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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;

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•	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 post retirement 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.

•	US (United States),

•	Andes (Chile, Colombia, and Argentina),

•	Brazil,

•	MCAC (Mexico, Central America and Caribbean),

•	Europe (formerly EMEA), and

•	Asia.

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(1)	27,595 proportional MW. Proportional MW is equal to gross MW of a generation facility times 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 three years, we have sold assets to generate $3.0 billion in equity proceeds for AES, decreasing the total number of countries where we have operations from 28 to 18. 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 2014, we raised $1.8 billion in asset sales proceeds and exited three countries.

•

Leveraging Our Platforms. We are focusing our growth on platform expansions, including adjacencies, in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns. We currently have 7,141 MW under construction — the most in AES' 34-year history. These projects represent $9 billion in total capital expenditures, with the majority of AES' $1.5 billion in equity already funded and we expect all of these projects to come on-line from 2015 through 2018. In 2014, we brought on-line the 247 MW heavy fuel oil-fired IPP4 power plant in Jordan and broke ground on six new construction projects, totaling 2,226 MW. Beyond the projects we currently have under construction, we will continue to advance select projects from our 12,000 MW development pipeline, including traditional power plants and adjacencies, such as energy storage. Adjacencies are smaller investments that add near-term growth and can be replicated across our portfolio. We are already successful - AES is the world leader in battery-based energy storage, with 228 MW (power plant equivalent dispatchable resource, including supply and load capability) in operation or under construction.

◦	AES has the most comprehensive and accomplished fleet of battery-based energy storage in the world

◦	U.S. Energy Information Administration (EIA) forecasts 28,000 MW of new renewable capacity in the next ten years and 82,000 MW of power plant retirements over the same period

▪	Energy storage can serve as a replacement resource, to absorb renewable energy

◦	AES Advancion is a complete battery-based grid resource offered to utility companies and renewable developers

▪	Tailored to specific market needs in terms of power and duration

•	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. We have reduced our global general & administrative expenses ("G&A") by $200 million, achieving the goal we established in 2011 one year early.

•

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. In 2014, we brought in partners at four of our businesses:

◦	CDPQ, a long-term institutional investor headquartered in Quebec, Canada, recently purchased direct and indirect interests in IPALCO, the Parent Company of IPL in Indiana, for $595 million.

◦	At Guacolda in Chile, we brought in Global Infrastructure Partners to acquire a 50% stake by investing $728 million, which allowed us to improve operations, without changing our ownership stake.

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◦	At Masinloc in the Philippines, Electricity Generating Company Limited ("EGCO"), a Thailand-based Independent Power Producer, took an indirect stake in the existing business, as well as potential expansion opportunities, for $443 million. AES and EGCO agreed to use the Masinloc platform as their exclusive vehicle for growth in the Philippines.

◦	At AES Dominicana in the Dominican Republic, we sold a minority interest in the business to the Estrella and Linda Groups, for $84 million, valuing our assets in the country at $1.2 billion. Estrella and Linda Groups represents strong local players and will support our planned platform expansions, such as upgrading our DPP power plant in the Dominican Republic.

•

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 $985 million of our shares and benefited from a low interest rate environment, by transacting on $18 billion in debt deals at the Parent and our subsidiaries. These debt transactions represent $9 billion in refinancing and $9 billion in new financing and extended the maturities on $2.9 billion in Parent debt.

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•	US SBU

•	Andes SBU

•	Brazil SBU

•	MCAC SBU

•	Europe SBU

•	Asia SBU

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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)	Energy Storage MW are power plant equivalent dispatchable resource, including supply and load capability.

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(1)	Energy Storage MW are power plant equivalent dispatchable resource, including supply and load capability.

(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, 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)	IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg.

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•	PJM capacity prices auctioned already (as discussed above)

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

•	Customer switching, competitive bidding and SSO rates (as discussed above)

•	Retail margins earned at DPLER

•	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, San Francisco de Mostazal, Ventanas 1, Ventanas 2 and Volcán.

(3)	Guacolda plants: Guacolda 1, Guacolda 2, Guacolda 3 and Guacolda 4. Unconsolidated entities for which the results of operations are reflected in Equity in Earnings of Affiliates.

(4)	The Company’s ownership in Guacolda is held through AES Gener, a 71%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 35%.

(5)	Gener - SING plants: Norgener 1 and Norgener 2.

(6)	Electrica Ventanas plant: Nueva Ventanas.

(7)	Electrica Campiche plant: Ventanas 4.

(8)	Energy Storage MW are power plant equivalent dispatchable resource, including supply and load capability.

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

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

(1)	Energy Storage MW are power plant equivalent dispatchable resource, including supply and load capability.

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•	Availability of hydro generation: dry hydrology scenarios reduce hydro generation

•	Availability of generation: forced outages may impact earnings

•	Regulatory rulings: a change in current governmental rulings could alter the ability to pass through or recover certain costs

•	Foreign exchange: 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

•	Generation margins: current legislation is trending towards rewarding renewable energy and penalizing coal assets, posing a risk to future coal margins

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•	Availability of generation: forced outages may impact earnings

•	Availability of hydro generation: dry hydrology scenarios reduce hydro generation

•	Foreign exchange: 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

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

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•	Exposure to fluctuations of the Argentine peso

•	Hydrology

•	Lack of subsequent regulatory adjustments for cost increases

•	Timely collection of FONINVEMEM installment and outstanding receivables

•	Level of gas prices for contracted generation (Energy Plus)

•	Access to foreign exchange for imports

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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 sold

•	Re-contracting price

•	Asset management and plant availability

•	Cost management

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•	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

•	Eletropaulo's Fourth tariff cycle outcomes in July 2015

•	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).

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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 2015 is close to 80%. 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.

•	New market rules for ancillary services enacted in 2014, particularly with regard to primary frequency regulation, reduced the revenues in the latter part of the 2014 and may impact future earnings

•	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 high spot prices for the additional energy purchased to fulfill contracts, partially mitigated by the compensation agreement with the government and the power barge which is expected to be operational in the first half of 2015

•	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

•	Spot prices are driven by hydrology since Panama is highly dependent on hydro generation (~56%), however, fluctuations in commodity prices, mainly oil prices, will affect the thermal generation cost impacting the spot prices and the opportunity cost of water

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Electricity Reform: implementing a complete restructuring of the industry including permitting process, terms and conditions for transmission and distribution services and a wholesale electricity market, among others. Under the proposed reform, the CFE will be transformed into a Productive State Enterprise, including separation of the vertically-integrated monopoly into generation, transmission, distribution and marketing activities.

•	Regulations to the Geothermal Energy Law: setting forth details on terms and conditions of the permitting process and of the exploitation of the resources.

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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

•	Level of wind resource for St. Nikola

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

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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

•	Regulated heat tariff levels

•	Weather conditions

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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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•	Availability - Masinloc carries the risk of providing replacement power to its customers whenever its availability is lower than the outage allowance provided for in the contracts

•	Regulatory - ERC intervention in the spot market could result in lower spot prices, and the ongoing review of Masinloc’s power supply contract with electric cooperatives could result in lower approved rates

•	Fuel costs - higher coal prices decrease margins on spot sales

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Spot prices - high spot prices can positively impact the performance of the business when excess capacity is available to sell into the spot market and negatively impact the business when it is required to buy replacement power due to outages outside of the contractual allowance, while low spot prices decrease margins from sales of excess energy (mostly post-2017 due to contracted level at the business)

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

•	May 1, 2015: Phase 1 begins for ozone-season NOx trading program. Existing units must begin 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.

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•	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

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•	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.

•	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;

•	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, government 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, 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 on 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 $383 million, $596 million, $1.9 billion, $272 million, and $332 million for the years ended December 31, 2014, 2013, 2012, 2011 and 2010, 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.

•	Overview of 2014 Results and Strategic Performance

•	Review of Consolidated Results of Operations

•	SBU Analysis and Non-GAAP Measures

•	Key Trends and Uncertainties

•	Capital Resources and Liquidity

•	Reducing complexity: By exiting businesses and markets where we do not have a competitive advantage, we have simplified our portfolio and reduced risk.

•	Leveraging our platforms: Focusing our growth on platform expansions, including adjacencies, in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns.

•	Performance excellence: We strive to be the low-cost manager of a portfolio of assets and to derive synergies and scale from our businesses.

•

Expanding access to capital: By building strategic partnerships at the project and business level. Through these partnerships, we aim to optimize our risk-adjusted returns in our existing businesses and growth projects. By selling down portions of certain businesses, we can adjust our global exposure to commodity, fuel, country and other macroeconomic risks. Partial sell-downs of our assets can serve to highlight the value of businesses in our portfolio.

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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.

•	Adjusted EPS of $1.30 and Proportional Free Cash Flow (FCF) of $891 million

•	Diluted EPS from continuing operations of $1.09 and net cash provided by operating activities of $1.8 billion

•	Returned 76% of discretionary cash to shareholders

•	Increased our quarterly dividend by 100%, to $0.10 per share, beginning in the first quarter of 2015

•	Invested $916 million in our balance sheet, by repurchasing shares and prepaying and refinancing debt

•	Closed ten transactions for $1.8 billion in equity proceeds from asset sales

•	Brought in four strategic partners to invest $1.9 billion in our subsidiaries

•	Achieved goal of reducing global G&A expenses by $200 million one year early

•	Capitalized on our existing footprint - broke ground on six new construction projects, totaling 2,226 MW, expected to come on-line from 2015 through 2018

•	Awarded long-term PPAs by Southern California Edison, for 1,284 MW of combined cycle gas-fired generation and 100 MW of battery-based energy storage

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

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•	Lost-Time Incident Case Rate: Number of lost-time cases per number of full-time employees or contractors.

•	Commercial Availability: Actual variable margin, as a percentage of potential variable margin if the unit had been available at full capacity during outages.

•	Equivalent Forced Outage Factor: The percentage of the time that a plant is not capable of producing energy, due to unplanned operational reductions in production.

•	Heat Rate: The amount of energy used by an electrical generator or power plant to generate one kilowatt-hour (kWh).

•	System Average Interruption Duration Index: The total hours of interruption the average customer experiences annually.

•	System Average Interruption Frequency Index: The average number of interruptions the average customer experiences annually.

•	Non-Technical Losses: Delivered energy that was not billed due to measurement error, theft or other reasons.

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•	US — Overall favorable variance of $196 million driven by regulatory retail rate increases at DPL in Ohio as well as higher rates, primarily pass-through, at IPL in Indiana, partially offset by lower volume at DPL primarily due to customer switching.

•	Andes — Overall favorable impact of $3 million driven by Chivor in Colombia due to higher spot and contract rates, somewhat offset by unfavorable foreign exchange rates, and Gener in Chile as a result of higher volume, partially offset by lower rates. Offsetting these results, Argentina decreased due to unfavorable foreign exchange rates.

•	Brazil — Overall favorable impact of $994 million driven by higher volumes and higher tariffs, primarily pass-through costs, at Eletropaulo and Sul. Tietê also increased due to higher rates. Unfavorable foreign exchange partially offset these results.

•	MCAC — Overall unfavorable impact of $31 million driven by the Dominican Republic due to lower third party gas sales, partially offset by higher PPA rates. El Salvador also decreased as a result of an unfavorable adjustment to unbilled revenue and lower pass-through costs. Offsetting these results, Puerto Rico and Panama increased due to higher volume and rates.

•	Europe — Overall favorable impact of $92 million driven by the start of operations at Jordan IPP4 which commenced operations in July 2014 and Ballylumford in the U.K. due to higher volume and favorable foreign exchange rates, somewhat offset by lower rates. These results were partially offset by Kilroot in the U.K. primarily due to lower volume.

•	Asia — Overall favorable impact of $8 million driven by higher pass-through fuel costs resulting from higher generation at Kelanitissa in Sri Lanka, partially offset by decrease in the Philippines primarily due to lower rates, somewhat offset by higher volume.

•

US — Overall favorable impact of $31 million driven by favorable results at US Generation including contributions from a platform expansion project at Tait energy storage project, combined with higher availability at Hawaii and increased market prices at Laurel Mountain. US Utilities benefited with favorable results at IPL in Indiana driven by higher wholesale and retail margin as well as lower pension costs, were largely offset by lower results at DPL in Ohio. DPL was driven by outages and lower gas availability in the first half of 2014 resulting in higher purchased power and related costs to supply higher demand from cold weather, partially offset by improvements in Q3 2014 from increased retail rates, lower fuel costs and higher capacity prices. Revenue increases due to pass-through costs do not have a corresponding impact on operating margin.

•

Andes — Overall favorable impact of $54 million driven by Chivor in Colombia due to higher generation, higher spot and contract prices, as well as ancillary services. Increases in Argentina were offset by lower results at Gener in Chile. Argentina increased due to the impact of Resolution 529, higher generation and availability, partially offset by higher fixed costs while Gener in Chile decreased due to lower contract and spot prices and lower availability, partially offset by full impact of new operations at Ventanas IV in 2014 and lower fixed costs.

•

Brazil — Overall unfavorable impact of $129 million driven by unfavorable foreign exchange rates and Tietê due to lower water inflows which led to lower generation and an increase in energy purchases at higher prices, partially offset by higher spot sales in first half of 2014 due to lower contracted volumes of energy sold. In addition, Uruguaiana decreased due to a non-recurring extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013. These results were partially offset by Eletropaulo driven by a non-recurring 2013 charge related to the recognition of a regulatory liability related to potential customer refunds as well as higher tariffs and volume. Revenue increases due to pass-through costs do not have a corresponding impact on operating margin.

•	MCAC — Overall unfavorable impact of $2 million driven by El Salvador due to an unfavorable adjustment to unbilled revenue, higher energy losses and lower demand. These results were largely offset by the Dominican Republic mainly related to higher spot sales and higher availability, partially offset by lower gas sales to third parties, lower frequency regulation, and lower PPA results.

•	Europe — Overall unfavorable impact of $12 million driven by Kilroot in the U.K. and Maritza in Bulgaria due to lower volume and higher outages, partially offset by higher rates. These results were partially offset by the new operations at Jordan IPP4 as discussed above, and Kazakhstan due to higher generation volume and rates, partially offset by unfavorable foreign exchange rates.

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Asia — Overall unfavorable impact of $93 million driven by Masinloc in the Philippines, due to lower plant availability and the market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013, and lower spot rates, partially offset by higher contract demand. Kelanitissa also decreased due to a reduction in rates according to the PPA.

•	US — Overall unfavorable impact of $106 million driven by the early termination of the PPA at Beaver Valley in Pennsylvania in early 2013, customer switching as well as lower capacity rates at DPL in Ohio, and the short-term restart in 2012 of two Huntington Beach generating units at Southland in California, partially offset by higher wholesale volume and prices at IPL in Indiana.

•	Andes — Overall unfavorable impact of $381 million driven by unfavorable foreign exchange rates of $128 million, lower prices from the impact of Resolution 95 in Argentina, and lower contract and spot prices at Gener in Chile, partially offset by higher spot prices at Chivor in Colombia as a result of dry hydrology.

•

Brazil — Overall unfavorable impact of $773 million driven by unfavorable foreign exchange rates of $631 million, lower demand as well as lower pass-through costs and the tariff reset implemented in April 2013 at Sul, and a decrease at Eletropaulo related to the recognition of a regulatory liability for customer refunds (See Item 1.—Business—Brazil SBU— Eletropaulo Regulatory Asset Base Update) somewhat offset by higher tariffs. Negative results above partially offset by higher prices and sales at Tietê and the temporary restart of operations during February and March of 2013 at Uruguaiana.

•	MCAC — Overall favorable impact of $140 million driven by higher spot prices as well as higher spot and gas sales to third parties in the Dominican Republic, higher prices in Mexico and Puerto Rico, partially offset by lower generation net of higher prices due to lower hydrology in Panama.

•

Europe — Overall favorable impact of $3 million driven by higher energy prices at Kilroot in the UK, pass-through costs at Maritza in Bulgaria and Jordan, as well as higher dispatch and fewer outages at Ballylumford in the UK, partially offset by lower capacity prices. The favorable results above were largely offset by the sale of 80% of our ownership in Cartagena in Spain in February 2012 and a non-recurring favorable arbitration settlement in 2012 prior to final sale of remaining AES interest in April 2013.

•	Asia — Overall unfavorable impact of $183 million due to higher contract levels at lower prices to reduce spot exposure, the reversal of a contingency and unrealized derivative gains in 2012 at Masinloc in the Philippines as well as lower generation at Kelanitissa in Sri Lanka as a result of higher hydrology.

•

US — Overall unfavorable impact of $43 million driven by the short-term restart of two Huntington Beach units at Southland in 2012, higher outages and related fixed costs at Hawaii, and higher maintenance costs at IPL in Indiana. The negative drivers above were partially offset by higher contributions for US Wind businesses and DPL with lower amortization expense largely offset by higher customer switching.

•

Andes — Largely unfavorable impact of $47 million driven by Chivor due to lower generation, somewhat offset by higher spot prices due to dry hydrology. Chile also decreased due to lower generation, higher spot purchases, and lower contract prices, offset by the commencement of operations of Ventanas IV in March 2013. These negative drivers were partially offset by an increase in Argentina driven by lower outages and higher volumes, somewhat offset by unfavorable foreign currency translation of $18 million and lower rates.

•

Brazil — Overall unfavorable impact of $98 million driven by an unfavorable foreign exchange impact of $84 million, lower tariffs and demand at Sul, as well as lower volumes and higher energy purchases due to low hydrology at Tietê, partially offset by the favorable reversal of a liability and the temporary restart of operations at Uruguaiana and higher tariffs and lower fixed costs at Eletropaulo, somewhat offset by recognition of a regulatory liability as discussed above.

•	MCAC — Overall unfavorable impact of $17 million driven by Panama due to dry hydrological conditions, which resulted in lower generation and higher energy purchases at higher prices, somewhat offset by favorable net settlements. Negative drivers above were partially offset by the Dominican Republic with higher spot sales, higher

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

•	Asia — Overall unfavorable impact of $67 million driven by higher contracted volume at lower prices as discussed above as well as reversal of a contingency of $16 million and an unrealized derivative gain in 2012 at Masinloc.

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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 by 31% associated with U.S. Dollar denominated debt, and losses at Termoandes (a U.S. Dollar functional currency subsidiary) primarily associated with cash and accounts receivable balances in local currency, and the purchase of Argentine sovereign bonds;

•	$17 million in Colombia, primarily due to a 23% depreciation of the Colombian Peso, positively impacting Chivor (a U.S. Dollar functional currency subsidiary) due to liabilities denominated in Colombian Pesos, primarily income tax payable and accounts payable;

•	$12 million in the United Kingdom, primarily due to a 6% depreciation of the Pound Sterling, resulting in gains at Ballylumford Holdings (a U.S. Dollar functional currency subsidiary) associated with intercompany notes payable denominated in Pound Sterling, and gains related to foreign currency derivatives; and

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•	$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 asset.

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

•	$16 million in Brazil, primarily due to a 9% devaluation of the Brazilian Real resulting in losses mainly associated with U.S. Dollar denominated liabilities.

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•	the gain on sale of 45% of our investment in Masin - AES Pte Ltd. as well as the gain on sale of the Company's entire interest in the UK Wind projects;

•	lower goodwill impairment expense recognized in 2014 compared to 2013;

•	higher interest income;

•	lower general and administrative expense;

•	gain on foreign currency transactions;

•	increase in income from operations of discontinued businesses; and

•	lower loss from disposal and impairments of discontinued businesses.

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•	lower operating margin;

•	increase in income tax expense; and

•	higher losses from debt extinguishments.

•	lower goodwill impairment expense;

•	lower income tax expense;

•	lower foreign currency losses;

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

•	lower general and administrative expense.

•	lower operating margin as described above;

•	the loss on the early extinguishment of debt at the Parent Company and at Masinloc;

•	lower gain on sale of investments recorded in 2013 on the sale of our remaining 20% interest in Cartagena as well as our 10% equity interest in Trinidad compared to the prior year gain recorded from the sale of 80% of our interest in Cartagena in the first quarter of 2012;

•	an increase in losses from the disposal and impairment of the discontinued businesses;

•	other non-operating expense associated with an impairment at our equity method investment at Elsta in the Netherlands.

•	Electricity and fuel purchases,

•	Operations and maintenance costs,

•	Depreciation and amortization expense,

•	Bad debt expense and recoveries,

•	General administrative and support costs at the businesses, and

•	Gains or losses on derivatives associated with the purchase of electricity or fuel.

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•	General and administrative expense in the corporate segment, as well as business development costs;

•	Interest expense and interest income;

•	Other expense and other income;

•	Realized foreign currency transaction gains and losses; and

•	Net equity in earnings of affiliates.

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(1)	Adjusted pretax contribution in each segment before intersegment eliminations includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees and the write-off of intercompany balances.

(1)	Unrealized derivative (gains) losses were net of income tax per share of $(0.07), $(0.02) and $0.04 in 2014, 2013, and 2012, respectively.

(2)	Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.02, $0.02 and $0.00 in 2014, 2013, and 2012, respectively.

(3)

Amount primarily relates to the gain from the sale of a noncontrolling interest in Masinloc of $283 million ($283 million, or $0.39 per share, net of income tax per share of $0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per share of $0.00), the loss from the sale of Ebute of $6 million ($6 million, or $0.01 per share, net of income tax per share of $0.00), the loss from the liquidation of AgCert International of $1 million (net benefit of $18 million, or $0.03 per share, including income tax per share of $0.03), the tax benefit of $24 million ($0.03 per share) related to the Silver Ridge Power transaction, the tax benefit of $18 million ($0.02 per share) associated with the agreement executed in December 2014 to sell a noncontrolling interest in IPALCO, and the tax benefit of $7 million ($0.01 per share) associated with the sale of a noncontrolling interest in our Dominican Republic businesses.

(4)	Amount primarily relates to the gain from the sale of the remaining 20% of our interest in Cartagena for $20 million ($15 million, or $0.02 per share, net of income tax per share of $0.01) as well as the gain from the sale of Trinidad for $3 million ($4 million, or $0.01 per share, net of income tax per share of $0.00).

(5)	Amount primarily relates to the gains from the sale of 80% of our interest in Cartagena for $178 million ($109 million, or $0.14 per share, net of income tax per share of $0.09) and equity method investments in China of $24 million ($25 million, or $0.03 per share, including an income tax credit of $1 million, or income tax per share of $0.00).

(6)

Amount primarily relates to the goodwill impairments at DPLER of $136 million ($136 million, or $0.19 per share, net of income tax per share of $0.00), and at Buffalo Gap of $28 million ($28 million, or $0.04 per share, net of income tax per share of $0.00), and asset impairments at Ebute of $67 million ($64 million, or $0.09 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.00), at DPL of $12 million ($7 million, or $0.01 per share, net of income tax per share of $0.01), at Newfield of $12 million ($6 million, or $0.01 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00), and at Elsta of $41 million ($31 million, or $0.04 per share, net of income tax per share of $0.01), as well as the other-than-temporary impairments of our equity method investment at Silver Ridge Power of $42 million ($27 million, or $0.04 per share, net of income tax per share of $0.02), and at Entek of $86 million ($86 million, or $0.12 per share, net of income tax per share of $0.00).

(7)

Amount primarily relates to the goodwill impairments at DPL of $307 million ($307 million, or $0.41 per share, net of income tax per share of $0.00), at Ebute of $58 million ($58 million, or $0.08 per share, net of income tax per share of $0.00) and at Mountain View of $7 million ($7 million, or $0.01 per share, net of income tax per share of $0.00). Amount also includes an other-than-temporary impairment of our equity method investment at Elsta of $129 million ($128 million, or $0.17 per share, net of income tax per share of $0.00) and asset impairments at Beaver Valley of $46 million ($30 million, or $0.04 per share, net of income tax per share of $0.02), at DPL of $26 million ($17 million, or $0.02 per share, net of income tax per

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(8)

Amount primarily relates to the goodwill impairment at DPL of $1.82 billion ($1.82 billion, or $2.39 per share, net of income tax per share of $0.00). Amount also includes other-than-temporary impairment of equity method investments in China of $32 million ($32 million, or $0.04 per share, net of income tax per share of $0.00), and at Inno Vent of $17 million ($17 million, or $0.02 per share, net of income tax per share of $0.00), as well as asset impairments of Wind turbines and projects of $41 million ($26 million, or $0.03 per share, net of income tax per share of $0.02) and asset impairments at Kelanitissa of $19 million ($17 million, or $0.02 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00) and at St. Patrick of $11 million ($11 million or $0.01 per share, net of income tax per share of $0.00).

(9)

Amount primarily relates to the loss on early retirement of debt at the Parent Company of $200 million ($130 million, or $0.18 per share, net of income tax per share of $0.10), at DPL of $31 million ($20 million, or $0.03 per share, net of income tax per share of $0.02), at Electrica Angamos of $20 million ($11 million, or $0.02 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00), at UK wind projects of $18 million ($15 million, or $0.02 per share, net of income tax per share of $0.00), at Warrior Run of $8 million ($5 million, or $0.01 per share, net of income tax per share of $0.00) and at Gener of $7 million ($4 million, or $0.01 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00).

(10)	Amount primarily relates to the loss on early retirement of debt at Parent Company of $165 million ($107 million, or $0.14 per share, net of income tax per share of $0.08), at Masinloc of $43 million ($39 million, or $0.05 per share, net of income tax per share of $0.00) and Changuinola of $14 million ($10 million, or $0.01 per share, net of income tax per share of $0.01).

(11)	Amount primarily relates to the loss on retirement of debt at the Parent Company of $15 million ($10 million, or $0.01 per share, net of income tax per share of $0.01).

•	US Generation increased by $26 million, primarily due to $11 million from increased availability as a result of fewer outages at Hawaii, $8 million at Laurel Mountain due to increased market prices, and $8 million due to the September 2013 completion of the Tait energy storage project; and

•	IPL in Indiana increased $24 million driven by higher wholesale margin of $14 million and lower fixed costs of $11 million primarily due to lower pension expense.

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

•	US Generation decreased $26 million, driven by a $24 million decline from the short-term restart of two Huntington Beach units at Southland in 2012, and higher outages at Hawaii of $24 million, partially offset by higher contributions from the US Wind portfolio of $32 million; and

•	IPL in Indiana declined $23 million, as a result of $13 million in higher maintenance costs driven by the timing and duration of major generating unit overhauls, and higher depreciation expense of $6 million due to additional utility plant assets placed in service.

•	DPL increased $6 million, as lower amortization expense of $81 million offset:

◦	A $30 million decrease in sales margin, as customer switching drove retail price decreases, partially offset by higher wholesale volumes;

◦	Lower PJM capacity margins of $12 million; and

◦	$19 million from unrealized gains on derivatives in 2012, which did not recur in 2013.

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•	Chivor in Colombia increased $55 million of which $72 million was due to higher generation, higher spot and contract prices, and ancillary services, partially offset by higher maintenance costs of $12 million and unfavorable foreign exchange rates of $9 million.

•	Argentina increased $8 million driven primarily by higher rates of $30 million as a result of the impact of Resolution 529, higher generation and availability of $13 million, partially offset by higher fixed costs of $27 million driven by higher inflation and unfavorable exchange rates of $5 million.

•	Gener in Chile decreased $9 million, largely driven by a reduction of $32 million from lower contract prices, spot prices in the SADI and lower Energy Plus margin and lower availability of $9 million; partially offset by the contribution of $10 million from Ventanas IV, which commenced operations in March 2013, and lower fixed costs from lower maintenance and salaries of $19 million.

•	Chivor in Colombia decreased $42 million, as dry hydrological conditions reduced generation output and spot volumes but increased spot prices in the market. Lower volumes had an unfavorable impact of $115 million, partially offset by the favorable impact of $84 million from higher prices.

•	Gener in Chile decreased $8 million, as a reduction of $30 million from lower contract prices and higher spot purchases was partially offset by higher generation of $24 million, as the commencement of operations at Ventanas IV in March 2013 was offset by lower gas availability and lower coal generation.

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

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

•	Uruguaiana decreased $51 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation in 2014 during the period of temporary restart of operations.

•

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

•	Sul increased $31 million, due to higher volume and rates of $52 million, partially offset by higher fixed costs and depreciation of $11 million and unfavorable foreign exchange rates of $10 million.

•	Sul decreased $96 million, due to lower tariffs of $33 million from the April 2013 tariff reset and lower volume of $44 million due to lower demand; and

•	Tietê decreased $81 million, driven by the negative impact of foreign currency translation of $68 million as well as lower volume and higher energy purchases of $24 million due to lower hydrology.

•	Uruguaiana increased $64 million, as a result of the extinguishment of a liability of $57 million and the temporary re-start of operations during February and March of 2013.

•	Eletropaulo increased $17 million, driven by higher tariffs of $171 million and lower fixed costs of $42 million, partially offset by the recognition of a regulatory liability of $224 million related to potential customer refunds.

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•	El Salvador decreased $22 million, due primarily to a one-time unfavorable adjustment to unbilled revenue, as well as higher energy losses and other fixed costs; and

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Panama decreased $8 million, driven by dry hydrological conditions, which resulted in lower generation and higher energy purchases of $38 million and the Esti tunnel settlement agreement received during 2013 of $31 million, partially offset by compensation from the government of Panama of approximately $40 million related to spot purchases from dry hydrological conditions, as well as lower fixed and other costs of $22 million.

•	Dominican Republic increased $19 million, mainly related to higher spot sales of $58 million and higher availability of $20 million, partially offset by lower gas sales to third parties of $27 million, lower frequency regulation of $26 million and lower PPA results of $14 million; and

•	Puerto Rico increased by $6 million, driven by a favorable bad debt reversal.

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

•	Dominican Republic increased $42 million, as a result of higher net energy transactions of $28 million, higher gas sales to third parties of $20 million, partially offset by $6 million due to other factors such as higher fixed costs.

•	El Salvador increased $17 million, due to the tariff increase approved by the regulator at the beginning of 2013.

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

•	Maritza decreased $17 million due to higher outages and related maintenance costs of $32 million, partially offset by higher rates of $10 million.

•	Jordan increased $17 million as the IPP4 Jordan plant commenced operations in July 2014; and

•	Kazakhstan increased $11 million driven by higher volumes and rates of $29 million, partially offset by unfavorable foreign exchange impact of $13 million.

•	Cartagena in Spain decreased $105 million, as a result of:

◦	A non-recurring, favorable arbitration settlement of $95 million in the first quarter of 2012; and

◦	The two-stage sale of the business, as AES owned 71% of the facility through February 2012 and 14% through April 2013, when the sale was completed.

•	Ballylumford in the U.K. decreased $29 million due to lower rates and capacity payments of $48 million, partially offset by fewer outages of $19 million.

•	Maritza in Bulgaria increased $30 million driven by $10 million from fewer outages, $6 million of lower fixed costs, and favorable foreign exchange rates of $7 million.

•	Kilroot in the U.K. increased $28 million driven by favorable dark spreads from higher energy prices and lower coal costs.

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Masinloc in the Philippines decreased by $79 million, driven by $33 million due to lower plant availability, a net decrease of $21 million of lower spot rates partially offset by higher volume, an unfavorable impact of $15 million resulting from the market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013, higher maintenance costs of $4 million; and

•	Kelanitissa in Sri Lanka decreased by $17 million, driven by the step-down in the contracted PPA price.

•	Masinloc in Philippines decreased $62 million, due to:

◦	The net impact of higher contracted volumes at lower prices, as a result of a new 7-year contract to reduce spot exposure, with an unfavorable impact of $31 million;

◦	A reversal of a contingency of $16 million in 2012; and

◦	An unrealized derivative gain of $15 million in 2012.

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•	Brazil — decrease of $549 million primarily driven by higher tax payments of $244 million across the region and higher energy purchases in excess of collections resulting from poor hydrology of $153 million and $84 million at the Utilities and Tietê, respectively;

•	MCAC — a decrease of $184 million primarily driven by a non-recurring $90 million settlement received in 2013 related to a fuel contract amendment and $12 million lower collections in Dominican Republic, as well as higher energy purchases of $46 million in Panama, and;

•	Europe — a decrease of $180 million primarily due to lower collections of $56 million at Maritza in Bulgaria and higher working capital requirements of $52 million in Northern Ireland in the U.K.

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•	an increase of $723 million in other assets primarily related to increased regulatory assets at Eletropaulo and Sul resulting from higher priced energy purchases recoverable through future tariffs as well as an increase at Alicura related to the recognition of interest associated with the FONINVEMEM agreement;

•	an increase of $520 million in accounts receivable primarily related to higher sales at Eletropaulo and Sul and lower collections at Maritza; and

•	a decrease of $89 million in net income tax and other tax payables primarily for payments of income taxes in excess of accruals of new current tax liabilities; partially offset by

•	an increase of $516 million in other liabilities primarily related to an increase in regulatory liabilities at Eletropaulo and Sul partially offset by pension contributions at IPL and payments for share-based compensation issuance withholding tax and termination of a derivative contract at the Parent Company.

•	US — an increase of $74 million primarily due to a bankruptcy settlement payment of the New York entities in 2012 and the proceeds from the PPA termination at Beaver Valley in January 2013;

•	Andes — a decrease of $276 million primarily driven by higher working capital requirements;

•	Brazil — a decrease of $106 million primarily related to lower collections and higher energy purchases at Sul, partially offset by the recovery of deferred costs from ANEEL, rate regulator, lower transmission costs and regulatory charges at Eletropaulo;

•	MCAC — an increase of $185 million primarily driven by a $90 million settlement received related to an amendment to a fuel contract and lower working capital requirements; and

•	Asia — a decrease of $85 million primarily driven by higher working capital requirements and lower operating results at Masinloc.

•	a decrease of $725 million in accounts payable and other current liabilities primarily at Eletropaulo and Sul due to lower costs and a decrease in regulatory liabilities and at Uruguaiana primarily related to the extinguishment of a liability as well as lower generation and higher payments to fuel supplier at Kelanitissa;

•

an increase of $103 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo and Sul, resulting from higher priced energy purchases which are recoverable through future tariffs and an increase at Alicura related to the recognition of interest associated to FONINVEMEM agreement, partially offset by a decrease in noncurrent regulatory assets at IPL related to the annual adjustment to pension benefits based on the actuarial valuation; partially offset by

•	a decrease of $358 million in prepaid expenses and other current assets mainly due to a decrease in current regulatory assets, for the recovery of prior period tariff cycle energy purchases and regulatory charges at Eletropaulo;

•	a decrease of $146 million in accounts receivable primarily related to lower tariffs at Eletropaulo combined with lower tariff and reduced consumption at Sul as well as lower revenue offset by higher collections at Kelanitissa, partially offset by lower collections at Maritza;

•	an increase of $137 million in other liabilities primarily due to an increase in noncurrent regulatory liabilities at Eletropaulo partially offset by a decrease in pension liability at IPL; and

•	a increase of $95 million in net income tax and other tax payables primarily due to accruals for new current tax liabilities offset by payments of income taxes.

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•	an increase of $589 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo, resulting from higher priced energy purchases, regulatory charges and transmission costs which are recoverable through future tariffs and the establishment of a noncurrent note receivable at Cartagena in Spain following the arbitration settlement, prior to its deconsolidation;

•	an increase of $241 million in accounts receivable primarily due to lower collection Eletropaulo and Andres as well as an increase in revenue at Sul and Kelanitissa;

•	a decrease of $47 million net income tax payables and other tax payables primarily for the payment of income taxes in excess of the accrual of new tax liabilities; partially offset by

•	an increase of $335 million in other liabilities primarily explained by an increase in noncurrent regulatory liabilities at Eletropaulo related to the tariff reset;

•	an increase of $330 million in accounts payable and other current liabilities primarily at Eletropaulo due to an increase in current regulatory liabilities driven by the tariff reset, offset by a decrease in other current liabilities arising from value-added tax payables; and

•	a decrease of $120 million in prepaid expenses and other current assets mainly due to the recovery of value-added taxes at our construction projects in Chile.

•	Capital expenditures of $2.0 billion consisting of $1.2 billion of growth capital expenditures and $865 million of maintenance and environmental capital expenditures. Material expenditures by business are as follows:

◦	Growth capital expenditures included amounts at Gener of $399 million, Eletropaulo of $146 million, IPL of $126 million, Mong Duong of $111 million, Jordan of $72 million, Maritza of $62 million, DPL of $46 million, Sul of $45 million and Panama of $42 million;

◦	Maintenance and environmental capital expenditures included amounts at IPL of $265 million, Eletropaulo of $90 million, Gener of $89 million, Tietê of $80 million, DPL of $65 million, Sul of $54 million and Altai of $43 million;

•

Acquisitions, net of cash acquired of $728 million consisted primarily of an acquisition at Gener in the second quarter for the remaining 50% interest in our equity investment in Guacolda, of which 50% less one share was subsequently sold during the same quarter. See Note 8—Investment in and Advances to Affiliates in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information;

•	Purchases of short-term investments, net of sales of $120 million including amounts at Brasiliana Energia of $81 million and Tietê of $63 million offset by net sales at Eletropaulo of $39 million; partially offset by

•

Proceeds from the sale of businesses, net of cash sold of $1.8 billion including $730 million at Gener related to the sale of 50% less one share of our interest in Guacolda, $436 million for the sale of 45% of our equity interest in Masinloc, $174 million related to the the sale of AES’ interest in Silver Ridge Power’s assets in Bulgaria, France, Greece, India and the United States, $158 million related to the UK Wind Sale, $156 million from the sale of our businesses in Cameroon and $125 million for the sale of Entek, our equity investment in Turkey; and

•

Decreases in restricted cash, debt service reserve and other assets of $419 million including amounts of $98 million primarily related to the Alstom settlement repayment at Maritza, $96 million at the Parent Company pertaining to letter of credit reductions for Jordan and Mong Duong development projects, as well as project debt refinancing of $70 million and $45 million at Angamos and Southland, respectively.

•	Capital expenditures of $2.0 billion consisting of $1.1 billion of growth capital expenditures and $934 million of maintenance and environmental capital expenditures.

◦	Growth capital expenditures included amounts at Gener of $317 million, Eletropaulo of $223 million, Jordan of $200 million, Sul of $72 million, Mong Duong of $48 million, DPL of $40 million, Sixpenny Wood of $25 million, Altai of $21 million, Yelvertoft of $20 million and Kribi of $20 million;

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◦	Maintenance and environmental expenditures included amounts at IPL of $246 million, Eletropaulo of $138 million, Tietê of $94 million, Gener of $92 million, DPL of $76 million, Sul of $61 million and Altai of $43 million; partially offset by

•	Proceeds from the sale of businesses, net of cash sold of $170 million including $110 million for the sale of the Ukraine businesses, $31 million for the sale of our 10% equity interest in Trinidad and $24 million for the sale of our remaining interest in Cartagena.

•	Repayments of recourse and non-recourse debt of $5.6 billion including amounts at the Parent Company of $2.1 billion, Gener of $905 million, Angamos of $780 million, DPL of $364 million, Southland of $188 million, Chivor of $165 million, Tietê of $132 million, $114 million related to the UK Wind sale, Eletropaulo of $110 million and Warrior Run of $109 million;

•	Payments for financed capital expenditures were $528 million including $310 million at Mong Duong, $143 million at Cochrane and $30 million at Changuinola;

•	Distributions to noncontrolling interests of $485 million including amounts at Tietê of $188 million, Brasiliana Energia of $69 million, Gener of $66 million and Buffalo Gap of $45 million;

•	Purchase of treasury stock of $308 million at the Parent Company; partially offset by

•	Issuances of recourse and non-recourse debt of $5.7 billion including new issuances at the Parent Company of $1.5 billion, Angamos of $800 million, Gener of $700 million, Mong Duong of $364 million, Tietê of $318 million, Cochrane of $305 million, US Generation Holdings of $299 million, Eletropaulo of $253 million, DPL of $200 million and Sul of $185 million.

•

Repayments of recourse and non-recourse debt of $4.6 billion including amounts at the Parent Company of $1.2 billion, DPL of $948 million, Masinloc of $560 million, Changuinola of $412 million, Tietê of $396 million, Caess of $301 million, IPL of $110 million, Warrior Run of $100 million, Puerto Rico of $73 million, Maritza of $57 million, Southland of $54 million, Sonel of $47 million and Sul of $44 million;

•	Payments for financed capital expenditures were $591 million primarily at Mong Duong for payments to the contractors which took place more than three months after the associated equipment was purchased or work performed;

•	Distributions to noncontrolling interests of $557 million including amounts at Tietê of $205 million, Brasiliana of $128 million, Gener of $62 million and Buffalo Gap of $54 million;

•	The purchase of treasury stock at the Parent Company was $322 million;

•	Payments for financing fees of $176 million including amounts at Gener of $54 million including amounts at the Alto Maipo and Cochrane projects, Mong Duong of $28 million and Eletropaulo of $25 million; partially offset by

•

Issuances of recourse and non-recourse debt of $5.0 billion including amounts of $750 million at the Parent Company, Gener of $707 million including amounts at the Cochrane and Alto Maipo projects, DPL of $645 million, Masinloc of $500 million, Tietê of $496 million, Mong Duong of $471 million, Changuinola of $420 million, Caess of $310 million, Jordan of $180 million, IPL of $170 million and Sul of $153 million; and

•	Contributions from noncontrolling interests of $210 million including amounts at Gener of $109 million including amounts at the Cochrane and Alto Maipo projects and at Mong Duong of $77 million.

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•	MCAC — $152 million decrease primarily driven by a non-recurring $90 million settlement received in 2013 related to a fuel contract amendment and $30 million lower collections in Dominican Republic, as well as higher energy purchases of $22 million in Panama;

•	Europe — $149 million decrease primarily driven by $56 million of lower collections in Bulgaria and $52 million of lower operating margins and higher working capital in Northern Ireland in the U.K.;

•	Brazil — $103 million decrease primarily driven by higher tax payments of $100 million across the region and higher energy purchases in excess of collections resulting from poor hydrology of $10 million and $20 million at the Utilities and Tietê, respectively;

•	US — $46 million decrease driven by $46 million proceeds from the PPA termination at Beaver Valley in 2013 and $41 million of higher working capital at DPL, partially offset by $52 million of lower maintenance capital expenditures at the U.S. Utilities;

•	Asia — $19 million decrease driven primarily by lower margins at Kelanitissa; and

•	Andes — $13 million decrease primarily related to $51 million in Chile driven by $28 million of VAT receivable timing and an interest rate swap payment of $18 million as well as $28 million in Argentina primarily due to an increase in interest receivables. These results were partially offset by an increase of $67 million at Chivor in Colombia primarily due to higher margins.

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

•	MCAC — $197 million increase driven by higher operating cash flow, as a result of a $90 million settlement related to an amendment to a fuel contract and lower working capital requirements, and

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

•	Andes — $193 million increase driven by lower operating cash flow from higher working capital requirements; and

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

•	dividends and other distributions from our subsidiaries, including refinancing proceeds;

•	proceeds from debt and equity financings at the Parent Company level, including availability under our credit facility; and

•	proceeds from asset sales.

•	interest;

•	principal repayments of debt;

•	acquisitions;

•	construction commitments;

•	other equity commitments;

•	common stock repurchases;

•	taxes;

•	Parent Company overhead and development costs; and

•	dividends on common stock.

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•	limitations on other indebtedness, liens, investments and guarantees;

•	limitations on dividends, stock repurchases and other equity transactions;

•	restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements;

•	maintenance of certain financial ratios; and

•	financial and other reporting requirements.

•	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, 2014 and do not reflect anticipated future refinancing, early redemptions or new debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2014.

(3)	See Note 13—Commitments to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further information.

(4)

These amounts do not include current liabilities on the Consolidated Balance Sheet except for the current portion of uncertain tax obligations. Noncurrent uncertain tax obligations are reflected in the “Other” column of the table above as the Company is not able to reasonably estimate the timing of the future payments. In addition, the amounts do not include: (1) regulatory liabilities (See Note 11—Regulatory Assets and Liabilities), (2) contingencies (See Note 14—Contingencies), (3) pension and other post retirement employee benefit liabilities (see Note 15—Benefit Plans) or (4) any taxes (See Note 22—Income Taxes) except for uncertain tax obligations, as the Company is not able to reasonably estimate the timing of future payments. See the indicated notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on the items excluded. Derivatives (See Note 6—Derivative Instruments and Hedging Activities) and incentive compensation are excluded as the Company is not able to reasonably estimate the timing or amount of the future payments.

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

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•	the estimate requires management to make assumptions about matters that were highly uncertain at the time the estimate was made;

•	different estimates reasonably could have been used; or

•	the impact of the estimates and assumptions on financial condition or operating performance is material.

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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.

•

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.

•

Level 3—pricing inputs that are unobservable from objective sources. Unobservable inputs are only used to the extent observable inputs are not 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 related to the Company's held-for-sale businesses of $1.2 billion as of December 31, 2013, were excluded from the table above and were included in the noncurrent assets of discontinued and held-for-sale businesses in the consolidated balance sheets. There were no discontinued and held-for-sale businesses at December 31, 2014.

(2)	Net electric generation and distribution assets and other include unamortized internal-use software costs of $115 million and $133 million as of December 31, 2014 and 2013, respectively.

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(1)	Amortized cost approximated fair value at December 31, 2014 and 2013.

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

(2)	See Note 21—Asset Impairment Expense and Note 24—Dispositions for further information.

(3)	See Note 23—Discontinued Operations and Held-For-Sale Businesses for further information. Fair value of long-lived assets held-for-sale exclude costs to sell.

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

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(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 $36 million and $46 million at December 31, 2014 and 2013, 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, 2014 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.

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(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 options and forwards and these embedded derivatives range in maturity through 2025 and 2017, respectively.

(1)	Represents the remaining tenor of our commodity derivatives weighted by the corresponding volume. These derivatives range in maturity through 2016.

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(1)

As of December 31, 2014 all amounts had contractual maturities of greater than one year. As of December 31, 2013, total receivables with the Argentine government were $286 million, and the amount presented in the table above excluded noncurrent receivables of $122 million which had not yet been converted into financing receivables and did not have contractual maturities of greater than one year at the time.

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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 71%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 35%.

(3)	OPGC has one coal-fired expansion project under development with a total capacity of 1,320 MW. The project started construction in April 2014 and is currently expected to begin operations in 2018. As of December 31, 2014, total capitalized costs at the project level were $186 million (AES share of $91 million).

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(1)

Represent development rights, including but not limited to, land control, various permits and right to acquire equity interests in development projects resulting from asset acquisitions by our wind operations in the U.K. The balance excludes project development rights of $70 million relating to our Poland wind operations that were fully impaired in the third quarter of 2013 and subsequently sold in November 2013. See Note 23—Discontinued Operations and Held-for-Sale Businesses for further information.

(2)	Excludes net balance of sales concessions of $32 million as of December 31, 2013 relating to our utility businesses in Cameroon that were included in noncurrent assets of discontinued operations. See Note 23—Discontinued Operations and Held for Sale Businesses for further information.

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

(4)	Includes renewable energy certificates, land-use rights 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 costs and primarily consist of purchased electricity, energy transmission costs and sector costs that are considered volatile. These costs are passed through for a period of 12 months as part of the annual tariff adjustment. Any remaining balance is considered in the following annual tariff adjustment, 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 the 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 at 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 $22 million and $13 million, as of December 31, 2014 and 2013, respectively. Other noncurrent regulatory assets that did not earn a rate of return were $73 million and $71 million, as of December 31, 2014 and 2013, 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 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 in a December 17, 2014 order from the PUCO and began in 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)	Probability of recovery through future rates, based upon established regulatory practices, which permit the recovery of current taxes. This amount is expected to be recovered, without interest, over the period as book-tax temporary differences reverse and become current taxes.

(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 is retroactive to July 2011 and will be 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 is lower than the pre-existing tariff rate, Eletropaulo is required to reduce customer tariffs for this difference over the next year. Accordingly, from July 2011 through June 2012, Eletropaulo recognized a regulatory liability for such estimated future refunds, which was 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 contemplates an amortization of 67.55% as from July 4, 2013. The remaining balance, representing 32.45%, will be considered in the next annual tariff adjustment. As of December 31, 2014, Eletropaulo had recorded a current regulatory liability of $76 million.

(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 recover or 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 regulatory asset base resulting from an administrative ruling in December 2013 which compelled Eletropaulo to refund customers beginning in July 2014.

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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 $3.0 billion on non-recourse debt outstanding at December 31, 2014. 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 9.80%. 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.

(3)	There was no non-recourse debt excluded from non-recourse debt and included in current and noncurrent liabilities of held for sale and discontinued businesses in the accompanying Consolidated Balance Sheets as of December 31, 2014. There were $658 million excluded in 2013.

•	Mong Duong drew $364 million under its construction loan facility;

•	Angamos issued new debt of $800 million, offset by repayments of $780 million;

•	Gener issued new debt of $700 million, more than offset by repayments of $905 million;

•	Southland, Shady Point and Hawaii (collectively US Generation Holdings) issued new debt of $299 million;

•	Eletropaulo issued new debt of $253 million; offset by repayments of $110 million;

•	DPL issued new debt of $200 million; more than offset by repayments of $364 million;

•	Tietê issued new debt of $318 million, offset by repayments of $132 million;

•	Cochrane drew $305 million under its construction loans;

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•	Sul issued new debt of $185 million;

•	Southland made repayments of $188 million;

•	Chivor made repayments of $165 million;

•	UK Wind made repayments of $114 million; and

•	Warrior Run made repayments of $109 million.

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(i)	all of the capital stock of domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by the Company; and

(ii)	certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements.

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(1)	$1.1 billion of the total net unfunded projected benefit obligation is due to Eletropaulo in Brazil.

(1)	A U.S. subsidiary of the Company has a defined benefit obligation of $748 million and $651 million as of December 31, 2014 and 2013, respectively, and uses salary bands to determine future benefit costs rather than rates of compensation increases. Rates of compensation increases in the table above do not include amounts related to this specific defined benefit plan.

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

•	discount rates;

•	salary growth;

•	retirement rates;

•	inflation;

•	expected return on plan assets; and

•	mortality rates.

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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 meet or exceed the assumed actuarial rate; and

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

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

(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.

•	US SBU;

•	Andes SBU;

•	Brazil SBU;

•	MCAC SBU;

•	Europe SBU (formerly EMEA); and

•	Asia SBU.

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(1)	Adjusted pretax contribution in each segment before intersegment eliminations includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees and the write-off of intercompany balances.

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(1)

Excludes revenue of $2 million, $23 million and $63 million for the years ended December 31, 2014, 2013 and 2012, respectively, and property, plant and equipment of $69 million as of December 31, 2013, related to Condon, Mid-West Wind, Red Oak and Ironwood which are reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

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(2)

Excludes revenue of $230 million, $473 million and $457 million for the years ended December 31, 2014, 2013 and 2012, respectively, and property, plant and equipment of $1,100 million as of December 31, 2013, related to Dibamba, Kribi and Sonel, which are reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

(3)	Excludes revenue of $187 million and $491 million for the years ended December 31, 2013 and 2012, respectively, related to Kievoblenergo and Rivnooblenergo, which are reflected as discontinued operations in the accompanying Consolidated Statements of Operations.

(4)	Excludes revenue of $18 million for the year ended December 31, 2012, related to Tisza II, which is reflected as discontinued operations in the accompanying Consolidated Statements of Operations.

(5)

Excludes revenue of $6 million and $11 million for the years ended December 31, 2013 and 2012, respectively, and property, plant and equipment of $19 million as of December 31, 2013, related to Saurashtra and our carbon reduction projects, which are reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

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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);

•	Tisza II (sold in December 2012);

•	Red Oak and Ironwood (sold in April 2012);

•	Eastern Energy in New York (disposed of in December 2012).

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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;

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•	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

•	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 $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.

(2)

Includes a pretax gain of approximately $283 million for the second 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 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. See Note 8—Investments In And Advances To Affiliates for further discussion.

(3)	Includes pretax impairment expense of $48 million, $0 million, $196 million and $352 million, for the first, second, third and fourth quarters of 2013, 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. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $14.78 (excluding PSU and RSU awards), with 13,859,232 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 $18.62. 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,

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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.

(D)

The AES Corporation Incentive Stock Option Plan adopted in 1991 provided for 57,500,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $35.44. This plan terminated on June 1, 2001, such that no additional grants may be granted under the plan after that date. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance in light of this plan’s termination and thus 24,354,930 shares are not included in Column (c) above.

(2)	Includes 4,993,450 (of which 832,757 are vested and 4,160,693 are unvested) shares underlying PSU and RSU awards (assuming performance at a maximum level), 1,487,156 shares underlying Director stock unit awards, and 7,061,847 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 13,542,453 shares.

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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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