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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;

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

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

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•	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.

(1)	26,912 proportional MW. Proportional MW is equal to gross MW of a generation facility multiplied by AES' equity ownership percentage in such facility.

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Reducing Complexity. By exiting businesses and markets where we do not have a competitive advantage, we have simplified our portfolio and reduced risk. Over the past four years, we have sold assets to generate $3.4 billion in equity proceeds for AES, decreasing the total number of countries where we have operations from 28 to 17. We exited Sri Lanka early in 2016, by selling our generation business, Kelanitissa, for $18 million. We exited several of these markets, including Ukraine, Turkey and Africa, at opportune times, as risks for these businesses have increased since the sales, which we believe would have adversely impacted the valuations of such businesses. In 2015, we announced or closed $787 million in asset sales proceeds.

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Leveraging Our Platforms. We are focusing our growth on platform expansions in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns. We currently have 5,620 MW under construction. These projects represent $7 billion in total capital expenditures, with 85% of AES' $1.2 billion in equity already funded, and we expect the majority of these projects to come on-line through 2018. In 2015, we brought on-line five projects for a total of 1,484 MW. This capacity includes the 1,240 MW coal-fired Mong Duong 2 facility in Vietnam, which we completed six months early and under budget.

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Performance Excellence. We strive to be a low-cost manager of a portfolio of international energy assets and to derive synergies and scale from our businesses. In 2011, we set a goal to reduce our G&A expenses by $200 million by 2015, and in 2014, we achieved these reductions one year early. We recently launched a $150 million cost reduction and revenue enhancement initiative. This initiative will include overhead reductions, procurement efficiencies and operational improvements. We expect to achieve at least $50 million in savings in 2016, ramping up to $150 million, including modest revenue enhancements, in 2018.

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Expanding Access to Capital. We have raised $2.5 billion in proceeds to AES 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 macroeconomic risks. Partial sell-downs of our assets can serve to highlight the value of businesses in our portfolio.

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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. To that end, since September 2011 we have repurchased $1.5 billion of our shares and benefited from a low interest rate environment, by transacting on $24 billion in debt deals at the Parent and our subsidiaries. These debt transactions represent $14 billion in refinancing and $10 billion in new financing, and we extended the maturities on $3.4 billion in Parent debt.

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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 12/31/15.

(1)

In the first quarter of 2015, La Caisse de depot et placement du Quebec ("CDPQ") invested $247 million for a 15% interest in AES US Investments, Inc. (AES US Investments), a subsidiary of AES that owns IPALCO Enterprises, Inc. ("IPALCO"). In the second quarter of 2015, CDPQ invested an additional $214 million and we expect CDPQ to invest an additional $134 million in IPALCO by 2016. After completion of this investment, CDPQ's direct and indirect interests in IPALCO will total 30%, AES will own 85% of AES US Investments, and AES US Investments will own 82.35% of IPALCO.

(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 approximately 2,109 MW. DP&L's share of this generation capacity is approximately 103 MW. DPL Energy, LLC plants: Tait Units 4-7 and Montpelier Units 1-4.

(2)

In the first quarter of 2015, CDPQ invested $247 million for a 15% interest in AES US Investments, Inc. (AES US Investments), a subsidiary of AES that owns IPALCO. In the second quarter of 2015, CDPQ invested an additional $214 million and we expect CDPQ to invest an additional $134 million in IPALCO by 2016. After completion of this investment, CDPQ's direct and indirect interests in IPALCO will total 30%, AES will own 85% of AES US Investments, and AES US Investments will own 82.35% of IPALCO. IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg.

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•	PJM capacity prices auctioned already

•	Non-bypassable revenue: $110 million in 2014 and 2015 and allowed to earn $110 million annually in 2016

•	Operational performance of generation facilities

•	PJM capacity prices

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

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

(3)	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%.

(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 (See Item 7.—Key Trends and Uncertainties— Operational—Weather sensitivity for further discussion)

•	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

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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)

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•	Regulatory changes from new government (See Item 7.—Key Trends and Uncertainties—Macroeconomics— Argentina for further discussion)

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(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 generated

•	Demand growth

•	Re-contracting price

•	Asset management and plant availability

•	Cost management

•	Ability to execute on its growth strategy

•	Arbitration settlement with YPF (see Item 3.—Legal Proceedings)

•	Secure long-term gas solution

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•	Hydrology, impacting quantity of energy sold and energy purchased

•	Brazilian economic growth and tariff increases, impacting energy consumption growth, losses and delinquency (see Item 7.—Key Trends and Uncertainties—Macroeconomics—Brazil for further information)

•	Ability of both Eletropaulo and Sul to pass through costs via productivity gains

•	Capital structure optimization to reduce leverage and interest costs

•	Sul's fourth tariff cycle outcomes in April 2018

•	July 2012 regulatory asset base resolution

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

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

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Spot prices are mainly driven by the fluctuations in commodity prices due to the dependency of the Dominican Republic on oil-based thermal generation. Since the fuel component is a pass-through cost under the PPAs, any variation in the oil prices will mainly impact the spot sales for both Andres and Itabo, which are expected to be net sellers in the upcoming years. Current contracting level for 2016 is close to 90%. Supply shortages in the near term (next 2 to 3 years) may provide opportunities for upside but new generation is expected to come online from 2018.

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

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•	Lower hydrology resulting in low generation and additional energy purchases to fulfill contracts, partially mitigated by additional generation from Estrella del Mar I, lower spot prices driven by the drop in commodities, and the compensation amount from the Government Compensation Agreement.

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In addition to spot prices being driven by hydrology since Panama is highly dependent on hydro generation (~56%), the fluctuations in commodity prices, mainly oil prices, affect the thermal generation cost impacting the spot prices and the opportunity cost of water. In the event of low hydrology, high commodity prices will increase the business exposure and the cost of replacement power to back up our contractual commitment.

•	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 2016 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.

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•	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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(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.

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

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•	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

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•	Availability of the operating units

•	Regulated electricity tariff-cap levels

•	Weather conditions

•	Cost of coal

•	Kazakhstan currency exchange rate fluctuation

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

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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).

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•	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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•	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;

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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.

•	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;

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•	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;

•	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.

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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;

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•	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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ITEM 1B.	UNRESOLVED STAFF COMMENTS

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ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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(1)	On November 28, 2011, AES completed the acquisition of 100% of the common stock of DPL Inc. Its results of operations have been included in AES's consolidated results of operations from the date of acquisition.

(2)

Includes pretax impairment expense of $602 million, $383 million, $596 million, $1.9 billion, and $272 million for the years ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively. See Note 9—Other Non-Operating Expense, Note 10—Goodwill and Other Intangible Assets and Note 21—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

•	Strategic Performance and Overview of 2015 Results

•	Review of Consolidated Results of Operations

•	SBU Performance Analysis

•	Key Trends and Uncertainties

•	Capital Resources and Liquidity

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•	Reducing complexity: By exiting businesses and markets where we do not have a competitive advantage, we are simplifying our portfolio and reducing risk. During 2015, we announced or closed $787 million in equity proceeds from the sales or sell-downs of seven businesses.

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Leveraging our platforms: We are focusing our growth on platform expansions in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns. We currently have 5,620 MW under construction, representing $7 billion in total capital expenditures, with 85% of AES' $1.2 billion in equity already funded. We expect the majority of these projects to come on-line through 2018. Beyond the projects we currently have under construction, we will continue to advance select projects from our development pipeline.

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Performance excellence: We strive to be the low-cost manager of a portfolio of assets and to derive synergies and scale from our businesses. In November, we launched a $150 million cost reduction and revenue enhancement initiative. This initiative will include overhead reductions, procurement efficiencies and operational improvements. We expect to achieve at least $50 million in savings in 2016, ramping up to $150 million, including modest revenue enhancements, in 2018.

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Expanding access to capital: We are 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 also serve to highlight or enhance 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 2015, we generated substantial cash by executing on our strategy, which we allocated in line with our capital allocation framework:

◦	Used $345 million to prepay and refinance Parent debt;

◦	returned $757 million to shareholders through share repurchases and quarterly dividends;

▪	increased our quarterly dividend by 10%, to $0.11 per share, beginning in the first quarter of 2016;

◦	invested $114 million in our subsidiaries, largely for projects that are currently under construction.

(1)	See reconciliation and definition under Non-GAAP Measures.

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•	$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, primarily 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, primarily 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

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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, 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.

•	$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).

•	$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 assets.

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•	an increase at Mong Duong due to commencement of operations in the current year,

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

•	an increase at Masinloc due to increased earnings 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 decease at Eletropaulo resulting from unfavorable foreign exchange and lower demand.

•	a decrease at Tietê due to lower earnings resulting from poor hydrology and increased prices for purchased energy,

•	a decrease at Uruguaiana due to a favorable arbitration settlement in 2013, and

•	a decrease at Panama related to poor hydrology.

•	Higher impairment expense

•	Lower gains from the sale of businesses

•	Lower debt extinguishment expense

•	Higher gains from the sale of businesses

•	Lower impairment expense

•	Lower general and administrative expenses

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(1)	Unrealized derivatives were net of income tax expense per share of $(0.08), $(0.07) and $(0.02) in 2015, 2014, and 2013, respectively.

(2)	Unrealized foreign currency transaction losses were net of income tax benefit per share of $0.03, $0.02 and $0.02 in 2015, 2014, and 2013, respectively.

(3)

Amount primarily relates to the gain from the sale of Solar Spain and Solar Italy of $7 million ($20 million, or $0.03 per share, including income tax benefit per share of $0.02), the gain from the sale of Armenia Mountain of $22 million ($14 million, or $0.02 per share, net of income tax expense per share of $0.01), and the loss from the tax consequences associated with the sale of a noncontrolling interest in Gener of $25 million, or $0.04 per share.

(4)

Amount primarily relates to the gain from the sale of a noncontrolling interest in Masinloc of $283 million ($0.39 per share, net of income tax per share of $0.00), the gain from the sale of the U.K. wind projects of $78 million ($0.11 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 benefit per share of $0.03), the tax benefit of $24 million ($0.03 per share) related to the Silver Ridge Power transaction, and 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.

(5)	Amount primarily relates to the gain from the sale of Cartagena of $20 million ($15 million, or $0.02 per share, net of income tax benefit per share of $0.01).

(6)

Amount primarily relates to the goodwill impairment at DPL of $317 million ($0.46 per share, net of income tax per share of $0.00) and asset impairments at Kilroot of $121 million ($95 million, or $0.14 per share, net of income tax benefit per share of $0.03), at U.K. Wind (Development Projects) of $38 million ($24 million, or $0.04 per share, net of income tax benefit per share of $0.01), and at Buffalo Gap III of $116 million ($18 million, or $0.03 per share, net of income tax benefit per share of $0.01).

(7)

Amount primarily relates to the goodwill impairments at DPLER of $136 million ($0.19 per share, net of income tax per share of $0.00), and at Buffalo Gap of $28 million ($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 income tax benefit per share of $0.00), and at Elsta of $41 million ($31 million, or $0.04 per share, net of income tax benefit per share of $0.01), and the other-than-temporary impairments at Silver Ridge Power of $42 million ($27 million, or $0.04 per share, net of income tax benefit per share of $0.02), and at Entek of $86 million ($0.12 per share, net of income tax benefit per share of $0.00).

(8)

Amount primarily relates to the goodwill impairments at DPL of $307 million ($0.41 per share, net of income tax per share of $0.00) and at Ebute of $58 million ($0.08 per share, net of income tax per share of $0.00), the other-than-temporary impairment at Elsta of $129 million ($128 million, or $0.17 per share, net of income tax benefit per share of $0.00) and the asset impairments at Beaver Valley of $46 million ($30 million, or $0.04 per share, net of income tax benefit per share of $0.02), and at DPL of $26 million ($17 million, or $0.02 per share, net of income tax benefit per share of $0.01).

(9)	Amount primarily relates to the loss on early retirement of debt at the Parent Company of $116 million ($75 million, or $0.11 per share, net of income tax benefit per share of $0.06) and at IPL of $22 million ($11 million, or $0.02 per share, net of income tax benefit per share of $0.01).

(10)

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 benefit per share of $0.10), at DPL of $31 million ($20 million, or $0.03 per share, net of income tax benefit per share of $0.02), at Electrica Angamos of $20 million ($11 million, or $0.02 per share, net of income tax benefit per share of $0.00), at U.K. wind projects of $18 million ($15 million, or $0.02 per share, net of income tax benefit per share of $0.00).

(11)	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 benefit 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 at Changuinola of $14 million ($10 million, or $0.01 per share, net of income tax benefit per share of $0.01).

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(1)	Refer to tables below for driver explanations by operating assets and liabilities.

(2)	Refer to below operating cash flow discussion by SBU for further information about the key drivers.

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(2)	Includes both recoverable and non-recoverable environmental capital expenditures. See Non GAAP Proportional Free Cash Flow for more information.

(2)	Includes both recoverable and non-recoverable environmental capital expenditures. See Non-GAAP Proportional Free Cash Flow for more information.

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(1)	Service concession asset expenditures excluded from 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 $84 million for the year ended December 31, 2015 . The Company adopted service concession accounting effective January 1, 2015.

(4)	Excludes IPL's proportional recoverable environmental capital expenditures of $205 million, $163 million and $110 million for the years December 31, 2015, 2014 and 2013, respectively.

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(1)	Operating cash flow and proportional free 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.

(1)	Excludes IPL's proportional recoverable environmental capital expenditures of $205 million, $163 million and $110 million for the years ended December 31, 2015, 2014 and 2013, respectively.

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

(2)	Includes proportional adjustment amount for service concession asset expenditures of $84 million for the year ended December 31, 2015. The Company adopted service concession accounting effective January 1, 2015.

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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. 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, 2015 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, 2015.

(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.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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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)	Net electric generation and distribution assets and other include unamortized internal-use software costs of $83 million and $115 million as of December 31, 2015 and 2014, respectively.

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(1)	Amortized cost approximated fair value at December 31, 2015 and 2014.

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(1)	See Note 21—Asset Impairment Expense for further information.

(2)	See Note 23—Discontinued Operations for further information. Fair value of long-lived assets held-for-sale is presented net of costs to sell.

(3)	See Note 8—Investments In and Advances to Affiliates for further information.

(4)	See Note 9—Other Non-Operating Expense for further information.

(5)	See Note 10—Goodwill and Other Intangible Assets for further information.

(1)	These accounts receivable principally relate to amounts due from CAMMESA, the administrator of the wholesale electricity market in Argentina, and are included in Noncurrent assets — Other in the accompanying Consolidated Balance Sheets. The fair value of these accounts receivable excludes value-added tax of $27 million and $36 million at December 31, 2015 and 2014, respectively.

(1)

The Company's interest rate derivative instruments primarily include accreting and amortizing notionals. The maximum derivative notional represents the largest notional at any point between December 31, 2015 and the maturity of the derivative instrument, which includes forward-starting derivative instruments. The interest rate and cross currency derivatives range in maturity through 2033 and 2028, respectively.

(2)	The percentage of variable-rate debt currently hedged is based on the related index and excludes forecasted issuances of debt and variable-rate debt tied to other indices where the Company has no interest rate derivatives.

(1)	Represents contractual notionals. The notionals for options have not been probability adjusted, which generally would decrease them.

(2)	Represents the remaining tenor of our foreign currency derivatives weighted by the corresponding notional. These derivatives matures through 2026.

(1)	Represents the remaining tenor of our commodity derivatives weighted by the corresponding volume. These derivatives range in maturity through 2018.

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(1)	Represents non-contingent consideration to be received in 2016 from the sale of the Cameroon businesses in 2014. Balance is classified as short-term as of December 31, 2015. See Note 23—Discontinued Operations.

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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%. At December 31, 2014, AES owned 71% of AES Gener, resulting in an AES effective ownership in Guacolda of 35%.

(3)	OPGC has one coal-fired expansion project under development. The project started construction in April 2014 and is currently expected to begin operations in 2018.

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(1)	2014 balance includes U.K. Wind operations. In August 2014 these assets were sold, but did not meet the criteria to be reported as discontinued operations and their results are reflected within continuing operations. See Note 24—Dispositions and Held-for-Sale Businesses for further information.

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

(3)	2014 balance includes DPLER which is considered held-for-sale as of December 31, 2015. See Note 24—Dispositions and Held-for-Sale Businesses for further information.

(4)	Includes renewable energy certificates, emission allowances and various other intangible assets none of which is individually significant.

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(1)

Recoverable or refundable per Brazilian National Electric Energy Agency ("ANEEL") regulations through the Annual Tariff Adjustment ("IRT"). These costs are generally non-controllable and primarily consist of purchased electricity, energy transmission, and sector costs that are considered volatile. The costs are passed through for a period of 12 months as part of the IRT. Any remaining balance is considered in the subsequent IRT, which results in a total of 24 months to recover or refund the costs. Favorable spot market sales are also subject to customer refunds through the IRT over the course of these time periods.

(2)	Deferred fuel costs incurred by our El Salvador subsidiaries associated with purchase of energy from the El Salvador spot market and power generation plants. In El Salvador, the deferred fuel adjustment represents the variance between the actual fuel costs and the fuel costs recovered in the tariffs. The variance is recovered quarterly in the tariff reset period.

(3)

Includes assets with and without a rate of return. Other current regulatory assets that did not earn a rate of return were $8 million and $22 million, as of December 31, 2015 and 2014, respectively. Other noncurrent regulatory assets that did not earn a rate of return were $237 million and $73 million, as of December 31, 2015 and 2014, respectively. Other current and noncurrent regulatory assets primarily consist of:

▪	Unamortized losses on long-term debt reacquired or redeemed in prior periods at IPL and DPL, which are amortized over the lives of the original issues in accordance with the Federal Energy Regulatory Commission ("FERC") and PUCO rules.

▪	Unamortized carrying charges and certain other costs related to Petersburg unit 4 at IPL.

▪	Deferred storm costs incurred primarily in 2008 to repair storm damage at DPL; recovery was approved via order from the PUCO on December 17, 2014 and began January 2015.

▪	Additional Regulatory Asset Base ("RAB") from a favorable decision on tariff reset (administrative appeal) at Eletropaulo.

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

(5)

The regulatory accounting standards allow the defined pension and postretirement benefit obligation to be recorded as a regulatory asset equal to the previously unrecognized actuarial gains and losses and prior service costs that are expected to be recovered through future rates. Pension expense is recognized based on the plan's actuarially determined pension liability. Recovery of costs is probable, but not yet determined. Pension contributions made by our Brazilian subsidiaries are not included in regulatory assets as those contributions are not covered by the established tariff in Brazil.

(6)	Probable recovery through future rates, based upon established regulatory practices, which permit the recovery of current taxes. This amount is expected to be recovered,

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(7)	Transmission service costs and other administrative costs from IPL's participation in the Midwest ISO market, which are recoverable but do not earn a rate of return. Recovery of costs is probable, but the timing is not yet determined.

(8)

In July 2012, the Brazilian energy regulator (the "Regulator") approved the periodic review and reset of a component of Eletropaulo's regulated tariff, which determines the margin to be earned by Eletropaulo. The review and reset of this tariff component was retroactive to July 2011 and applied to customers' invoices from July 2012 to June 2015. From July 2011 through June 2012, Eletropaulo invoiced customers under the then-existing tariff rate, as required by the Regulator. As the new tariff rate was lower than the previous rate, Eletropaulo was required to reduce customer tariffs for the difference over the next year. Accordingly, from July 2011 through June 2012, Eletropaulo recognized a regulatory liability for the estimated future refunds, subsequently adjusted as of June 30, 2012 upon the finalization of the new tariff with the Regulator. The refund to customers was considered in the 2013 tariff adjustment, which contemplated an amortization of 67.55% from July 4, 2013. The remaining balance, representing 32.45%, was considered in the next annual tariff adjustment. There was no recorded current regulatory liability at Eletropaulo as of December 31, 2015.

(9)	Amounts received for costs expected to be incurred to improve the efficiency of our plants in Brazil as part of the IRT.

(10)

Other current and noncurrent regulatory liabilities primarily consist of liabilities owed to electricity generators due to variance in energy prices during rationing periods ("Free Energy"). Our Brazilian subsidiaries are authorized to refund this cost associated with monthly energy price variances between the wholesale energy market prices owed to the power generation plants producing Free Energy and the capped price reimbursed by the local distribution companies which are passed through to the final customers through energy tariffs. The balance excludes asset retirement obligations that were reclassified out of Other.

(11)	Obligations for removal costs which do not have an associated legal retirement obligation as defined by the accounting standards on asset retirement obligations.

(12)	Obligations established by ANEEL in Brazil associated with electric utility concessions and represent amounts received from customers or donations not subject to return. These donations are allocated to support energy network expansion and to improve utility operations to meet customers' needs. The term of the obligation is established by ANEEL. Settlement shall occur when the concession ends.

(13)	Represents adjustments to the RAB resulting from an administrative ruling in December 2013 compelling Eletropaulo to refund customers beginning July 2014.

(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 $3.2 billion on non-recourse debt outstanding at December 31, 2015. 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 2.87% to 8.24%. These agreements expire at various dates from 2016 through 2033.

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

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•	Gener issued new debt of $1.1 billion, offset by repayments of $423 million which includes a loss on extinguishment of debt of $19 million;

•	IPALCO issued new debt of $847 million, offset by repayments of $602 million which includes a loss on extinguishment of debt of $22 million;

•	Sul issued new debt of $513 million, offset by repayments of $486 million which includes a loss on extinguishment of debt of $4 million;

•	Eletropaulo issued new debt of $354 million; offset by repayments of $211 million;

•	DPL issued new debt of $325 million; more than offset by repayments of $475 million which includes a loss on extinguishment of debt of $2 million;

•	Panama issued new debt of $300 million, offset by repayments of $287 million which includes a loss on extinguishment of debt of $15 million;

•	Mong Duong drew $203 million under its construction loan facility;

•	Tietê issued new debt of $153 million, more than offset by repayments of $226 million;

•	Andres issued new debt of $180 million, offset by repayments of $176 million which includes a loss on extinguishment of debt of $11 million; and

•	Itabo made repayments of $123 million which includes a loss on extinguishment of debt of $8 million.

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(1)	$686 million and $1.1 billion of the total net unfunded projected benefit obligation is due to Eletropaulo in Brazil as of December 31, 2015 and 2014, respectively.

(1)

A U.S. subsidiary of the Company has defined benefit obligations of $6 million and $748 million as of December 31, 2015 and 2014, respectively, for which salary bands, rather than rates of compensation increases, are used to determine future benefit costs. Rates of compensation increases in the table above do not include amounts related to these specific defined benefit plans. A plan with a defined benefit obligation of $742 million at December 31, 2014 and which used salary bands at that date is using a rate of compensation increase as at December 31, 2015. The rate of compensation increase for this plan is included in the weighted average in the above table for calculating the benefit obligation as at December 31, 2015, but is not included in the weighted average for calculating the benefit obligation as at December 31, 2014 or the periodic benefit cost for 2014 or 2015.

(2)	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)	Amounts in parentheses indicate debits to the Consolidated Statements of Operations.

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(1)	Excludes revenue of $2 million and $23 million for the years ended December 31, 2014 and 2013, respectively, related to Condon and Mid-West Wind, which are reflected as discontinued operations in the accompanying Consolidated Statements of Operations.

(2)	Property, plant & equipment as of December 31, 2015 includes the impact of adopting ASU No. 2014-05, Service Concession Arrangements, on a modified retrospective basis as of January 1, 2015. See Note 1—General and Summary of Significant Accounting Policies for more information.

(3)	Excludes revenue of $230 million and $473 million for the years ended December 31, 2014 and 2013, respectively, related to Sonel, which is reflected as discontinued

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(4)	Excludes revenue of $187 million for the years ended December 31, 2013 related to Kievoblenergo and Rivnooblenergo, which are reflected as discontinued operations in the accompanying Consolidated Statements of Operations.

(5)	Excludes revenue of $6 million for the years ended December 31, 2013 related to Saurashtra, which is reflected as discontinued operations in the accompanying Consolidated Statements of Operations.

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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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•	Cameroon (sold in June 2014)

•	Saurashtra (sold in February 2014)

•	U.S. wind projects (sold in January 2014)

•	Poland wind projects (sold in November 2013)

•	Ukraine utilities (sold in April 2013)

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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;

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•	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

•	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 $8 million, $37 million, $231 million and $326 million, for the first, second, third and fourth quarters of 2015, respectively. See Note 9—Other Non-Operating Expense, Note 10—Goodwill and Other Intangible Assets, and Note 21—Asset Impairment Expense for further discussion.

(2)

Includes a pretax gain of approximately $283 million for the third quarter of 2014 related to the sale of a noncontrolling interest in Masinloc. See Note 16—Equity for further discussion. Includes pretax gain of approximately $78 million for the third quarter of 2014 related to the sale of the U.K. wind projects. See Note 24—Dispositions and Held-for-Sale Businesses for further discussion. Includes pretax interest income of $59 million recognized on FONIVEMEM III receivables at AES Argentina in the fourth quarter of 2014. Also includes a pretax foreign currency derivative gain of $106 million recognized on the FONIVEMEM III receivables in the fourth quarter of 2014. See Note 7—Financing Receivables for further discussion. Includes pretax loss of $41 million recognized in Net equity in earnings of affiliates corresponding to the Company's share of an asset impairment at Elsta in the fourth quarter of 2014. See Note 8—Investments In And Advances To Affiliates for further discussion.

(3)	Includes pretax impairment expense of $166 million, $107 million, $31 million and $79 million, for the first, second, third and fourth quarters of 2014, respectively. See Note 9—Other Non-Operating Expense, Note 10—Goodwill and Other Intangible Assets, and Note 21—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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ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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

•	information regarding AES's Code of Ethics found under the heading 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 Governance Matters—Section 16(a) Beneficial Ownership Reporting Compliance; and

•	information regarding AES's Financial Audit Committee found under the heading The Committees of the Board—Financial Audit Committee (the “Audit Committee”).

ITEM 11.	EXECUTIVE COMPENSATION

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

(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's 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's 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's stockholders, bringing the total authorized shares to 45,750,000. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $13.79 (excluding performance stock units, restricted stock units and director stock units), with 15,986,481 shares available for future issuance).

(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 $19.58. In conjunction with the 2010 amendment to the 2003 Long

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(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 5,494,311 (of which 1,067,734 are vested and 4,426,577 are unvested) shares underlying PSU and RSU awards (assuming performance at a maximum level), 1,451,533 shares underlying Director stock unit awards, and 7,155,375 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 14,101,219 shares.

ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES

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ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	Financial Statements.

(b)	Exhibits.

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(c)	Schedules

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