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•	the economic climate, particularly the state of the economy in the areas in which we operate, including the fact that the global economy faces considerable uncertainty for the foreseeable future, which further increases many of the risks discussed in this Form 10-K;

•	changes in inflation, demand for power, interest rates and foreign currency exchange rates, including our ability to hedge our interest rate and foreign currency risk;

•	changes in the price of electricity at which our generation businesses sell into the wholesale market and our utility businesses purchase to distribute to their customers, and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk;

•	changes in the prices and availability of coal, gas and other fuels (including our ability to have fuel transported to our facilities) and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk, and our ability to meet credit support requirements for fuel and power supply contracts;

•	changes in and access to the financial markets, particularly changes affecting the availability and cost of capital in order to refinance existing debt and finance capital expenditures, acquisitions, investments and other corporate purposes;

•	our ability to manage liquidity and comply with covenants under our recourse and non-recourse debt, including our ability to manage our significant liquidity needs and to comply with covenants under our senior secured credit facility and other existing financing obligations;

•	changes in our or any of our subsidiaries' corporate credit ratings or the ratings of our or any of our subsidiaries' debt securities or preferred stock, and changes in the rating agencies' ratings criteria;

•	our ability to purchase and sell assets at attractive prices and on other attractive terms;

•	our ability to compete in markets where we do business;

•	our ability to manage our operational and maintenance costs, the performance and reliability of our generating plants, including our ability to reduce unscheduled down times;

•	our ability to locate and acquire attractive "greenfield" or "brownfield" projects and our ability to finance, construct and begin operating our "greenfield" or "brownfield" projects on schedule and within budget;

•	our ability to enter into long-term contracts, which limit volatility in our results of operations and cash flow, such as PPAs, fuel supply, and other agreements and to manage counterparty credit risks in these agreements;

•	variations in weather, especially mild winters and cooler summers in the areas in which we operate, the occurrence of difficult hydrological conditions for our hydropower plants, as well as hurricanes and other storms and disasters, and low levels of wind or sunlight for our wind and solar facilities;

•	our ability to meet our expectations in the development, construction, operation and performance of our new facilities, whether greenfield, brownfield or investments in the expansion of existing facilities;

•	the success of our initiatives in other renewable energy projects, as well as GHG emissions reduction projects and energy storage projects;

•	our ability to keep up with advances in technology;

•	the potential effects of threatened or actual acts of terrorism and war;

•	the expropriation or nationalization of our businesses or assets by foreign governments, with or without adequate compensation;

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•	our ability to achieve reasonable rate treatment in our utility businesses;

•	changes in laws, rules and regulations affecting our international businesses;

•	changes in laws, rules and regulations affecting our North America business, including, but not limited to, regulations which may affect competition, the ability to recover net utility assets and other potential stranded costs by our utilities;

•	changes in law resulting from new local, state, federal or international energy legislation and changes in political or regulatory oversight or incentives affecting our wind business and solar projects, our other renewables projects and our initiatives in GHG reductions and energy storage, including tax incentives;

•	changes in environmental laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, mercury, hazardous air pollutants and other substances, GHG legislation, regulation and/or treaties and coal ash regulation;

•	changes in tax laws and the effects of our strategies to reduce tax payments;

•	the effects of litigation and government and regulatory investigations;

•	our ability to maintain adequate insurance;

•	decreases in the value of pension plan assets, increases in pension plan expenses and our ability to fund defined benefit pension and other postretirement plans at our subsidiaries;

•	losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets;

•	changes in accounting standards, corporate governance and securities law requirements;

•	our ability to maintain effective internal controls over financial reporting;

•	our ability to attract and retain talented directors, management and other personnel, including, but not limited to, financial personnel in our foreign businesses that have extensive knowledge of accounting principles generally accepted in the United States; and

•	information security breaches.

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(1)	Investments in subsidiaries excludes $2.2 billion investment in DPL.

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(1)	AES owns these assets together with third-party tax equity investors with variable ownership interests. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes, that vary over the life of the projects. The proceeds from the issuance of tax equity are recorded as noncontrolling interest in the Company's Consolidated Balance Sheets.

(2)	Power Purchase Agreement with Direct Energy is for 80% of annual expected energy output.

(3)	AES operates these facilities located throughout the U.S. through management or O&M agreements as of December 31, 2016.

(1)

DPL subsidiary DP&L has the following plants: Tait Units 1-3 and diesels, Yankee Street, Yankee Solar, Monument and Sidney. DP&L jointly owned plants: Conesville Unit 4, Killen, Miami Fort Units 7 & 8, Stuart and Zimmer. In addition to the above, DP&L also owns a 4.9% equity ownership in OVEC ("Ohio Valley Electric Corporation"), an electric generating company. OVEC has two plants in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of

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(2)	CDPQ owns direct and indirect interests in IPALCO which total 30%. AES owns 85% of AES US Investments and AES US Investments owns 82.35% of IPALCO. IPL plants: Georgetown, Harding Street, Petersburg and Eagle Valley (new CCGT currently under construction). 3.2 MW of IPL total is considered a transmission asset.

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•	rate case outcomes

•	the timely recovery of capital expenditures through base rate growth

•	the passage of new legislation or implementation of regulations

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•	The establishment of a five-year Distribution Modernization Rider designed to collect $90 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure;

•	The establishment of a Distribution Investment Rider for distribution investments, with one component designed to collect $35 million in revenue per year to enable the implementation of smart grid and advanced metering, ending after the fifth year of the term of the ESP,

•	A commitment by the Company to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC);

•	A commitments to commence the sale process of our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants and;

•	A commitment to develop or procure wind and/or solar energy projects in Ohio,

•	Restrictions on DPL making dividend or tax sharing payments, various other riders, and competitive retail market enhancements.

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•	PJM capacity prices

•	Outcome of DP&L's pending ESP 3 case, including the amount of non-bypassable revenue

•	Outcome of DP&L's pending distribution rate case

•	Operational performance of generation facilities

•	Recovery in the power market, particularly as it relates to an expansion in dark spreads

•	Sale or transfer to a DPL affiliate of DP&L generation assets

•	DPL's ability to reduce its cost structure

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•	AES Hawaii — AES Hawaii receives a fuel payment from its offtaker under a PPA expiring in 2022, which is based on a fixed rate indexed to the Gross National Product - Implicit Price Deflator. Since the fuel payment is not directly linked to market prices for fuel, the risk arising from fluctuations in market prices for coal is borne by AES Hawaii.

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U.S. Wind — AES has 736 MW of wind capacity in the U.S., located in California, Texas and West Virginia. Typically, these facilities sell under long-term PPAs. AES financed most of these projects with tax equity structures. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in a net loss to AES consolidated results in periods in which the facilities report net income. These non cash net losses will be expected to reverse during the life of the facilities. Some of the wind projects are exposed to the volatility of energy prices and their revenue may change materially as energy prices fluctuate in their respective markets of operations.

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AES Distributed Energy — AES has 103 MW of solar capacity in the U.S., located across multiple states. Distributed Energy's Commercial and Utility division, which comprised 89 MW of solar capacity as of December 31, 2016, sells electricity generated by photovoltaic solar energy systems to public sector, utility, and non-profit entities through power purchase agreements. AES has added 33 MW of commercial and utility capacity in 2016. A majority of this new capacity has been financed with tax equity structures. Under these tax equity structures, the tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in a net loss to AES consolidated results in periods in which the facilities report net income. These non cash net losses will be expected to reverse during the life of the facilities.

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(1)	Guacolda plants: Guacolda 1, 2, 3, 4, and 5. Unconsolidated entities for which the results of operations are reflected in Equity in Earnings of Affiliates. The Company's ownership in Guacolda is held through AES Gener, a 67%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 33%.

(2)	Electrica Santiago plants: Nueva Renca, Renca, Los Vientos and Santa Lidia.

(3)	Gener — SIC plants: Alfalfal, Laguna Verde, Laguna Verde Turbogas, Laja, Maitenes, Queltehues, Ventanas 1, Ventanas 2 and Volcán.

(4)	Gener — SING plants: Norgener 1 and Norgener 2.

(5)	Electrica Ventanas plant: Ventanas 3.

(6)	Electrica Campiche plant: Ventanas 4.

(7)	TermoAndes is located in Argentina, but is connected to both the SING in Chile and the SADI in Argentina.

(8)	AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses.

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•	Dry hydrology scenarios reduce hydro generation

•	Forced outages may impact earnings

•	Changes in current regulatory rulings could alter the ability to pass through or recover certain costs

•	AES is exposed to the fluctuation of the Chilean peso, which may pose a risk to earnings; our hedging strategy reduces this risk, but some residual risk to earnings remains

•	Tax policy changes

•	Current legislation is trending towards promoting renewable energy and strengthening regulations on thermal generation assets, posing a risk to future coal margins

•	Market price risk when re-contracting

•	Cochrane project began operations (Unit 2 on October 12 and Unit 1 on July 9) adding 532 MW to the SING.

•	Cochrane Energy Storage began operations in October 2016 adding 20 MW of batteries contributing to system stability in the SING.

•	Andes Solar with 21 MW began operations in May 2016

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•	Adjustments to the scarcity price so that it reflects a true value of thermal plants that operate in periods of crisis.

•	A plan to implement an option to assign firm energy obligations without the need for reliability auctions but with obligation of signing energy contracts with non-regulated demand.

•	Possible participation of renewable plants in the market and its effect in the formation of prices and operation of the market.

•	The implementation of the standardized contract market, and

•	The possibility of entering into the intraday markets and markets of the previous day are still being considered.

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•	Forced outages may impact earnings

•	AES is exposed to fluctuation of the Colombian peso, which pose a risk to earnings; our hedging strategy reduces this risk, but some residual risk to earnings remains

•	Chivor has exposure to the spot market as hedge levels are lower in the future

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•	Timely collection of FONINVEMEM installment and outstanding receivables (See Note 7—Financing Receivables in Item 8.—Financial Statements and Supplementary Data for further discussion)

(1)	Tietê plants with installed capacity: Água Vermelha (1,396 MW), Bariri (143 MW), Barra Bonita (141 MW), Caconde (80 MW), Euclides da Cunha (109 MW), Ibitinga (132 MW), Limoeiro (32 MW), Mogi-Guaçu (7 MW), Nova Avanhandava (347 MW), Promissão (264 MW), Sao Joaquim (3 MW) and Sao Jose (4 MW).

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•	Hydrology, impacting quantity of energy sold and energy purchased

•	Brazilian economic scenario and tariff increases, impacting energy consumption growth, losses and delinquency

•	Quality indicators recovery plan

•	Ability of Eletropaulo to pass through costs via productivity gains

•	Ability of Eletropaulo to solve involuntary exposure

•	Capital structure optimization to reduce leverage and interest costs

•	The CTEEP Eletrobrás case (see Item 3.—Legal Proceedings for further information)

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•	Hydrology, impacting quantity of energy generated in MRE

•	Demand growth

•	Re-contracting price

•	Asset management and plant availability

•	Cost management

•	Ability to execute on its growth strategy

(1)	Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine).

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•	Changes in spot prices due to fluctuations in commodity prices, (since fuel is a pass-through cost under the PPAs, any variation in oil prices will impact the spot sales for both Andres and Itabo)

•	Contracting levels and the extent of capacity awarded

•	Supply shortages in the near term (next two to three years) may provide opportunities for short term upside, but new generation is expected to come online beginning 2018

•	Additional sales derived from domestic natural gas demand are expected to continue providing income and growth based on the entry of future projects and the fees from the infrastructure service.

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•	In the event of low hydrology, high commodity prices will increase the business exposure and the cost of replacement power to fulfill our contractual commitments, partially mitigated by additional generation from Estrella del Mar I.

•	Fluctuations in commodity prices, mainly oil prices, affect the thermal generation cost impacting the spot prices and the opportunity cost of water.

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•	Constraints imposed by the capacity of the transmission line connecting the west side of the country with the load center are expected to continue until the end of 2017 keeping surplus power trapped, particularly during the wet season.

•	Country demand as GDP growth is expected to remain strong over the short and medium term.

•	The energy market liberalization in January 2016 through the implementation of: wholesale electricity market (day ahead and real time market), ancillary services, capacity, Clean Energy Certificates, and Financial Transmission Rights market.

•	CFE's, former state-owned electric monopoly, vertical and horizontal disintegration into different segments of the value chain: generation, transmission, distribution and commercialization.

•	CENACE as new ISO is responsible for managing the wholesale electricity market, transmission and distribution infrastructure, planning the network developments, guaranteeing open access to network infrastructure, executing competitive mechanisms to cover regulated demand, and setting transmission charges.

•	Implementation of annual mid and long term auctions to secure supply for the regulated demand, establishing a PPA with CFE as the Basic Supplier.

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•	Operational performance (as the companies are fully contracted and better performance provides additional financial benefits including performance incentives and/or excess energy sales (in the case of TEG/TEP).

•	The energy prices of TEG/TEP for the sales in excess over its long-term contracts are driven by the average production cost of CFE which is highly dependent on natural gas and oil.

•	If the average production cost of CFE is higher than the cost of generating with pet coke, our businesses in Mexico will benefit provided that they are able to sell energy in excess of their PPAs.

(1)	AES operates these facilities under concession agreements until 2017.

(2)	Unconsolidated entity, the results of operations of which are reflected in Equity in Earnings of Affiliates.

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(3)	Includes Kilroot Open Cycle Gas Turbine ("OCGT").

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•	the availability of the operating units

•	the level of wind resource for St. Nikola

•	NEK's ability to meet the terms of the PPA contract

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•	Regulatory changes to the market structure and payment mechanism

•	Availability of the operating units

•	Commodity prices (gas, coal and CO2) and sufficient market liquidity to hedge prices in the short-term

•	Electricity demand in the SEM (including impact of wind generation)

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•	Availability of the operating units;

•	Regulated electricity tariff-cap levels and heat tariff levels

•	Weather conditions,

•	Regulatory changes to the market structure and payment mechanism

•	Cost of coal and Kazakhstan currency exchange rate fluctuation.

(1)	Unconsolidated entity for which the results of operations are reflected in Equity in Earnings of Affiliates.

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•	Operating performance of the facility

•	Regulatory and environmental policy changes

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•	Operating performance of the facility

•	Demand from contracted customers

•	Whole sale electricity price in the market

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•	January 1, 2015: Phase 1 (2015 and 2016) began for annual trading programs. Existing units must have begun monitoring and reporting SO2 and NOx emissions.

•	May 1, 2015: Phase 1 began for ozone-season NOx trading program. Existing units must have begun monitoring and reporting NOx emissions.

•	December 1, 2015 (and each Dec. 1 thereafter): Date by which sources must demonstrate compliance with ozone-season NOx trading program (i.e., allowance transfer deadline).

•	March 1, 2016 (and each March 1 thereafter): Date by which sources must demonstrate compliance with annual trading programs (i.e., allowance transfer deadline).

•	January 1, 2017: Phase 2 (2017 and beyond) begins for annual trading programs. Assurance provisions in effect.

•	May 1, 2017: Phase 2 (2017 and beyond) begins for ozone-season NOx trading program. Assurance provisions in effect.

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•	whether and how the states in which the Company's U.S. businesses operate respond to the CPP;

•	whether the states adopt an emissions trading regime and, if so, which trading regime;

•	how other states respond to the CPP, which will affect the size and robustness of any emissions trading market; and

•	how other companies may respond in the face of increased carbon costs.

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•	risks related to our high level of indebtedness;

•	risks associated with our ability to raise needed capital;

•	external risks associated with revenue and earnings volatility;

•	risks associated with our operations; and

•	risks associated with governmental regulation and laws.

•	making it more difficult to satisfy debt service and other obligations at the holding company and/or individual subsidiaries;

•	increasing the likelihood of a downgrade of our debt, which could cause future debt costs and/or payments to increase under our debt and related hedging instruments and consume an even greater portion of cash flow;

•	increasing our vulnerability to general adverse industry and economic conditions, including but not limited to adverse changes in foreign exchange rates and commodity prices;

•	reducing the availability of cash flow to fund other corporate purposes and grow our business;

•	limiting our flexibility in planning for, or reacting to, changes in our business and the industry;

•	placing us at a competitive disadvantage to our competitors that are not as highly leveraged; and

•	limiting, along with the financial and other restrictive covenants relating to such indebtedness, among other things, our ability to borrow additional funds as needed or take advantage of business opportunities as they arise, pay cash dividends or repurchase common stock.

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•	reducing The AES Corporation's receipt of subsidiary dividends, fees, interest payments, loans and other sources of cash since the project subsidiary will typically be prohibited from distributing cash to The AES Corporation during the pendency of any default;

•	under certain circumstances, triggering The AES Corporation's obligation to make payments under any financial guarantee, letter of credit or other credit support which The AES Corporation has provided to or on behalf of such subsidiary;

•	causing The AES Corporation to record a loss in the event the lender forecloses on the assets;

•

triggering defaults in The AES Corporation's outstanding debt and trust preferred securities. For example, The AES Corporation's senior secured credit facility and outstanding senior notes include events of default for certain bankruptcy related events involving material subsidiaries. In addition, The AES Corporation's senior secured credit facility includes certain events of default relating to accelerations of outstanding material debt of material subsidiaries or any subsidiaries that in the aggregate constitute a material subsidiary;

•	the loss or impairment of investor confidence in the Company; or

•	foreclosure on the assets that are pledged under the non-recourse loans, therefore eliminating any and all potential future benefits derived from those assets.

•	principal repayments of debt;

•	interest and preferred dividends;

•	acquisitions;

•	construction and other project commitments;

•	other equity commitments, including business development investments;

•	equity repurchases and/or cash dividends on our common stock;

•	taxes; and

•	Parent Company overhead costs.

•	dividends and other distributions from its subsidiaries;

•	proceeds from debt and equity financings at the Parent Company level; and

•	proceeds from asset sales.

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•	general economic and capital market conditions;

•	the availability of bank credit;

•	investor confidence;

•	the financial condition, performance and prospects of The AES Corporation in general and/or that of any subsidiary requiring the financing as well as companies in our industry or similar financial circumstances; and

•	changes in tax and securities laws which are conducive to raising capital.

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•	plant availability in the markets generally;

•	availability and effectiveness of transmission facilities owned and operated by third parties;

•	competition;

•	electricity usage;

•	seasonality;

•	foreign exchange rate fluctuation;

•	availability and price of emission credits;

•	hydrology and other weather conditions;

•	illiquid markets;

•	transmission or transportation constraints or inefficiencies;

•	availability of competitively priced renewables sources;

•	increased adoption of distributed generation;

•	available supplies of natural gas, crude oil and refined products, and coal;

•	generating unit performance;

•	natural disasters, terrorism, wars, embargoes, and other catastrophic events;

•	energy, market and environmental regulation, legislation and policies;

•	geopolitical concerns affecting global supply of oil and natural gas;

•	general economic conditions in areas where we operate which impact energy consumption; and

•	bidding behavior and market bidding rules.

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•	economic, social and political instability in any particular country or region;

•	adverse changes in currency exchange rates;

•	government restrictions on converting currencies or repatriating funds;

•	unexpected changes in foreign laws and regulations or in trade, monetary or fiscal policies;

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•	high inflation and monetary fluctuations;

•	restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;

•	threatened or consummated expropriation or nationalization of our assets by foreign governments;

•	risks relating to the failure to comply with the U.S. Foreign Corrupt Practices Act, United Kingdom Bribery Act or other anti-bribery laws applicable to our operations;

•	difficulties in hiring, training and retaining qualified personnel, particularly finance and accounting personnel with GAAP expertise;

•	unwillingness of governments and their agencies, similar organizations or other counterparties to honor their contracts;

•	unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and economically unfavorable to counterparties, against such counterparties, whether such counterparties are governments or private parties;

•	inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;

•	adverse changes in government tax policy;

•	difficulties in enforcing our contractual rights or enforcing judgments or obtaining a favorable result in local jurisdictions; and

•	potentially adverse tax consequences of operating in multiple jurisdictions.

•

changes in the availability of our generation facilities or distribution systems due to increases in scheduled and unscheduled plant outages, equipment failure, failure of transmission systems, labor disputes, disruptions in fuel supply, poor hydrologic and wind conditions, inability to comply with regulatory or permit requirements or catastrophic events such as fires, floods, storms, hurricanes, earthquakes, dam failures, explosions, terrorist acts, cyber attacks or other similar occurrences; and

•	changes in our operating cost structure including, but not limited to, increases in costs relating to gas, coal, oil and other fuel; fuel transportation; purchased electricity; operations, maintenance and repair; environmental compliance, including the cost of purchasing emissions offsets and capital expenditures to install environmental emission equipment; transmission access; and insurance.

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•	we will be successful in transitioning them to private ownership;

•	such businesses will perform as expected;

•	integration or other one-time costs will not be greater than expected;

•	we will not incur unforeseen obligations or liabilities;

•	such businesses will generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them; or

•	the rate of return from such businesses will justify our decision to invest capital to acquire them.

•	changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs to be included in the rates we charge our customers, including but not limited to costs incurred to upgrade our power plants to comply with more stringent environmental regulations;

•	changes in the determination of what is an appropriate rate of return on invested capital or a determination that a utility's operating income or the rates it charges customers are too high, resulting in a reduction of rates or consumer rebates;

•	changes in the definition or determination of controllable or non-controllable costs;

•	adverse changes in tax law;

•	changes in law or regulation which limit or otherwise affect the ability of our counterparties (including sovereign or private parties) to fulfill their obligations (including payment obligations) to us or our subsidiaries;

•	changes in environmental law which impose additional costs or limit the dispatch of our generating facilities within our subsidiaries;

•	changes in the definition of events which may or may not qualify as changes in economic equilibrium;

•	changes in the timing of tariff increases;

•	other changes in the regulatory determinations under the relevant concessions;

•	other changes related to licensing or permitting which affect our ability to conduct business; or

•	other changes that impact the short or long term price-setting mechanism in the markets where we operate.

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(1)

Includes pretax impairment expense of $1.1 billion, $602 million, $383 million, $596 million, and $1.9 billion for the years ended December 31, 2016, 2015, 2014, 2013 and 2012, respectively. See Note 8—Other Non-Operating Expense, Note 9—Goodwill and Other Intangible Assets and Note 20—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

•	Executive Summary

•	Overview of 2016 Results and Strategic Performance

•	Review of Consolidated Results of Operations

•	SBU Performance Analysis

•	Key Trends and Uncertainties

•	Capital Resources and Liquidity

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(1)	See reconciliation and definition under SBU Performance Analysis—Non-GAAP Measures.

(2)	Disclosure of Proportional Free Cash Flow will be discontinued beginning in the first quarter of 2017. See further discussion under SBU Performance Analysis—Non-GAAP Measures.

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•	Unfavorable FX impacts of $511 million, primarily in Brazil of $213 million, Argentina of $94 million, Kazakhstan of $63 million and Colombia of $54 million.

•	Brazil due to lower rates for energy sold in Brazil under new contracts at Tietê; operations in 2015 but not in 2016 at Uruguiana; the reversal of a contingent regulatory liability in 2015, and lower demand, partially offset by the annual tariff adjustment at Eletropaulo.

•	Lower pass-through costs at El Salvador and IPP4 in Jordan, the sale of DPLER in January 2016, and lower rates at DPL.

•	The full operations at Mong Duong in 2016 compared to Unit 1 in March 2015 with principal operations commencing in April 2015

•	The commencement of operations at Cochrane in Chile with Unit 1 operational in July 2016 and principal operations in October).

•	Higher environmental returns and new rate case at IPL.

•	Unfavorable FX impacts of $80 million, primarily in Kazakhstan, Argentina, and Colombia.

•	Brazil driven by the revenue drivers above as well as higher fixed costs at Eletropaulo.

•	Higher margin at Gener, impact from full operations at Mong Duong in Vietnam and Cochrane in Chile, and higher margins at IPL as discussed above.

•	Unfavorable FX impacts of $2.2 billion, mainly in Brazil of $1.8 billion, Colombia of $179 million, and Bulgaria of $74 million.

•	US Utilities due to lower volumes primarily at DPL and outages, milder weather, and lower demand at IPL.

•	Lower prices in the Dominican Republic and El Salvador (primarily resulting from lower pass-through costs).

•	Brazil due to higher tariffs at Eletropaulo (including higher pass-through costs) and the reversal of a contingent regulatory liability at Eletropaulo.

•	Higher capacity prices at DPL.

•	Commencement of principal operations at Mong Duong in April 2015.

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•	Unfavorable FX impacts of $362 million, primarily in Brazil of $228 million and Colombia of $83 million.

•	Brazil due to lower demand, lower hydrology, and higher fixed costs.

•	The Dominican Republic due to lower prices and lower availability.

•	Higher tariffs in Brazil as discussed above and lower spot prices on energy purchases at Tietê.

•	Higher generation and lower energy purchases driven by improved hydrological conditions in Panama.

•	Higher prices at Chivor driven by a strong El Niño.

•	Higher availability at Gener and Masinloc.

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(1)	Includes gains of $17 million, $247 million and $172 million on foreign currency derivative contracts for the years ended December 31, 2016, 2015 and 2014, respectively.

•	$124 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 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,

•	$29 million in Colombia, mainly due to the depreciation of the Colombian Peso, positively impacting Chivor (a U.S. Dollar functional currency subsidiary) due to liabilities denominated in Colombian Pesos,

•	$11 million in the United Kingdom, mainly due to the 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

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•	$31 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, and

•	$18 million in Chile primarily due to the devaluation of the Chilean Peso at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos, partially offset by gains on foreign currency derivatives.

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$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 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, mainly 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, mainly 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, mainly 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.

•	$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).

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•	a decrease at Tietê due to lower earnings

•	a decrease at Eletropaulo resulting from the the reversal of a contingent regulatory liability in 2015, and

•	asset impairments at Buffalo Gap I and II;

•	a lower asset impairment at Buffalo Gap III in 2015, and

•	income tax benefits at Eletropaulo.

•	an increase at Mong Duong due to commencement of operations in 2015,

•	an increase at Gener primarily due to the restructuring of Guacolda,

•	an increase at Masinloc due to increased earnings in 2015 and the 2014 sale of a noncontrolling interest in that business

•	a decrease at Buffalo Gap III resulting from the asset impairment expense allocation to the tax equity partner, and

•	a decrease at Eletropaulo resulting from unfavorable foreign exchange and lower demand.

•	impairments and loss on sale at discontinued businesses;

•	higher impairment expense on long lived assets;

•	lower operating margins at our US, Brazil and Europe SBUs;

•	lower equity in earnings of affiliates due to the 2015 restructuring at Guacolda; and

•	lower gains on foreign currency derivatives.

•	lower effective tax rate;

•	lower debt extinguishment expense; and

•	absence of goodwill impairment expense.

•	Higher impairment expense

•	Lower gains from the sale of businesses

•	Lower debt extinguishment expense

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(1)	Amount primarily relates to the loss on deconsolidation of UK Wind of $20 million, or $0.03 per share and losses associated with the sale of Sul of $10 million, or $0.02; partially offset by the gain on sale of DPLER of $22 million, or $0.03 per share.

(2)	Amount primarily relates to the gains on the sale of Armenia Mountain of $22 million, or $0.03 per share and from the sale of Solar Spain and Solar Italy of $7 million, or $0.01 per share.

(3)	Amount primarily relates to the gain on the sale of a noncontrolling interest in Masinloc of $283 million, or $0.39 per share; and the gain from the sale of the U.K. wind projects of $78 million, or $0.11 per share.

(4)	Amount primarily relates to asset impairments at DPL of $859 million, or $1.30 per share; $159 million at Buffalo Gap II ($49 million, or $0.07 per share, net of NCI); and $77 million at Buffalo Gap I ($23 million, or $0.03 per share, net of NCI).

(5)	Amount primarily relates to the goodwill impairment at DPL of $317 million, or $0.46 per share, and asset impairments at Kilroot of $121 million ($119 million, or $0.17 per share, net of NCI), at Buffalo Gap III of $116 million ($27 million, or $0.04 per share, net of NCI), and at U.K. Wind (Development Projects) of $38 million ($30 million, or $0.04 per share, net of NCI).

(6)

Amount primarily relates to the goodwill impairments at DPLER of $136 million, or $0.19 per share, and at Buffalo Gap I & II of $28 million, or $0.04 per share; and asset impairments at Ebute of $67 million ($64 million, or $0.09 per share, net of NCI), at Elsta of $41 million, or $0.06 per share; and the other-than-temporary impairments at Entek of $86 million, $0.12 per share and at Silver Ridge Power of $42 million, or $0.06 per share.

(7)	Amount primarily relates to the loss on early retirement of debt at the Parent Company of $19 million, or $0.03 per share.

(8)	Amount primarily relates to the loss on early retirement of debt at the Parent Company of $116 million, or $0.17 per share and at IPL of $22 million ($17 million, or $0.02 per share, net of NCI).

(9)	Amount primarily relates to the loss on early retirement of debt at the Parent Company of $200 million, or $0.28 per share, at DPL of $31 million, or $0.04 per share, at Angamos of $20 million ($14 million, or $0.02 per share, net of NCI) and at U.K. wind projects of $18 million, or $0.02 per share.

(10)	Amount primarily relates to the per share income tax benefit associated with asset impairment of $332 million, or $0.50 per share in the twelve months ended December 31, 2016.

(11)	Amount primarily relates to the per share income tax benefit associated with losses on extinguishment of debt of $55 million, or $0.08 per share in the twelve months ended December 31, 2015.

(12)	Amount primarily relates to the per share income tax benefit associated with losses on extinguishment of debt of $90 million, or $0.12 per share and dispositions/acquisitions of $67 million, or $0.09 per share in the twelve months ended December 31, 2014.

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(1)	Service concession asset expenditures are excluded from the proportional free cash flow non-GAAP metric.

(2)

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 noncontrolling interests for each entity by its corresponding consolidated cash flow metric and are totaled to the resulting figures. For example, Parent Company A owns 20% of Subsidiary Company B, a consolidated subsidiary. Thus, Subsidiary Company B has an 80% noncontrolling interest. Assuming a consolidated net cash flow from operating activities of $100 from Subsidiary B, the proportional adjustment factor for Subsidiary B would equal $80 (or $100 x 80%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then sums these amounts to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to noncontrolling 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.

(3)	Includes proportional adjustment amount for service concession asset expenditures of $15 million and $84 million for the years ended December 31, 2016 and 2015, respectively. The Company adopted service concession accounting effective January 1, 2015.

(4)	Excludes IPL's proportional recoverable environmental capital expenditures of $132 million, $205 million and $163 million for the years ended December 31, 2016, 2015 and 2014, respectively.

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(1)	See Item 1. Business for the respective ownership interest for key business. In addition, AES owns 70% of IPL as of March 2016 compared to 75% beginning April 2015, 85% beginning in February 2015 and 100% prior to February 2015.

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(1)	See Item 1. Business for the respective ownership interest for key business. In addition, AES owned 71% of Gener and Chivor prior to sell down effective December 2015 which resulted in ownership of 67%. The Alto Maipo (under construction) and Cochrane plants are owned 40%.

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(1)	See Item 1. Business for the respective ownership interest for key business.

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(1)	See Item 1. Business for the respective ownership interest for key business. In addition, AES owned 92% of Andres and Los Mina and 46% of Itabo in the Dominican Republic until December 2015 when the ownership changed to 90% at Andres and Los Mina and 45% at Itabo.

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(1)	See Item 1. Business for the respective ownership interest for key business.

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(1)	See Item 1. Business for the respective ownership interest for key business.

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(1)	Refer to the table below for explanations of the variance in operating assets and liabilities.

(2)	Amounts included in the table above include the results of discontinued operations, where applicable.

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(1)	Refer to the tables below for a breakout of capital expenditure by type and by primary business driver.

(1)	Includes both recoverable and non-recoverable environmental capital expenditures. See SBU Performance Analysis for more information.

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(1)	Refer to the tables below for a breakout of capital expenditures by type and by primary business driver.

(1)	Includes both recoverable and non-recoverable environmental capital expenditures. See SBU Performance Analysis for more information.

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(1)	See Note 11—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for more information regarding significant recourse debt transactions.

(1)	See Note 11—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for more information regarding significant recourse debt transactions.

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(1)	Operating cash flow as presented above include the effect of intercompany transactions with other segments except for interest, tax sharing, charges for management fees and transfer pricing.

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(1)	Includes the results of AES Sul, which is excluded from continuing operations in the Condensed Consolidated Statements of Operations but is included within operating cash flow on the Condensed Consolidated Statements of Cash Flows. See Note 22 of Item 8.—Notes to Condensed Consolidated Financial Statements within this Form 10-K for further information.

(1)	Includes the results of AES Sul, which is excluded from continuing operations in the Condensed Consolidated Statements of Operations but is included within operating cash flow on the Condensed Consolidated Statements of Cash Flows. See Note 22 of Item 8.—Notes to Condensed Consolidated Financial Statements within this Form 10-K for further information

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•	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.

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(1)	Includes recourse and non-recourse debt presented on the Consolidated Balance Sheet. These amounts exclude capital lease obligations which are included in the capital lease category.

(2)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 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, 2016.

(3)

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, these amounts do not include: (1) regulatory liabilities (See Note 10—Regulatory Assets and Liabilities), (2) contingencies (See Note 13—Contingencies), (3) pension and other post retirement employee benefit liabilities (see Note 14—Benefit Plans), (4) derivatives and incentive compensation (See Note 5—Derivative Instruments and Hedging Activities) or (5) any taxes (See Note 21—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.

(4)	For further information see the note referenced below in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.

(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.

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•	Level 1 — unadjusted quoted prices in active markets accessible by the Company for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

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Level 2 — pricing inputs other than quoted market prices included in Level 1 which are based on observable market data, that are directly or indirectly observable for substantially the full term of the asset or liability. These include quoted market prices for similar assets or liabilities, quoted market prices for identical or similar assets in markets that are not active, adjusted quoted market prices, inputs from observable data such as interest rate and yield curves, volatilities or default rates observable at commonly quoted intervals or inputs derived from observable market data by correlation or other means.

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Level 3 — pricing inputs that are unobservable from objective sources. Unobservable inputs are only used to the extent observable inputs aren't available. These inputs maintain the concept of an exit price from the perspective of a market participant and reflect assumptions of other market participants. The Company considers all market participant assumptions that are available without unreasonable cost and effort. These are given the lowest priority and are generally used in internally developed methodologies to generate management's best estimate of the fair value when no observable market data is available.

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(1)	Represents the carrying values at the dates of measurement, before fair value adjustment.

(2)	See Note 20—Asset Impairment Expense for further information.

(3)	Per the Company's policy, pre-tax loss was limited to the impairment of long-lived assets. Upon disposal of AES Sul, we incurred an additional pre-tax loss on sale of $602 million. See Note 22—Discontinued Operations for further information.

(4)	See Note 7—Investments In and Advances to Affiliates for further information.

(5)	See Note 9—Goodwill and Other Intangible Assets for further information.

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(1)	See Note 20—Asset Impairment Expense for further discussion of each DPL impairment.

(1)	These accounts receivable principally relate to amounts due from CAMMESA, the administrator of the wholesale electricity market in Argentina, and are included in Other noncurrent assets in the accompanying Consolidated Balance Sheets. The fair value and carrying amount of these receivables exclude VAT of $24 million and $27 million as of December 31, 2016 and 2015, respectively.

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(1)	Based on the credit rating of certain subsidiaries

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(1)	Represent VIEs in which the Company holds a variable interest but is not the primary beneficiary.

(2)	The Company's ownership in Guacolda is held through AES Gener, a 67%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 33%.

(3)	OPGC has one coal-fired project under development which is an expansion of our existing OPGC business. The project started construction in April 2014 and is expected to begin operations in 2018.

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(1)	Represent legal rights to receive system reliability payments from the regulator.

(2)	Includes renewable energy credits, organization costs, project development rights, and other individually insignificant intangible assets.

(1)	The carrying value of these definite-lived intangible assets equals their salvage value

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(1)	Past expenditures on which the Company does not earn a rate of return.

•	Unamortized carrying charges, certain environmental costs, and demand charges at IPL and DPL.

•	Unamortized premiums reacquired or redeemed on long term debt at IPL and DPL, which are amortized over the lives of the original issuances.

•	Unrecovered fuel and purchased power costs at IPL and DPL.

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(1)

The interest rate on variable rate debt represents the total of a variable component that is based on changes in an interest rate index and of a fixed component. The Company has interest rate swaps and option agreements in an aggregate notional principal amount of approximately $3.6 billion on non-recourse debt outstanding at December 31, 2016. These agreements economically fix the variable component of the interest rates on the portion of the variable-rate debt being hedged so that the total interest rate on that debt has been fixed at rates ranging from approximately 1.99% to 8.25%. The debt agreements expire at various dates from 2017 through 2073.

(2)	Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.

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(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.

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(1)	$1.2 billion and $686 million of the total net unfunded projected benefit obligation is due to Eletropaulo in Brazil as of December 31, 2016 and 2015, respectively.

(1)	Includes an inflation factor that is used to calculate future periodic benefit cost, but is not used to calculate the benefit obligation.

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•	maintenance of sufficient income and liquidity to pay retirement benefits and other lump sum payments;

•	long-term rate of return in excess of the annualized inflation rate;

•	long-term rate of return, net of relevant fees, that meets or exceeds the assumed actuarial rate; and

•	long-term competitive rate of return on investments, net of expenses, that equals or exceeds various benchmark rates.

(1)	Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.

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(1)	Plan assets of our Brazilian subsidiaries are invested in private equities and commercial real estate through the plan administrator in Brazil. The fair value of these assets is determined using the income approach through annual appraisals based on a discounted cash flow analysis.

(2)	Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.

(3)	Loans to participants are stated at cost, which approximates fair value.

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(1)	See Note 18—Redeemable stock of subsidiaries for further information on increase in paid-in capital transferred to redeemable stock of subsidiaries.

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(1)	Amount represents fair market value on the date of conversion.

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(1)	Amount represents fair market value on the date of conversion.

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(1)	$5 million increase in fair value of DP&L preferred shares offset by $1 million decrease in fair value of Colon common stock.

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(1)	Characteristics of quotas are similar to common stock.

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(1)

During the fourth quarter of 2016, we recognized a full allowance on a non-trade receivable in the MCAC SBU as a result of payment delays and discussions with the counterparty. The allowance relates to certain reimbursements the Company was expecting in connection with a legal matter. Management believes the counterparty is obligated to pay and plans to continue to attempt to fully collect the non-trade receivable.

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(1)	DPLER and Kelanitissa were classified as held-for-sale as of December 31, 2015. See Note 23—Dispositions for further information.

(2)	Amounts were classified as both current and long-term on the Consolidated Balance Sheet as of December 31, 2015.

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(1)	Income from continuing operations, net of tax, of $8 million less the $5 million adjustment to retained earnings to record the DP&L redeemable preferred stock at its redemption value as of December 31, 2016.

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•	economic, social and political instability in any particular country or region;

•	inability to economically hedge energy prices;

•	volatility in commodity prices;

•	adverse changes in currency exchange rates;

•	government restrictions on converting currencies or repatriating funds;

•	unexpected changes in foreign laws, regulatory framework, or in trade, monetary or fiscal policies;

•	high inflation and monetary fluctuations;

•	restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;

•	threatened or consummated expropriation or nationalization of our assets by foreign governments;

•	unwillingness of governments, government agencies, similar organizations or other counterparties to honor their commitments;

•	unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and economically unfavorable to counterparties, against such counterparties, whether such counterparties are governments or private parties;

•	inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;

•	adverse changes in government tax policy;

•	difficulties in enforcing our contractual rights, enforcing judgments, or obtaining a just result in local jurisdictions; and

•	potentially adverse tax consequences of operating in multiple jurisdictions.

•	changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs;

•	changes in the definition or determination of controllable or noncontrollable costs;

•	adverse changes in tax law;

•	changes in the definition of events which may or may not qualify as changes in economic equilibrium;

•	changes in the timing of tariff increases;

•	other changes in the regulatory determinations under the relevant concessions; or

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•	changes in environmental regulations, including regulations relating to GHG emissions in any of our businesses.

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(1)	Includes pretax impairment expense of $159 million, $235 million, $79 million and $625 million, for the first, second, third and fourth quarters of 2016, respectively. See Note 20—Asset Impairment Expense for further discussion.

(2)	Includes pretax impairment expense of $8 million, $37 million, $231 million and $326 million, for the first, second, third and fourth quarters of 2015, respectively. See Note 9—Goodwill and Other Intangible Assets and Note 20—Asset Impairment Expense for further discussion.

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•	pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

•	provide reasonable assurance that unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements are prevented or detected timely.

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•	information regarding the directors required by this item found under the heading Board of Directors;

•	information regarding AES' Code of Ethics found under the heading Additional Governance Matters - AES Code of Business Conduct and Corporate Governance Guidelines;

•	information regarding compliance with Section 16 of the Exchange Act required by this item found under the heading Additional Governance Matters - Other Governance Information - Section 16(a) Beneficial Ownership Reporting Compliance; and

•	information regarding AES' Financial Audit Committee found under the heading Board and Committee Governance Matters - Financial Audit Committee (the “Audit Committee”).

(a)	Security Ownership of Certain Beneficial Owners.

(b)	Security Ownership of Directors and Executive Officers.

(c)	Changes in Control.

(d)	Securities Authorized for Issuance under Equity Compensation Plans.

(1)	The following equity compensation plans have been approved by the Company's Stockholders:

(A)

The AES Corporation 2003 Long Term Compensation Plan was adopted in 2003 and provided for 17,000,000 shares authorized for issuance thereunder. In 2008, an amendment to the Plan to provide an additional 12,000,000 shares was approved by AES' stockholders, bringing the total authorized shares to 29,000,000. In 2010, an additional amendment to the Plan to provide an additional 9,000,000 shares was approved by AES' stockholders, bringing the total authorized shares to 38,000,000. In 2015, an additional amendment to the Plan to provide an additional 7,750,000 shares was approved by AES' stockholders, bringing the total

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(B)

The AES Corporation 2001 Plan for outside directors adopted in 2001 provided for 2,750,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $21.44. In conjunction with the 2010 amendment to the 2003 Long Term Compensation plan, ongoing award issuance from this plan was discontinued in 2010. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 2,078,579 shares is not included in Column (c) above.

(C)

The AES Corporation Second Amended and Restated Deferred Compensation Plan for directors provided for 2,000,000 shares authorized for issuance. Column (b) excludes the Director stock units granted thereunder. In conjunction with the 2010 amendment to the 2003 Long Term Compensation Plan, ongoing award issuance from this plan was discontinued in 2010 as Director stock units will be issued from the 2003 Long Term Compensation Plan. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 105,341 shares is not included in Column (c) above.

(2)	Includes 4,745,968 (of which 427,520 are vested and 4,318,488 are unvested) shares underlying PSU and RSU awards (assuming performance at a maximum level), 1,556,575 shares underlying Director stock unit awards, and 6,328,077 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 12,630,620 shares.

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(a)	Financial Statements.

(b)	Exhibits.

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(c)	Schedules

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