2013, the East Kazakhstan Ecology Department (“ED”) issued an order directing AES Ust-Kamenogorsk CHP ("UK CHP") to pay approximately KZT 720 million ($4.03.9 million) in damages ("April 2013 Order”). The ED claimed that UK CHP was illegally operating without an emissions permit for 27 days in February-March 2013. In June 2013, the ED filed a lawsuit with the Specialized Interregional Economic Court (the “Economic Court”) seeking to require UK CHP to pay the assessed damages. UK CHP thereafter filed a separate lawsuit with the Economic Court challenging the April 2013 Order and the ED's allegations. In that lawsuit, in August 2013, the Economic Court ruled in UK CHP's favor and required the ED to vacate the April 2013 Order. That ruling was upheld on two intermediate appeals; however,appeals and thereafter the ED maydid not further appeal to the Kazakhstan Supreme Court. The Economic Court also dismissed the lawsuit filed by the ED. UK CHP believes it has meritorious claims and defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurance that it will be successful in its efforts. In December 2013, AES Changuinola’s EPC Contractor initiated arbitration pursuant to the parties’ EPC Contract and related settlement agreements. The Contractor alleged, among other things, that AES Changuinola failed to make a settlement payment, release retainage, and acknowledge completion of AES Changuinola hydropower facility. In total, the Contractor sought approximately $41 million in damages, plus interest and costs. AES Changuinola denied the claims and asserted counterclaims against the Contractor. In July 2014, the parties settled the dispute.
ITEM 1A. RISK FACTORS There have been no material changes to the risk factors as previously disclosed in our 2013 Form 10-K under Part 1 — Item 1A. — Risk Factors. ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS The following table presents information regarding purchases made by The AES Corporation of its common stock: | | | | | | | | | | | | | | | | Repurchase Period | | Total Number of Shares Purchased | | Average Price Paid Per Share | | Total Number of Shares Repurchased as part of a Publicly Announced Purchase Plan (1) | | Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan | 4/1/2014 - 4/30/14 | | — |
| | $ | — |
| | — |
| | $ | 191,479,504 |
| 5/1/2014 - 5/31/14 | | 1,165,334 |
| | 13.73 |
| | 1,165,334 |
| | 175,481,733 |
| 6/1/2014 - 6/30/14 | | 1,140,379 |
| | 13.89 |
| | 1,140,379 |
| | 159,636,730 |
| Total | | 2,305,713 |
| | $ | 13.81 |
| | 2,305,713 |
| | |
| | | | | | | | | | | | | | | | Repurchase Period | | Total Number of Shares Purchased | | Average Price Paid Per Share | | Total Number of Shares Repurchased as part of a Publicly Announced Purchase Plan (1) | | Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan (2) | 7/1/2014 - 7/31/14 | | — |
| | $ | — |
| | — |
| | $ | 299,636,730 |
| 8/1/2014 - 8/31/14 | | 2,594,646 |
| | 14.67 |
| | 2,594,646 |
| | 261,596,648 |
| 9/1/2014 - 9/30/14 | | 4,783,741 |
| | 14.57 |
| | 4,783,741 |
| | 191,963,430 |
| Total | | 7,378,387 |
| | $ | — |
| | 7,378,387 |
| | |
_____________________________
| | (1)(1) See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program. (2) The authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases, purchases by contract (including, without limitation, accelerated stock repurchase programs or 10b5-1 plans) and/or privately negotiated transactions. There can be no assurance as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time. | See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program.
|
ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. MINE SAFETY DISCLOSURES Not applicable. ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS | | | | 4.1 | | Eighteenth Supplemental Indenture, dated May 20, 2014, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on May 20, 2014. | | | | 31.1 | | Rule13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith). | | | 31.2 | | Rule 13a-14(a)/15d-14(a) Certification of Thomas M. O’Flynn (filed herewith). | | | 32.1 | | Section 1350 Certification of Andrés Gluski (filed herewith). | | | 32.2 | | Section 1350 Certification of Thomas M. O’Flynn (filed herewith). | | | 101.INS | | XBRL Instance Document (filed herewith). | | | 101.SCH | | XBRL Taxonomy Extension Schema Document (filed herewith). | | | 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith). | | | 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document (filed herewith). | | | 101.LAB | | XBRL Taxonomy Extension Label Linkbase Document (filed herewith). | | | 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith). |
SIGNATURES Pursuant to the requirements 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.
| | | | | | | | | | | | THE AES CORPORATION (Registrant) | | | | | | | | | Date: | August 6,November 5, 2014 | By: | | /s/ THOMAS M. O’FLYNN | | | | | | Name: | | Thomas M. O’Flynn | | | | | | Title: | | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | | | | | | | | | | | | By: | | /s/ SHARON A. VIRAG | | | | | | Name: | | Sharon A. Virag | | | | | | Title: | | Vice President and Controller (Principal Accounting Officer) |
s in millions) | | ( Adjusted Pretax Contribution: For a reconciliation of Adjusted PTC to net income from continuing operations, see Note 12 — Segments included in Item 1. — Financial Statements of this Form 10-Q.
Adjusted EPS | | | | | | | | | | | | | | | | | | | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Reconciliation of Adjusted Earnings Per Share | | 2014 | | 2013 | | 2014 | | 2013 | | Diluted earnings per share from continuing operations | | $ | 0.20 |
| | $ | 0.22 |
| | $ | 0.13 |
| | $ | 0.37 |
| | Unrealized derivative (gains) losses (1) | | (0.02 | ) | | (0.05 | ) | | (0.03 | ) | | (0.03 | ) | | Unrealized foreign currency transaction (gains) losses (2) | | — |
| | 0.04 |
| | 0.03 |
| | 0.05 |
| | Disposition/acquisition (gains) losses | | — |
| | (0.03 | ) | (3) | — |
| | (0.03 | ) | (4) | Impairment losses | | 0.09 |
| (5) | — |
| | 0.26 |
| (6) | 0.05 |
| (7) | Loss on extinguishment of debt | | 0.01 |
| (8) | 0.17 |
| (9) | 0.14 |
| (10 | ) | 0.21 |
| (11) | Adjusted earnings per share | | $ | 0.28 |
| | $ | 0.35 |
| | $ | 0.53 |
| | $ | 0.62 |
| |
| | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Reconciliation of Adjusted Earnings Per Share | | 2014 | | 2013 | | 2014 | | 2013 | | Diluted earnings per share from continuing operations | | $ | 0.67 |
| | $ | 0.23 |
| | $ | 0.81 |
| | $ | 0.61 |
| | Unrealized derivative (gains) losses (1) | | 0.01 |
| | — |
| | (0.02 | ) | | (0.04 | ) | | Unrealized foreign currency transaction (gains) losses (2) | | 0.06 |
| | (0.02 | ) | | 0.07 |
| | 0.04 |
| | Disposition/acquisition (gains) losses | | (0.51 | ) | (3) | — |
| | (0.51 | ) | (4) | (0.03 | ) | (5) | Impairment losses | | 0.08 |
| (6) | 0.18 |
| (7) | 0.34 |
| (8) | 0.23 |
| (9) | Loss on extinguishment of debt | | 0.06 |
| (10) | — |
| | 0.20 |
| (11 | ) | 0.20 |
| (12) | Adjusted earnings per share | | $ | 0.37 |
| | $ | 0.39 |
| | $ | 0.89 |
| | $ | 1.01 |
| |
_____________________________ | | (1) | Unrealized derivative (gains) losses were net of income tax per share of $(0.01)$0.00 and $(0.02)$(0.01) in the three months ended JuneSeptember 30, 2014 and 2013, and of $(0.01) and $(0.02)$(0.03) in the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively. |
| | (2) | Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.00$0.03 and $0.00$(0.01) in the three months ended JuneSeptember 30, 2014 and 2013, and of $0.01$0.04 and $0.01 in the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively. |
| | (3) | Amount primarily relates to the gain from the sale of the remaining 20%a noncontrolling interest in Cartagena for $20Masinloc of $283 million ($15283 million, or $0.02$0.39 per share, net of income tax per share of $0.01).$0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per |
share of $0.00), the tax benefit of $12 million ($0.02 per share) associated with the agreement executed in September 2014 to sell a noncontrolling interest in our Dominican Republic businesses, and the tax expense of $4 million ($0.01 per share) related to the Silver Ridge Power transaction. | | (4) | Amount primarily relates to the gain from the sale of a noncontrolling interest in Masinloc of $283 million ($283 million, or $0.39 per share, net of income tax per share of $0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per share of $0.00), the tax benefit of $12 million ($0.02 per share) associated with the agreement executed in September 2014 to sell a noncontrolling interest in our Dominican Republic businesses, and the tax expense of $4 million ($0.01 per share) related to the Silver Ridge Power transaction. |
| | (5) | Amount primarily relates to the gain from the sale of the remaining 20% interest in Cartagena forof $20 million ($1514 million, or $0.02 per share, net of income tax per share of $0.01), the gain from the sale of wind turbines for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00), the gain from the sale of Trinidad for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00) as well as the gain from the sale of Chengdu, an equity method investment in China forof $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00). |
| | (5)(6)
| Amount primarily relates to the assetother-than-temporary impairment of our equity method investment at EbuteEntek of $52$18 million ($3412 million, or $0.05$0.02 per share, net of income tax per share of $0.02) and$0.01), the asset impairment at NewfieldEbute of $11$15 million ($6 million, or $0.00 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our equity method investment at Silver Ridge of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02). |
| | (6)
| Amount primarily relates to the goodwill impairments at DPLER of $136 million ($92 million, or $0.13 per share, net of income tax per share of $0.06), at Buffalo Gap of $18 million ($1823 million, or $0.03 per share, net of income tax per sharenoncontrolling interest of $0.00)$1 million and asset impairments at Ebute of $52 million ($34 million, or $0.05 per share, net of income tax per share of $0.02)$(0.01)), at Newfieldand a tax benefit of $11$25 million ($6 million, or $0.000.03 per share, net of income tax per share of $0.00),share) associated with the previously recognized goodwill impairment at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our equity method investment at Silver Ridge of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02).DPLER. |
| | (7) | Amount primarily relates to other-than-temporary impairment of our equity method investment at Elsta of $122 million ($89 million, or $0.12 per share, net of income tax per share of $0.04). Amount also includes asset impairment at Beaver ValleyItabo (San Lorenzo) of $46$15 million ($346 million, or $0.05$0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02). |
| | (8) | Amount primarily relates to the loss on early retirementgoodwill impairments at DPLER of debt$136 million ($117 million, or $0.16 per share, net of income tax per share of $0.03), and at CorporateBuffalo Gap of $13$18 million ($18 million, or $0.03 per share, net of income tax per share of $0.00), and asset impairments at Ebute of $67 million ($57 million, or $0.08 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01), at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.01), and at Newfield of $11 million ($6 million, or $0.00 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00) as well as the other-than-temporary impairments of our equity method investment at Silver Ridge Power of $42 million ($28 million, or $0.04 per share, net of income tax per share of $0.02) and at Entek of $18 million ($12 million, or $0.02 per share, net of income tax per share of $0.01). |
| | (9) | Amount primarily relates to the loss on early retirementother-than-temporary impairment of debtour equity method investment at CorporateElsta in the Netherlands of $163$122 million ($12189 million, or $0.16$0.12 per share, net of income tax per share of $0.06)$0.04). Amount also includes the asset impairment at Beaver Valley of $46 million ($33 million, or $0.04 per share, net of income tax per share of $0.02), the asset impairment at Itabo (San Lorenzo) of $15 million ($6 million, or $0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as the goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02). |
| | (10) | Amount primarily relates to the loss on early retirement of debt at Corporatethe Parent Company of $145$43 million ($9925 million, or $0.14$0.03 per share, net of income tax per share of $0.06)$0.03), at UK wind projects of $18 million ($14 million, or $0.02 per share, net of income tax per share of $0.01) and at Gener of $6 million ($3 million, or $0.00 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00). |
| | (11) | Amount primarily relates to the loss on early retirement of debt at Corporatethe Parent Company of $188 million ($123 million, or $0.17 per share, net of income tax per share of $0.09), at UK wind projects of $18 million ($14 million, or $0.02 per share, net of income tax per share of $0.01) and at Gener of $8 million ($4 million, or $0.01 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00). |
| | (12) | Amount primarily relates to the loss on early retirement of debt at the Parent Company of $165 million ($123120 million, or $0.16 per share, net of income tax per share of $0.06) and at Masinloc of $43 million ($29 million, or $0.04 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01). |
Operating Margin and Adjusted PTC Analysis US SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our US SBU for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 144 |
| | $ | 147 |
| | $ | (3 | ) | | -2 | % | | $ | 278 |
| | $ | 292 |
| | $ | (14 | ) | | -5 | % | Noncontrolling Interests Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Derivatives Adjustment | | — |
| | (13 | ) | | | | | | 9 |
| | — |
| | | | | Adjusted Operating Margin | | $ | 144 |
| | $ | 134 |
| | $ | 10 |
| | 7 | % | | 287 |
| | 292 |
| | $ | (5 | ) | | -2 | % | Adjusted PTC | | $ | 80 |
| | $ | 63 |
| | $ | 17 |
| | 27 | % | | $ | 155 |
| | $ | 196 |
| | $ | (41 | ) | | 21 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 222 |
| | $ | 206 |
| | $ | 16 |
| | 8 | % | | $ | 500 |
| | $ | 498 |
| | $ | 2 |
| | — | % | Noncontrolling Interests Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Derivatives Adjustment | | 5 |
| | 2 |
| | | | | | 14 |
| | 2 |
| | | | | Adjusted Operating Margin | | $ | 227 |
| | $ | 208 |
| | $ | 19 |
| | 9 | % | | 514 |
| | 500 |
| | $ | 14 |
| | 3 | % | Adjusted PTC | | $ | 156 |
| | $ | 132 |
| | $ | 24 |
| | 18 | % | | $ | 311 |
| | $ | 328 |
| | $ | (17 | ) | | 5 | % |
Operating marginMargin for the three months ended JuneSeptember 30, 2014 decreased $3increased $16 million, or 2%8%. This performance was driven primarily by the following businessesbusiness and key operating drivers: DPL decreased $19 million, primarily due to a $15 million impact from unrealized mark-to-market gains on derivatives in 2013 that did not recur, combined with a decrease in sales volumes, partially offset by an increase in retail rates. This decrease was partially offset by:
US GenerationOhio increased by $14 million, primarily due to $8regulatory retail rate increases and reduced fuel and purchase power costs of $41 million, relating to the implementationpartially offset by decreased retail sales of the synchronous condensers to provide ancillary services in June 2013 at Southland, $3$25 million due to the completion of
the Tait energy storage project at DPL in September 2013,resulting from customer switching and an increase in market prices relating to production at Laurel Mountain of $2 million. mild weather.
Adjusted Operating Margin increased $1019 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.non-controlling interests within operating margin. Adjusted PTC increased $1724 million driven by a $3$5 million gain recognized from proceeds relatingat Buffalo Gap, due to a bankruptcy settlement at Laurel Mountain,an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest (See Note 1 — General and Summary of Significant Accounting Policies — Noncontrolling Interests included in Item 8. — Financial Statements and Supplementary Data in the Company's 2013 Form 10-K) as well as the increase of $1019 million in Adjusted Operating Margin described above.
Operating marginMargin for the sixnine months ended JuneSeptember 30, 2014 decreased $14increased $2 million, or 5%0.4%. This performance was driven primarily by the following businesses and key operating drivers: DPL decreased $48US Generation increased by $32 million, primarily due to $11 million from increased availability as a result of fewer outages at Hawaii, $7 million relating to the implementation of the synchronous condensers to provide ancillary services in June 2013 and lower fixed costs at Southland, $8 million at Laurel Mountain due to increased market prices, and $8 million due to the September 2013 completion of the Tait energy storage project; and
IPL in Indiana increased $4 million driven by higher wholesale and retail margin of $13 million, partially offset by higher fixed costs and depreciation of $9 million. These increases were partially offset by: DPL decreased $34 million, primarily due to decreases of $31 million attributable to outages and lower gas availability, which resulted in higher purchased power and related costs to supply higher demand from cold weather during the first quarter as well as outages and lower gains on unrealized derivativederivatives of $13 million in the second quarter. This decrease was The results above were partially offset by:
US Generation increased by $33 million, primarily due to $11 millionimprovements in Q3 resulting from increased availability as a resultretail rates and lower fuel costs of fewer outages at Hawaii, $11 million relating to the implementation of the synchronous condensers to provide ancillary services in June 2013 at Southland, $8 million at Laurel Mountain due to increased market prices relating to production, and $6 million due to the completion 2013 of the Tait energy storage project in September 2013.$16 million.
Adjusted Operating Margin decreased $5increased $14 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.non-controlling interests within operating margin. Adjusted PTC decreased $41$17 million driven by net gains of $53 million recognized as a result of the early termination of the PPA and coal supply contract at Beaver Valley during the first quarter of 2013, partially offset by an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest at Buffalo Gap and Armenia Wind of $10 million, settlements at Laurel Mountain of $6 million, as well as the decreaseincrease of $5$14 million in Adjusted Operating Margin described above. Andes SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Andes SBU for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 148 |
| | $ | 148 |
| | $ | — |
| | — | % | | $ | 239 |
| | $ | 282 |
| | $ | (43 | ) | | -15 | % | Noncontrolling Interests Adjustment | | 32 |
| | 34 |
| | | | | | 56 |
| | 71 |
| | | | | Derivatives Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 116 |
| | $ | 114 |
| | $ | 2 |
| | — | % | | $ | 183 |
| | $ | 211 |
| | $ | (28 | ) | | -13 | % | Adjusted PTC | | $ | 104 |
| | $ | 88 |
| | $ | 16 |
| | 18 | % | | $ | 157 |
| | $ | 169 |
| | $ | (12 | ) | | 7 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 212 |
| | $ | 134 |
| | $ | 78 |
| | 58 | % | | $ | 451 |
| | $ | 416 |
| | $ | 35 |
| | 8 | % | Noncontrolling Interests Adjustment | | 53 |
| | 29 |
| | | | | | 109 |
| | 100 |
| | | | | Derivatives Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 159 |
| | $ | 105 |
| | $ | 54 |
| | 51 | % | | $ | 342 |
| | $ | 316 |
| | $ | 26 |
| | 8 | % | Adjusted PTC | | $ | 120 |
| | $ | 109 |
| | $ | 11 |
| | 10 | % | | $ | 277 |
| | $ | 278 |
| | $ | (1 | ) | | — | % |
Including the neutralunfavorable impact of foreign currency translation and remeasurement of $3 million, operating margin for the three months ended JuneSeptember 30, 2014 remained flat.increased $78 million, or 58%. This performance was driven primarily by the following businesses and key operating drivers: Chivor in Colombia increased $55 million as higher inflows resulted in higher generation and spot sales of $44 million as well as higher rates of $6 million. Gener in Chile increased $30 million due to higher coal and diesel availability of $19 million, and favorable contract and spot prices of $10 million in the SIC market. This increase was offset by: Argentina increaseddecreased $6 million driven by higher rates of $17 million related to the Resolution 529 adjustment (retroactive from February 2014), offset by higher fixed costs of $9 million mainly caused by inflation, adjustments. This increase was offset by:
Gener in Chile decreased $4 million due to lower spot prices and lower margins on Energy Plus contracts at Termoandesgeneration of $8$7 million, and lower contract prices at Norgenerunfavorable foreign exchange rate impact of $5$4 million, partially offset by lower fixed costs from lower maintenancehigher rates of $8 million; and
Chivor in Colombia decreased $2$16 million from higher fixed costs related to the tunnel maintenance, partially offset by higher ancillary services and spot prices.Resolution 529 adjustment.
Adjusted Operating Margin increased $254 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.
Adjusted PTC increased $1611 million, driven by the increase of $254 million in Adjusted Operating Margin described above, partially offset by a non-recurring benefit of $20 million from FONINVEMEM III interest income on receivables in 2013 in Argentina and lower realized foreign currency lossesequity in earnings at Guacolda in Chile of $15 million in Chile.$12 million. Including the unfavorable impact of foreign currency translation and remeasurement of $3$7 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased $43increased $35 million, or 15%8%. This performance was driven primarily by the following businesses and key operating drivers:
Chivor in Colombia increased $52 million largely driven by significantly higher generation of $51 million resulting in higher spot and contract sales and ancillary services. This increase was offset by: Gener in Chile decreased $44$14 million, largely driven by lower availability in the first quarter due primarily to planned outages of $22 million, a reduction of $39$29 million from lower contract prices, spot prices in the SADI and lower Energy Plus margin and lower availability of $6 million; partially offset by the contribution of $10 million from Ventanas IV, which commenced operations in March 2013, and lower fixed costs from lower maintenance and salaries of $9 million;$10 million. Chivor in ColombiaArgentina decreased $3$4 million driven by higher fixed costs as described above and lower foreign currency exchange rates,of $25 million driven by higher inflation; partially offset by higher prices and AGC sales; and
Argentina increased $3 million driven by higher rates of $17$21 million as a result of the impact of Resolution 529, partially offset by higher fixed costs of $16 million driven by higher inflation adjustment.529.
Adjusted Operating Margin decreased $28increased $26 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina. Adjusted PTC decreased $12$1 million, driven by the decreaseincrease of $28$26 million in Adjusted Operating Margin described above, partiallyprimarily offset by higher equity earningsa non-recurring benefit in 2013 from the sale of a transmission line of Guacolda and lower realized foreign currency losses in Chile.FONINVEMEM III interest income on receivables as discussed above. Brazil SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Brazil SBU for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 270 |
| | $ | 313 |
| | $ | (43 | ) | | -14 | % | | $ | 591 |
| | $ | 516 |
| | $ | 75 |
| | 15 | % | Noncontrolling Interests Adjustment | | 188 |
| | 223 |
| | | | | | 423 |
| | 372 |
| | | | | Derivatives Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 82 |
| | $ | 90 |
| | $ | (8 | ) | | -9 | % | | $ | 168 |
| | $ | 144 |
| | $ | 24 |
| | 17 | % | Adjusted PTC | | $ | 115 |
| | $ | 78 |
| | $ | 37 |
| | 47 | % | | $ | 184 |
| | $ | 120 |
| | $ | 64 |
| | 53 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 44 |
| | $ | 306 |
| | $ | (262 | ) | | -86 | % | | $ | 635 |
| | $ | 822 |
| | $ | (187 | ) | | -23 | % | Noncontrolling Interests Adjustment | | 29 |
| | 208 |
| | | | | | 453 |
| | 580 |
| | | | | Derivatives Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 15 |
| | $ | 98 |
| | $ | (83 | ) | | -85 | % | | $ | 182 |
| | $ | 242 |
| | $ | (60 | ) | | -25 | % | Adjusted PTC | | $ | — |
| | $ | 84 |
| | $ | (84 | ) | | -100 | % | | $ | 184 |
| | $ | 204 |
| | $ | (20 | ) | | 10 | % |
Including the unfavorable impact of foreign currency translation of $23 million, operating marginOperating Margin for the three months ended JuneSeptember 30, 2014 decreased $43$262 million, or 14%86%. This performance was driven primarily by the following businesses and key operating drivers:
Uruguaiana decreased $39 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation volumes from a temporary restart of operations;
Tietê decreased $12$202 million, driven by unfavorable foreign exchange rates of $16 million anddue to lower hydrology which led to lower generation volumes of $40 million as a result of low water inflows, partially offset byand an increase in energy purchases at higher spot prices of $45 million; andprices; Eletropaulo decreased $5$29 million due to higher fixed costs of $53$39 million, including higher payroll and pension expense, as well as higher depreciation and unfavorable impact of foreign exchange, partially offset by $59$15 million of higher rates as a result of the July 20132014 tariff adjustmentadjustment; and volume. These decreases were partially offset by:
Sul increaseddecreased by $13$26 million driven by lower volume and higher volumes from warmer weather of $10 million.fixed costs. Adjusted Operating Margin decreased $883 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê. Adjusted PTC increasedecreased $3784 million, asdue to the decrease of $883 million in Adjusted Operating Margin as described above was offset by the reversal of a loss contingency related to interest expense of $47 million at Sul that is no longer considered probable.above.
Including the unfavorable impact of foreign currency translation of $83 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 increased $75decreased $187 million, or 15%23%. This performance was driven primarily by the following businesses and key operating drivers: Tietê increased $74decreased $129 million, driven by a net impact of $142 million related to higher sales in the spot market, partially offset by lower contracted volumes of energy sold to Eletropaulo, and unfavorable foreign exchange rates of $61 million; Eletropaulo increased $24 million, driven by higher tariffs and volume of $99 million, partially offset by unfavorable foreign exchange rates of $17 million and the net impact of $61 million of lower hydrology which led to lower generation and an increase in energy purchases at higher fixed costs of $56 million; and
Sul increased $23 million, due to higher volume of $35 million,prices, partially offset by higher fixed cost expensespot sales in first half of $3 million mainly related to services,2014 due to the stormy weather, and unfavorable foreign exchange rateslower contracted volumes of $5 million.
These increases were partially offset by:energy sold;
Uruguaiana decreased $46$48 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation in 2014 during the period of temporary restart of operations.operations; Eletropaulo decreased $5 million, driven by higher fixed costs and depreciation of $103 million and unfavorable foreign exchange rates of $16 million, partially offset by higher tariffs and volume of $114 million; and Sul decreased $3 million, due to higher fixed cost and depreciation expense of $14 million mainly driven by storm related maintenance costs, lower rates of $10 million due to the April 2013 tariff reset, and unfavorable foreign exchange rates of $4 million, partially offset by higher volume of $26 million. Adjusted Operating Margin increased $24decreased $60 million primarily due to the drivers discussed above, adjusted for the impact of noncontrollingnon-controlling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.
Adjusted PTC increased $64decreased $20 million, driven by the increasedecrease of the $24$60 million in Adjusted Operating Margin described above and higher interest rates and debt, partially offset by the reversal of a loss contingency resulting from a change in estimate related to interest expense of $47 million at Sul that is no longer considered probable, partially offset by higher interest expense, as a result of an increase in interest rates.probable. MCAC SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our MCAC SBU for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 146 |
| | $ | 149 |
| | $ | (3 | ) | | -2 | % | | $ | 235 |
| | $ | 254 |
| | $ | (19 | ) | | -7 | % | Noncontrolling Interests Adjustment | | 17 |
| | 12 |
| | | | | | 10 |
| | 31 |
| | | | | Derivatives Adjustment | | (3 | ) | | (1 | ) | | | | | | (2 | ) | | (1 | ) | | | | | Adjusted Operating Margin | | $ | 126 |
| | $ | 136 |
| | $ | (10 | ) | | -7 | % | | $ | 223 |
| | $ | 222 |
| | $ | 1 |
| | — | % | Adjusted PTC | | $ | 95 |
| | $ | 104 |
| | $ | (9 | ) | | -9 | % | | $ | 160 |
| | $ | 160 |
| | $ | — |
| | 0% |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 176 |
| | $ | 143 |
| | $ | 33 |
| | 23 | % | | $ | 411 |
| | $ | 397 |
| | $ | 14 |
| | 4 | % | Noncontrolling Interests Adjustment | | 20 |
| | 14 |
| | | | | | 30 |
| | 45 |
| | | | | Derivatives Adjustment | | — |
| | — |
| | | | | | (2 | ) | | (1 | ) | | | | | Adjusted Operating Margin | | $ | 156 |
| | $ | 129 |
| | $ | 27 |
| | 21 | % | | $ | 379 |
| | $ | 351 |
| | $ | 28 |
| | 8 | % | Adjusted PTC | | $ | 124 |
| | $ | 96 |
| | $ | 28 |
| | 29 | % | | $ | 284 |
| | $ | 256 |
| | $ | 28 |
| | 11 | % |
Including the unfavorable impact of currency translation of $1 million, operating margin for the three months ended JuneSeptember 30, 2014 decreased $3increased $33 million, or 2%23%. This performance was driven primarily by the following businesses and key operating drivers: Dominican Republic increased $23 million, mainly related to the favorable impact of rates of $29 million due to lower fuel prices, higher PPA prices, and higher prices of gas sales to third parties; and Panama decreased $8increased $12 million, driven by the Esti tunnel settlement agreement received during the second quarter of 2013 of $31 million, partially offset by a compensation from the government of Panama of $16$13 million related to spot purchases driven by dry hydrological conditions, as well as lower fixed costs of $7 million; and El Salvador decreased $4 million, due primarily to higher energy losses and other fixed costs.
This decrease was partially offset by:
Dominican Republic increased $11 million, mainly related to higher sales due to higher generation of $15 million, as well as higher availability during Q2 2014 of $9 million, partially offset by lower volume of gas sales to third parties of $8 million and higher fuel prices of $5 million.conditions.
Adjusted Operating Margin decreaseincreased $10$27 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina, 50% of Itabo in the Dominican Republic, and a weighted average of 75% of its businesses in El Salvador. Adjusted PTC decreaseincreased $928 million, driven by the decreaseincrease of $1027 million in Adjusted Operating Margin as described above.
Including the unfavorable impact of currency translation of $2$4 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased $19increased $14 million, or 7%4%. This performance was driven primarily by the following businesses and key operating drivers: Dominican Republic increased $59 million, mainly related to lower fuel costs of $31 million and higher PPA prices of $12 million, higher availability of $20 million and related lower maintenance expenses of $8 million, partially offset by lower gas sales to third parties of $11 million. This increase was partially offset by: Panama decreased $39$27 million, driven by dry hydrological conditions, which resulted in lower generation and higher energy purchases of $45$51 million and the Esti tunnel settlement agreement received during 2013 of $31 million, partially offset by compensation from the government of Panama of $23$36 million related to spot purchases from dry hydrological conditions, as well as lower fixed and other costs during 2014 of $14$17 million; and El Salvador decreased $18$15 million, due primarily to a one-time unfavorable adjustment to unbilled revenue, as well as higher energy losses and other fixed costs. This decrease was partially offset by:
Dominican Republic increased $36 million, mainly related to higher availability of $17 million, lower maintenance and other costs of $7 million and higher PPA prices of $12 million.
Mexico increased $5 million, mainly driven by higher availability.
Adjusted Operating Margin increased $1$28 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina, 50% of Itabo in the Dominican Republic, and a weighted average of 75% of its businesses in El Salvador. Adjusted PTC remained flat,increased $28 million, driven by the increase of $1$28 million in Adjusted Operating Margin described above, partially offset by lower equity in earnings from the Trinidad business, which was sold in 2013.above.
EMEA SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our EMEA SBU for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 77 |
| | $ | 86 |
| | $ | (9 | ) | | -10 | % | | $ | 210 |
| | $ | 200 |
| | $ | 10 |
| | 5 | % | Noncontrolling Interests Adjustment | | 5 |
| | 5 |
| | | | | | 11 |
| | 11 |
| | | | | Derivatives Adjustment | | (4 | ) | | — |
| | | | | | (4 | ) | | — |
| | | | | Adjusted Operating Margin | | $ | 68 |
| | $ | 81 |
| | $ | (13 | ) | | -16 | % | | $ | 195 |
| | $ | 189 |
| | $ | 6 |
| | 3 | % | Adjusted PTC | | $ | 73 |
| | $ | 72 |
| | $ | 1 |
| | 1 | % | | $ | 188 |
| | $ | 168 |
| | $ | 20 |
| | 12 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 94 |
| | $ | 85 |
| | $ | 9 |
| | 11 | % | | $ | 304 |
| | $ | 285 |
| | $ | 19 |
| | 7 | % | Noncontrolling Interests Adjustment | | 7 |
| | 6 |
| | | | | | 18 |
| | 17 |
| | | | | Derivatives Adjustment | | 4 |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 91 |
| | $ | 79 |
| | $ | 12 |
| | 15 | % | | $ | 286 |
| | $ | 268 |
| | $ | 18 |
| | 7 | % | Adjusted PTC | | $ | 79 |
| | $ | 66 |
| | $ | 13 |
| | 20 | % | | $ | 267 |
| | $ | 234 |
| | $ | 33 |
| | 14 | % |
Including the neutral impact of foreign currency translation, operating marginOperating Margin for the three months ended JuneSeptember 30, 2014 decreasedincreased $9 million, or 10%11%. This performance was driven primarily by the following businesses and key operating drivers:
Jordan increased $8 million as the IPP4 Jordan plant commenced operations in July 2014; Maritza (Bulgaria)in Bulgaria increased $8 million, driven by better availability of $5 million related to timing of scheduled outages and lower depreciation of $3 million; and Ebute in Nigeria increased $6 million primarily due to fewer outages of $2 million and lower depreciation of $2 million. These increases were partially offset by: Kilroot in the United Kingdom (U.K.) decreased $12$17 million driven by lower availability related to higher scheduled outages. This decrease was partially offset by:
Kilroot (United Kingdom "U.K.") increased $5 million driven by higherdispatch and rates of $6 million, including income from energy price hedges, and strengthening of the British Pound, partially offset by higher outages of $2$14 million.
Adjusted Operating Margin decreaseincreased $1312 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives. Adjusted PTC increased $113 million, as a result of the decreaseincrease of $1312 million in Adjusted Operating Margin described aboveabove. Including the unfavorable impact of foreign currency translation of $1 million, operating margin for the nine months ended September 30, 2014 increased $19 million, or 7%. This performance was driven primarily by the following businesses and key operating drivers: Jordan increased $8 million as the IPP4 Jordan plant commenced operations in July 2014; Ebute increased $7 million due to fewer outages of $6 million and lower depreciation; Kazakhstan increased $6 million driven by higher generation volumes and rates of $19 million, partially offset by unfavorable foreign exchange impact of $8 million; and Wind businesses in the U.K. increased $4 million, driven by higher contributions from Sixpenny Wood, Yelvertoft and Drone Hill, which were sold in August 2014. These results were partially offset by: Kilroot decreased $10 million, driven by lower dispatch and higher outages of $19 million, partially offset by higher rates of $11 million, including income from energy price hedges, and favorable foreign exchange impact. Adjusted Operating Margin increased $18 million due to the drivers above adjusted for non-controlling interests and excluding unrealized gains and losses on derivatives. Adjusted PTC increased $33 million, driven primarily by the increase of $18 million in Adjusted Operating Margin, as well as a reversal of a liability of $18 million in Kazakhstan from the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES. Including the favorable impact of foreign currency translation of $1 million, operating margin for the six months ended June 30, 2014 increased $10 million, or 5%. This performance was driven primarily by the following businesses and key operating drivers:
Kilroot (U.K.) increased $6 million, driven by higher rates, including income from energy price hedges, favorable FX,AES, partially offset by lower dispatch and higher outages;
Wind businesses (U.K.) increased $4 million, driven primarily by new business generation from Sixpenny Wood and Yelvertoft which commenced commercial operation in July 2013 and higher generation from Drone Hill;
Kazakhstan increased $3 million driven by higher generation volumes and rates, partially offset by unfavorable foreign currency; and
Ballylumford (U.K.) increased $2 million, due to higher volumes, partially offset by higher fixed costs.
These results were partially offset by:
Maritza (Bulgaria) decreased $6 million, driven primarily by higher scheduled outages, partially offset by higher rates.
Adjusted Operating Margin increased $6 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $20 million, driven primarily by the increase of $6 million in Adjusted Operating Margin, as well as a reversal of a liability in Kazakhstan as described above, partially offset by lower equity in earnings from Turkey.
Asia SBU The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Asia SBU for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 27 |
| | $ | 45 |
| | $ | (18 | ) | | -40 | % | | $ | 37 |
| | $ | 83 |
| | $ | (46 | ) | | -55 | % | Noncontrolling Interests Adjustment | | 1 |
| | 3 |
| | | | | | 1 |
| | 5 |
| | | | | Derivatives Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 26 |
| | $ | 42 |
| | $ | (16 | ) | | -38 | % | | $ | 36 |
| | $ | 78 |
| | $ | (42 | ) | | -54 | % | Adjusted PTC | | $ | 23 |
| | $ | 40 |
| | $ | (17 | ) | | -43 | % | | $ | 31 |
| | $ | 71 |
| | $ | (40 | ) | | 56 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2014 | | 2013 | | $ Change | | % Change | | 2014 | | 2013 | | $ Change | | % Change | | | ($’s in millions) | Operating Margin | | $ | 12 |
| | $ | 38 |
| | $ | (26 | ) | | -68 | % | | $ | 49 |
| | $ | 121 |
| | $ | (72 | ) | | -60 | % | Noncontrolling Interests Adjustment | | 9 |
| | 2 |
| | | | | | 10 |
| | 7 |
| | | | | Derivatives Adjustment | | — |
| | — |
| | | | | | — |
| | — |
| | | | | Adjusted Operating Margin | | $ | 3 |
| | $ | 36 |
| | $ | (33 | ) | | -92 | % | | $ | 39 |
| | $ | 114 |
| | $ | (75 | ) | | -66 | % | Adjusted PTC | | $ | 2 |
| | $ | 30 |
| | $ | (28 | ) | | -93 | % | | $ | 33 |
| | $ | 101 |
| | $ | (68 | ) | | 67 | % |
Operating margin for the three months ended JuneSeptember 30, 2014 decreased by $1826 million, or 40%68%. This performance was driven primarily by the following businesses and key operating drivers: Masinloc (Philippines)in the Philippines decreased by $17$23 million driven by lower plant availability and related maintenance of $14 million and the net impact of lower spot sales and lower price of spot purchases of $2$18 million; and Kelanitissa (Sri Lanka)in Sri Lanka decreased by $5$6 million driven by the step down in the contracted PPA price.price and higher outages and maintenance costs. Adjusted Operating Margin decreased by $16$33 million due to the drivers above adjusted for the impact of non-controlling interests. AES owns 92%51% of Masinloc after the sell-down in mid-July 2014, and 90% of Kelanitissa. In the comparative period in 2013, AES owned 92% of Masinloc. Adjusted PTC decreased by $17$28 million, driven by the decrease of $16$33 million in Adjusted Operating Margin described above.above, partially offset by the impact of lower proportional interest expense at Masinloc, and OPGC higher equity earnings. Operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased by $46$72 million, or 55%60%. This performance was driven primarily by the following businesses and key operating drivers: Masinloc (Philippines)in the Philippines decreased by $41$64 million, driven by $20$33 million due to lower plant availability, an unfavorable impact of $15 million resulting from the market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013, higher fixed costs of $5 million primarily due to maintenance, and net impact of higher contract demand at lower prices and lower spot sales and lower price of spot purchases of $5$4 million; and Kelanitissa (Sri Lanka)in Sri Lanka decreased by $10$16 million driven by the step down in the contracted PPA price. Adjusted Operating Margin decreased by $42$75 million due to the drivers above adjusted for the impact of non-controlling interests. AES owns 92%51% of Masinloc after the sell-down in mid-July 2014, and 90% of Kelanitissa. In the comparative period in 2013, AES owned 92% of Masinloc. Adjusted PTC decreased by $40$68 million, driven by the decrease of $42$75 million in Adjusted Operating Margin described above, partially offset by the impact of lower proportional interest expense at Masinloc due to a 2013 debt refinancing.and gains on foreign currency. Key Trends and Uncertainties During the remainder of 2014 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors, a combination of factors, (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1. — Business and Item 1A. — Risk Factors of the 2013 Form 10-K. Regulatory Ohio—As noted in Item 1. — Business - United States— US SBU — Dayton Power & Light Company of the 2013 Form 10-K, an order was issued by the Public Utilities Commission of Ohio ("PUCO") in September 2013 (the “ESP Order”), which states that DP&L’s next ESP begins January 1, 2014 and extends through May 31, 2017. On March 19, 2014, the PUCO issued a second entry on rehearing ("Entry on Rehearing") which changes some terms of the ESP order. The Entry on Rehearing shortens the time by which DP&L must divest its generation assets to no later than January 1, 2016 from May 31, 2017 in the ESP Order. The Entry on Rehearing also terminates the potential extension of the Service Stability Rider on April 30, 2017 instead of May 31, 2017. In addition, the Entry on Rehearing accelerates DP&L’s phase-in of the competitive bidding structure to 10% in 2014, 60% in 2015 and 100% in 2016, compared to 10% in 2014, 40% in 2015, 70% in 2016 and 100% in June 2017 in the ESP Order. Parties, including DP&L, have filed applications for rehearing on this Commission Order, which were granted in the PUCO’s third entry on rehearing on May 7, 2014. On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the deadline by which DP&L must divest its generation assets to January 1, 2017. The Ohio Consumer's Counsel has filed an application for rehearing on this Order, which was denied by the PUCO. On June 30, 2014, several intervening parties filed a joint motion to stay collection of the Service Stability Rider while appeals are pending. This motion to stay was denied by the PUCO. The Industrial Energy Users of Ohio and the Ohio Consumer's Counsel filed Notices of Appeal of various aspects of the ESP Order and Entries on Rehearing to the Ohio Supreme Court on August 29, 2014 and September 22, 2014, respectively. On September 19, 2014, DP&L filed a Notice of Cross-appeal of the accelerated phase-in of the competitive bidding structure.
In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets on or before May 31, 2017. DP&L amended its application on February 25, 2014 and again on May 23, 2014. On September 17, 2014, the PUCO issued a Finding and Order in which it approved of DP&L’s plan to separate its generation assets with minor modifications. Specifically, DP&L’s request to defer costs associated with the Ohio Valley Electric Corporation (OVEC) which are not currently being recovered through existing rates was denied, and DP&L was ordered to transfer environmental liabilities with the generation assets. See Item 1. - — Business -— United States SBU -— Dayton Power & Light Company of the 2013 Form 10-K for further details of the ESP order and the filing to separate generation. Philippines—In November and December 2013, the Philippines spot market witnessed an unprecedented price spike compared to historical levels. On March 11, 2014, Energy Regulatory Commission ("ERC") declared the market prices from this period void and ordered the market operator to recalculate the prices for all market participants for November and December 2013 billing months. The recalculation of prices based on the load weighted average prices for the first nine months of 2013 resulted in an unfavorable adjustment of approximately $15 million to Masinloc spot sales. The ERC’s review of the motions for reconsideration filed by market participants including Masinloc is on-going. A secondary price cap was established for May and June 2014 and has been extended to mid-August,December, as a temporary measure to mitigate spot price impacts in the market. AtAs of this time the measure is expected to apply temporarilyhas not had a material impact on our business in 2014, in which case the impact may not be material.Philippines. However, if similar measures are implemented on a permanent basis, the impact could be material. Dominican Republic— In August 2014, the Superintendence of Electricity (Sectoral Regulatory Body of the Electricity Sector), modified the rules for offering primary frequency regulation service, an ancillary service item. The former rules allocated the service to generators based on merit order and those which were the most flexible and could enter the system quickly generally satisfied the supply requirement. The new rule assigns a mandatory minimum margin to all generators which must be provided by own source or through bilateral contracts with other generators who can offer the service, and any additional supply requirement must be allocated using the merit order process. As the AES businesses, Andres and Los Mina, were lower in the merit order they received a majority of the allocation under the former rules. The lower allocation of this service to these units under the new rules will have an impact of lowering the margin from frequency regulation which will be partially offset by higher energy dispatch. Operational Sensitivity to Dry Hydrological Conditions
Our hydroelectric generation facilities are sensitive to changes in the weather, particularly the level of water inflows into generation facilities. Throughout 2013 and 2014, dry hydrological conditions in Brazil, Panama, Chile and Colombia have presented challenges for our businesses in these markets. Low rainfall and water inflows caused reservoir levels to be below historical levels, reduced generation output, and increased prices for electricity. If our hydroelectric generation facilities cannot generate sufficient energy to meet contractual arrangements, we may need to purchase energy to fulfill our obligations, which could have a material adverse impact on our results of operations. Some local forecasts suggest continued dry conditions for the remainder of 2014. Once rainfall and water inflows return to normal levels, high market prices and low generation could persist until reservoir levels are fully recovered. In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels, and manages an Energythere is a mechanism called MRE (Energy Reallocation MechanismMechanism) created to share hydrological risk across all generators. If the system of hydroelectric generation facilities generates less than the assured energy of the system, the shortfall is shared among generators, and depending on a generator's contract level, is fulfilled with spot market purchases. We expect the system operator in Brazil to pursue a more conservative reservoir management strategy going forward, including the dispatch of up to 16 GW of thermal generation capacity, which could result in lower dispatch of hydroelectric generation facilities and electricity prices higher than historicalat high levels. During the first and second quarters of 2014, AES Tietê benefited from lower contract levels and captured spot sales at favorable prices. However, AES Tietê has higher contract obligations in the second half of 2014 and may needhas needed to fulfill some of these obligations with spot purchases, so itthey will be sensitive to generation output and spot prices for electricity during this period. Finally, if dry conditions persist in Brazil throughout 2014 and into the next rainy season, from NovemberDecember 2014 to April 2015, there is a risk that the
government of Brazil could implement a rationing program in 2015, which could have a material adverse impact on our results of operations and cash flows. In Panama, dry hydrological conditions continue to reduce generation output from hydroelectric facilities and have increased spot prices for electricity. From March to June 2014, the government of Panama implemented certain energy saving measures designed to reduce demand for electricity during the peak hours by approximately 300 MW, which contributed to water savings in the key hydroelectric dams and lower spot prices. AES Panama has had to purchase energy on the spot market to fulfill its contract obligations when its generation output is below its contract levels, and we expect this trend to continue for the remainder of the year. As authorized on March 31, 2014, the government of Panama agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70MW reduction in contracted capacity for the period
2014-2016 by compensating AES Panama for spot purchases up to $40 million in 2014, $30 million in 2015 and $30 million in 2016. Compensation payments recognized through September 30, 2014 were $36 million, of which $12 million are pending to be collected. AES owns 49% of AES Panama. Additionally, as part of our strategy to reduce our reliance on hydrology, AES Panama acquired a 72MW power barge for $26 million, financed with non-recourse debt, in September 2014, which we expect to become operational in the first quarter of 2015. Taxes Chilean Tax Reform On April 1,September 29, 2014, the Chilean government sent to Congress a bill proposingenacted comprehensive tax reforms. The proposed reforms would introducewhich introduced significant changes which, among others, include an increase in theto corporate income tax rate from 20% to 25% over a periodrates, modification of 4 years, the introduction of “Greenshareholder level income tax beginning in 2017, and new “green taxes” primarily over CO2 emissions and from 2017 a shareholder level tax on accrued profits rather than on actual dividends. The potential new legislation is being debatedalso beginning in Congress and could be subject to2017. See Note 17 — Income Taxes in Part I. Item 1. — Financial Statements of this Form 10-Q for further modification in the next several months. Should the bill be approved, the financial impact could be material.information. Macroeconomic and Political During the past few years, economic conditions in some countries where our subsidiaries conduct business have deteriorated. Global economic conditions remain volatile and could have an adverse impact on our businesses in the event these recent trends continue. Argentina — In Argentina, economic conditions are deteriorating, as measured by indicators such as non-receding inflation, diminishing foreign reserves, the potential for continued devaluation of the local currency, and a decline in economic growth. Many of these economic conditions in conjunction with the restrictions to freely access the foreign exchange currency established by the Argentine Government since 2012, have contributed to the development of a limited parallel unofficial foreign exchange market that is less favorable than the official exchange. At JuneSeptember 30, 2014, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank. See Note 6 — Financing Receivables in Part I Item 1. — Financial Statements of this Form 10-Q for further information on the long-term receivables. Although our businesses in Argentina have been able to access foreign currency for parts, equipment and equipmentfuel purchases and debt payments when needed, a further weakening of the Argentine Peso and local economic activity could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to the Parent Company, and the value of our assets. Argentina defaulted on its public debt in 2001, when it stopped making payments on about $100 billion amid a deep economic crisis. In 2005 and 2010, Argentina restructured its defaulted bonds into new securities valued at about 33 cents on the dollar. Between the two transactions, 93% of the bondholders agreed to exchange their defaulted bonds for new bonds. The remaining 7% did not accept the restructured deal. Since then, a certain group of the “hold-out” bondholders have been in judicial proceedings with Argentina regarding payment. More recently, the United States District Court ruled that Argentina would need to make payment to such hold-out bondholders according to the original applicable terms. Despite intense negotiations with the hold-out bondholders through the U.S. District Court appointed Special Master, on July 30, 2014 the parties failed to reach a settlement agreement and consequently (as referred by S&P and Fitch ratings) Argentina fell into a selective default resulting from failure to make interest payments on its Discount Bonds maturing in December 2033. Argentina has expressed thatAlthough this situation remains unresolved, it will attempt to reach a satisfactory settlement agreement to unlock the current situation. This situation has not caused any significant changes that impact our current exposures other than those that are discussed above in regards to the macroeconomics within the country. Bulgaria—Our investments in Bulgaria rely on offtaker contracts with NEK, the state-owned electricity public supplier and energy trading company. Maritza, a lignite-fired generation facility, has experienced ongoing delays in the collection of outstanding receivables as a result of liquidity issues faced by NEK. In November 2013, Maritza and NEK signed a rescheduling agreement for the overdue receivables as of November 12, 2013. Under the terms of the agreement, NEK paid $70 million of the overdue receivables and agreed to pay the remaining receivables in 13 equal monthly installments beginning December 2013. NEK has made payments according to the schedule through JulySeptember 2014. As of JuneSeptember 30, 2014, Maritza had outstanding receivables of $226 million, representing $43$50 million of current receivables, $30$14 million of the rescheduled receivables not yet due, $85$74 million of receivables overdue by less than 90 days and $69$88 million of receivables overdue by more than 90 days. On July 31, 2014 Maritza entered into a tripartite agreement with NEK and Mini Maritza Iztok EAD
(MMI), our fuel supplier, which reduced Maritza's outstanding receivables from NEK by $17.3$17 million through an offset of payables due by Maritza to MMI. Additionally, NEK has agreed to four additional monthly installments totaling $27.6$28 million to be paid equally from August to November, 2014. Maritza has also received payments on outstanding receivables of $14.5 million subsequent to June 30, 2014 which were not under the tripartite agreement. Although Maritza continued to collect overdue receivables during the secondthird quarter of 2014 and thereafter, there continue to be risks associated with collections, which could result in a write-off of the remaining receivables and/or liquidity problems which could impact Maritza's ability to meet its obligations, if the situation around collections were to deteriorate significantly. In May and June 2014, Bulgaria’s State Energy and Water Regulatory Commission (SEWRC) issued decisions precluding the ability of NEK to pass-through to the regulated market certain costs incurred by NEK pursuant to the PPA with Maritza,
which could further impactimpacted NEK's liquidity and its ability to make payments under the PPA. SEWRC also instructed NEK and Maritza to begin negotiating amendments to the PPA, including taking one of Maritza’s units out of the PPA and reducing the price of the remaining unit’s output by 30%. It is unclear whether NEK will abide by its obligations underHowever, SEWRC confirmed that until such negotiations conclude, the PPA or objectis in full force and effect and NEK has not objected to Maritza's invoices going forward.invoices. Maritza has filed appeals and requests for suspension of these SEWRC decisions with the Supreme Administrative Court in Bulgaria.Bulgaria with the first hearing scheduled for the beginning of 2015. In addition, SEWRC announced that it has asked the Directorate-General for Competition of the European Commission (DG Comp) to review NEK's respective PPAs with Maritza and a separate generator pursuant to European state aid rules, and to suspend the PPAs pending the completion of that review. DG Comp has not contacted Maritza about the SEWRC's request to date. On July 24, 2014, the Government of Bulgaria formally resigned.resigned and the Caretaker Government was appointed by the President. Preliminary Parliamentary Elections are scheduled forwere held on October 5, 2014 to put2014. Eight political parties were elected and are currently discussing the formation of a new government in place. Installation of the new governmentwhich is expected to allow the negotiations to continue in a productive manner. Meanwhile the Caretaker Government requested and received the resignations of the former Chairman and two commissioners of the Regulator. The new leadership approved an end-consumer energy price increase of approximately 10% effective October 1, 2014, which is expected to slightly improve NEK's liquidity. The Caretaker Government also established an Energy Board, which is consultative body comprised of members who have an interest in the energy sector, with the objective to discuss and propose measures to be taken for stabilization of the energy sector. Maritza is a member of the Energy Board. As a result of any of the foregoing events (including failure by NEK to honor its obligations under the PPA for any reason), we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value (including, without limitation, the value of receivables listed above) and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. For further information about the risks associated with the Company's investment in Maritza, see the following items in the Company's 2013 Form 10-K: Item 1— Business - EMEA; Item 1A. — Risk Factors of the 2013 Form 10-K — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and Item 7: Management's Discussion & Analysis - Key Risks and Uncertainties.Uncertainties. See Note 8 — Debt included in Part I Item 1. — Financial Statements of this Form 10-Q for further information on current existing debt defaults. Further, Maritza is in litigation related to construction delays and related matters. For further information on the litigation see Part II Item 1. — Legal Proceedings. Maritza will take all actions necessary to protect its interests, whether through negotiated agreement with NEK or through enforcement of its rights under the PPA. In addition, if necessary, Maritza will defend the PPA in any assessment or proceeding that may be initiated by DG Comp in response to SEWRC's request. As such, as of JuneSeptember 30, 2014, we concluded there is no indicator of an impairment of the long-lived assets in Bulgaria for Maritza, which were $1.4$1.3 billion and total debt of $797$720 million, and Kavarna, which were $280$256 million and total debt of $190$176 million. Therefore, there is no reason to believemanagement believes the carrying amount of the asset group was notis recoverable as of JuneSeptember 30, 2014. Puerto Rico— Our subsidiary in Puerto Rico has a long-term PPA with the Puerto Rico Electric Power Authority (“PREPA”), a state-owned entity that supplies virtually all of the electric power consumed in the Commonwealth and generates, transmits and distributes electricity to 1.5 million customers. As a result of macroeconomic challenges in the country, including a seven-year recession, PREPA faces economic challenges including, but not limited to reliance on high cost fuel oil, decline in electricity sales, high customer power rates, high operating costs, past due accounts receivables from government institutions, and very low liquidity along with challenges obtaining financing due to the recent downgrades, and has struggled to honor its payment obligations to electricity generators on a timely basis. As a result, AES Puerto Rico's receivables balance has increased toas of September 30, 2014 is $95 million, outstanding as of June 30, 2014, of which $27$33 million is overdue and days sales outstanding from PREPA has deteriorated, which has caused our business to start to be delayed in our payments to suppliers. Subsequent to JuneSeptember 30, 2014, the overdue receivables of $27$30 million have been collected. In February 2014, all agencies downgraded the Commonwealth of Puerto Rico and it's public sector companies (PREPA included) to below investment grade. On June 28, 2014, the Governor of Puerto Rico signed into law the Recovery Act, which allows public corporations to adjust their debts in the interest of all creditors, and establishes procedures for the orderly enforcement. With the recent passing of the Recovery Act, the ratings were further reduced. S&PThe downgrade on PREPA has yet to lowerhad a direct impact on AES Puerto Rico's bonds, except for Moody's which rates the Commonwealth's rating butbonds above the state-owned corporation given AES Puerto Rico is expected to do so in the near term.lowest cost producer of electricity. We believe that AES Puerto Rico’s unique position as the lowest cost energy producer and cost-effective alternative for PREPA relative to fuel oil generated power, positions the business well and reduces the probability of negative impacts from a potential PREPA restructuring process. However there can be no assurance as to the final terms of any restructuring or potential impacts on AES Puerto Rico. If AES Puerto Rico fails to receive payment in accordance with the terms of the PPA with PREPA, its liquidity issues could worsen, which could further impact AES Puerto Rico's ability to meet its obligations. See Item 1A. — Risk Factors of the
2013 Form 10-K — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and "We have a significant amount of debt, a large percentage of which is secured, which could adversely affect our business and the ability to fulfill our obligations." As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. Our Puerto Rico business will take all actions necessary to protect its interests, whether through negotiated agreement with PREPA or through enforcement of its rights under the PPA. In October 2014, the Parent Company reached an agreement with an investor in AES Puerto Rico's preferred shares to retire the investment at a fixed redemption value of $52 million. The redemption is expected to be completed by the end of 2014. As the events pertaining to the Recovery Act continue to
unfold, we concluded that there is no indicator of an impairment of the long-lived assets in Puerto Rico, which were $620$635 million and total debt of $584 million, and there is no reason to believe$594 million. Therefore, management believes the carrying amount of the asset group was notis recoverable as of JuneSeptember 30, 2014. If global economic conditions deteriorate further, it could also affect the prices we receive for the electricity we generate or transmit. Utility regulators or parties to our generation contracts may seek to lower our prices based on prevailing market conditions pursuant to PPAs, concession agreements or other contracts as they come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual price or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses. Impairments
Goodwill — Since its annual goodwill impairment test in the fourth quarter of 2013, the Company has been monitoring three reporting units, DP&L, DPLER and Buffalo Gap, as “at risk.” A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. In the first quarter of 2014, the Company recognized a full goodwill impairment of $136 million at DPLER and a goodwill impairment of $18 million at Buffalo Gap. The Company continues to monitor the remaining goodwill of $10 million at Buffalo Gap and the $316 million goodwill at DP&L. It is possible that the Company may incur goodwill impairment at DP&L, Buffalo Gap or any other reporting unit in future periods if certain events, such as, adverse changes in their business or operating environments occur. Environmental The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts) and certain air emissions, such as SOsulfur dioxide (SO2), NOnitrogen oxides (NOx), particulate matter (PM)and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A. —- Risk Factors, “Our“Our businesses are subject to stringent environmental laws and regulations,,” “Our“Our businesses are subject to enforcement initiatives from environmental regulatory agencies,,” and “Regulators,“Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows”flows” set forth in the Company’s Form 10-K for the year ended December 31, 2013.2013. The following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in Item 1. —- Business —- Regulatory Matters —- Environmental and Land Use Regulations of the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 and in Item 2. —- Management's Discussion and Analysis of Financial Condition and Results of Operations —- Key Trends and Uncertainties —- Regulatory —- Environmental of the Company'sCompany’s Quarterly ReportReports on Form 10-Q for the fiscal quarterquarters ended March 31, 2014 and June 30, 2014. UpdateTax on Greenhouse GasCarbon and Other Emissions Regulationsin Chile
In September 2014, the government of Chile enacted a carbon tax of $5.00 per ton of CO2, as well as taxes on emissions of PM, SO2 and NOx. The United States Environmental Protection Agency (“EPA”) issued proposed rules establishing greenhouse gas (“GHG”) performance standardsamount of the annual tax on PM, SO2 and NOx depends on volume and geographic location of the emissions, among other factors. This tax will be paid annually for existing power plants under Clean Air Act Section 111(d) on June 2, 2014. Under the proposed rule, states would be judged against state-specific carbon dioxide emissions targetsin the previous year, beginning in 2020, with expected total U.S. power section2018 for emissions reductionin 2017. The financial impact to the Company of 30% from 2005 levels by 2030. The proposed rule requires states to submit
implementation plans to meet the standards set forth in the rule by June 30, 2016, with the possibility of one or two-year extensions under certain circumstances. The proposed rule will be subject to a public comment process during the course of this year, after which time EPA is expected to finalize it by President Obama’s June 1, 2015 deadline. Among other things, the Company's U.S.-based businessesthese taxes could be required to make efficiency improvements to existing facilities. However, it is too soon to determine what the rule, and the corresponding state implementation plans affecting the Company’s U.S.-based businesses, will require once they are finalized, whether they will survive judicial and other challenges, and if so, whether and when the rule and the corresponding state implementations plan would materially impact the Company’s business, operations or financial condition.
In addition,material in October 2013, the U.S. Supreme Court granted certiorari for several cases that address EPA’s authority to issue GHG Prevention of Significant Deterioration (“PSD”) permits under Section 165 of the CAA. In June 2014, the U.S. Supreme Court ruled that EPA had exceeded its statutory authority in issuing the so-called “Tailoring Rule” under Section 165 of the CAA by regulating all sources that emitted GHGs. However, the U.S. Supreme Court also held that EPA could impose GHG Best Achievable Control Technology (“BACT”) requirements for sources already required to implement under PSD for other pollutants. Therefore, if future modifications to the Company's U.S.-based businesses' sources require PSD review for other pollutants, it may also trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHG and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of the U.S. Supreme Court’s ruling and GHG BACT requirements applicable to the operation of the Company's U.S.-based businesses cannot be determined at this time as these businesses are not required to implement BACT until they construct a new major source or make a major modification of an existing major source. However, the cost of compliance could be material.
Update on MATS
As further discussed in Item 1. Business — United States Environmental and Land Use Regulations — MATS in the Company's Form 10-K for the year ended December 31, 2013, several lawsuits challenging the Mercury Air Toxics Standards (“MATS”) were filed and consolidated into a single proceeding before the United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”). On April 15, 2014, a three-judge panel of the D.C. Circuit denied the challenges. Twenty-three states and certain industry groups have petitioned the United States Supreme Court to review the decision. We currently cannot predict whether the petition will be granted.
On June 20, 2014, IPL contemporaneously filed a waiver request/alternative complaint with the Federal Energy Regulatory Commission ("FERC") requesting a waiver that will allow IPL to keep 216 MW of reliable capacity available at its Eagle Valley generating station from June 1, 2015 through April 15, 2016. Both of these filings request that the FERC either waive or reform certain requirements of the Midcontinent Independent System Operator, Inc. market tariff for failing to address the specific circumstances resulting from compliance with MATS.
Update on Cooling Water Intake Structures Standards
As further discussed in Item 1. Business — United States Environmental and Land Use Regulations — Water Discharges in the Company's Form 10-K for the year ended December 31, 2013, the Company’s facilities are subject to the U.S. Clean Water Act Section 316(b) rule issued by the EPA which seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the “Best Technology Available” (“BTA”) for cooling water intake structures. On May 19, 2014, the EPA announced its final standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other industrial facilities. These standards require subject facilities that utilize at least 25% of the withdrawn water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day to choose among seven BTA options to reduce fish impingement. In addition, facilities that withdraw at least 125 million gallons per day for cooling purposes must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. This decision process would include public input as part of permit renewal or permit modification. It is possible this process could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility are required to reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards for entrainment. It is not yet possible to predict the total impacts of this recent final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.periods.
Update on Environmental Wastewater Requirements As discussed in Item 1. Business - United States Environmental and Land Use Regulations - Water Discharges in the Company's Form 10-K for the year ended December 31, 2013, certainDP&L is appealing various aspects of the Company’s U.S.-based businesses are subject toa National Pollutant Discharge Elimination System (“NPDES”) permit for J.M. Stuart Station issued by the Ohio EPA. NPDES permits that regulate specific industrial waste waterwastewater and storm water discharges to the watersinto a water of the United States under the FederalU.S. Clean Water Act (“CWA”). In June 2014, the EPA alongAct. It is believed that compliance with the U.S. Army Corpspermit as written will require capital expenses that will be material to DP&L. The cost of Engineers issuedcompliance and the timing of such costs is uncertain and may vary considerably depending on a proposed rule definingcompliance plan that would need to be developed, the waterstype of capital projects that may be necessary, and the uncertainties that may arise in the likely event that permits and approvals from other governmental entities would likely be required to construct and operate any such capital project. DP&L has appealed various aspects of the United States. This rulemakingfinal permit to the Environmental Review Appeals Commission and a hearing has been scheduled for March 2015. The compliance schedule in the potentialfinal permit has been modified to impact all programs underaccommodate the CWA. Expansion of regulated waterways is possible based on initial reviewtiming of the proposal, which may impact several permitting programs. Although we cannot at this time determine the timing or impacthearing. The outcome of compliance with any new regulations, more stringent regulations could have a material impact on our operations and/or consolidated financial results.such appeal is uncertain. Update on the CSAPR
As furtherAlso as discussed in Item 1. 1. Business —- United States Environmental and Land Use Regulations — CAIR and CSAPR - Water Dischargesin the Company's Form 10-K for the year ended December 31, 2013, in responsethe Indiana Department of Environmental Management (“IDEM”) issued NPDES permits to the D.C. Circuit’s striking down muchIPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. These permits set new water quality-based levels of acceptable metal effluent water discharges for the EPA’s Clean Air Interstate Rule (“CAIR”)Petersburg and remanding itHarding Street facilities, as well as monitoring and other requirements designed to protect aquatic life, with full compliance with the new metal effluent limitations required by October 2015. IPL received an extension to the EPA, the EPA issued a new rule in July 2011 titled “Federal Implementation Planscompliance deadline through September 2017 for IPL’s Harding Street and Petersburg facilities through agreed orders with IDEM. IPL conducted studies to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, the CSAPR would have required significant reductions in SO2 and NOx emissions from covered sources, such as power plants, in certain states in which subsidiaries of the Company operate. Once fully implemented (originally planned for 2014), the rule would requiredetermine what operational changes and/or additional SO2 emission reductions of 73% and additional NOx reductions of 54% from 2005 levels. The CSAPR would be implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of new emissions allowances that the EPAequipment will create. The CSAPR contemplates limited interstate and intra-state trading of emissions allowances by covered sources. Initially, the EPA would issue emissions allowances to affected power plants based on state emissions budgets established by the EPA under the CSAPR. The future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time.
Upon petitions for review filed by many states, utilities and other affected parties, the D.C. Circuit vacated the CSAPR in August 2012 and required the EPA to continue administering CAIR pending the promulgation of a valid replacement to the CSAPR. Prior to this decision, the D.C. Circuit had granted a stay of the CSAPR. On April 29, 2014, the United States Supreme Court upheld the CSAPR, reversing the D.C. Circuit Court’s decision to vacate the CSAPR.
It is difficult to predict the steps that will follow this ruling. There remain numerous challenges to the CSAPR that must be addressed, some of which could again result in delay or invalidation of the CSAPR. On June 26, 2014, EPA filed a motion in the D.C. Circuit requesting that the court lift the stay of the CSAPR. EPA also requested that the court extend CSAPR’s compliance deadlines by three years, so that the Phase 1 emissions budgets that were to begin in 2012 would now apply starting in 2015, and the Phase 2 emissions that were to begin in 2014 would apply starting in 2017. The multiple parties to the litigation have filed oppositions to EPA’s motion to lift the stay and all parties have filed motions to govern further proceedings. If the D.C. Circuit grants EPA’s motion, the Company anticipates an increase in capital costs and other expenditures and operational restrictions that would be required to comply with the new limitations. On August 15, 2014, IPL announced its intent to file plans with the IURC to refuel Unit 7 at Harding Street from coal-fired to natural gas. This conversion is part of IPL's overall wastewater compliance plan for its power plants. On October 16, 2014, IPL filed its wastewater compliance plans with the IURC. IPL is seeking approval for a reinstated CSAPR. AtCertificate of Public Convenience and Necessity (CPCN) to install and operate wastewater treatment technologies at its Petersburg and Harding Street plants. If approved, IPL will invest $332 million in these projects to ensure compliance with the wastewater treatment requirements by 2017. IPL expects to recover through its environmental rate adjustment mechanism, operating or capital expenditures related to compliance with these NPDES permit requirements. Recovery of these costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding; however, there can be no assurances that IPL will be successful in that regard. In light of the uncertainties at this time, we cannot predict the impact that such rules would haveof these permit requirements on the Company; they could have a material impact on the Company's business,our consolidated results of operations, cash flows, or financial condition, and results of operations.
IPL Unit Retirement and Replacement Generation
As discussed in Item 1. Business — United States Environmental and Land Use Regulations — Unit Retirement and Replacement Generation in the Company's Form 10-K for the year ended December 31, 2013, in April 2013, IPL filed a petition and case-in-chief with the IURC seeking a CPCN to build a 550 MW to 725 MW combined cycle gas turbine (“CCGT”) at its Eagle Valley generating station and to refuel its Harding Street generating station Units 5 and 6 from coal to natural gas (about 100MW each). In May 2014, the IURC issued an order on the CPCN authorizing the refueling project and granting approval to build a 644 to 685 MW CCGT at a total budget of $649 million. The current estimated cost of these projects is $626 million. IPL was granted authority to accrue post in-service allowance for debt and equity funds used during construction and to defer the recognition of depreciation expense of the CCGT and refueling project until such time that we are allowed to collect both a return and depreciation expense on the CCGT and refueling project. The CCGTbut it is expected to be placed into service in April 2017, and the refueling project is expected to be completed in early 2016. The costs to build and operate the CCGT and for the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after the assets have been placed in service.material.
Capital Resources and Liquidity Overview As of JuneSeptember 30, 2014, the Company had unrestricted cash and cash equivalents of $1.51.7 billion, of which approximately $15229 million was held at the Parent Company and qualified holding companies, and approximatelycompanies. The Company had $424686 million was held in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $1.0 billion967 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.915.7 billion and $5.85.3 billion, respectively. Of the approximately $2.12.3 billion of our current non-recourse debt, $1.1$1.4 billion was presented as such because it is due in the next twelve months and $1.00.9 billion relates to debt considered in default due to covenant violations. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks. Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated
long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company’s only material un-hedged exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility and floating rate senior unsecured notes due 2019. On a consolidated basis, of the Company’s $15.915.7 billion of total non-recourse debt outstanding as of JuneSeptember 30, 2014, approximately $3.94.1 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate. In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At JuneSeptember 30, 2014, the Parent Company had provided outstanding financial and performance-related guarantees, indemnities or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $620 million$1.0 billion in aggregate (excluding those collateralized by letters of credit and other obligations discussed below). As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At JuneSeptember 30, 2014, we had $1 million in letters of credit outstanding, provided under our senior secured credit facility, and $10297 million in cash collateralized letters of credit outstanding outside of our senior secured credit facility. These letters of credit operate to guarantee performance relating to certain project development activities and business operations. During the quarter ended JuneSeptember 30, 2014, the Company paid letter of credit fees ranging from 0.2% to 2.5% per annum on the outstanding amounts. We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has
near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary. Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses. As of JuneSeptember 30, 2014, the Company had approximately $258246 million and $3924 million of accounts receivable related to certain of its generation businesses in Argentina and the Dominican Republic and its utility businesses in Brazil classified as “Noncurrent assets — other” and “Current assets — Accounts receivable,” respectively. The noncurrent portion primarily consists of accounts receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond JuneSeptember 30, 2014, or one year from the latest balance sheet date. The majority of Argentinian receivables have been converted into long-term financing for the construction of power plants. See Note 6 — Financing Receivables included in Part I Item 1. — Financial Statements of this Form 10-Q and Item 1. — Business — Regulatory Matters — Argentina included in the 2013 Form 10-K for further information. Consolidated Cash Flows During the sixnine months ended JuneSeptember 30, 2014,, cash and cash equivalents decreaseincreased $127$28 million to $1.5$1.7 billion. The decreaseincrease in cash and cash equivalents was due to $453 million1.2 billion of cash provided by operating activities, $391364 million of cash used
in investing activities, $250844 million of cash used in financing activities, an unfavorable effect of foreign currency exchange rates on cash of $1455 million and a $75 million decrease in cash of discontinued and held-for-sale businesses. Operating Activities — Net cash provided by operating activities decreased $732824 million to $453 million during the six months endedJune 30, 2014 compared to $1.2 billion during the sixnine months ended JuneSeptember 30, 2014 compared to $2 billion during the nine months endedSeptember 30, 2013. This performance was driven primarily by the following SBUs and key operating activities: Brazil — a decrease of $505 million primarily at Eletropaulo and Sul due to higher prices of energy purchases as well as higher taxes; MCAC — a decrease of $179 million at our generation businesses primarily due to higher working capital requirements; and EMEA — a decrease of $94 million primarily due to higher working capital requirements. OperatingNet cash flow forprovided by operating activities was $1.2 billion during the sixnine months ended JuneSeptember 30, 2014. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization, impairment expenses and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $1 billion in operating assets and liabilities. This net use of cash forwithin operating activities of $1 billion was primarily due to the following:
an increase of $316494 million in accounts receivable primarily related to higher sales at Eletropaulo, Sul and Alicura and lower collections at Maritza; an increase of $439 million in other assets primarily related to increased regulatory assets at Eletropaulo and Sul resulting from higher priced energy purchases recoverable through future tariffs; an increase of $312 million in accounts receivable primarily related to higher sales at Sul, Alicura and Gener, return of operations at Uruguaiana in March 2014 and lower collections at Maritza;
a decrease of $194 million in accounts payable and other current liabilities primarily at Eletropaulo relating to a decrease in regulatory liabilities; a decrease of $176239 million in net income tax and other tax payables primarily related to payments of income taxes exceeding accruals for the 2014 tax liability.liability; partially offset by
an increase of $319 million in other liabilities primarily related to an increase in regulatory liabilities at Eletropaulo and Sul partially offset by reduced pension contributions at IPL and payments for share-based compensation issuance tax and derivative termination at the Parent Company. Net cash provided by operating activities was $1.22.0 billion during the sixnine months ended JuneSeptember 30, 2013. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $310255 million in operating assets and liabilities. This net use of cash forwithin operating activities of $310$255 million was primarily due to: a decrease of $252$578 million in accounts payable and other current liabilities primarily at Eletropaulo and Sul due to lower costs and a decrease in regulatory liabilities and a decrease in value added taxes payables due to the lower tariff in 2013 andas well as at Uruguaiana primarily related to the extinguishment of a liability based on a favorable arbitration decision; an increase of $147$149 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo and Sul, resulting from higher priced energy purchases which are recoverable through future tariffs; partially offset bya decrease of $134$403 million in net income taxprepaid expenses and other tax payablescurrent assets primarily from payment of income taxes exceeding accrualsdue to a decrease in current regulatory assets, for the tax liability on 2013 income, partially offset by an accrualrecovery of indirect taxes in Brazil; partially offset by prior-period tariff cycle energy purchases and transportation costs at Eletropaulo and Sul; anda decrease of $191$135 million in accounts receivable primarily duerelated to lower tariffs in 2013 at Eletropaulo and higher collections combined with lower tariffs and reduced consumption at Sul, partially offset by lower collections at Maritza.
The net decrease of cash flows from operating activities of $732 million for the six months endedJune 30, 2014 compared to the six months endedJune 30, 2013 was primarily the result of the following:
Brazil — a decrease of $442 million primarily at Eletropaulo and Sul due to higher prices of energy purchases as well as higher taxes and interest on debt.
US — a decrease of $160 million primarily due to proceeds from the PPA termination at Beaver Valley in January 2013 and lower operating results and higher working capital requirements at DPL.
MCAC — a decrease of $154 million at our generation businesses primarily due to higher working capital requirements.
Investing Activities — Net cash used in investing activities was $391364 million during the sixnine months ended JuneSeptember 30, 2014 primarily attributable to the following: Capital expenditures of $908 million1.4 billion consisting of $536$789 million of growth capital expenditures and $372$600 million of maintenance and environmental capital expenditures. Growth capital expenditures primarily included amounts at Gener of $250$303 million, Eletropaulo of $83$125 million,Vietnam Mong Duong of $45$72 million, Jordan of $71 million, IPL of $61 million and Jordan $38Sul of $35 million. Maintenance and environmental capital expenditures primarily included amounts at IPL of $105$178 million, Eletropaulo of $42$73 million, Tietê of $40$64 million, Gener of $50 million, DPL of $48 million and DPLSul of $32 million.$41 million; Acquisitions, net of cash acquired of $728 million consisted of an acquisition at Gener in the second quarter for the remaining 50% interest in our equity investment in Guacolda, of which 50% less one share was subsequently sold during the same quarter. See Note 7 — Investment in and Advances to Affiliates in Item 1. — Financial Statements of this Form 10-Q for further information. These amounts wereinformation; partially offset by Proceeds from the sale of businesses of $890 million with$1.7 billion including $730 million at Gener related to the sale of 50% less one share of our interest in Guacolda, $443 million for the sale of 45% of our equity interest in Masinloc, $179 million related to the the sale of AES’ interest in Silver Ridge Power’s assets in Bulgaria, France, Greece, India and $160the United States and $156 million from the sale of our businessesbusiness in Cameroon,Cameroon; and
Decreases in restricted cash, debt service reserves and other assets of $162 million including amounts at the USParent Company of $66 million, Maritza of $44 million and India; and SalesAlto Maipo of short-term investments, net of purchases of $273 million primarily in Brazil.$37 million.
Net cash used in investing activities was $706 million1.3 billion during the sixnine months ended JuneSeptember 30, 2013. This was primarily attributable to the following: Capital expenditures of $866 million$1.3 billion consisting of $454$690 million of growth capital expenditures and $412$640 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Eletropaulo of $138$188 million, Gener of $81$166 million, Jordan of $54$95 million, Sul of $44$57 million, Sixpenny WoodDPL of $22$28 million, Mong Duong of $19$27 million, Yelvertoft of $20 million, Kribi of $17 million and YelvertoftAltai of $19$16 million. Maintenance and environmental capital expenditures included amounts at IPALCOIPL of $87$164 million, Eletropaulo of $72$103 million, DPL of $63 million, Gener of $47$61 million, DPLTietê of $46$53 million, Sul of $39$50 million, Altai of $21 million and Itabo of $15 million; Purchase of short-term investments, net of sales of $263 million including amounts at Eletropaulo of $212 million, Sul of $32 million and Tietê of $30$29 million; partially offset by Proceeds from the sale of business, net of cash sold of $135$167 million including $113 million for the sale of the Ukraine businesses, $31 million for the sale of our 10% equity interest in Trinidad and $24 million for the sale of our remaining interest in Cartagena.
Net cash used in investing activities decreased $315903 million to $391364 million during the sixnine months ended JuneSeptember 30, 2014 compared to net cash used in investing activities of $706 million1.3 billion during the sixnine months ended JuneSeptember 30, 2013. This net decrease was primarily due to an increase in proceeds from the sale of business, net of cash sold of $1.5 billion, a decrease in purchases of short-term investments, net of sales of $343212 million, partially offset by an increase in acquisitions of $725 million. Financing Activities — Net cash used in financing activities was $250844 million during the sixnine months ended JuneSeptember 30, 2014. This was primarily attributable to the following: Payments for financed capital expenditures of $312 million, primarily at Mong Duong with $272 million in payments to the contractors, which took place more than three months after the associated equipment was purchased or work performed;
Distributions to minority interests of $197 million primarily at Tietê with $109 million; and
Repayments of recourse and non-recourse debt of $3.03.7 billion including amounts at the Parent Company of $1.7$2 billion, Gener of $853$905 million, Tietê of $132 million, Maritza of $65 million, Shady Point of $52 million, Puerto Rico of $51 million and Puerto Rico$114 million related to the UK Wind sale; Distributions to noncontrolling interests of $42$377 million including amounts at Tietê of $188 million, Brasiliana Energia of $65 million, Gener of $35 million and Buffalo Gap of $33 million; Payments for financed capital expenditures of $360 million primarily at Mong Duong of $272 million; partially offset by Issuances of recourse and non-recourse debt of $3.23.8 billion, including new issuances at the Parent Company of $1.5 billion, Gener of $700 million, Mong Duong of $298 million, Eletropaulo of $253 million, Cochrane of $173 million, IPL of $130 million and Tietê of $129 million; and a draw down under construction loan facility at Mong Duong of $272 million. Net cash used in financing activities was $799635 million during the sixnine months ended JuneSeptember 30, 2013. This was primarily attributable to the following:
Payments for financed capital expenditures of $257 million, primarily at Mong Duong for payments to the contractors, which took place more than three months after the associated equipment was purchased or work performed;
Distributions to noncontrolling interests of $211 million included amounts at Tietê of $98 million, Brasiliana of $34 million, Buffalo Gap of $25 million, and Gener of $18 million;
Payments for financing fees of $127 million included amounts at Cochrane of $41 million, Eletropaulo of $25 million, and Mong Duong of $13 million; and
Repayments of recourse and non-recourse debt of $3.4$3.5 billion primarilyincluded amounts at the Parent Company of $1.2 billion, Masinloc of $546 million, DPL of $425 million, Tietê of $396 million, El Salvador of $301 million, IPL of $110 million, Warrior Run of $87$93 million, Puerto Rico of $52$65 million, Maritza of $57 million, Sonel of $46 million and Sul of $37$40 million; Payments for financed capital expenditures of $436 million, primarily at Mong Duong for payments to the contractors which took place more than three months after the associated equipment was purchased or work performed; Distributions to noncontrolling interests of $385 million included amounts at Tietê of $154 million, Brasiliana Energia of $96 million, Gener of $39 million and MaritzaBuffalo Gap of $29$19 million; Payments for financing fees of $148 million included amounts at Cochrane of $42 million, Eletropaulo of $25 million, Mong Duong of $20 million and the Parent Company of $17 million; partially offset by Issuances of recourse and non-recourse debt of $3.1$3.8 billion,, including amounts at the Parent Company for $750 million, DPL of $645 million, Masinloc of $500 million, Tietê of $496 million, Mong Duong of $339 million, El Salvador of $310 million, Mong Duong of $210 million, DPL of $200 million, IPL of $170 million, Sul of $150 million, Jordan of $138 million, Cochrane of $82$120 million,Warrior Run of $74 million and Kribi of $63 million; and Contributions from noncontrolling interests of $157 million including amounts at Mong Duong of $55 million, Alto Maipo of $50 million and JordanCochrane of $61$34 million. Net cash used in financing activities decreasedincreased $549209 million to $250844 million during the sixnine months ended JuneSeptember 30, 2014 compared to net cash used in financing activities of $799635 million during the sixnine months ended JuneSeptember 30, 2013. This net decreaseincrease was primarily due to a decreasean increase in the repayments of recourse and non-recourse debt of $363 million and an increase in the issuance of recourse and non-recourse debt of $102162 million.
Proportional Free Cash Flow (a non-GAAP measure) We define Proportional Free Cash Flow as cash flows from operating activities less maintenance capital expenditures (including non-recoverable environmental capital expenditures), adjusted for the estimated impact of noncontrolling interests. The proportionate share of cash flows and related adjustments attributable to noncontrolling interests in our subsidiaries comprise the proportional adjustment factor presented in the reconciliation below. We exclude environmental capital expenditures that are expected to be recovered through regulatory, contractual or other mechanisms. An example of recoverable environmental capital expenditures is IPL's investment in MATS-related environmental upgrades that are recovered through a tracker. See Item 1. Business— US SBU — IPALCO — Environmental Matters in the 2013 Form 10-K for details of these investments. The GAAP measure most comparable to proportional free cash flow is cash flows from operating activities. We believe that proportional free cash flow better reflects the underlying business performance of the Company, as it measures the cash generated by the business, after the funding of maintenance capital expenditures, that may be available for investing or repaying debt or other purposes. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly-owned by the Company. The presentation of free cash flow has material limitations. Proportional free cash flow should not be construed as an alternative to cash from operating activities, which is determined in accordance with GAAP. Proportional free cash flow does not represent our cash flow available for discretionary payments because it excludes certain payments that are required or to which we have committed, such as debt service requirements and dividend payments. Our definition of proportional free cash flow may not be comparable to similarly titled measures presented by other companies
| | | | | | | | | | | | | | | | | | | | Three months ended June 30, | | Six months ended June 30, | | | 2014 | | 2013 | | 2014 | | 2013 | | | (in millions) | Calculation of Maintenance Capital Expenditures for Free Cash Flow Reconciliation Below: | | | | | | | | | Maintenance Capital Expenditures | | $ | 152 |
| | $ | 174 |
| | $ | 289 |
| | $ | 360 |
| Environmental Capital Expenditures | | 77 |
| | 42 |
| | 111 |
| | 73 |
| Growth Capital Expenditures | | 414 |
| | 354 |
| | 820 |
| | 690 |
| Total Capital Expenditures | | $ | 643 |
| | $ | 570 |
| | $ | 1,220 |
| | $ | 1,123 |
| Consolidated | | | | | | | | | Net cash provided by operating activities | | $ | 232 |
| | $ | 567 |
| | $ | 453 |
| | $ | 1,185 |
| Less: Maintenance Capital Expenditures, net of reinsurance proceeds | | 152 |
| | 174 |
| | 289 |
| | 360 |
| Less: Non-recoverable Environmental Capital Expenditures | | 25 |
| | 26 |
| | 36 |
| | 47 |
| Free Cash Flow | | $ | 55 |
| | $ | 367 |
| | $ | 128 |
| | $ | 778 |
| Reconciliation of Proportional Operating Cash Flow | | | | | | | | | Net cash provided by operating activities | | $ | 232 |
| | $ | 567 |
| | $ | 453 |
| | $ | 1,185 |
| Less: Proportional Adjustment Factor (1) | | 64 |
| | 263 |
| | 44 |
| | 367 |
| Proportional Operating Cash Flow | | $ | 168 |
| | $ | 304 |
| | $ | 409 |
| | $ | 818 |
| Proportional | | | | | | | | | Proportional Operating Cash Flow | | $ | 168 |
| | $ | 304 |
| | $ | 409 |
| | $ | 818 |
| Less: Proportional Maintenance Capital Expenditures, net of reinsurance proceeds (1) | | 102 |
| | 121 |
| | 206 |
| | 258 |
| Less: Proportional Non-recoverable Environmental Capital Expenditures (1) | | 19 |
| | 18 |
| | 27 |
| | 34 |
| Proportional Free Cash Flow | | $ | 47 |
| | $ | 165 |
| | $ | 176 |
| | $ | 526 |
|
| | | | | | | | | | | | | | | | | | | | Three months ended September 30, | | Nine months ended September 30, | | | 2014 | | 2013 | | 2014 | | 2013 | | | (in millions) | Calculation of Maintenance Capital Expenditures for Free Cash Flow Reconciliation Below: | | | | | | | | | Maintenance Capital Expenditures | | $ | 169 |
| | $ | 166 |
| | $ | 458 |
| | $ | 526 |
| Environmental Capital Expenditures | | 62 |
| | 72 |
| | 172 |
| | 145 |
| Growth Capital Expenditures | | 298 |
| | 405 |
| | 1,119 |
| | 1,095 |
| Total Capital Expenditures | | $ | 529 |
| | $ | 643 |
| | $ | 1,749 |
| | $ | 1,766 |
| Consolidated | | | | | | | | | Net cash provided by operating activities | | $ | 763 |
| | $ | 855 |
| | $ | 1,216 |
| | $ | 2,040 |
| Less: Maintenance Capital Expenditures, net of reinsurance proceeds | | 169 |
| | 166 |
| | 458 |
| | 526 |
| Less: Non-recoverable Environmental Capital Expenditures | | 16 |
| | 22 |
| | 52 |
| | 69 |
| Free Cash Flow | | $ | 578 |
| | $ | 667 |
| | $ | 706 |
| | $ | 1,445 |
| Reconciliation of Proportional Operating Cash Flow | | | | | | | | | Net cash provided by operating activities | | $ | 763 |
| | $ | 855 |
| | $ | 1,216 |
| | $ | 2,040 |
| Less: Proportional Adjustment Factor (1) | | 208 |
| | 327 |
| | 251 |
| | 694 |
| Proportional Operating Cash Flow | | $ | 555 |
| | $ | 528 |
| | $ | 965 |
| | $ | 1,346 |
| Proportional | | | | | | | | | Proportional Operating Cash Flow | | $ | 555 |
| | $ | 528 |
| | $ | 965 |
| | $ | 1,346 |
| Less: Proportional Maintenance Capital Expenditures, net of reinsurance proceeds (1) | | 116 |
| | 114 |
| | 322 |
| | 372 |
| Less: Proportional Non-recoverable Environmental Capital Expenditures (1) | | 12 |
| | 17 |
| | 39 |
| | 51 |
| Proportional Free Cash Flow | | $ | 427 |
| | $ | 397 |
| | $ | 604 |
| | $ | 923 |
|
(1) The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds), and proportional non-recoverable environmental capital expenditures are calculated by multiplying the percentage owned by non-controlling interests for each entity by its corresponding consolidated cash flow metric and adding up the resulting figures. For example, the Company owns approximately 70% of AES Gener, its subsidiary in Chile. Assuming a consolidated net cash flow from operating activities of $100 from AES Gener, the proportional adjustment factor for AES Gener would equal approximately $30 (or $100 x 30%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then adds these amounts together to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to non-controlling interests as a result of (a) non-cash items which impact income but not cash and (b) AES’ ownership interest in the subsidiary where such items occur. Proportional Free Cash Flow for the three months ended JuneSeptember 30, 2014 compared to the three months ended JuneSeptember 30, 2013 increased $30 million, driven by higher Proportional Operating Cash Flow and lower Proportional Non-recoverable Environmental Capital Expenditures. This performance was driven primarily by increases from the following SBUs and key operating drivers: US — driven by higher operating cash flow at the US Utilities driven by lower working capital requirements and higher earnings; and Brazil — driven by Sul due to higher collections, partially offset by higher energy purchases and higher tax payments. These increases were partially offset by decreases at:
Asia — driven by Masinloc due to lower earnings and higher working capital requirements; EMEA — driven by lower results for Wind entities driven by sale of UK Wind assets, sold in August 2014, and lower collections at Kavarna in Bulgaria as well as Kilroot in the U.K. driven by lower earnings; MCAC — driven by higher working capital requirements as a result of lower collections and timing of inventory in the Dominican Republic. Proportional Free Cash Flow for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 decreased $118$319 million, driven by lower Proportional Operating Cash Flow, partially offset by lower Proportional Maintenance and Non-recoverable Environmental Capital Expenditures. This performance was driven primarily by decreasesincreases from the following SBUs and key operating drivers: MCAC — due todriven by higher working capital requirements in the Dominican Republic;Republic and Panama; Brazil — driven by higher pricesprice of energy purchases as well asand higher taxes and interest on debt at Eletropaulo and Sul.Sul; and These decreases were partially offset by an increase at:
CorpEMEA — driven by lower interest payments.
Proportional Free Cash Flow for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 decreased $350 million, driven by lower Proportional Operating Cash Flow, partially offset by lower Proportional Maintenance Capital Expenditures. This performance was driven primarily by decreases from the following SBUs and key operating drivers:
Brazil — driven by higher prices of energy purchases as well as higher taxes and interest on debt at Eletropaulo and Sul;
MCAC — due to higher working capital requirements in the Dominican Republic; and
US — due to proceeds from the PPA termination at Beaver Valley in January 2013 and lower operating resultsmargins and higher working capital requirementsin the U.K. and lower collections at DPL, partially offset by lower proportional maintenance capital expenditures.Maritza and Kavarna in Bulgaria.
Parent Company Liquidity The following discussion of Parent Company Liquidity has been included because we believe it is a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company Liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to cash and cash equivalents which are determined in accordance with GAAP as a measure of liquidity. Cash and cash equivalents are disclosed in the condensed consolidated statements of cash flows. Parent Company Liquidity may differ from similarly titled measures used by other companies. The principal sources of liquidity at the Parent Company level are:
dividends and other distributions from our subsidiaries, including refinancing proceeds; proceeds from debt and equity financings at the Parent Company level, including availability under our credit facilities; and proceeds from asset sales. Cash requirements at the Parent Company level are primarily to fund: interest; principal repayments of debt; acquisitions; construction commitments; other equity commitments; common stock repurchases; taxes; Parent Company overhead and development costs; and dividends on common stock. The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents,” at the periods indicated as follows: | | | | | | | | | | Parent Company Liquidity | | June 30, 2014 | | December 31, 2013 | | | (in millions) | Consolidated cash and cash equivalents | | $ | 1,515 |
| | $ | 1,642 |
| Less: Cash and cash equivalents at subsidiaries | | 1,500 |
| | 1,510 |
| Parent and qualified holding companies’ cash and cash equivalents | | 15 |
| | 132 |
| Commitments under Parent credit facilities | | 800 |
| | 800 |
| Less: Borrowings under the credit facilities | | (120 | ) | | — |
| Less: Letters of credit under the credit facilities | | (1 | ) | | (1 | ) | Borrowings available under Parent credit facilities | | 679 |
| | 799 |
| Total Parent Company Liquidity | | $ | 694 |
| | $ | 931 |
|
| | | | | | | | | | Parent Company Liquidity | | September 30, 2014 | | December 31, 2013 | | | (in millions) | Consolidated cash and cash equivalents | | $ | 1,670 |
| | $ | 1,642 |
| Less: Cash and cash equivalents at subsidiaries | | 1,441 |
| | 1,510 |
| Parent and qualified holding companies’ cash and cash equivalents | | 229 |
| | 132 |
| Commitments under Parent credit facilities | | 800 |
| | 800 |
| Less: Letters of credit under the credit facilities | | (1 | ) | | (1 | ) | Borrowings available under Parent credit facilities | | 799 |
| | 799 |
| Total Parent Company Liquidity | | $ | 1,028 |
| | $ | 931 |
|
The Company paid a dividend of $0.05 per share to its common stockholders during the three months ended JuneSeptember 30, 2014. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance we will be able to continue the payment of dividends. While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets (see Key Trends and Uncertainties and Global Economic Considerations in this Item 2), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured credit facility. See Item 1A. — Risk Factors “The, “The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.otherwise.” of the Company’s 2013 Form 10-K. Various debt instruments at the Parent Company level, including our senior secured credit facilities, contain certain restrictive covenants. The covenants provide for, among other items:
limitations on other indebtedness, liens, investments and guarantees; limitations on dividends, stock repurchases and other equity transactions; restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements; maintenance of certain financial ratios; and
financial and other reporting requirements. As of JuneSeptember 30, 2014, the Parent Company was in compliance with these covenants. Non-Recourse Debt While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:
reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default; triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary; causing us to record a loss in the event the lender forecloses on the assets; and triggering defaults in our outstanding debt at the Parent Company. For example, our senior secured credit facilities and outstanding debt securities at the Parent Company include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries. Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying condensed consolidated balance sheet amounts to $2.12.3 billion. The portion of current debt related to such defaults was $1.00.9 billion at JuneSeptember 30, 2014, all of which was non-recourse debt related to two subsidiaries — Maritza and Kavarna. None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’s corporate debt agreements as of JuneSeptember 30, 2014 in order for such defaults to trigger an event of default or permit acceleration under AES’s indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities. A material subsidiary is defined in the Company's senior secured revolving credit facility as any business that contributed 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of JuneSeptember 30, 2014, none of the defaults listed above individually or in the aggregate results in or is at risk of triggering a cross-default under the recourse debt of the Company.
Critical Accounting Policies and Estimates The condensed consolidated financial statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. The Company’s significant accounting policies are described in Note 1 — General and Summary of Significant Accounting Policies to the consolidated financial statements included in our 2013 Form 10-K. The Company’s critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2013 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that those policiesthese remain the Company’sas critical accounting policies as of and for the sixnine months ended JuneSeptember 30, 2014. During the third quarter of 2014, the following additional critical accounting estimate was employed with respect to the Company's sales of noncontrolling interests: Sales of Noncontrolling Interests The accounting for a sale of noncontrolling interests under the accounting standards depends on whether the sale is considered to be a sale of in-substance real estate (as opposed to an equity transaction), where the gain (loss) on sale would be recognized in earnings rather than within stockholders’ equity. If management's estimation process determines that there is no significant value beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest is recognized in earnings. However, if it is determined that significant value likely exists beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest would be recognized within stockholders’ equity. In-substance real estate is comprised of land plus improvements and integral equipment. The determination of whether property, plant and equipment is integral equipment is based on the significance of the costs to remove the equipment from its existing location (including the cost of repairing damage resulting from the removal), combined with the decrease in the fair value of the equipment as a result of those removal activities. When the combined total of removal costs and the decrease in fair value of the equipment exceeds 10% of the fair value of the equipment, the equipment is considered integral equipment. The accounting standards specifically identify power plants as an example of in-substance real estate. Where the consolidated entity in which noncontrolling interests have been sold contains in-substance real estate, management estimates the extent to which the total fair value of the assets of the entity is represented by the in-substance real estate and whether significant value exists beyond the in-substance real estate. This estimation considers all qualitative and quantitative factors relevant for each sale and, where appropriate, includes making quantitative estimates about the fair value of the entity and its identifiable assets and liabilities (including any favorable or unfavorable contracts) by analogy to the accounting standards on business combinations. As such, these estimates may require significant judgment and assumptions, similar to the critical accounting estimates previously disclosed in our 2013 Form 10-K for impairments and fair value. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Overview Regarding Market Risks Our generation and utility businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal and environmental credits. We operate in multiple countries and as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between
our functional currency, the U.S. Dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments. These disclosures set forth in this Item 3 are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 3. For further information regarding market risk, see Item 1A. — Risk Factors, Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations, Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance, and We may not be adequately hedged against our exposure to changes in commodity prices or interest rates of the 2013 Form 10-K. Commodity Price Risk Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term sales or under contract sales that leave an
un-hedged exposure on some of our capacity or through imperfect fuel pass-throughs. In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations and sharing or pass-through mechanisms. These businesses subject our operational results to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options. When hedging the output of our generation assets, we utilize contract strategies that lock in the spread per MWh between variable costs and the price at which the electricity can be sold. The portion of our sales and purchases that are not subject to such agreements or contracted businesses where indexation is not perfectly matched to business drivers will be exposed to commodity price risk. AES businesses will see changes in variable margin performance as global commodity prices shift. For the remainder of 2014, we project pretax earnings exposure on a 10% move in commodity prices would be approximately $5 million for natural gas, $5 million for oil and less than $5 million for coal. Our estimates exclude correlation of oil with coal or natural gas. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some of our businesses. Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Spot power prices, contract indexation provisions and generation costs can be directly or indirectly affected by movements in the price of natural gas, oil and coal. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. OffsetsExposures are not perfectly linear or symmetric. The sensitivities are affected by a number of local or indirect market factors. Examples of these factors include hydrology, local energy market supply/demand balances, regional fuel supply issues, regional competition, bidding strategies and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, certain power plants may limit downside exposure by reducing dispatch in low market environments. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices. In the US SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Additionally, at DPL, open access allows our retail customers to switch to alternative suppliers; falling energy prices may increase the rate at which our customers switch to alternative suppliers; DPL sells generation in excess of its retail demand under short-term sales. Given that natural gas-fired generators set power prices for many markets, higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during some periods. In the Andes SBU, our business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. In the central region, the contract sales generally cover the efficient generation from our coal-fired and hydroelectric assets. Any residual spot price risk will primarily be driven by the amount of hydrological inflows. In the case of low hydroelectric generation, spot price exposure is capped by the ability to dispatch our natural gas/diesel assets.assets which can be an expensive cap depending on fuel pricing at the time required. There is a small amount of coal generation in the northern region that is not covered by the portfolio of contract sales and therefore subject to spot price risk. In both regions, generators with oil or oil-linked fuel generally set power prices. In Colombia, we
operate under a short-term sales strategy and have commodity exposure to un-hedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel. In the Brazil SBU, the hydroelectric generating facility is covered by contract sales. Under normal hydrological volatility, spot price risk is mitigated through a regulated sharing mechanism across all hydroelectric generators in the country. Under drier conditions, the sharing mechanism may not be sufficient to cover the business' contract position, and therefore it may have to purchase power at spot prices driven by the cost of thermal generation. In the MCAC SBU, our businesses have commodity exposure on un-hedged volumes. Panama is largelyhighly contracted under a portfolio of fixed volume contract sales. To the extent hydrological inflows are greater than or less than the contract sales volume, the business will be sensitive to changes in spot power prices which may be driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices. Additionally, the contract levels do not always match our generation availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot market to satisfy contract obligations.
In the EMEA SBU, our Kilroot facility operates on a short-term sales strategy. To the extent that sales are un-hedged, the commodity risk at our Kilroot business is to the clean dark spread — the difference between electricity price and our coal-based variable dispatch cost including emissions. Natural gas-fired generators set power prices for many periods, so higher natural gas prices generally expand margins and higher coal or emissions prices reduce them. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods. At our Ballylumford facility, the regulator has the right to terminate the contract, which would impact our commodity exposure. Our operations in Turkey are sensitive to the spread between power and natural gas prices, both of which have historically demonstrated a relationship to oil. As a result of these relationships, falling oil prices could compress margins realized at the business. In the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume soldor shortfalls of generation relative to contract volumes settled in the spot market. Low oil prices may be a driver of margin compression since oil affects spot power sale prices. Foreign Exchange Rate Risk In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in the U.S. Dollar or currencies other than their own functional currencies. We have varying degrees of exposure to changes in the exchange rate between the U.S. Dollar and the following currencies: Argentine Peso, Brazilian Real, British Pound, Chilean Peso, Colombian Peso, Dominican Peso, Euro, Indian Rupee, KazakhstaniKazakhstan Tenge, Mexican Peso and Philippine Peso. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations. We have entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. The largest foreign exchange risks over a twelve-month forward-looking period are stemming from the following currencies: Argentine Peso, British Pound, Brazilian Real, Colombian Peso, Euro and Kazakhstan Tenge. As of JuneSeptember 30, 2014, assuming a 10% U.S. Dollar appreciation, adjusted pretax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro and Kazakhstan Tenge relative to the U.S. Dollar are projected to be reduced by approximately $5 million, $5 million, $5 million, $5 million, less than $5 million and $5 million respectively,for each currency for the remainder of 2014. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pretax earnings for 2014 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted pretax earnings exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility. Interest Rate Risks We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt, as well as interest rate swap, cap and floor and option agreements. Decisions on the fixed-floating debt ratio are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-
recoursenon-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Most of our interest rate risk is related to non-recourse financings at our businesses.
As of JuneSeptember 30, 2014, the portfolio’s pretax earnings exposure for the remainder of 2014 to a 100-basis-point increase in interest rates for our Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro, Kazakhstani Tenge and U.S. Dollar denominated debt would be approximately $10 million based on the impact of a one time, 100-basis-point upward shift in interest rates on interest expense for the debt denominated in these currencies. The amounts do not take into account the historical correlation between these interest rates. ITEM 4. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures The Company, under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”)CEO and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our
disclosure controls and procedures were effective as of JuneSeptember 30, 2014 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure. Changes in Internal Controls over Financial Reporting ThereOn May 14, 2013, The Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) issued an updated version of its Internal Control - Integrated Framework (the “2013 Framework”). Originally issued in 1992 (the “1992 Framework”), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. We have reviewed the 2013 Framework and integrated the changes into the Company’s internal controls over financial reporting. We expect that management’s assessment of the overall effectiveness of our internal controls over financial reporting for the year ending December 31,2014 will be based on the 2013 Framework and that the change will not be significant to our overall control structure over financial reporting.
As of September 30 2014, there were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II: OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of JuneSeptember 30, 2014. In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro (“FDC”) against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the FDC found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$1.511.53 billion ($685629 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off of EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo’s defenses in the execution suit. On appeal, the case was remanded to the FDC for further proceedings.proceedings to determine whether Eletropaulo is liable for the debt. In December 2012, the FDC issued a decision that Eletropaulo is liable for the debt. However, that decision was annulled on appeal and the case was remanded to the FDC for further proceedings. On remand at the FDC, the FDC has appointed an accounting expert who will issue a report on the amount of the alleged debt and the responsibility for its payment in light of the privatization. The parties will be entitled to take discovery and present arguments on the issues to be determined by the expert. The expert has been nominated by the FDC. If the FDC again finds Eletropaulo liable for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the FDC grants such request, Eletropaulo’s results of operations may be materially adversely affected and, in turn, the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the FDC against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of São Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1.51.6 million ($680656 thousand) as of JuneSeptember 30, 2014, or pay an indemnification amount of approximately R$15 million ($76 million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court’s decision, the case has been remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision. In January 2014, Eletropaulo informed the court that it intended to comply with the court’s decision by donating a green area inside a protection zone and restore watersheds, the aggregate cost of which is expected to be approximately R$1.51.6 million ($680656 thousand). Eletropaulo also requested that the court add the current owner of the land where the Associação facilities are located, Empresa Metropolitana de Águas e Energia S.A. (“EMAE”), as a party to the lawsuit and order EMAE to perform the demolition and reforestation aspects of the court’s decision. In July 2014, the court requested the Secretary of the Environment for the State of São Paulo to notify the court of its opinion regarding the acceptability of the green areas to be donated by Eletropaulo to the State of São Paulo. In December 2001, Gridco Ltd. ("Gridco") served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the shareholders agreement between Gridco, the Company, AES ODPL, Jyoti and the Central Electricity Supply Company of Orissa Ltd. ("CESCO"), an affiliate of the Company. In the arbitration, Gridco asserted that a comfort letter issued by the Company in connection with the Company's indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO's financial obligations to Gridco. Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. A majority of the tribunal later awarded the respondents, including the Company, some of their costs relating to the arbitration. Gridco filed challenges of the tribunal's awards with the local Indian court. Gridco's challenge of the costs award has been dismissed by the court, but its challenge of the liability award
remains pending. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified Eletropaulo that it had commenced an inquiry into the BNDES financings provided to AES Elpa and AES Transgás, the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo, and the quality of service provided by Eletropaulo to its customers. The MPF requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FCSP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. The lawsuit remains before the FCSP, but the FCSP has suspended the lawsuit pending a decision on MPF's interlocutory appeal. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts. Pursuant to their environmental audit, AES Sul and AES Florestal discovered 200 barrels of solid creosote waste and other contaminants at a pole factory that AES Florestal had been operating. The conclusion of the audit was that a prior operator of the pole factory, Companhia Estadual de Energia (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. On their initiative, AES Sul and AES Florestal communicated with Brazilian authorities and CEEE about the adoption of containment and remediation measures. In March 2008, the State Attorney of the State of Rio Grande do Sul, Brazil filed a public civil action against AES Sul, AES Florestal and CEEE seeking an order requiring the companies to recover the contaminated area located on the grounds of the pole factory and an indemnity payment (approximately R$6 million ($32 million)) to the State’s Environmental Fund. In October 2011, the State Attorney Office filed a request for an injunction ordering the defendant companies to remediatecontain and remove the contaminated areacontamination immediately. The court granted injunctive relief on October 18, 2011, but determined only that defendant CEEE was required to proceed with the remediationremoval work. In May 2012, CEEE began the remediationremoval work in compliance with the injunction. The remediationremoval costs are estimated to be approximately R$60 million ($2725 million) and the work is ongoing.was completed in February 2014. In parallel with the removal activities, a court-appointed expert investigation took place, which was concluded in May 2014. The parties have until November 2014 to present their response to the report of the court-appointed expert. The case is in the evidentiary stage awaiting the production of the court’s expert opinion on several matters, including which of the parties had utilized the products found in the area. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. In January 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. (“Este”)) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court’s decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity’s appeal remains pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) in Brazil initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Estado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF sought an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous
obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserted that if it was determined that AESU was responsible for the termination of the GSA, AESU was liable for TGM’s alleged losses, including losses under the TA. In April 2011, the arbitrations were consolidated into a single proceeding. The hearing on liability issues took place in December 2011. In May 2013, the arbitral Tribunal issued a liability award in AESU's favor. YPF thereafter challenged the
award in Argentine court. In June 2014, at AESU's request, a Uruguayan court temporarily enjoined YPF from pursuing its action in the Argentine court, pending a final determination by the Uruguayan court on whether YPF is entitled to challenge the liability award in the Argentine court. It is unclear whether YPF will complyhas not complied with the temporary injunction.injunction to date. In August 2014, a Uruguayan appellate court issued a decision declaring that only the Uruguayan courts have jurisdiction to review awards in the arbitration and that the Tribunal must disregard litigation outside of Uruguay when deciding issues in the arbitration. In October 2014, an Argentine appellate court issued a decision purporting to suspend the arbitration, and later issued an order threatening sanctions against violations of its decision. Given the competing decisions of the Uruguayan and Argentine courts, the Tribunal has suspended the damages phase of the arbitration until February 2, 2015, at which time the Tribunal will consider whether to lift the suspension. In the arbitration,meantime, the Tribunal has asked the parties are submitting their respective evidence on damages. The final evidentiary hearing on damages will take place on November 6-7, 2014.to remove any alleged obstacles to the progress of the arbitration. AESU believes it has meritorious claims and defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.
In April 2009, the Antimonopoly Agency in Kazakhstan initiated an investigation of certain power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”). The Antimonopoly Agency determined that the Hydros had abused their market position and charged monopolistically high prices for power from January-February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million)648 thousand) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($2 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of the Hydros. In the course of criminal proceedings, the financial police expanded the periods at issue to the entirety of 2009 for UK HPP and from January-October 2009 for Shulbinsk HPP, and sought increased damages of KZT 1.2 billion ($76 million) from UK HPP and KZT 1.3 billion ($7 million) from Shulbinsk HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts. In October 2009, AES Mérida III, S. de R.L. de C.V. (AES Mérida), one of our businesses in Mexico, initiated arbitration against its fuel supplier and electricity offtaker, Comisión Federal de Electricidad (“CFE”), seeking a declaration that CFE breached the parties’ power purchase agreement (“PPA”) by supplying gas that did not comply with the PPA’s specifications. Alternatively, AES Mérida requested a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputed the claims. Although it did not assert counterclaims, in its closing brief CFE asserted that it is entitled to a partial refund of the capacity charge payments that it made for power generated with the out-of-specification gas. In July 2012, the arbitral Tribunal issued an award in AES Mérida’s favor. In December 2012, CFE initiated an action in Mexican court seeking to nullify the award. AES Mérida opposed the request and asserted a counterclaim to confirm the award. In February 2014, the court rejected CFE's claims and granted AES Mérida's request to confirm the award. CFE has appealed the court's decision. AES Mérida believes it has meritorious grounds to defeat that action; however, there can be no assurances that it will be successful. In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the Clean Air Act (“CAA”) Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard. In November 2009, April 2010, December 2010, April 2011, June 2011, August 2011, and November 2011, and October 2014, substantially similar personal injury lawsuits were filed by a total of 4950 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit, the plaintiffs allege that the coal combustion byproductsby-products of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The Company is not able to estimate damages, if any, at this time. The AES defendants moved for partial dismissal of both the November 2009 and April
2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. In November 2011, the AES defendants again moved for partial dismissal of those amended complaints, and in both lawsuits, the Superior Court dismissed the plaintiffs' claims for future medical monitoring expenses but declined to dismiss their claims under Dominican Republic Law 64-00. The AES defendants filed an answer to the November 2009 lawsuit in June 2012. The Superior Court has stayed the remaining six lawsuits as well as any subsequently filed similar lawsuits. The Superior Court hasbetween April 2010 and November 2011, and may also ordered that, forstay the present,October 2014 lawsuit. Presently, discovery will proceedis proceeding only in the November 2009 lawsuit and will be limited toon causation
and exposure issues. The AES defendants believe they have meritorious defenses and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts. On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns a 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million. The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units, allegedly because of the purported characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor’s claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately €240 million ($327304 million) in the arbitration, plus interest and costs. The evidentiary hearing took place on November 27-December 6, 2013, and January 6-17, 2014. Closing arguments were heard on May 21-22, 2014. The parties are awaiting the Tribunal's award. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. On February 11, 2011, Eletropaulo received a notice of violation from São Paulo State’s Environmental Authorities for allegedly destroying 0.32119 hectares of native vegetation at the Conservation Park of Serra do Mar (“Park”), without previous authorization or license. The notice of violation asserted a fine of approximately R$1 million ($454410 thousand) and the suspension of Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities (“São Paulo EA”), Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the notice of violation or reduce the fine. In December 2011, the São Paulo EA declined to vacate the notice of violation but recognized the possibility of 40% reduction inof the fine if Eletropaulo agrees to recover the affected area with additional vegetation. Eletropaulo has not appealed the decision and is now discussing the terms of a possible settlement with the São Paulo EA, including a plan to recover the affected area by primarily planting additional trees. In March 2012, the State of São Paulo Prosecutor’s Office of São Bernardo do Campo initiated a Civil Proceeding to review the compliance by Eletropaulo with the terms of any possible settlement. Eletropaulo has had several meetings and field inspections to settle the details of the recovery project. Eletropaulo was informed by the Park Administrator that the area where the recovery project was to be located was no longer available. The Park Administrator subsequently approved a new area for the recovery project. Eletropaulo is currently awaiting the draft of the agreement by the environmental agency, and expects to proceed with the recovery project after reaching agreement with the environmental agency. In February 2011, a consumer protection group, S.O.S. Consumidores (“SOSC”), filed a lawsuit in the State of São Paulo Federal Court against the Brazilian Regulatory Agency (“ANEEL”), Eletropaulo and all other distribution companies in the State of São Paulo, claiming that the distribution companies had overcharged customers for electricity. SOSC asserted that the distribution companies’ tariffs had been incorrectly calculated by ANEEL, and that the tariffs were required to be corrected from the effective dates of the relevant concession contracts. SOSC asserted that ANEEL erred in May 2010, when the agency corrected the alleged error going forward but declared that the tariff calculations made in the past were correct. Eletropaulo opposed the lawsuit on the ground that it had not wrongfully collected amounts from its customers, as its tariffs had been calculated in accordance with the concession contract with the Federal Government and ANEEL’s rules. Subsequently, the lawsuit was transferred to the Federal Court of Belo Horizonte ("FCBH"), which was presiding over similar lawsuits against other distribution companies and ANEEL. In January 2014, the FCBH dismissed the lawsuit against Eletropaulo and the other distribution companies. Incompanies ("January 2014 Decision"). An appeal was filed in May 2014, SOSC appealedbut that decision.appeal was unsuccessful. The January 2014 Decision has become final and unappealable. SOSC's lawsuit will continue against ANEEL. If SOSC ultimately
prevails against the agency, it is possible that SOSC may file a new lawsuit against Eletropaulo seeking refunds. Eletropaulo estimates that its liability to customers could be approximately R$855 million ($388 million). Eletropaulo believes it has meritorious defenses and willwould vigorously defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.any such lawsuit. In June 2011, the São Paulo Municipal Tax Authority (the “Municipality”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking to collect services tax (“ISS”) that allegedly had not been paid on revenues for services rendered by Eletropaulo. Eletropaulo challenged the assessments on the ground that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$2.82.86 billion ($1.271.17 billion) as estimated by Eletropaulo. Eletropaulo has appealed to the Second Instance Administrative Court. No tax is due while the appeal is pending. Eletropaulo believes it has
meritorious defenses to the assessments and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. In January 2012, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê paid PIS and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê challenged the assessment on the ground that the tax rate was set in the applicable legislation. In April 2013, the First Instance Administrative Court determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable for unpaid taxes, interest and penalties totaling approximately R$844854 million ($383350 million) as estimated by AES Tietê. AES Tietê has filed an appeal to the Second Instance Administrative Court. No tax is due while the appeal is pending. AES Tietê believes it has meritorious defenses to the claim and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. In August 2012, Fondo Patrimonial de las Empresas Reformadas (“FONPER”) (the Dominican instrumentality that holds the Dominican Republic’s shares in Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”)) filed a criminal complaint against certain current and former employees of AES. The criminal proceedings include a related civil component initiated against Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NCI”) (the AES affiliate that manages Itabo). FONPER asserts claims relating to the alleged mismanagement of Itabo and seeks approximately $270 million in damages. The Dominican District Attorney (“DA”) has admitted the criminal complaint and is investigating the allegations set forth therein. In September 2012, one of the individual defendants responded to the criminal complaint, denying the charges and seeking an immediate dismissal of same. In April 2013, the DA requested that the Dominican Camara de Cuentas ("Camara") perform an audit of the allegations in the criminal complaint. The audit is ongoing and the Camara has not issued its report to date. Further, in August 2012, Coastal and NCI initiated an international arbitration proceeding against FONPER and the Dominican Republic, seeking a declaration that Coastal and NCI have acted both lawfully and in accordance with the relevant contracts with FONPER and the Dominican Republic in relation to the management of Itabo. Coastal and NCI also seek a declaration that the criminal complaint is a breach of the relevant contracts between the parties, including the obligation to arbitrate disputes. Coastal and NCI further seek damages from FONPER and the Dominican Republic resulting from their breach of contract. FONPER and the Dominican Republic have denied the claims and challenged the jurisdiction of the arbitral Tribunal. The Tribunal has not yet established the procedural schedule for the arbitration.arbitration, but has not yet scheduled the final evidentiary hearing. The AES defendants believe they have meritorious claims and defenses, which they will assert vigorously; however, there can be no assuranceassurances that they will be successful in their efforts. In April 2013, the East Kazakhstan Ecology Department (“ED”) issued an order directing AES Ust-Kamenogorsk CHP ("UK CHP") to pay approximately KZT 720 million ($4.03.9 million) in damages ("April 2013 Order”). The ED claimed that UK CHP was illegally operating without an emissions permit for 27 days in February-March 2013. In June 2013, the ED filed a lawsuit with the Specialized Interregional Economic Court (the “Economic Court”) seeking to require UK CHP to pay the assessed damages. UK CHP thereafter filed a separate lawsuit with the Economic Court challenging the April 2013 Order and the ED's allegations. In that lawsuit, in August 2013, the Economic Court ruled in UK CHP's favor and required the ED to vacate the April 2013 Order. That ruling was upheld on two intermediate appeals; however,appeals and thereafter the ED maydid not further appeal to the Kazakhstan Supreme Court. The Economic Court also dismissed the lawsuit filed by the ED. UK CHP believes it has meritorious claims and defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurance that it will be successful in its efforts. In December 2013, AES Changuinola’s EPC Contractor initiated arbitration pursuant to the parties’ EPC Contract and related settlement agreements. The Contractor alleged, among other things, that AES Changuinola failed to make a settlement payment, release retainage, and acknowledge completion of AES Changuinola hydropower facility. In total, the Contractor sought approximately $41 million in damages, plus interest and costs. AES Changuinola denied the claims and asserted counterclaims against the Contractor. In July 2014, the parties settled the dispute.
ITEM 1A. RISK FACTORS There have been no material changes to the risk factors as previously disclosed in our 2013 Form 10-K under Part 1 — Item 1A. — Risk Factors. ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS The following table presents information regarding purchases made by The AES Corporation of its common stock: | | | | | | | | | | | | | | | | Repurchase Period | | Total Number of Shares Purchased | | Average Price Paid Per Share | | Total Number of Shares Repurchased as part of a Publicly Announced Purchase Plan (1) | | Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan | 4/1/2014 - 4/30/14 | | — |
| | $ | — |
| | — |
| | $ | 191,479,504 |
| 5/1/2014 - 5/31/14 | | 1,165,334 |
| | 13.73 |
| | 1,165,334 |
| | 175,481,733 |
| 6/1/2014 - 6/30/14 | | 1,140,379 |
| | 13.89 |
| | 1,140,379 |
| | 159,636,730 |
| Total | | 2,305,713 |
| | $ | 13.81 |
| | 2,305,713 |
| | |
| | | | | | | | | | | | | | | | Repurchase Period | | Total Number of Shares Purchased | | Average Price Paid Per Share | | Total Number of Shares Repurchased as part of a Publicly Announced Purchase Plan (1) | | Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan (2) | 7/1/2014 - 7/31/14 | | — |
| | $ | — |
| | — |
| | $ | 299,636,730 |
| 8/1/2014 - 8/31/14 | | 2,594,646 |
| | 14.67 |
| | 2,594,646 |
| | 261,596,648 |
| 9/1/2014 - 9/30/14 | | 4,783,741 |
| | 14.57 |
| | 4,783,741 |
| | 191,963,430 |
| Total | | 7,378,387 |
| | $ | — |
| | 7,378,387 |
| | |
_____________________________
| | (1)(1) See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program. (2) The authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases, purchases by contract (including, without limitation, accelerated stock repurchase programs or 10b5-1 plans) and/or privately negotiated transactions. There can be no assurance as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time. | See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program.
|
ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. MINE SAFETY DISCLOSURES Not applicable. ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS | | | | 4.1 | | Eighteenth Supplemental Indenture, dated May 20, 2014, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on May 20, 2014. | | | | 31.1 | | Rule13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith). | | | 31.2 | | Rule 13a-14(a)/15d-14(a) Certification of Thomas M. O’Flynn (filed herewith). | | | 32.1 | | Section 1350 Certification of Andrés Gluski (filed herewith). | | | 32.2 | | Section 1350 Certification of Thomas M. O’Flynn (filed herewith). | | | 101.INS | | XBRL Instance Document (filed herewith). | | | 101.SCH | | XBRL Taxonomy Extension Schema Document (filed herewith). | | | 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith). | | | 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document (filed herewith). | | | 101.LAB | | XBRL Taxonomy Extension Label Linkbase Document (filed herewith). | | | 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith). |
SIGNATURES Pursuant to the requirements 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.
| | | | | | | | | | | | THE AES CORPORATION (Registrant) | | | | | | | | | Date: | August 6,November 5, 2014 | By: | | /s/ THOMAS M. O’FLYNN | | | | | | Name: | | Thomas M. O’Flynn | | | | | | Title: | | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | | | | | | | | | | | | By: | | /s/ SHARON A. VIRAG | | | | | | Name: | | Sharon A. Virag | | | | | | Title: | | Vice President and Controller (Principal Accounting Officer) |
s in millions) |