Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Key Topics in the Management Discussion and Analysis

Our discussion covers the following:

•Overview of 2014 Results and Strategic Performance
•Review of Consolidated Results of Operations
•SBU Analysis and Non-GAAP Measures
•Key Trends and Uncertainties
•Capital Resources and Liquidity

Overview of 2014 Results and Strategic Performance

Management’s Strategic Priorities

Management is focused on the following priorities:

•Reducing complexity: By exiting businesses and markets where we do not have a competitive advantage, we have simplified our portfolio and reduced risk.
•Leveraging our platforms: Focusing our growth on platform expansions, including adjacencies, in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns.
•Performance excellence: We strive to be the low-cost manager of a portfolio of assets and to derive synergies and scale from our businesses.
•Expanding access to capital: By building strategic partnerships at the project and business level. Through these partnerships, we aim to optimize our risk-adjusted returns in our existing businesses and growth projects. By selling down portions of certain businesses, we can adjust our global exposure to commodity, fuel, country and other macroeconomic risks. Partial sell-downs of our assets can serve to highlight the value of businesses in our portfolio.
•Allocating capital in a disciplined manner: Our top priority is to maximize risk-adjusted returns to our shareholders, which we achieve by investing our discretionary cash and recycling the capital we receive from asset sales and strategic partnerships.

In 2014, we made significant progress on our strategy and continued to position our company for the future. We also met our financial guidance, despite sustained poor hydrological conditions in Latin America, particularly in Brazil and Panama, where rainfall has been at some of the lowest levels recorded in many decades. Our key achievements in 2014 were:

•Adjusted EPS of $1.30 and Proportional Free Cash Flow (FCF) of $891 million
•Diluted EPS from continuing operations of $1.09 and net cash provided by operating activities of $1.8 billion
•Returned 76% of discretionary cash to shareholders
•Increased our quarterly dividend by 100%, to $0.10 per share, beginning in the first quarter of 2015
•Invested $916 million in our balance sheet, by repurchasing shares and prepaying and refinancing debt
•Closed ten transactions for $1.8 billion in equity proceeds from asset sales
•Brought in four strategic partners to invest $1.9 billion in our subsidiaries
•Achieved goal of reducing global G&A expenses by $200 million one year early
•Capitalized on our existing footprint - broke ground on six new construction projects, totaling 2,226 MW, expected to come on-line from 2015 through 2018
•Awarded long-term PPAs by Southern California Edison, for 1,284 MW of combined cycle gas-fired generation and 100 MW of battery-based energy storage

2014 Strategic Performance

Earnings Per Share Results in 2014

Years Ended December 31,
201420132012
Diluted earnings per share from continuing operations$1.09$0.38(1.27)
Adjusted earnings per share (a non-GAAP measure)(1)$1.30$1.29$1.21
(1)See reconciliation and definition under Non-GAAP Measures.

Diluted earnings per share from continuing operations increased $0.71, to $1.09, principally due to lower goodwill impairment expense and current year gains on the sale of investments. Additionally, higher interest income, foreign currency transaction gains, and lower general and administrative expenses added to the increase. These increases were partially offset by lower operating margin, higher income tax expense, and higher losses on debt extinguishments.

Adjusted EPS increased by 1% to $1.30 primarily due to lower Parent Company interest expense, lower general and administrative expenses, and lower share count, partially offset by lower contribution from the Asia SBU and increased tax expense.

Capital Management and Allocation

We continue to focus on improving cash generation and optimizing the use of our parent discretionary cash. During 2014, we generated $1.8 billion of cash flow from operating activities and closed multiple asset sales. In terms of uses, we deployed our discretionary cash to pay quarterly dividends of $0.05 per share, allocated $308 million to repurchase 22 million shares (see Note 16—Equity in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information), allocated $608 million to reduce recourse debt and extend near-term maturities at the Parent Company, and invested $327 million in our subsidiaries, largely for platform expansions. The largest investments in platform expansions in 2014 were related to environmental upgrades at IPL, where we expect to receive full recovery for qualifying costs, including a return on equity, and our expansion project at our Amman East facility in Jordan.

Reducing Complexity

In 2014, we announced or closed asset sale transactions representing $1.8 billion in equity proceeds to AES. With these transactions, we exited operations in Cameroon, Nigeria and Turkey. These asset sales are part of our strategy to maximize shareholder value by exiting markets where we do not have a compelling competitive advantage and reinvesting capital into expanding our platforms.

In 2014, we added 247 MW of new capacity, through one platform expansion project: IPP4 in Jordan. Our planned future capacity growth will come from a combination of projects currently under construction and development. We have 7,141 MW of new capacity under construction and expected to come on-line through 2018.

Safe, Reliable and Sustainable Operations

Our 2014 operating performance for the year was driven by the strategic management of our assets and cost reductions across our portfolio, but we also faced dry hydrological conditions across many markets in Latin America and reliability challenges at two of our generation assets in the Philippines and the US and utilities in Brazil.

We continue to focus on safety as our top priority. Our safety performance improved in 2014, as we lowered our lost-time incident case rates for both employees and operational contractors.

Generation in GWh is down 4% compared to 2013, mainly driven by dry hydrological conditions in Brazil and Panama, as well as higher unplanned outages at our generation plants in Ohio and Philippines. The dry conditions were partially offset by new capacity in Chile.

Compared to 2013, KPI performance declined in our generation metrics. Our Commercial Availability and EFOF performance deteriorated, largely driven by our unplanned outages at our generation plants in Ohio and the Philippines as discussed above. Most of these events have been resolved and mitigation plans have been implemented. Additionally, one strategic initiative focusing on coal blending can reduce the efficiency of certain generating units, which unfavorably affects our heat rate; however, it is offset by the financial benefits from utilizing lower-cost coal.

Our utility portfolio performance also declined mainly driven by severe weather-related impacts in our Brazil businesses which increased our SAIDI and SAIFI. However, we saw improvements in our non-technical losses performance mainly through strategic initiatives in our Brazil businesses on identifying and preventing fraudulent customers.

Our key performance indicators for the years ended December 31, 2014 and 2013 are as follows:

20142013Variance 2013-2014
Safety: Employee Lost-Time Incident Case Rate.082.10422%
Safety: Operational Contractor Lost-Time Incident Case Rate.078.11633%
Generation
Commercial Availability (%)90.50%93.55%(3.05)%
Equivalent Forced Outage Factor (EFOF, %)3.29%2.92%(0.4)%
Heat Rate (BTU/kWh)9,7919,638(153)
Utility
System Average Interruption Duration Index (SAIDI, hours)6.135.96(0.17)
System Average Interruption Frequency Index (SAIFI, number of interruptions)3.702.97(0.73)
Non-Technical Losses (%)2.03%2.52%0.49%

Definitions:

•Lost-Time Incident Case Rate: Number of lost-time cases per number of full-time employees or contractors.
•Commercial Availability: Actual variable margin, as a percentage of potential variable margin if the unit had been available at full capacity during outages.
•Equivalent Forced Outage Factor: The percentage of the time that a plant is not capable of producing energy, due to unplanned operational reductions in production.
•Heat Rate: The amount of energy used by an electrical generator or power plant to generate one kilowatt-hour (kWh).
•System Average Interruption Duration Index: The total hours of interruption the average customer experiences annually.
•System Average Interruption Frequency Index: The average number of interruptions the average customer experiences annually.
•Non-Technical Losses: Delivered energy that was not billed due to measurement error, theft or other reasons.

Review of Consolidated Results of Operations

Years Ended December 31,
Results of operations201420132012% change 2014 vs. 2013% change 2013 vs. 2012
(in millions, except per share amounts)
Revenue:
US SBU$3,826$3,630$3,7365%-3%
Andes SBU2,6422,6393,020—%-13%
Brazil SBU6,0095,0155,78820%-13%
MCAC SBU2,6822,7132,573-1%5%
Europe SBU1,4391,3471,3447%—%
Asia SBU5585507331%-25%
Corporate and Other1579114%-22%
Intersegment eliminations(25)(10)(39)-150%74%
Total Revenue17,14615,89117,1648%-7%
Operating Margin:
US SBU6996687115%-6%
Andes SBU58753358010%-8%
Brazil SBU742871969-15%-10%
MCAC SBU541543560—%-3%
Europe SBU403415504-3%-18%
Asia SBU76169236-55%-28%
Corporate and Other5325(15)112%267%
Intersegment eliminations(13)2338-157%-39%
Total Operating Margin3,0883,2473,583-5%-9%
General and administrative expenses(187)(220)(274)15%20%
Interest expense(1,471)(1,482)(1,544)1%4%
Interest income36527534833%-21%
Loss on extinguishment of debt(261)(229)(8)-14%NM
Other expense(68)(76)(82)11%7%
Other income12412598-1%28%
Gain on disposal and sale of investments35826219NM-88%
Goodwill impairment expense(164)(372)(1,817)56%80%
Asset impairment expense(91)(95)(73)4%-30%
Foreign currency transaction gains (losses)11(22)(170)150%87%
Other non-operating expense(128)(129)(50)1%-158%
Income tax expense(419)(343)(685)-22%50%
Net equity in earnings of affiliates192535-24%-29%
INCOME (LOSS) FROM CONTINUING OPERATIONS1,176730(420)61%274%
Income (loss) from operations of discontinued businesses27(27)47200%-157%
Net gain (loss) from disposal and impairments of discontinued operations(56)(152)1663%NM
NET INCOME (LOSS)1,147551(357)108%254%
Noncontrolling interests:
(Income) from continuing operations attributable to noncontrolling interests(387)(446)(540)13%17%
(Income) loss from discontinued operations attributable to noncontrolling interests99(15)—%160%
Net income (loss) attributable to The AES Corporation$769$114$(912)575%113%
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income (loss) from continuing operations, net of tax$789$284$(960)178%130%
Income (loss) from discontinued operations, net of tax(20)(170)4888%-454%
Net income (loss)$769$114$(912)575%113%
Net cash provided by operating activities$1,791$2,715$2,901-34%-6%
DIVIDENDS DECLARED PER COMMON SHARE$0.25$0.17$0.0847%113%

NM — Not meaningful

Components of Revenue, Cost of Sales and Operating Margin—Revenue includes revenue earned from the sale of energy from our utilities and the production of energy from our generation plants, which are classified as regulated and non-regulated on the Consolidated Statements of Operations, respectively. Revenue also includes the gains or losses on derivatives associated with the sale of electricity.

Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, O&M costs, depreciation and amortization expense, bad debt expense and recoveries, general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.

Operating margin is defined as revenue less cost of sales.

Year ended December 31, 2014:

Revenue increased $1.3 billion, or 8%, to $17.1 billion in 2014 compared with $15.9 billion in 2013. The key operating drivers of the change at each of the SBUs are as follows:

•US — Overall favorable variance of $196 million driven by regulatory retail rate increases at DPL in Ohio as well as higher rates, primarily pass-through, at IPL in Indiana, partially offset by lower volume at DPL primarily due to customer switching.
•Andes — Overall favorable impact of $3 million driven by Chivor in Colombia due to higher spot and contract rates, somewhat offset by unfavorable foreign exchange rates, and Gener in Chile as a result of higher volume, partially offset by lower rates. Offsetting these results, Argentina decreased due to unfavorable foreign exchange rates.
•Brazil — Overall favorable impact of $994 million driven by higher volumes and higher tariffs, primarily pass-through costs, at Eletropaulo and Sul. Tietê also increased due to higher rates. Unfavorable foreign exchange partially offset these results.
•MCAC — Overall unfavorable impact of $31 million driven by the Dominican Republic due to lower third party gas sales, partially offset by higher PPA rates. El Salvador also decreased as a result of an unfavorable adjustment to unbilled revenue and lower pass-through costs. Offsetting these results, Puerto Rico and Panama increased due to higher volume and rates.
•Europe — Overall favorable impact of $92 million driven by the start of operations at Jordan IPP4 which commenced operations in July 2014 and Ballylumford in the U.K. due to higher volume and favorable foreign exchange rates, somewhat offset by lower rates. These results were partially offset by Kilroot in the U.K. primarily due to lower volume.
•Asia — Overall favorable impact of $8 million driven by higher pass-through fuel costs resulting from higher generation at Kelanitissa in Sri Lanka, partially offset by decrease in the Philippines primarily due to lower rates, somewhat offset by higher volume.

Operating margin decreased $159 million, or 5%, to $3.1 billion in 2014 compared with $3.2 billion in 2013. The key operating drivers of the change at each of the SBUs are as follows:

•US — Overall favorable impact of $31 million driven by favorable results at US Generation including contributions from a platform expansion project at Tait energy storage project, combined with higher availability at Hawaii and increased market prices at Laurel Mountain. US Utilities benefited with favorable results at IPL in Indiana driven by higher wholesale and retail margin as well as lower pension costs, were largely offset by lower results at DPL in Ohio. DPL was driven by outages and lower gas availability in the first half of 2014 resulting in higher purchased power and related costs to supply higher demand from cold weather, partially offset by improvements in Q3 2014 from increased retail rates, lower fuel costs and higher capacity prices. Revenue increases due to pass-through costs do not have a corresponding impact on operating margin.
•Andes — Overall favorable impact of $54 million driven by Chivor in Colombia due to higher generation, higher spot and contract prices, as well as ancillary services. Increases in Argentina were offset by lower results at Gener in Chile. Argentina increased due to the impact of Resolution 529, higher generation and availability, partially offset by higher fixed costs while Gener in Chile decreased due to lower contract and spot prices and lower availability, partially offset by full impact of new operations at Ventanas IV in 2014 and lower fixed costs.
•Brazil — Overall unfavorable impact of $129 million driven by unfavorable foreign exchange rates and Tietê due to lower water inflows which led to lower generation and an increase in energy purchases at higher prices, partially offset by higher spot sales in first half of 2014 due to lower contracted volumes of energy sold. In addition, Uruguaiana decreased due to a non-recurring extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013. These results were partially offset by Eletropaulo driven by a non-recurring 2013 charge related to the recognition of a regulatory liability related to potential customer refunds as well as higher tariffs and volume. Revenue increases due to pass-through costs do not have a corresponding impact on operating margin.
•MCAC — Overall unfavorable impact of $2 million driven by El Salvador due to an unfavorable adjustment to unbilled revenue, higher energy losses and lower demand. These results were largely offset by the Dominican Republic mainly related to higher spot sales and higher availability, partially offset by lower gas sales to third parties, lower frequency regulation, and lower PPA results.
•Europe — Overall unfavorable impact of $12 million driven by Kilroot in the U.K. and Maritza in Bulgaria due to lower volume and higher outages, partially offset by higher rates. These results were partially offset by the new operations at Jordan IPP4 as discussed above, and Kazakhstan due to higher generation volume and rates, partially offset by unfavorable foreign exchange rates.
•Asia — Overall unfavorable impact of $93 million driven by Masinloc in the Philippines, due to lower plant availability and 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, and lower spot rates, partially offset by higher contract demand. Kelanitissa also decreased due to a reduction in rates according to the PPA.

Year Ended December 31, 2013

Revenue decreased $1.3 billion, or 7%, to $15.9 billion in 2013 compared with $17.2 billion in 2012. The key operating drivers of the change at each of the SBUs are as follows:

•US — Overall unfavorable impact of $106 million driven by the early termination of the PPA at Beaver Valley in Pennsylvania in early 2013, customer switching as well as lower capacity rates at DPL in Ohio, and the short-term restart in 2012 of two Huntington Beach generating units at Southland in California, partially offset by higher wholesale volume and prices at IPL in Indiana.
•Andes — Overall unfavorable impact of $381 million driven by unfavorable foreign exchange rates of $128 million, lower prices from the impact of Resolution 95 in Argentina, and lower contract and spot prices at Gener in Chile, partially offset by higher spot prices at Chivor in Colombia as a result of dry hydrology.
•Brazil — Overall unfavorable impact of $773 million driven by unfavorable foreign exchange rates of $631 million, lower demand as well as lower pass-through costs and the tariff reset implemented in April 2013 at Sul, and a decrease at Eletropaulo related to the recognition of a regulatory liability for customer refunds (See Item 1.—Business—Brazil SBU— Eletropaulo Regulatory Asset Base Update) somewhat offset by higher tariffs. Negative results above partially offset by higher prices and sales at Tietê and the temporary restart of operations during February and March of 2013 at Uruguaiana.
•MCAC — Overall favorable impact of $140 million driven by higher spot prices as well as higher spot and gas sales to third parties in the Dominican Republic, higher prices in Mexico and Puerto Rico, partially offset by lower generation net of higher prices due to lower hydrology in Panama.
•Europe — Overall favorable impact of $3 million driven by higher energy prices at Kilroot in the UK, pass-through costs at Maritza in Bulgaria and Jordan, as well as higher dispatch and fewer outages at Ballylumford in the UK, partially offset by lower capacity prices. The favorable results above were largely offset by the sale of 80% of our ownership in Cartagena in Spain in February 2012 and a non-recurring favorable arbitration settlement in 2012 prior to final sale of remaining AES interest in April 2013.
•Asia — Overall unfavorable impact of $183 million due to higher contract levels at lower prices to reduce spot exposure, the reversal of a contingency and unrealized derivative gains in 2012 at Masinloc in the Philippines as well as lower generation at Kelanitissa in Sri Lanka as a result of higher hydrology.

Operating margin decreased $336 million, or 9%, to $3.2 billion in 2013 compared with $3.6 billion in 2012. The key operating drivers of the change at each of the SBUs are as follows:

•US — Overall unfavorable impact of $43 million driven by the short-term restart of two Huntington Beach units at Southland in 2012, higher outages and related fixed costs at Hawaii, and higher maintenance costs at IPL in Indiana. The negative drivers above were partially offset by higher contributions for US Wind businesses and DPL with lower amortization expense largely offset by higher customer switching.
•Andes — Largely unfavorable impact of $47 million driven by Chivor due to lower generation, somewhat offset by higher spot prices due to dry hydrology. Chile also decreased due to lower generation, higher spot purchases, and lower contract prices, offset by the commencement of operations of Ventanas IV in March 2013. These negative drivers were partially offset by an increase in Argentina driven by lower outages and higher volumes, somewhat offset by unfavorable foreign currency translation of $18 million and lower rates.
•Brazil — Overall unfavorable impact of $98 million driven by an unfavorable foreign exchange impact of $84 million, lower tariffs and demand at Sul, as well as lower volumes and higher energy purchases due to low hydrology at Tietê, partially offset by the favorable reversal of a liability and the temporary restart of operations at Uruguaiana and higher tariffs and lower fixed costs at Eletropaulo, somewhat offset by recognition of a regulatory liability as discussed above.
•MCAC — Overall unfavorable impact of $17 million driven by Panama due to dry hydrological conditions, which resulted in lower generation and higher energy purchases at higher prices, somewhat offset by favorable net settlements. Negative drivers above were partially offset by the Dominican Republic with higher spot sales, higher

international gas prices and volume of gas sales to third parties and higher availability in El Salvador due to the tariff increase at the beginning of 2013.

•Europe — Overall unfavorable impact of $89 million driven by Cartagena due to a non-recurring, favorable arbitration settlement in 2012 and the two-stage sale of the business as discussed above as well as Ballylumford due to lower capacity payments, somewhat offset by fewer outages. The negative results above were partially offset by favorable dark spreads from higher energy prices and lower coal costs at Kilroot and fewer outages and lower fixed costs at Maritza in Bulgaria.
•Asia — Overall unfavorable impact of $67 million driven by higher contracted volume at lower prices as discussed above as well as reversal of a contingency of $16 million and an unrealized derivative gain in 2012 at Masinloc.

General and administrative expenses

General and administrative expenses includes expenses related to corporate staff functions and/or initiatives, executive management, finance, legal, human resources and information systems, as well as global development costs.

General and administrative expenses decreased $33 million, or 15%, to $187 million in 2014 from 2013 primarily due to lower employee-related costs and business development costs.

General and administrative expenses decreased $54 million, or 20%, to $220 million in 2013 from 2012 primarily due to Company restructuring efforts, resulting in a decrease in employee related costs, professional fees and business development costs.

Interest expense

Interest expense decreased $11 million, or 1%, to $1.5 billion in 2014 from 2013. The decrease was primarily attributable to lower interest expense of $53 million at the Parent Company due to a reduction in debt principal, and a $48 million reversal of contingent interest accruals associated with disputed purchased energy obligations at Sul for which it was determined, based on developments during the second quarter of 2014, that the likelihood of an unfavorable outcome for the payment of interest on the disputed obligation was no longer probable. These decreases were partially offset by income of $34 million in the prior year resulting from the ineffectiveness on derivative interest rate swaps accounted for as cash flow hedges at Puerto Rico, and higher interest expense of $24 million at Gener due to an increase in debt principal.

Interest expense decreased $62 million, or 4%, to $1.5 billion in 2013 from 2012. This decrease was primarily due to reduced debt principal as well as the prior year prepayment of an interest rate cash flow hedge that resulted in a reclassification of deferred losses from other comprehensive income to earnings at the Parent Company, favorable foreign currency translation and lower interest rates in Brazil, as well as income resulting from ineffectiveness on interest rate swaps in Puerto Rico that continue to qualify for hedge accounting. These decreases were partially offset by a monetary correction on the adjustment to the regulatory liability related to the asset base at Eletropaulo as a result of a ruling by the regulator in December 2013.

Interest income

Interest income increased $90 million, or 33%, to $365 million in 2014 from 2013. The increase was primarily due to interest income of $59 million recognized on FONINVEMEM III receivables in Argentina which satisfied the criteria for revenue recognition in the fourth quarter and $23 million in higher interest rates from an increase in regulatory assets at Eletropaulo. See Note 7—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Interest income decreased $73 million, or 21%, to $275 million in 2013 from 2012. The decrease was primarily in Brazil, due to lower interest-bearing assets, lower investment balances, unfavorable foreign currency translation, and lower interest rates. The decrease was partially offset by interest income related to FONINVEMEM III receivables in Argentina which satisfied the criteria for revenue recognition during 2013.

Loss on extinguishment of debt

Loss on extinguishment of debt was $261 million for the year ended December 31, 2014. This loss was primarily related to $193 million, $31 million, and $20 million in early extinguishment of debt at the Parent Company, DPL, and Gener, respectively. See Note 12—Debt included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Loss on extinguishment of debt was $229 million and $8 million for the years ended December 31, 2013 and 2012. The loss in 2013 was primarily related to the loss on the early retirement of recourse debt at the Parent Company and the loss on the early extinguishment of debt at Masinloc. See Note 12—Debt included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. The loss in 2012 was primarily related to a early retirement of debt at the Parent Company and at Eletropaulo.

Other income and expense

See discussion of the components of other income and expense in Note 20—Other Income and Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Gain on sale of investments

Gain on sale of investments for the year ended December 31, 2014 was $358 million, which is primarily related to the sale of 45% of our investment in Masin-AES Pte Ltd. and 100% of our interest in UK Wind. See Note 16—Equity of this form 10-K for further information.

Gain on sale of investments for the year ended December 31, 2013 was $26 million, which was primarily related to the sale of our remaining 20% interest in Cartagena as well as the sale of our 10% equity interest in Trinidad Generation Unlimited. See Note 24—Dispositions included in Item 8.—Financial Statements and Supplemental Data of this Form 10-K for further information.

Gain on sale of investments for the year ended December 31, 2012 was $219 million, which was primarily related to the sale of 80% of our interest in Cartagena, as well as the sale of certain investments in China.

Goodwill impairment

The Company recognized goodwill impairment expense of $164 million, $372 million, and $1.8 billion for the years ended December 31, 2014, 2013, and 2012. See Note 10—Goodwill and Other Intangible Assets included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Asset impairment expense

The Company recognized asset impairment expense of $91 million, $95 million and $73 million, respectively, for the years ended December 31, 2014, 2013 and 2012. See Note 21—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Foreign currency transaction gains (losses)

Foreign currency transaction gains (losses) were as follows:

Years Ended December 31,
201420132012
(in millions)
Argentina$66$2$(5)
Colombia176(7)
United Kingdom122(6)
Philippines11(10)(159)
Brazil(4)(12)(16)
Mexico(14)—3
Chile(30)(20)9
AES Corporation(34)55
Other(13)56
Total(1)$11$(22)$(170)

(1) Includes gains (losses) of $172 million, $60 million and $(160) million on foreign currency derivative contracts for the years ended December 31, 2014, 2013 and 2012, respectively.

The Company recognized net foreign currency transaction gains of $11 million for the year ended December 31, 2014 primarily due to gains of:

•$66 million in Argentina, due to the favorable impact from foreign currency derivatives related to government receivables, partially offset by losses from the devaluation of the Argentine Peso by 31% associated with U.S. Dollar denominated debt, and losses at Termoandes (a U.S. Dollar functional currency subsidiary) primarily associated with cash and accounts receivable balances in local currency, and the purchase of Argentine sovereign bonds;
•$17 million in Colombia, primarily due to a 23% depreciation of the Colombian Peso, positively impacting Chivor (a U.S. Dollar functional currency subsidiary) due to liabilities denominated in Colombian Pesos, primarily income tax payable and accounts payable;
•$12 million in the United Kingdom, primarily due to a 6% depreciation of the Pound Sterling, resulting in gains at Ballylumford Holdings (a U.S. Dollar functional currency subsidiary) associated with intercompany notes payable denominated in Pound Sterling, and gains related to foreign currency derivatives; and
•$11 million in the Philippines, primarily due to amortization of frozen embedded derivatives and a 4% appreciation of the Philippine Peso against the U.S. Dollar, resulting in a revaluation of cash accounts, customer receivables, and deferred tax asset.

These gains were partially offset by losses of:

•$34 million at The AES Corporation primarily due to decreases in the valuation of intercompany notes receivable denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the year, partially offset by gains related to foreign currency option purchases;
•$30 million in Chile primarily due to a 16% devaluation of the Chilean Peso, resulting in a $39 million loss at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos, primarily cash, accounts receivable and VAT receivables, partially offset by income of $9 million on foreign currency derivatives; and
•$14 million in Mexico, primarily due to a 13% devaluation of the Mexican Peso, resulting in a loss at TEGTEP and Merida (U.S. Dollar functional currency subsidiaries) from working capital denominated in Pesos (primarily cash, recoverable tax, and VAT).

The Company recognized foreign currency transaction losses of $22 million for the year ended December 31, 2013 primarily due to losses of:

•$20 million in Chile, primarily due to a 9% weakening of the Chilean Peso, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with net working capital denominated in Chilean Pesos, mainly cash, accounts receivables and tax receivables, partially offset by gains related to foreign currency derivatives;
•$12 million in Brazil, primarily due to a 15% weakening of the Brazilian Real resulting in losses mainly associated with U.S. Dollar denominated liabilities; and
•$10 million in the Philippines (a U.S. Dollar functional currency subsidiary beginning in 2013), primarily due to the 8% weakening of the Philippine Peso, resulting in revaluation of cash accounts, customer receivables and deferred tax asset.

The Company recognized foreign currency transaction losses of $170 million for the year ended December 31, 2012 primarily due to losses of:

•$159 million in the Philippines, primarily due to unrealized foreign exchange losses on embedded derivatives as a result of the forecasted strengthening of the Philippine Peso, partially offset by gains from the 7% appreciation of the Philippine Peso on U.S. Dollar denominated debt at Masinloc, which had been a Philippine Peso functional currency subsidiary; and
•$16 million in Brazil, primarily due to a 9% devaluation of the Brazilian Real resulting in losses mainly associated with U.S. Dollar denominated liabilities.

Other non-operating expense

Total other non-operating expense was $128 million, $129 million and $50 million for the years ended December 31, 2014, 2013 and 2012. The amounts in 2014 consist of other-than-temporary impairment losses of $86 million and $42 million at Entek and Silver Ridge, respectively. See Note 9—Other Non-Operating Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Income tax expense

Income tax expense increased $76 million, or 22%, to $419 million in 2014. The Company’s effective tax rates were 27% and 33% for the years ended December 31, 2014 and 2013, respectively.

The net decrease in the 2014 effective tax rate was due, in part, to the 2014 sale of approximately 45% of the Company's interest in Masin AES Pte Ltd., which owns the Company's business interests in the Philippines, and the 2014 sale of the Company's interests in four U.K. wind projects. Neither of these transactions gave rise to income tax expense. Further, the 2014 effective tax rate benefited from the release of valuation allowance against U.S. capital loss carryforwards and a change in tax status at a subsidiary operating in the Dominican Republic. Offsetting these items is the unfavorable impact of Chilean income tax law reform enacted in the third quarter of 2014. See Note 16—Equity for additional information regarding the sale of approximately 45% of the Company's interest in Masin - AES Pte Ltd. See Note 24—Dispositions for additional information regarding the sale of the Company's interests in four U.K wind projects. See Note 22—Income Taxes for additional information regarding the Chilean tax law reform.

Income tax expense decreased $342 million, or 50%, to $343 million in 2013. The Company’s effective tax rates were 33% and 298% for the years ended December 31, 2013 and 2012, respectively.

The net decrease in the 2013 effective tax rate was principally due to a 2012 nondeductible impairment of goodwill at our U.S. utility, DPL, and in part to the net favorable resolution of various uncertain tax positions in 2013. See Note 10—Goodwill and Other Intangible Assets for additional information regarding goodwill impairment.

Our effective tax rate reflects the tax effect of significant operations outside the United States, which are generally taxed at rates lower than the U.S. statutory rate of 35 percent. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate.

We recognized tax expense of $419 million for the year ended December 31, 2014, while our cash payments for income taxes, net of refunds, totaled $480 million. The difference resulted primarily from income tax benefit on current year U.S. losses.

The Company also benefits from reduced tax rates in certain countries as a result of satisfying specific commitments regarding employment and capital investment. One such benefit related to our operations in the Philippines expired in the 4th quarter of 2014. Accordingly, the Company’s effective tax rate and cash tax payments may increase in future periods. See Note 22—Income Taxes for additional information regarding these reduced rates.

Net equity in earnings of affiliates

Net equity in earnings of affiliates decreased $6 million, or 24%, to $19 million in 2014 from $25 million in 2013. The decrease was primarily a result of an asset impairment charge at Elsta due to long lived assets that were determined to not be recoverable of which our share was $41 million. These items were partially offset by a $22 million lower loss recognized at Entek on an embedded foreign currency derivative and a $19 million increase as a result of the sale of equity interests in Silver Ridge Power, LLC ("SRP") See Note 8—Investments in and Advances to Affiliates included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Net equity in earnings of affiliates decreased $10 million to $25 million in 2013 from $35 million in 2012. The decrease was primarily related to the sale of Yangcheng in China in the third quarter of 2012 as well as higher losses at Entek in Turkey resulting from a loss on an embedded foreign currency derivative, partially offset by increased earnings at Guacolda due to higher energy sales as a result of lower purchase costs.

Income from continuing operations attributable to noncontrolling interests

Income from continuing operations attributable to noncontrolling interests decreased $59 million, or 13%, to $387 million in 2014. The decrease was primarily due to decreased operating margin at Tietê related to lower hydrology and higher prices of energy purchased in the spot market, decreased operating margin at Uruguaiana due to a favorable arbitration settlement in 2013 for $53 million, and decreased operating margin at Panama related to lower hydrology. This was partially offset by increased operating margin at Eletropaulo due to the 2013 recognition of a $269 million regulatory liability related to customer refunds. For details on regulatory liabilities, see Note 11—Regulatory Assets and Liabilities.

Income from continuing operations attributable to noncontrolling interests decreased $94 million, or 17%, from $540 million to $446 million in 2013. This was primarily due to lower operating income at Tietê and Panama related to lower hydrology, the recognition of a regulatory liability related to customer refunds at Eletropaulo, and a reduction in income at Cartagena which was deconsolidated in February 2012 as a result of the sale of 80% of our interest.

Discontinued operations

Total discontinued operations was a net loss of $29 million, a net loss of $179 million, and a net income of $63 million for the years ended December 31, 2014, 2013 and 2012, respectively. See Note 23—Discontinued Operations and Held-for-Sale Businesses included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Net income attributable to The AES Corporation

Net income attributable to The AES Corporation increased $655 million to $769 million in 2014 compared to net income of $114 million in 2013. The key drivers of the increase included:

•the gain on sale of 45% of our investment in Masin - AES Pte Ltd. as well as the gain on sale of the Company's entire interest in the UK Wind projects;
•lower goodwill impairment expense recognized in 2014 compared to 2013;
•higher interest income;
•lower general and administrative expense;
•gain on foreign currency transactions;
•increase in income from operations of discontinued businesses; and
•lower loss from disposal and impairments of discontinued businesses.

These increases were partially offset by:

•lower operating margin;
•increase in income tax expense; and
•higher losses from debt extinguishments.

Net income attributable to The AES Corporation was $114 million in 2013, which is an increase of $1.03 billion compared to net loss of $912 million in 2012. The key drivers included:

•lower goodwill impairment expense;
•lower income tax expense;
•lower foreign currency losses;
•lower interest expense, primarily at the Parent Company, due to a reduction in debt principal as well as the prior year prepayment of an interest rate cash flow hedge that resulted in a reclassification of deferred losses from other comprehensive income to earnings; and
•lower general and administrative expense.

These increases were partially offset by:

•lower operating margin as described above;
•the loss on the early extinguishment of debt at the Parent Company and at Masinloc;
•lower gain on sale of investments recorded in 2013 on the sale of our remaining 20% interest in Cartagena as well as our 10% equity interest in Trinidad compared to the prior year gain recorded from the sale of 80% of our interest in Cartagena in the first quarter of 2012;
•an increase in losses from the disposal and impairment of the discontinued businesses;
•other non-operating expense associated with an impairment at our equity method investment at Elsta in the Netherlands.

Non-GAAP Measures

Adjusted Operating Margin, Adjusted PTC, Adjusted EPS, and Proportional Free Cash Flow are non-GAAP supplemental measures that are used by management and external users of our consolidated financial statements such as investors, industry analysts and lenders.

Adjusted Operating Margin

Operating margin is defined as revenue less cost of sales. Cost of sales includes costs incurred directly by the businesses in the ordinary course of business, such as:

•Electricity and fuel purchases,
•Operations and maintenance costs,
•Depreciation and amortization expense,
•Bad debt expense and recoveries,
•General administrative and support costs at the businesses, and
•Gains or losses on derivatives associated with the purchase of electricity or fuel.

We define Adjusted Operating Margin as operating margin, adjusted for the impact of noncontrolling interests, excluding unrealized gains or losses related to derivative transactions.

The GAAP measure most comparable to Adjusted Operating Margin is operating margin. We believe that Adjusted Operating Margin better reflects the underlying business performance of the Company. 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, as well as the variability due to unrealized derivatives gains or losses. Adjusted Operating Margin should not be construed as an alternative to operating margin, which is determined in accordance with GAAP.

Adjusted PTC and Adjusted EPS

We define Adjusted PTC as pretax income from continuing operations attributable to AES excluding gains or losses of

the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency

gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and

(e) costs due to the early retirement of debt. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis,

adjusted for the aforementioned items.

Adjusted PTC reflects the impact of noncontrolling interests and excludes the items specified in the definition above. In addition to the revenue and cost of sales reflected in operating margin, Adjusted PTC includes the other components of our income statement, such as:

•General and administrative expense in the corporate segment, as well as business development costs;
•Interest expense and interest income;
•Other expense and other income;
•Realized foreign currency transaction gains and losses; and
•Net equity in earnings of affiliates.

We define Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt.

The GAAP measure most comparable to Adjusted PTC is income from continuing operations attributable to AES. The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. We believe that Adjusted PTC and Adjusted EPS better reflect the underlying business performance of the Company and are considered in the Company’s internal evaluation of financial performance. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose of or acquire business interests or retire debt, which affect results in a given period or periods. In addition, for Adjusted PTC, earnings before tax represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. Adjusted PTC and Adjusted EPS should not be construed as alternatives to income from continuing operations attributable to AES and diluted earnings per share from continuing operations, which are determined in accordance with GAAP.

Proportional Free Cash Flow

Refer to Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Proportional Free Cash Flow (A non-GAAP Measure) for the discussion and reconciliation of Proportional Free Cash Flow to its nearest GAAP measure.

Reconciliations of Non-GAAP Measures

Adjusted Operating Margin

Reconciliation of Adjusted Operating Margin to Operating MarginYears Ended December 31,
201420132012
Adjusted Operating Margin(in millions)
US$711$684$707
Andes444402431
Brazil235271356
MCAC482472489
Europe373392447
Asia51159204
Corp/Other5325(15)
Intersegment Eliminations(13)2338
Total Adjusted Operating Margin2,3362,4282,657
Noncontrolling Interests Adjustment760833908
Derivatives Adjustment(8)(14)18
Operating Margin$3,088$3,247$3,583

Adjusted PTC

Adjusted Pretax Contribution(1) Year Ended December 31,Total Adjusted PTCIntersegmentExternal Adjusted PTC
201420132012201420132012201420132012
(in millions)
US SBU$445$440403$10$1140$455$451$443
Andes SBU421353369619(16)427372353
Brazil SBU242212321333245215324
MCAC SBU352339387261210378351397
Europe SBU34834537557(2)353352373
Asia SBU4614220122248144203
Corporate and Other(533)(624)(717)(52)(54)(37)(585)(678)(754)
Total Adjusted Pretax Contribution1,3211,2071,339———1,3211,2071,339
Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates:
Non-GAAP Adjustments:
Unrealized derivative gains (losses)13557(120)
Unrealized foreign currency gains (losses)(110)(41)13
Disposition/acquisition gains36130206
Impairment losses(416)(588)(1,951)
Loss on extinguishment of debt(274)(225)(16)
Pre-tax contribution1,017440(529)
Add: Income from continuing operations before taxes, attributable to noncontrolling interests578633794
Less: Net equity in earnings of affiliates192535
Income from continuing operations before taxes and equity in earnings of affiliates$1,576$1,048$230
(1)Adjusted pretax contribution in each segment before intersegment eliminations includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees and the write-off of intercompany balances.

Adjusted EPS

Years Ended December 31,
Reconciliation of Adjusted EPS201420132012
Diluted earnings (loss) per share from continuing operations$1.09$0.38$(1.26)
Unrealized derivative (gains) losses(1)(0.12)(0.05)0.11
Unrealized foreign currency transaction (gains) losses(2)0.140.02(0.02)
Disposition/acquisition (gains)(0.59)(3)(0.03)(4)(0.18)(5)
Impairment losses0.53(6)0.75(7)2.55(8)
Loss on extinguishment of debt0.25(9)0.22(10)0.01(11)
Adjusted EPS$1.30$1.29$1.21
(1)Unrealized derivative (gains) losses were net of income tax per share of $(0.07), $(0.02) and $0.04 in 2014, 2013, and 2012, respectively.
(2)Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.02, $0.02 and $0.00 in 2014, 2013, and 2012, respectively.
(3)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 loss from the sale of Ebute of $6 million ($6 million, or $0.01 per share, net of income tax per share of $0.00), the loss from the liquidation of AgCert International of $1 million (net benefit of $18 million, or $0.03 per share, including income tax per share of $0.03), the tax benefit of $24 million ($0.03 per share) related to the Silver Ridge Power transaction, the tax benefit of $18 million ($0.02 per share) associated with the agreement executed in December 2014 to sell a noncontrolling interest in IPALCO, and the tax benefit of $7 million ($0.01 per share) associated with the sale of a noncontrolling interest in our Dominican Republic businesses.
(4)Amount primarily relates to the gain from the sale of the remaining 20% of our interest in Cartagena for $20 million ($15 million, or $0.02 per share, net of income tax per share of $0.01) as well as the gain from the sale of Trinidad for $3 million ($4 million, or $0.01 per share, net of income tax per share of $0.00).
(5)Amount primarily relates to the gains from the sale of 80% of our interest in Cartagena for $178 million ($109 million, or $0.14 per share, net of income tax per share of $0.09) and equity method investments in China of $24 million ($25 million, or $0.03 per share, including an income tax credit of $1 million, or income tax per share of $0.00).
(6)Amount primarily relates to the goodwill impairments at DPLER of $136 million ($136 million, or $0.19 per share, net of income tax per share of $0.00), and at Buffalo Gap of $28 million ($28 million, or $0.04 per share, net of income tax per share of $0.00), and asset impairments at Ebute of $67 million ($64 million, or $0.09 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.00), at DPL of $12 million ($7 million, or $0.01 per share, net of income tax per share of $0.01), at Newfield of $12 million ($6 million, or $0.01 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00), and at Elsta of $41 million ($31 million, or $0.04 per share, net of income tax per share of $0.01), as well as the other-than-temporary impairments of our equity method investment at Silver Ridge Power of $42 million ($27 million, or $0.04 per share, net of income tax per share of $0.02), and at Entek of $86 million ($86 million, or $0.12 per share, net of income tax per share of $0.00).
(7)Amount primarily relates to the goodwill impairments at DPL of $307 million ($307 million, or $0.41 per share, net of income tax per share of $0.00), at Ebute of $58 million ($58 million, or $0.08 per share, net of income tax per share of $0.00) and at Mountain View of $7 million ($7 million, or $0.01 per share, net of income tax per share of $0.00). Amount also includes an other-than-temporary impairment of our equity method investment at Elsta of $129 million ($128 million, or $0.17 per share, net of income tax per share of $0.00) and asset impairments at Beaver Valley of $46 million ($30 million, or $0.04 per share, net of income tax per share of $0.02), at DPL of $26 million ($17 million, or $0.02 per share, net of income tax per

share of $0.01), at Itabo (San Lorenzo) of $16 million ($6 million, or $0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00), at El Salvador for $4 million ($4 million, or $0.01 per share, net of income tax per share of $0.00).

(8)Amount primarily relates to the goodwill impairment at DPL of $1.82 billion ($1.82 billion, or $2.39 per share, net of income tax per share of $0.00). Amount also includes other-than-temporary impairment of equity method investments in China of $32 million ($32 million, or $0.04 per share, net of income tax per share of $0.00), and at Inno Vent of $17 million ($17 million, or $0.02 per share, net of income tax per share of $0.00), as well as asset impairments of Wind turbines and projects of $41 million ($26 million, or $0.03 per share, net of income tax per share of $0.02) and asset impairments at Kelanitissa of $19 million ($17 million, or $0.02 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00) and at St. Patrick of $11 million ($11 million or $0.01 per share, net of income tax per share of $0.00).
(9)Amount primarily relates to the loss on early retirement of debt at the Parent Company of $200 million ($130 million, or $0.18 per share, net of income tax per share of $0.10), at DPL of $31 million ($20 million, or $0.03 per share, net of income tax per share of $0.02), at Electrica Angamos of $20 million ($11 million, or $0.02 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00), at UK wind projects of $18 million ($15 million, or $0.02 per share, net of income tax per share of $0.00), at Warrior Run of $8 million ($5 million, or $0.01 per share, net of income tax per share of $0.00) and at Gener of $7 million ($4 million, or $0.01 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00).
(10)Amount primarily relates to the loss on early retirement of debt at Parent Company of $165 million ($107 million, or $0.14 per share, net of income tax per share of $0.08), at Masinloc of $43 million ($39 million, or $0.05 per share, net of income tax per share of $0.00) and Changuinola of $14 million ($10 million, or $0.01 per share, net of income tax per share of $0.01).
(11)Amount primarily relates to the loss on retirement of debt at the Parent Company of $15 million ($10 million, or $0.01 per share, net of income tax per share of $0.01).

The Company reported a loss from continuing operations of $1.27 per share in 2012. For purposes of measuring diluted loss per share under GAAP, common stock equivalents were excluded from weighted-average shares as their inclusion would be anti-dilutive. However, for purposes of computing Adjusted EPS, the Company has included the impact of dilutive common stock equivalents as the inclusion of the defined adjustments result in income for Adjusted EPS. The table below reconciles the weighted-average shares used in GAAP diluted earnings per share to the weighted-average shares used in calculating the non-GAAP measure of Adjusted EPS.

December 31, 2012
LossShares$ Per Share
Reconciliation of Denominator Used For Adjusted EPS(in millions except per share data)
GAAP DILUTED (LOSS) PER SHARE
Loss from continuing operations attributable to The AES Corporation common stockholders$(960)755$(1.27)
EFFECT OF DILUTIVE SECURITIES
Stock options—1—
Restricted stock units—40.01
NON-GAAP DILUTED (LOSS) PER SHARE$(960)760$(1.26)

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:

For the Years Ended December 31,
201420132012$ Change 2014 vs. 2013$ Change 2013 vs. 2012% Change 2014 vs. 2013% Change 2013 vs. 2012
($’s in millions)
Operating Margin$699$668$711$31$(43)5%-6%
Noncontrolling Interests Adjustment———
Derivatives Adjustment12$16(4)
Adjusted Operating Margin$711$684$707$27$(23)4%-3%
Adjusted PTC$445$440$403$5$371%9%

Fiscal year 2014 versus 2013

Operating margin for 2014 increased $31 million, or 5%. This performance was driven primarily by the following businesses and key operating drivers:

•US Generation increased by $26 million, primarily due to $11 million from increased availability as a result of fewer outages at Hawaii, $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 $24 million driven by higher wholesale margin of $14 million and lower fixed costs of $11 million primarily due to lower pension expense.

These increases were partially offset by:

•DPL decreased $19 million, primarily due to decreases of $71 million mainly attributable to outages which resulted in higher purchased power and related costs, especially in the first quarter when we experienced lower gas availability and higher demand as result of cold weather. Also contributing to the decrease was increased customer switching to third party CRES providers. These results were largely offset by higher rates of $57 million from increased retail rates, lower fuel costs and capacity pricing.

Adjusted Operating Margin increased $27 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owned 100% of its businesses in the US in 2014, so there is no adjustment for noncontrolling interests.

Adjusted PTC decreased $5 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, largely offset by an increase of $27 million in Adjusted Operating Margin described above as well as an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest at Buffalo Gap and Armenia Wind of $13 million and settlements at Laurel Mountain of $6 million.

Fiscal year 2013 versus 2012

Operating margin decreased by $43 million, or 6%. This performance was driven primarily by the following businesses and key operating drivers:

•US Generation decreased $26 million, driven by a $24 million decline from the short-term restart of two Huntington Beach units at Southland in 2012, and higher outages at Hawaii of $24 million, partially offset by higher contributions from the US Wind portfolio of $32 million; and
•IPL in Indiana declined $23 million, as a result of $13 million in higher maintenance costs driven by the timing and duration of major generating unit overhauls, and higher depreciation expense of $6 million due to additional utility plant assets placed in service.

These decreases were partially offset by:

•DPL increased $6 million, as lower amortization expense of $81 million offset:
◦A $30 million decrease in sales margin, as customer switching drove retail price decreases, partially offset by higher wholesale volumes;
◦Lower PJM capacity margins of $12 million; and
◦$19 million from unrealized gains on derivatives in 2012, which did not recur in 2013.

Adjusted Operating Margin decreased $23 million 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.

Adjusted PTC increased $37 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, partially offset by the decrease of $23 million in Adjusted Operating Margin discussed above.

Andes SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Andes SBU for the periods indicated:

For the Years Ended December 31,
201420132012$ Change 2014 vs. 2013$ Change 2013 vs. 2012% Change 2014 vs. 2013% Change 2013 vs. 2012
($’s in millions)
Operating Margin$587$533$580$54$(47)10%-8%
Noncontrolling Interests Adjustment$(143)(131)(149)
Derivatives Adjustment———
Adjusted Operating Margin$444$402$431$42$(29)10%-7%
Adjusted PTC$421$353$369$68$(16)19%-4%

Fiscal year 2014 versus 2013

Including the unfavorable impact of foreign currency translation and remeasurement of $14 million, operating margin increased $54 million, or 10%. This performance was driven primarily by the following businesses and key operating drivers:

•Chivor in Colombia increased $55 million of which $72 million was due to higher generation, higher spot and contract prices, and ancillary services, partially offset by higher maintenance costs of $12 million and unfavorable foreign exchange rates of $9 million.
•Argentina increased $8 million driven primarily by higher rates of $30 million as a result of the impact of Resolution 529, higher generation and availability of $13 million, partially offset by higher fixed costs of $27 million driven by higher inflation and unfavorable exchange rates of $5 million.

This increase was offset by:

•Gener in Chile decreased $9 million, largely driven by a reduction of $32 million from lower contract prices, spot prices in the SADI and lower Energy Plus margin and lower availability of $9 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 $19 million.

Adjusted Operating Margin increased $42 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 $68 million, driven by the increase of $42 million in Adjusted Operating Margin described above, and a net benefit of $45 million related to FONINVEMEM interest income on receivables in 2014 and 2013, partially offset by realized FX losses at Chile as well as non-recurring equity tax reversal of $8 million at Colombia in 2013.

Fiscal year 2013 versus 2012

Including the unfavorable impact of foreign currency translation and remeasurement of $18 million, operating margin for 2013 decreased $47 million, or 8%. This performance was driven primarily by the following businesses and key operating drivers:

•Chivor in Colombia decreased $42 million, as dry hydrological conditions reduced generation output and spot volumes but increased spot prices in the market. Lower volumes had an unfavorable impact of $115 million, partially offset by the favorable impact of $84 million from higher prices.
•Gener in Chile decreased $8 million, as a reduction of $30 million from lower contract prices and higher spot purchases was partially offset by higher generation of $24 million, as the commencement of operations at Ventanas IV in March 2013 was offset by lower gas availability and lower coal generation.

These decreases were partially offset by:

•AES Argentina increased $4 million, as lower outages of $18 million and higher volumes of $15 million were partially offset by lower rates of $8 million from the implementation of Resolution 95 and unfavorable exchange rates of $9 million.

Adjusted Operating Margin decreased $29 million due to the drivers above. AES owns 71% of Gener and Chivor and 100% of AES Argentina.

Adjusted PTC decreased $16 million driven by the decrease of $29 million in Adjusted Operating Margin described above, partially offset by higher interest income from the beginning of the accrual of interest on the FONINVEMEM III receivables in Argentina.

Brazil SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Brazil SBU for the periods indicated:

For the Years Ended December 31,
201420132012$ Change 2014 vs. 2013$ Change 2013 vs. 2012% Change 2014 vs. 2013% Change 2013 vs. 2012
($’s in millions)
Operating Margin$742$871$969$(129)$(98)-15%-10%
Noncontrolling Interests Adjustment$(507)(600)(613)
Derivatives Adjustment———
Adjusted Operating Margin$235$271$356$(36)$(85)-13%-24%
Adjusted PTC$242$212$321$30$(109)14%-34%

Fiscal year 2014 versus 2013

Including the unfavorable impact of foreign currency translation of $97 million, operating margin decreased $129 million, or 15%. This performance was driven primarily by the following businesses and key operating drivers:

•Tietê decreased $315 million, driven by unfavorable foreign exchange rates of $58 million and the net impact of $252 million of lower hydrology which led to lower generation and an increase in energy purchases at higher prices, partially offset by higher spot sales in the first half of 2014 due to lower contracted volumes of energy sold; and
•Uruguaiana decreased $51 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.

These results were partially offset by:

•Eletropaulo increased $207 million, driven by a non-recurring 2013 charge related to the recognition of a regulatory liability of $198 million related to potential customer refunds, higher rates of $124 million driven by higher tariff and volume of $46 million, partially offset by higher fixed costs and depreciation of $133 million, primarily personnel/pension costs related, and unfavorable foreign exchange rates of $28 million; and
•Sul increased $31 million, due to higher volume and rates of $52 million, partially offset by higher fixed costs and depreciation of $11 million and unfavorable foreign exchange rates of $10 million.

Adjusted Operating Margin decreased $36 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 increased $30 million, driven by the reversal of a loss contingency resulting from a change in estimate related to interest expense of $47 million that is no longer considered probable and 2014 municipalities settlement interest of $12 million at Sul, partially offset by the decrease of $36 million in Adjusted Operating Margin described above and higher interest rates and debt.

Fiscal year 2013 versus 2012

Including the unfavorable impact of foreign currency translation of $84 million, operating margin decreased $98 million, or 10%. This performance was driven primarily by the following businesses and key operating drivers:

•Sul decreased $96 million, due to lower tariffs of $33 million from the April 2013 tariff reset and lower volume of $44 million due to lower demand; and
•Tietê decreased $81 million, driven by the negative impact of foreign currency translation of $68 million as well as lower volume and higher energy purchases of $24 million due to lower hydrology.

These decreases were partially offset by:

•Uruguaiana increased $64 million, as a result of the extinguishment of a liability of $57 million and the temporary re-start of operations during February and March of 2013.
•Eletropaulo increased $17 million, driven by higher tariffs of $171 million and lower fixed costs of $42 million, partially offset by the recognition of a regulatory liability of $224 million related to potential customer refunds.

Adjusted Operating Margin decreased $85 million for the year 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 decreased $109 million, as a result of the decrease of $85 million in Adjusted Operating Margin described above, and higher interest expense from higher outstanding debt and a monetary correction related to the asset base ruling for Eletropaulo in December 2013.

MCAC SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our MCAC SBU for the periods indicated:

For the Years Ended December 31,
201420132012$ Change 2014 vs. 2013$ Change 2013 vs. 2012% Change 2014 vs. 2013% Change 2013 vs. 2012
($’s in millions)
Operating Margin$541$543$560$(2)$(17)—%(3)%
Noncontrolling Interests Adjustment$(59)$(69)$(74)
Derivatives Adjustment—(2)3
Adjusted Operating Margin$482$472$489$10$(17)2%(3)%
Adjusted PTC$352$339$387$13$(48)4%(12)%

Fiscal year 2014 versus 2013

Including the unfavorable impact of currency translation of $3 million, operating margin decreased $2 million, or 0.4%. This performance was driven primarily by the following businesses and key operating drivers:

•El Salvador decreased $22 million, due primarily to a one-time unfavorable adjustment to unbilled revenue, as well as higher energy losses and other fixed costs; and
•Panama decreased $8 million, driven by dry hydrological conditions, which resulted in lower generation and higher energy purchases of $38 million and the Esti tunnel settlement agreement received during 2013 of $31 million, partially offset by compensation from the government of Panama of approximately $40 million related to spot purchases from dry hydrological conditions, as well as lower fixed and other costs of $22 million.

These decreases were partially offset by:

•Dominican Republic increased $19 million, mainly related to higher spot sales of $58 million and higher availability of $20 million, partially offset by lower gas sales to third parties of $27 million, lower frequency regulation of $26 million and lower PPA results of $14 million; and
•Puerto Rico increased by $6 million, driven by a favorable bad debt reversal.

Adjusted Operating Margin increased $10 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 and 50% of Itabo in the Dominican Republic, 99% of TEG/TEP and 55% of Merida in Mexico and a weighted average of 75% of its businesses in El Salvador.

Adjusted PTC increased $13 million, driven by the increase in Adjusted Operating Margin of $10 million as described above.

Fiscal year 2013 versus 2012

Including the unfavorable impact of foreign currency translation of $2 million, operating margin decreased $17 million, or 3%. This performance was driven primarily by the following businesses and key operating drivers:

•Panama decreased $75 million, driven by dry hydrological conditions, which resulted in lower generation and higher energy purchases at higher prices of $88 million, partially offset by favorable net settlements related to the Esti tunnel of $22 million.

This decrease was partially offset by:

•Dominican Republic increased $42 million, as a result of higher net energy transactions of $28 million, higher gas sales to third parties of $20 million, partially offset by $6 million due to other factors such as higher fixed costs.
•El Salvador increased $17 million, due to the tariff increase approved by the regulator at the beginning of 2013.

Adjusted Operating Margin increased $17 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 (as of December 2013) and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina and 50% of Itabo in the Dominican Republic, 99% of TEG/TEP and 55% of Merida in Mexico, and a weighted average of 75% of its businesses in El Salvador.

Adjusted PTC increased $48 million, driven by the increase in Adjusted Operating Margin of $17 million described above, and lower interest income in the Dominican Republic and the receipt of property damage insurance proceeds in 2012 related to the Esti tunnel in Panama.

Europe SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Europe SBU for the periods indicated:

For the Years Ended December 31,
201420132012$ Change 2014 vs. 2013$ Change 2013 vs. 2012% Change 2014 vs. 2013% Change 2013 vs. 2012
($’s in millions)
Operating Margin$403$415$504$(12)$(89)-3%-18%
Noncontrolling Interests Adjustment$(26)$(23)$(55)
Derivatives Adjustment(4)—(2)
Adjusted Operating Margin$373$392$447$(19)$(55)-5%-12%
Adjusted PTC$348$345$375$3$(30)1%-8%

Fiscal year 2014 versus 2013

Including the unfavorable impact of foreign currency translation of $10 million, operating margin decreased $12 million, or 3%. This performance was driven primarily by the following businesses and key operating drivers:

•Kilroot decreased $31 million driven by lower dispatch and higher outages and related maintenance costs of $46 million, partially offset by higher rates of $13 million, including income from energy price hedges, and favorable foreign exchange rates; and
•Maritza decreased $17 million due to higher outages and related maintenance costs of $32 million, partially offset by higher rates of $10 million.

These results were partially offset by:

•Jordan increased $17 million as the IPP4 Jordan plant commenced operations in July 2014; and
•Kazakhstan increased $11 million driven by higher volumes and rates of $29 million, partially offset by unfavorable foreign exchange impact of $13 million.

Adjusted Operating Margin decreased $19 million due to the drivers above adjusted for noncontrolling interests, primarily Jordan with Amman East at 36% and IPP4 at 60%, and excluding unrealized gains and losses on derivatives.

Adjusted PTC increased $3 million, driven primarily by the decrease of $19 million in Adjusted Operating Margin described above, offset by the 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.

Fiscal year 2013 versus 2012

Including the favorable impact of foreign currency translation of $5 million, operating margin decreased $89 million, or 18%. This performance was driven primarily by the following businesses and key operating drivers:

•Cartagena in Spain decreased $105 million, as a result of:
◦A non-recurring, favorable arbitration settlement of $95 million in the first quarter of 2012; and
◦The two-stage sale of the business, as AES owned 71% of the facility through February 2012 and 14% through April 2013, when the sale was completed.
•Ballylumford in the U.K. decreased $29 million due to lower rates and capacity payments of $48 million, partially offset by fewer outages of $19 million.

These decreases were partially offset by:

•Maritza in Bulgaria increased $30 million driven by $10 million from fewer outages, $6 million of lower fixed costs, and favorable foreign exchange rates of $7 million.
•Kilroot in the U.K. increased $28 million driven by favorable dark spreads from higher energy prices and lower coal costs.

Adjusted Operating Margin decreased $55 million due to the drivers above adjusted for the impact of noncontrolling interests, primarily Cartagena in Spain due to the two stage sale of the business as described above, and excluding unrealized gains and losses on derivatives.

Adjusted PTC decreased $30 million, driven by the decrease of $55 million in Adjusted Operating Margin described above, partially offset by lower interest expense and realized foreign currency gains at Kilroot and higher equity earnings from Turkey and Elsta in the Netherlands.

Asia SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Generation businesses in Asia for the periods indicated:

For the Years Ended December 31,
201420132012$ Change 2014 vs. 2013$ Change 2013 vs. 2012% Change 2014 vs. 2013% Change 2013 vs. 2012
($’s in millions)
Operating Margin$76$169$236$(93)$(67)-55%-28%
Noncontrolling Interests Adjustment(25)(10)(17)
Derivatives Adjustment——(15)
Adjusted Operating Margin$51$159$204$(108)$(45)-68%-22%
Adjusted PTC$46$142$201$(96)$(59)-68%-29%

Fiscal year 2014 versus 2013

Operating margin decreased $93 million, or 55%. This performance was driven primarily by the following businesses and key operating drivers:

•Masinloc in the Philippines decreased by $79 million, driven by $33 million due to lower plant availability, a net decrease of $21 million of lower spot rates partially offset by higher volume, 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 maintenance costs of $4 million; and
•Kelanitissa in Sri Lanka decreased by $17 million, driven by the step-down in the contracted PPA price.

Adjusted Operating Margin decreased $108 million due to the drivers above adjusted for the impact of non-controlling interests and excluding unrealized gains on derivatives. AES owned 92% of Masinloc until July 2014 when AES reduced its ownership to 51%.

Adjusted PTC decreased $96 million, driven by the decrease of $108 million in Adjusted Operating Margin described above, partially offset by the impact of lower proportional interest expense at Masinloc and gains on foreign currency.

Fiscal year 2013 versus 2012

Operating margin decreased $67 million, or 28%. This performance was driven primarily by the following business and key operating drivers:

•Masinloc in Philippines decreased $62 million, due to:
◦The net impact of higher contracted volumes at lower prices, as a result of a new 7-year contract to reduce spot exposure, with an unfavorable impact of $31 million;
◦A reversal of a contingency of $16 million in 2012; and
◦An unrealized derivative gain of $15 million in 2012.

Adjusted Operating Margin decreased $45 million due to the drivers discussed above adjusted for the impact of noncontrolling interests and excluding unrealized gains on derivatives. AES owned 92% of Masinloc (prior to partial sale in 2014).

Adjusted PTC decreased $59 million, driven primarily by the decrease of $45 million in Adjusted Operating Margin described above, as well as a reduction in equity earnings from the sale of our businesses in China in 2012, partially offset by lower interest expense at Masinloc.

Key Trends and Uncertainties

During 2015 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 (or other adverse factors unknown to us) may impact 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 this Form 10-K.

Regulatory

Philippines—In November and December 2013, the Philippines spot market witnessed an unprecedented price spike compared to historical levels. On March 11, 2014, the 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 denied all motions for reconsideration filed by the generating companies.

Prior to the high price events in 2013, there was a primary price cap for spot prices set at 62,000 pesos per MWh. This cap was lowered to 32,000 pesos per MWh on January 4, 2014 pursuant to a joint resolution by the ERC, the Department of Energy (DoE) and the market operator. On May 5, 2014, a secondary price cap of 6,245 pesos per MWh was established on an interim basis to be applied when certain high price thresholds were met over time. On December 15, 2014, the ERC issued a resolution to change the temporary nature of the secondary price cap into a permanent secondary price cap. Based on historical trends we do not expect either the primary or the secondary price cap mechanisms to be triggered.

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 met the supply requirement. The new rule assigns a mandatory minimum margin to all generators which must be provided by its own source or through bilateral contracts with other generators who can offer the service. Additional supply requirements are allocated using the merit order process. The AES businesses, Andres and Los Mina, were previously lower in the merit order and 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 margin from frequency regulation, which will be partially offset by higher energy dispatch due to increased capacity.

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 hydrological conditions do not improve and 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 may continue through first half of 2015. Even if rainfall and water inflows return to historical average, 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 there is a mechanism called MRE 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. The system average inflows in 2014 were the 10th worst of the historical data since 1931. The consequences of unfavorable hydrology are (i) thermal plants (more expensive to the system) being dispatched, (ii) lower hydro power generation with deficits in the MRE and (iii) high spot prices. During 2014 spot prices sustained significantly high levels causing financial stress to most agents in the energy sector. From February to April 2014, the spot price was at the cap level of R$822/MWh, contributing to the average spot price of R$690/MWh in 2014. During October and November 2014, ANEEL conducted a public hearing to define a new spot price cap, reducing it from R$822/MWh to R$388/MWh from January 2015 forward. The lower cap price will result in a meaningful reduction on expenses for the agents that are negatively exposed to the spot price in 2015.

We expect the system operator in Brazil to continue to pursue a more conservative reservoir management strategy going forward, including the dispatch of up to 17 GW of thermal generation capacity, which could result in lower dispatch of hydroelectric generation facilities and electricity prices at high levels. AES Tietê has contract obligations throughout 2015 and may need to fulfill some of these obligations with spot purchases, so they will be sensitive to generation output and spot prices for electricity during this period. In addition, the costs incurred by our distribution companies, AES Eletropaulo and AES Sul, on energy purchases are passed through to customers with adjustments on a yearly basis, so working capital will be sensitive to significant increases in energy prices. In order to reduce potential working capital needs, on February 2015 ANEEL opened two public hearings i) to discuss an Extraordinary Tariff Review requested by distribution companies and ii) to discuss adjustments to a tariff flag mechanism that may change the tariff to customers on a monthly basis depending on energy prices. These items are expected to increase tariffs starting in March 2015, anticipating pass-through of energy costs thus reducing potential working capital needs for distribution companies.

Finally, if dry conditions persist into the next rainy season through April 2015, there is a risk that the government of Brazil could implement a rationing program in 2015. If rationing were to occur, we would expect rules to be implemented that may include, but are not limited to, i) adjustments to hydroelectric generation PPAs in accordance with the overall load reduction affecting contracting position of hydroelectric generators and distribution companies, ii) reduction in energy consumption impacting hydroelectric generation and margins of distribution companies, iii) increases in costs for distribution companies to provide additional customer services, communications, and to comply with rationing decree rules and iv) increases in losses and delinquency for distribution companies due to higher tariffs and potential penalties. As a result, if below long-term average hydrology continues and/or Brazil implements a rationing program, we would expect there to be an adverse impact on our results of operations and cash flows of our generation and distribution businesses in Brazil. Finally, an Extraordinary Tariff Review may be applied to partially or completely offset the reduction in margin and increase on costs, losses and delinquency incurred by distribution companies due to rationing, mitigating the adverse impact on results.

In Panama, dry hydrological conditions continued in 2014 reducing generation output from hydroelectric facilities and increasing 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 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 through the first half of the year which will continue to impact our results of operations. 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 December 31, 2014 were $40 million, of which $3 million are pending to be collected. Additionally, as part of our strategy to reduce our reliance on hydrology, AES Panama acquired a 72MW power barge for $27 million, financed with non-recourse debt, in September 2014, which we expect to become operational in the first quarter of 2015.

Taxes

The Company expects its effective tax rate in future years to be higher than the current year effective rate of 27%. As discussed in Item 7.— Review of Consolidated Results of Operations, the current year rate was favorably impacted by certain non-recurring items and the Company’s benefit from reduced income tax rates on its operations in the Philippines which expired in the fourth quarter of 2014. Further, as noted in Critical Accounting Policies and Estimates (also in Item 7. of this Form 10-K), the Company is subject to higher income tax rates in Colombia for the next four years.

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 remain unfavorable, as measured by indicators such as non-receding inflation, increased government deficits, diminished sovereign reserves, lack of foreign currency accessibility, the potential for continued devaluation of the local currency, and a decline in expectations for 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 December 31, 2014, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank. See Note 7—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information on the long-term receivables. In January 2014, the Argentine Peso devalued by approximately 20%, the most rapid depreciation since 2002. While the currency has stabilized in the later part of 2014, 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. Although this situation remains unresolved, it has not caused any significant changes that impact our current exposures, however, as noted above, there could be impacts on our businesses in the future.

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 December 2014 when the final installment was paid. 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 million through an offset of payables due by Maritza to MMI. Additionally in 2014, NEK paid four additional monthly installments totaling $28 million as agreed upon on time. As of December 31, 2014, Maritza had outstanding receivables of $262 million, representing $57 million of current receivables, $75 million of receivables overdue by less than 90 days and $130 million of receivables overdue by more than 90 days. Although Maritza continued to collect overdue receivables during the fourth 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. No allowance has been recognized on the receivables as the Company continues to assert that collection is probable. See Note 12—Debt included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information on current existing debt defaults. Litigation related to construction delays and related matters was settled in December 2014. For further information on the litigation see Item 3.—Legal Proceedings.

In May and June 2014, Bulgaria’s 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 further impacted 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%. However, SEWRC confirmed that until such negotiations conclude, the PPA is in full force and effect and NEK has not objected to Maritza's invoices. Maritza has filed appeals and requests for suspension of these SEWRC decisions with the Supreme Administrative Court in Bulgaria. The requests for suspension were denied by SAC. Further, on November 17, 2014, SEWRC replaced its May 2014 decision taking one of Maritza’s units out of the PPA and reducing the price of the remaining unit’s output by 30% with a decision which only required NEK and Maritza to start negotiations towards amending the PPA, without any prescribed parameters. Following the repeal of the decision, Maritza withdrew its appeal against that decision but continues to appeal the other May 2014 decisions. In addition, SEWRC announced in June 2014 that it has asked the 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. 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.

In June 2014, new measures aiming at allocating to renewable energy producers the cost associated with the imbalance between forecasted and actual generation (known as Balancing Market) became effective. Saint-Nikola, a wind farm located in Kavarna, has been negatively impacted by these measures. Saint-Nikola is challenging the validity of the calculation methodology with SEWRC, and will take all actions necessary to protect its interests.

On July 24, 2014, the Government of Bulgaria formally resigned and the Caretaker Government was appointed by the President. Preliminary Parliamentary Elections were held on October 5, 2014. A coalition led by center-right party GERB formed a new government led by Prime Minister Boyko Borisov. The new government set as one of its priorities the restructuring of the energy sector, which is necessary to restore NEK’s liquidity. The first measure announced by the new government was an end-consumer energy price increase of approximately 10% effective October 1, 2014. The other measures are being prepared by the Energy Commission of the Parliament, and are expected to be promulgated by June 2015. One of the components of the energy sector restructuring is the negotiation of an amendment of Maritza’s PPA. Maritza has engaged in negotiations with SEWRC, NEK, and other Bulgarian instrumentalities concerning these matters. In February 2015, the Company signed a Memorandum of Understanding with the Government of Bulgaria to commence negotiations on proposed amendments to the existing PPA with NEK, which includes the payment of all outstanding receivables. 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.

Furthermore, as noted in Item 1.—Business—Bulgaria, during the fourth quarter of 2013, NEK requested a consent from Maritza for a restructuring. In February 2014, the NEK restructuring was implemented after approval by the regulatory authorities. As a result, NEK’s credit rating fell below the rating NEK had upon the issuance of the Government Support Letter in 2005. Also, as a result of this restructuring NEK transmission license was revoked by the Regulator. These are defaults under the PPA, which triggered additional events of default under the project debt agreements. For further information on the importance of long-term contracts and our counterparty credit risk, see Item 1A.—Risk Factors—“We may not be able to enter into long-term contracts, which reduce volatility in our results of operations.” 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.

As of December 31, 2014, we concluded there is no indicator of an impairment of the long-lived assets in Bulgaria for Maritza, which were $1.3 billion and total debt of $690 million, and Kavarna, which were $242 million and total debt of $168 million. Therefore, management believes the carrying amount of the asset group is recoverable as of December 31, 2014.

In December 2014 the Agency for State Financial Inspection started an audit to evaluate the compliance of Maritza with Public Procurement rules. Based on an extensive regulatory review conducted in 2011 at the time of Maritza plant commissioning, Maritza does not follow Public Procurement rules and will defend its rights if necessary after the conclusion of the audit, expected by June 2015.

Puerto Rico— Our subsidiary in Puerto Rico has a long-term PPA with the 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 receivable 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.

In February 2014, all agencies downgraded the Commonwealth of Puerto Rico and its 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. The downgrade on PREPA has had a direct impact on AES Puerto Rico's bonds. While Fitch rates both AES PR and PREPA with CC, Moody's rates AES Puerto Rico bonds (B3) three notches above PREPA (Caa3) citing as reasons the priority position of PREPA's contractual payments to AES PR as an operating expense as well as the project's strategic importance to PREPA as an efficient, reliable and relatively low cost source of power. 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.

On December 14, 2014 PREPA presented the first stage of the business plan to bondholders, which laid out key financial information on the current affairs of PREPA. The report, presented by PREPA's Chief Restructuring Officer ("CRO") complied with a key milestone in the Forbearance Agreement that expires on March 2, 2015 with bondholders. While the report is subject to strict confidentiality clauses, the CRO has stated that it does not contain recommendations or proposals on the utility’s capital structure, rates, payroll or any other fronts. During January, the CRO informed that their recommendations will not be ready until June 2015. The CRO is required to submit the recommendations to the Forbearance Committee which should state whether PREPA intends to restructure its debt combined with other restructuring actions on vendor negotiations, fuel cost contacts, capital needs and labor costs.

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 impact AES Puerto Rico's ability to meet its obligations. For further information, see Item 1A.—Risk Factors—“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. AES Puerto Rico's receivables balance as of December 31, 2014 is $89 million, of which $24 million is overdue. Subsequent to December 31, 2014, the full overdue amount has been collected.

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. As the events pertaining to the Recovery Act continue to unfold, we concluded that there was no indicator of an impairment of the long-lived assets in Puerto Rico, which were $632 million and total debt of $528 million. Therefore, management believes the carrying amount of the asset group is recoverable as of December 31, 2014.

If the above referenced 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 — In the fourth quarter of 2014, the Company completed its annual October 1 goodwill impairment tests and recognized goodwill impairment expense of $10 million. Year to date, the Company has recognized goodwill impairment expense of $164 million. The Company has no reporting units considered to be "at risk." A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. The Company monitors its reporting units at risk of step 1 failure on an ongoing basis. It is possible that the Company may incur goodwill impairment charges at any reporting

units containing goodwill in future periods if adverse changes in their business or operating environments occur. See Note 10—Goodwill and Other Intangible Assets included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Capital Resources and Liquidity

Overview

As of December 31, 2014, the Company had unrestricted cash and cash equivalents of $1.5 billion, of which $507 million was held at the Parent Company and qualified holding companies. The Company also had $709 million in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $694 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.6 billion and $5.3 billion, respectively. Of the approximately $2.0 billion of our current non-recourse debt, $1.1 billion was presented as such because it is due in the next twelve months and $858 million relates to debt considered in default due to covenant violations. The defaults are not payment defaults, but are instead technical defaults triggered by failure to comply with other covenants and/or other conditions such as (but not limited to) failure to meet information covenants, complete construction or other milestones in an allocated time, meet certain minimum or maximum financial ratios, or other requirements contained in the non-recourse debt documents of the Company.

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. Approximately $151 million of our recourse debt matures within the next twelve months, which we expect to repay using a combination of cash on hand at the Parent Company, net cash provided by operating activities and/or net proceeds from the issuance of new debt at the Parent Company.

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 $15.6 billion of total non-recourse debt outstanding as of December 31, 2014, approximately $3.9 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 December 31, 2014, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $417 million 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 December 31, 2014, we had $61 million in letters of credit outstanding, provided under our senior secured credit facility, and $74 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 year ended December 31, 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 December 31, 2014, the Company had approximately $293 million and $31 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 December 31, 2015, 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 7—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data and Item 1.—Business—Regulatory Matters—Argentina of this Form 10-K for further information.

Consolidated Cash Flows

During the year ended December 31, 2014, cash and cash equivalents decreased $103 million to $1.5 billion. The decrease in cash and cash equivalents was due to $1.8 billion of cash provided by operating activities, $656 million of cash used in investing activities, $1.3 billion of cash used in financing activities, an unfavorable effect of foreign currency exchange rates on cash of $51 million and a $75 million decrease in cash of discontinued and held-for-sale businesses.

$ Change
2014201320122014 vs. 20132013 vs. 2012
(in millions)
Net cash provided by (used in) operating activities$1,791$2,715$2,901$(924)$(186)
Net cash provided by (used in) investing activities(656)(1,774)(895)1,118(879)
Net cash provided by (used in) financing activities(1,262)(1,136)(1,867)(126)731

Operating Activities

2014 Cash Flows from Operating Activities

For the year ended December 31, 2014 compared to the year ended December 31, 2013, the net decrease in cash flows from operating activities of $924 million, or 34% to $1.8 billion was primarily the result of the following:

•Brazil — decrease of $549 million primarily driven by higher tax payments of $244 million across the region and higher energy purchases in excess of collections resulting from poor hydrology of $153 million and $84 million at the Utilities and Tietê, respectively;
•MCAC — a decrease of $184 million primarily driven by a non-recurring $90 million settlement received in 2013 related to a fuel contract amendment and $12 million lower collections in Dominican Republic, as well as higher energy purchases of $46 million in Panama, and;
•Europe — a decrease of $180 million primarily due to lower collections of $56 million at Maritza in Bulgaria and higher working capital requirements of $52 million in Northern Ireland in the U.K.

Operating cash flow of $1.8 billion for the year ended December 31, 2014 resulted primarily from net income and adjustments for non-cash items (principally depreciation and amortization, gain from sale of assets and investments, and

impairment expense), which was partially offset by a net use of cash from changes in operating assets and liabilities of $1.0 billion due to the following:

•an increase of $723 million in other assets primarily related to increased regulatory assets at Eletropaulo and Sul resulting from higher priced energy purchases recoverable through future tariffs as well as an increase at Alicura related to the recognition of interest associated with the FONINVEMEM agreement;
•an increase of $520 million in accounts receivable primarily related to higher sales at Eletropaulo and Sul and lower collections at Maritza; and
•a decrease of $89 million in net income tax and other tax payables primarily for payments of income taxes in excess of accruals of new current tax liabilities; partially offset by
•an increase of $516 million in other liabilities primarily related to an increase in regulatory liabilities at Eletropaulo and Sul partially offset by pension contributions at IPL and payments for share-based compensation issuance withholding tax and termination of a derivative contract at the Parent Company.

2013 Cash Flows from Operating Activities

For the year ended December 31, 2013 compared to the year ended December 31, 2012, the net decrease in cash flows from operating activities of $186 million, or 6% to $2.7 billion was primarily the result of the following:

•US — an increase of $74 million primarily due to a bankruptcy settlement payment of the New York entities in 2012 and the proceeds from the PPA termination at Beaver Valley in January 2013;
•Andes — a decrease of $276 million primarily driven by higher working capital requirements;
•Brazil — a decrease of $106 million primarily related to lower collections and higher energy purchases at Sul, partially offset by the recovery of deferred costs from ANEEL, rate regulator, lower transmission costs and regulatory charges at Eletropaulo;
•MCAC — an increase of $185 million primarily driven by a $90 million settlement received related to an amendment to a fuel contract and lower working capital requirements; and
•Asia — a decrease of $85 million primarily driven by higher working capital requirements and lower operating results at Masinloc.

Operating cash flow of $2.7 billion for the year ended December 31, 2013 resulted primarily from net loss and adjustments for non-cash items (principally gain and losses on sales and disposals, impairment charges, depreciation and amortization, and deferred income taxes), which was partially offset by a net use of cash from changes in operating assets and liabilities of $76 million due to the following:

•a decrease of $725 million in accounts payable and other current liabilities primarily at Eletropaulo and Sul due to lower costs and a decrease in regulatory liabilities and at Uruguaiana primarily related to the extinguishment of a liability as well as lower generation and higher payments to fuel supplier at Kelanitissa;
•an increase of $103 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 and an increase at Alicura related to the recognition of interest associated to FONINVEMEM agreement, partially offset by a decrease in noncurrent regulatory assets at IPL related to the annual adjustment to pension benefits based on the actuarial valuation; partially offset by
•a decrease of $358 million in prepaid expenses and other current assets mainly due to a decrease in current regulatory assets, for the recovery of prior period tariff cycle energy purchases and regulatory charges at Eletropaulo;
•a decrease of $146 million in accounts receivable primarily related to lower tariffs at Eletropaulo combined with lower tariff and reduced consumption at Sul as well as lower revenue offset by higher collections at Kelanitissa, partially offset by lower collections at Maritza;
•an increase of $137 million in other liabilities primarily due to an increase in noncurrent regulatory liabilities at Eletropaulo partially offset by a decrease in pension liability at IPL; and
•a increase of $95 million in net income tax and other tax payables primarily due to accruals for new current tax liabilities offset by payments of income taxes.

2012 Cash Flows from Operating Activities

Net cash provided by operating activities was $2.9 billion for the year ended December 31, 2012. Operating cash flow resulted primarily from net income and adjustments for non-cash items (principally depreciation and amortization, contingencies, deferred income taxes, losses on the extinguishment of debt, gains and losses on sales and disposals, and impairment charges), as well as a net source of cash from changes in operating assets and liabilities of $68 million due to the following:

•an increase of $589 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo, resulting from higher priced energy purchases, regulatory charges and transmission costs which are recoverable through future tariffs and the establishment of a noncurrent note receivable at Cartagena in Spain following the arbitration settlement, prior to its deconsolidation;
•an increase of $241 million in accounts receivable primarily due to lower collection Eletropaulo and Andres as well as an increase in revenue at Sul and Kelanitissa;
•a decrease of $47 million net income tax payables and other tax payables primarily for the payment of income taxes in excess of the accrual of new tax liabilities; partially offset by
•an increase of $335 million in other liabilities primarily explained by an increase in noncurrent regulatory liabilities at Eletropaulo related to the tariff reset;
•an increase of $330 million in accounts payable and other current liabilities primarily at Eletropaulo due to an increase in current regulatory liabilities driven by the tariff reset, offset by a decrease in other current liabilities arising from value-added tax payables; and
•a decrease of $120 million in prepaid expenses and other current assets mainly due to the recovery of value-added taxes at our construction projects in Chile.

Investing Activities

2014 Cash Flows from Investing Activities

Net cash used in investing activities was $656 million for the year ended December 31, 2014 primarily attributable to the following:

•Capital expenditures of $2.0 billion consisting of $1.2 billion of growth capital expenditures and $865 million of maintenance and environmental capital expenditures. Material expenditures by business are as follows:
◦Growth capital expenditures included amounts at Gener of $399 million, Eletropaulo of $146 million, IPL of $126 million, Mong Duong of $111 million, Jordan of $72 million, Maritza of $62 million, DPL of $46 million, Sul of $45 million and Panama of $42 million;
◦Maintenance and environmental capital expenditures included amounts at IPL of $265 million, Eletropaulo of $90 million, Gener of $89 million, Tietê of $80 million, DPL of $65 million, Sul of $54 million and Altai of $43 million;
•Acquisitions, net of cash acquired of $728 million consisted primarily 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 8—Investment in and Advances to Affiliates in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information;
•Purchases of short-term investments, net of sales of $120 million including amounts at Brasiliana Energia of $81 million and Tietê of $63 million offset by net sales at Eletropaulo of $39 million; partially offset by
•Proceeds from the sale of businesses, net of cash sold of $1.8 billion including $730 million at Gener related to the sale of 50% less one share of our interest in Guacolda, $436 million for the sale of 45% of our equity interest in Masinloc, $174 million related to the the sale of AES’ interest in Silver Ridge Power’s assets in Bulgaria, France, Greece, India and the United States, $158 million related to the UK Wind Sale, $156 million from the sale of our businesses in Cameroon and $125 million for the sale of Entek, our equity investment in Turkey; and
•Decreases in restricted cash, debt service reserve and other assets of $419 million including amounts of $98 million primarily related to the Alstom settlement repayment at Maritza, $96 million at the Parent Company pertaining to letter of credit reductions for Jordan and Mong Duong development projects, as well as project debt refinancing of $70 million and $45 million at Angamos and Southland, respectively.

2013 Cash Flows from Investing Activities

Net cash used in investing activities was $1.8 billion for the year ended December 31, 2013 primarily attributable to the following:

•Capital expenditures of $2.0 billion consisting of $1.1 billion of growth capital expenditures and $934 million of maintenance and environmental capital expenditures.
◦Growth capital expenditures included amounts at Gener of $317 million, Eletropaulo of $223 million, Jordan of $200 million, Sul of $72 million, Mong Duong of $48 million, DPL of $40 million, Sixpenny Wood of $25 million, Altai of $21 million, Yelvertoft of $20 million and Kribi of $20 million;
◦Maintenance and environmental expenditures included amounts at IPL of $246 million, Eletropaulo of $138 million, Tietê of $94 million, Gener of $92 million, DPL of $76 million, Sul of $61 million and Altai of $43 million; partially offset by
•Proceeds from the sale of businesses, net of cash sold of $170 million including $110 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.

Financing Activities

2014 Cash Flows from Financing Activities

Net cash used in financing activities was $1.3 billion for the year ended December 31, 2014 primarily attributable to the following:

•Repayments of recourse and non-recourse debt of $5.6 billion including amounts at the Parent Company of $2.1 billion, Gener of $905 million, Angamos of $780 million, DPL of $364 million, Southland of $188 million, Chivor of $165 million, Tietê of $132 million, $114 million related to the UK Wind sale, Eletropaulo of $110 million and Warrior Run of $109 million;
•Payments for financed capital expenditures were $528 million including $310 million at Mong Duong, $143 million at Cochrane and $30 million at Changuinola;
•Distributions to noncontrolling interests of $485 million including amounts at Tietê of $188 million, Brasiliana Energia of $69 million, Gener of $66 million and Buffalo Gap of $45 million;
•Purchase of treasury stock of $308 million at the Parent Company; partially offset by
•Issuances of recourse and non-recourse debt of $5.7 billion including new issuances at the Parent Company of $1.5 billion, Angamos of $800 million, Gener of $700 million, Mong Duong of $364 million, Tietê of $318 million, Cochrane of $305 million, US Generation Holdings of $299 million, Eletropaulo of $253 million, DPL of $200 million and Sul of $185 million.

2013 Cash Flows from Financing Activities

Net cash used in financing activities was $1.1 billion for the year ended December 31, 2013 primarily attributable to the following:

•Repayments of recourse and non-recourse debt of $4.6 billion including amounts at the Parent Company of $1.2 billion, DPL of $948 million, Masinloc of $560 million, Changuinola of $412 million, Tietê of $396 million, Caess of $301 million, IPL of $110 million, Warrior Run of $100 million, Puerto Rico of $73 million, Maritza of $57 million, Southland of $54 million, Sonel of $47 million and Sul of $44 million;
•Payments for financed capital expenditures were $591 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 $557 million including amounts at Tietê of $205 million, Brasiliana of $128 million, Gener of $62 million and Buffalo Gap of $54 million;
•The purchase of treasury stock at the Parent Company was $322 million;
•Payments for financing fees of $176 million including amounts at Gener of $54 million including amounts at the Alto Maipo and Cochrane projects, Mong Duong of $28 million and Eletropaulo of $25 million; partially offset by
•Issuances of recourse and non-recourse debt of $5.0 billion including amounts of $750 million at the Parent Company, Gener of $707 million including amounts at the Cochrane and Alto Maipo projects, DPL of $645 million, Masinloc of $500 million, Tietê of $496 million, Mong Duong of $471 million, Changuinola of $420 million, Caess of $310 million, Jordan of $180 million, IPL of $170 million and Sul of $153 million; and
•Contributions from noncontrolling interests of $210 million including amounts at Gener of $109 million including amounts at the Cochrane and Alto Maipo projects and at Mong Duong of $77 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.

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. US SBU—IPL—Environmental Matters 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.

201420132012
Calculation of Maintenance Capital Expenditures for Free Cash Flow Reconciliation Below:(in millions)
Maintenance Capital Expenditures$666$760$968
Environmental Capital Expenditures24121175
Growth Capital Expenditures1,6371,6081,227
Total Capital Expenditures$2,544$2,579$2,270
Consolidated
Net cash provided by operating activities$1,791$2,715$2,901
Less: Maintenance Capital Expenditures, net of reinsurance proceeds666760923
Less: Non-recoverable Environmental Capital Expenditures7810166
Free Cash Flow$1,047$1,854$1,912
Reconciliation of Proportional Operating Cash Flow
Net cash provided by operating activities$1,791$2,715$2,901
Less: Proportional Adjustment Factor(1)359834966
Proportional Operating Cash Flow$1,432$1,881$1,935
Proportional
Proportional Operating Cash Flow$1,432$1,881$1,935
Less: Proportional Maintenance Capital Expenditures, net of reinsurance proceeds(1)485535634
Less: Proportional Non-recoverable Environmental Capital Expenditures(1)567551
Proportional Free Cash Flow$891$1,271$1,250

(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 71% 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 $29 (or $100 x 29%). 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 year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $380 million, driven primarily by the following SBUs and key operating drivers excluding intercompany related transactions pertaining to interest, tax sharing and charges for management fee and transfer pricing:

•MCAC — $152 million decrease primarily driven by a non-recurring $90 million settlement received in 2013 related to a fuel contract amendment and $30 million lower collections in Dominican Republic, as well as higher energy purchases of $22 million in Panama;
•Europe — $149 million decrease primarily driven by $56 million of lower collections in Bulgaria and $52 million of lower operating margins and higher working capital in Northern Ireland in the U.K.;
•Brazil — $103 million decrease primarily driven by higher tax payments of $100 million across the region and higher energy purchases in excess of collections resulting from poor hydrology of $10 million and $20 million at the Utilities and Tietê, respectively;
•US — $46 million decrease driven by $46 million proceeds from the PPA termination at Beaver Valley in 2013 and $41 million of higher working capital at DPL, partially offset by $52 million of lower maintenance capital expenditures at the U.S. Utilities;
•Asia — $19 million decrease driven primarily by lower margins at Kelanitissa; and
•Andes — $13 million decrease primarily related to $51 million in Chile driven by $28 million of VAT receivable timing and an interest rate swap payment of $18 million as well as $28 million in Argentina primarily due to an increase in interest receivables. These results were partially offset by an increase of $67 million at Chivor in Colombia primarily due to higher margins.

These decreases were partially offset by:

•Corporate — $98 million increase primarily driven by lower Parent interest of $69 million.

Proportional Free Cash Flow for the year ended December 31, 2013 compared to the year ended December 31, 2012 increased $21 million, driven primarily by the following SBUs and key operating drivers excluding intercompany related transactions pertaining to interest, tax sharing and charges for management fee and transfer pricing:

•MCAC — $197 million increase driven by higher operating cash flow, as a result of a $90 million settlement related to an amendment to a fuel contract and lower working capital requirements, and
•US — $110 million increase as a result of higher operating cash flow from a settlement received related to the bankruptcy of the New York entities in 2012 and the proceeds from the PPA termination at Beaver Valley in January 2013, as well as $48 million due to lower capital expenditures.

These increases were partially offset by:

•Andes — $193 million increase driven by lower operating cash flow from higher working capital requirements; and
•Asia — $76 million decrease largely due to lower operating cash flow from higher working capital requirements and lower operating results at Masinloc.

Parent Free Cash Flow (a non-GAAP measure)

The Company defines Parent Free Cash Flow as dividends and other distributions received from our operating businesses less certain cash costs at the Parent Company level, primarily interest payments, overhead, and development costs. Parent Free Cash Flow is used to fund shareholder dividends, share repurchases, growth investments, recourse debt repayments, and other uses by the Parent Company. Refer to Item 1—Business—Overview for further discussion of the Parent Company's capital allocation strategy.

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 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 facility; 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 facility. 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 December 31, 2014 and 2013 as follows:

Parent Company Liquidity20142013
(in millions)
Consolidated cash and cash equivalents$1,539$1,642
Less: Cash and cash equivalents at subsidiaries1,0321,510
Parent and qualified holding companies’ cash and cash equivalents507132
Commitments under Parent credit facility800800
Less: Letters of credit under the credit facility(61)(1)
Borrowings available under Parent credit facility739799
Total Parent Company Liquidity$1,246$931

The Company paid dividends of $0.20 per share to its common stockholders during the year ended December 31, 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.

Recourse Debt:

Our recourse debt at year-end was approximately $5.3 billion and $5.7 billion in 2014 and 2013, respectively. See Note 12—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional detail.

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, Global Economic Conditions), 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. See Item 1A.—Risk Factors—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, of this Form 10-K.

Various debt instruments at the Parent Company level, including our senior secured credit facility, 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 December 31, 2014, we were in compliance with these covenants at the Parent Company level.

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 facility 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 consolidated balance sheets amounts to $2.0 billion. The portion of current debt related to such defaults was $858 million at December 31, 2014, all of which was non-recourse debt

related to two subsidiaries — Maritza and Kavarna. See Note 12—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional detail.

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’ corporate debt agreements as of December 31, 2014 in order for such defaults to trigger an event of default or permit acceleration under AES’ 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 December 31, 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.

Contractual Obligations and Parent Company Contingent Contractual Obligations

A summary of our contractual obligations, commitments and other liabilities as of December 31, 2014 is presented in the table below, which excludes any businesses classified as discontinued operations or held-for-sale (in millions):

Contractual ObligationsTotalLess than 1 year1-3 years3-5 yearsMore than 5 yearsOtherFootnote Reference(5)
Debt Obligations(1)$20,858$2,144$3,623$3,282$11,809$—12
Interest Payments on Long-Term Debt(2)10,3491,2012,0881,6455,415—n/a
Capital Lease Obligations(3)159102020109—13
Operating Lease Obligations(3)80557114132502—13
Electricity Obligations(3)52,0973,5596,8776,85634,805—13
Fuel Obligations(3)6,9391,2661,5808583,235—13
Other Purchase Obligations(3)9,4001,3771,8281,3214,874—13
Other Long-Term Liabilities
Reflected on AES’ Consolidated Balance Sheet under GAAP(4)716—2405435666n/a
Total$101,323$9,614$16,370$14,168$61,105$66
(1)Includes recourse and non-recourse debt presented on the Consolidated Balance Sheet. See Note 12—Debt to the Consolidated Financial Statements included in Item 8—Financial Statements and Supplementary Data of this Form 10-K which provides additional disclosure regarding these obligations. These amounts exclude capital lease obligations which are included in the capital lease category, see (3) below.
(2)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2014 and do not reflect anticipated future refinancing, early redemptions or new debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2014.
(3)See Note 13—Commitments to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further information.
(4)These amounts do not include current liabilities on the Consolidated Balance Sheet except for the current portion of uncertain tax obligations. Noncurrent uncertain tax obligations are reflected in the “Other” column of the table above as the Company is not able to reasonably estimate the timing of the future payments. In addition, the amounts do not include: (1) regulatory liabilities (See Note 11—Regulatory Assets and Liabilities), (2) contingencies (See Note 14—Contingencies), (3) pension and other post retirement employee benefit liabilities (see Note 15—Benefit Plans) or (4) any taxes (See Note 22—Income Taxes) except for uncertain tax obligations, as the Company is not able to reasonably estimate the timing of future payments. See the indicated notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on the items excluded. Derivatives (See Note 6—Derivative Instruments and Hedging Activities) and incentive compensation are excluded as the Company is not able to reasonably estimate the timing or amount of the future payments.
(5)For further information see the note referenced below in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.

The following table sets forth our Parent Company contingent contractual obligations as of December 31, 2014:

Contingent contractual obligationsAmountNumber of AgreementsMaximum Exposure Range for Each Agreement
(in millions)(in millions)
Guarantees and commitments$39016$1 - 53
Asset sale related indemnities(1)27127
Cash collateralized letters of credit749<$1 - 47
Letters of credit under the senior secured credit facility615<$1 - 29
Total$55231

(1) Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal.

As of December 31, 2014, the Company had no commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit disclosed above.

We have a diverse portfolio of performance-related contingent contractual obligations. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, subsidiary default, political risk, tax indemnities,

spot market power prices, sponsor support and liquidated damages under power sales agreements for projects in development, in operation and under construction. In addition, we have an asset sale program through which we may have customary indemnity obligations under certain assets sale agreements. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations beyond 2014, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.

Critical Accounting Policies and Estimates

The 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. AES’ significant accounting policies are described in Note 1—General and Summary of Significant Accounting Policies to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

An accounting estimate is considered critical if:

•the estimate requires management to make assumptions about matters that were highly uncertain at the time the estimate was made;
•different estimates reasonably could have been used; or
•the impact of the estimates and assumptions on financial condition or operating performance is material.

Management believes that the accounting estimates employed are appropriate and the resulting balances are reasonable; however, actual results could materially differ from the original estimates, requiring adjustments to these balances in future periods. Management has discussed these critical accounting policies with the Audit Committee, as appropriate. Listed below are the Company’s most significant critical accounting estimates and assumptions used in the preparation of the Consolidated Financial Statements.

Income Taxes

We are subject to income taxes in both the United States and numerous foreign jurisdictions. Our worldwide income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the Internal Revenue Service and other taxing authorities. The Company and certain of its subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each tax jurisdiction when determining the adequacy of the provision for income taxes. Accounting guidance for uncertainty in income taxes prescribes a more likely than not recognition threshold. Tax reserves have been established, which the Company believes to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While the Company believes that the amounts of the tax estimates are reasonable, it is possible that the ultimate outcome of current or future examinations may be materially different than the reserve amounts.

Because we have a wide range of statutory tax rates in the multiple jurisdictions in which we operate, any changes in our geographical earnings mix could materially impact our effective tax rate. Furthermore, our tax position could be adversely impacted by changes in tax laws, tax treaties or tax regulations or the interpretation or enforcement thereof and such changes may be more likely or become more likely in view of recent economic trends in certain of the jurisdictions in which we operate. For example, on December 23, 2014, the Colombian Government enacted new taxes and modifications of existing taxes to apply as of January 1, 2015. Among other impacts, income tax rates, inclusive of temporary surcharges, will be 39% in 2015, 40% in 2016, 42% in 2017 and 43% in 2018 before reverting to 34% for 2019 and beyond. The impact of these higher rates for the four year period will be material to the Company.

The Company’s provision for income taxes could be adversely impacted by changes to the U.S. taxation of earnings of our foreign subsidiaries. Since 2006, the Company has benefited from the Controlled Foreign Corporation look-through rule, originally enacted in the TIPRA of 2005. The provision has been subject to repeated temporary extensions, including the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 and the American Taxpayer Relief Act of 2012. On December 19, 2014, the Controlled Foreign Corporation look-through rule was once again retroactively reinstated to January 1, 2014 for a period of one year through the Tax Increase Prevention Act of 2014. There can be no assurance that this provision will continue to be extended beyond December 31, 2014. Accordingly, if this provision is not renewed, our expected effective tax rate could increase by amounts that may be material to the Company.

In addition, U.S. income taxes and foreign withholding taxes have not been provided on undistributed earnings for certain of our non-U.S. subsidiaries to the extent such earnings are considered to be indefinitely reinvested in the operations of those subsidiaries.

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized.

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 discussed below for impairments and fair value.

Impairments

Our accounting policies on goodwill and long-lived assets are described in detail in Note 1—General and Summary of Significant Accounting Policies, included in Item 8 of this Form 10-K. The Company makes considerable judgments in its impairment evaluations of goodwill and long-lived assets; however, the fair value determination is typically the most judgmental part in an impairment evaluation.

The Company determines the fair value of a reporting unit or a long-lived asset (asset group) by applying the approaches prescribed under the fair value measurement accounting framework. Generally, the market approach and income approach are most relevant in the fair value measurement of our reporting units and long-lived assets; however, due to the lack of available relevant observable market information in many circumstances, the Company often relies on the income approach. The Company may engage an independent valuation firm to assist management with the valuation. The decision to engage an independent valuation firm considers all relevant facts and circumstances, including a cost/benefit analysis and the Company’s internal valuation knowledge of the long-lived asset (asset group) or business. The Company develops the underlying assumptions consistent with its internal budgets and forecasts for such valuations. Additionally, the Company uses an internal discounted cash flow valuation model (the “DCF model”), based on the principles of present value techniques, to estimate the fair value of its reporting units or long-lived assets under the income approach. The DCF model estimates fair value by discounting our internal budgets and cash flow forecasts, adjusted to reflect market participant assumptions, to the extent necessary, at an appropriate discount rate.

Management applies considerable judgment in selecting several input assumptions during the development of our internal budgets and cash flow forecasts. Examples of the input assumptions that our budgets and forecasts are sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power prices and commodity prices. Whenever appropriate, management obtains these input assumptions from observable market data sources (e.g., Economic Intelligence Unit) and extrapolates the market information if an input assumption is not observable for the entire forecast period. Many of these input assumptions are dependent on other economic assumptions, which are often derived from statistical economic models with inherent limitations such as estimation differences. Further, several input assumptions are based on historical trends which often do not recur. The input assumptions most significant to our budgets and cash flows are based on expectations of macroeconomic factors which have been volatile recently. It is not uncommon that different market data sources have different views of the macroeconomic factors expectations and related assumptions. As a result, macroeconomic factors and related assumptions are often available in a narrow range; however, in some situations these ranges become wide and the use of a different set of input assumptions could produce significantly different budgets and cash flow forecasts.

A considerable amount of judgment is also applied in the estimation of the discount rate used in the DCF model. To the extent practical, inputs to the discount rate are obtained from market data sources (e.g., Bloomberg, Capital IQ, etc.). The Company selects and uses a set of publicly traded companies from the relevant industry to estimate the discount rate inputs.

Management applies judgment in the selection of such companies based on its view of the most likely market participants. It is reasonably possible that the selection of a different set of likely market participants could produce different input assumptions and result in the use of a different discount rate.

Fair value of a reporting unit or a long-lived asset (asset group) is sensitive to both input assumptions to our budgets and cash flow forecasts and the discount rate. Further, estimates of long-term growth and terminal value are often critical to the fair value determination. As part of the impairment evaluation process, management analyzes the sensitivity of fair value to various underlying assumptions. The level of scrutiny increases as the gap between fair value and carrying amount decreases. Changes in any of these assumptions could result in management reaching a different conclusion regarding the potential impairment, which could be material. Our impairment evaluations inherently involve uncertainties from uncontrollable events that could positively or negatively impact the anticipated future economic and operating conditions.

Further discussion of the impairment charges recognized by the Company can be found within Note 10—Goodwill and Other Intangible Assets, Note 21—Asset Impairment Expense and Note 9—Other Non-Operating Expense to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

Fair Value

Fair Value Hierarchy

The Company uses valuation techniques and methodologies that maximize the use of observable inputs and minimize the use of unobservable inputs. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices are not available, valuation models are applied to estimate the fair value using the available observable inputs. The valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

To increase consistency and enhance disclosure of the fair value of financial instruments, the fair value measurement standard includes a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. For more information regarding the fair value hierarchy, see Note 1—General and Summary of Significant Accounting Policies included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.

Fair Value of Financial Instruments

A significant number of the Company’s financial instruments are carried at fair value with changes in fair value recognized in earnings or other comprehensive income each period. The Company makes estimates regarding the valuation of assets and liabilities measured at fair value in preparing the Consolidated Financial Statements. These assets and liabilities include short and long-term investments in debt and equity securities, included in the balance sheet line items “Short-term investments” and “Other assets (Noncurrent)”, derivative assets, included in “Other current assets” and “Other assets (Noncurrent)” and derivative liabilities, included in “Accrued and other liabilities (current)” and “Other long-term liabilities”. Investments are generally fair valued based on quoted market prices or other observable market data such as interest rate indices. The Company’s investments are primarily certificates of deposit, government debt securities and money market funds. Derivatives are valued using observable data as inputs into internal valuation models. The Company’s derivatives primarily consist of interest rate swaps, foreign currency instruments, and commodity and embedded derivatives. Additional discussion regarding the nature of these financial instruments and valuation techniques can be found in Note 4—Fair Value included in Item 8. – Financial Statements and Supplementary Data of this Form 10-K.

Fair Value of Nonfinancial Assets and Liabilities

Significant estimates are made in determining the fair value of long-lived tangible and intangible assets (i.e., property, plant and equipment, intangible assets and goodwill) during the impairment evaluation process. In addition, the majority of assets acquired and liabilities assumed in a business combination are required to be recognized at fair value under the relevant accounting guidance. In determining the fair value of these items, management makes several assumptions discussed in the Impairments section.

Accounting for Derivative Instruments and Hedging Activities

We enter into various derivative transactions in order to hedge our exposure to certain market risks. We primarily use derivative instruments to manage our interest rate, commodity and foreign currency exposures. We do not enter into derivative transactions for trading purposes.

In accordance with the accounting standards for derivatives and hedging, we recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value except where derivatives qualify and are designated as “normal purchase/normal sale” transactions. Changes in fair value of derivatives are recognized in earnings unless specific

hedge criteria are met. Income and expense related to derivative instruments are recognized in the same category as that generated by the underlying asset or liability. See Note 6—Derivative Instruments and Hedging Activities included in Item 8 of this Form 10-K for further information on the classification.

The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective and is designated and qualifies as a fair value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. The Company has no fair value hedges at this time. Changes in the fair value of a derivative that is highly effective and is designated as and qualifies as a cash flow hedge, are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. For all hedge contracts, the Company provides formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging.

The fair value measurement accounting standard provides additional guidance on the definition of fair value and defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. The fair value measurement standard requires the Company to consider and reflect the assumptions of market participants in the fair value calculation. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk, both of the reporting entity (for liabilities) and of the counterparty (for assets). Due to the nature of the Company’s interest rate swaps, which are typically associated with non-recourse debt, credit risk for AES is evaluated at the subsidiary level rather than at the Parent Company level. Nonperformance risk on the Company’s derivative instruments is an adjustment to the initial asset/liability fair value position that is derived from internally developed valuation models that utilize observable market inputs.

As a result of uncertainty, complexity and judgment, accounting estimates related to derivative accounting could result in material changes to our financial statements under different conditions or utilizing different assumptions. As a part of accounting for these derivatives, we make estimates concerning nonperformance, volatilities, market liquidity, future commodity prices, interest rates, credit ratings (both ours and our counterparty’s) and exchange rates.

The fair value of our derivative portfolio is generally determined using internal valuation models, most of which are based on observable market inputs including interest rate curves and forward and spot prices for currencies and commodities. The Company derives most of its financial instrument market assumptions from market efficient data sources (e.g., Bloomberg, Reuters and Platt’s). In some cases, where market data is not readily available, management uses comparable market sources and empirical evidence to derive market assumptions to determine a financial instrument’s fair value. In certain instances, the published curve may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve. Additionally, in the absence of quoted prices, we may rely on “indicative pricing” quotes from financial institutions to input into our valuation model for certain of our foreign currency swaps. These indicative pricing quotes do not constitute either a bid or ask price and therefore are not considered observable market data. For individual contracts, the use of different valuation models or assumptions could have a material effect on the calculated fair value.

Regulatory Assets and Liabilities

Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, any asset write-offs would be required to be recognized in operating income.

Consolidation

The Company has recently entered into several transactions whereby the Company sells an interest in its controlled subsidiaries and/or equity method investments. In connection with each transaction, the Company must determine whether the sale of the interest impacts the Company’s consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, the Company is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights.

If the entity is determined to be a variable interest entity, the most significant judgment in determining whether the Company must consolidate the entity is whether the subsidiary, including its related parties and de facto agents, collectively have power and benefits. If AES is determined to have power and benefits, the entity will be consolidated by AES.

Alternatively, if the entity is determined to be a voting model entity, the most significant judgments involve determining whether the non-AES shareholders have substantive participating rights. The assessment of shareholder rights and whether they are substantive participating rights requires significant judgment since the rights provided under shareholders’ agreements may

include selecting, terminating, and setting the compensation of management responsible for implementing the subsidiary’s policies and procedures, establishing operating and capital decisions of the entity, including budgets, in the ordinary course of business. On the other hand, if shareholder rights are only protective in nature (referred to as protective rights) then such rights would not overcome the presumption that the owner of a majority voting interest shall consolidate its investee. Significant judgment is required to determine whether minority rights represent substantive participating rights or protective rights that do not affect the evaluation of control. While both represent an approval or veto right, a distinguishing factor is the underlying activity or action to which the right relates.

New Accounting Pronouncements

The Company did not adopt any new accounting pronouncements during the year that had a material impact on the Company's financial position or results of operations. See Note 1—General and Summary of Significant Accounting Policies included in Item 8 of this Form 10-K for further information about accounting pronouncements issued but not yet effective.

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