AES CORP - Annual Report: 2019 (Form 10-K)

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•	the economic climate, particularly the state of the economy in the areas in which we operate and the state of the economy in China, which impacts demand for electricity in many of our key markets, 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 fulfill our obligations, 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;

•	our ability to receive funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise;

•	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 operate power generation, distribution and transmission facilities, including managing availability, outages and equipment failures;

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

•	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, wildfires and low levels of wind or sunlight for our wind and solar facilities;

•	the performance of our contracts by our contract counterparties, including suppliers or customers;

•	severe weather and natural disasters;

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•	our ability to raise sufficient capital to fund development projects or to successfully execute our development projects;

•	the success of our initiatives in renewable energy projects and energy storage projects;

•	the availability of government incentives or policies that support the development of renewable energy generation projects;

•	our ability to keep up with advances in technology;

•	changes in number of customers or in customer usage;

•	the operations of our joint ventures and equity method investments that we do not control;

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

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

•	changes in laws, rules and regulations affecting our utilities businesses, 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 government policies or tax incentives;

•	changes in environmental laws, including requirements for reduced emissions, GHG legislation, regulation, and/or treaties and CCR regulation and remediation;

•	changes in tax laws, including U.S. tax reform, and challenges to our tax positions;

•	the effects of litigation and government and regulatory investigations;

•	the performance of our acquisitions;

•	our ability to maintain adequate insurance;

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

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

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

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

•	our ability to attract and retain talented directors, management and other personnel;

•	cyber-attacks and information security breaches; and

•	data privacy.

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•	As of December 31, 2019, our backlog of 6,145 MW includes:

◦	3,009 MW under construction and coming on-line through 2021; and

◦	3,136 MW of renewables signed under long-term PPAs

•	We completed construction of 2,181 MW of new projects, including:

◦	1,320 MW OPGC 2 plant in India; and

◦	861 MW of solar, wind and energy storage globally

•	We finalized a joint venture in the Dominican Republic to expand our LNG capacity by 50 TBTU

•	We received approval from the Government of Vietnam to develop the 2.2 GW Son My 2 combined cycle gas turbine (CCGT) power plant

•	Our joint venture with Siemens, Fluence, is the global leader in the fast-growing energy storage market, which is expected to increase from 6 GW of installed capacity in 2017, to more than 40 GW by 2022

◦	Fluence has been awarded or delivered 1.7 GW of projects, including 961 MW awarded in 2019

•	We announced the merger of Simple Energy to form Uplight, which is the market leader in providing cloud-based digital energy solutions in the U.S.

•	We formed a 10-year strategic alliance with Google to develop and implement solutions to enable broad adoption of clean energy

•	Following our efforts to strengthen our balance sheet, our Parent Company credit rating was upgraded to investment grade (BBB-) by Fitch and our BB+ credit rating was raised to Positive outlook by S&P

•	We are executing on $100 million in annual run rate cost savings from digital initiatives, including utilizing data and technology for maintenance, outage prevention, inspection and procurement, to be realized by 2022

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(1)	Unconsolidated entity, accounted for as an equity affiliate.

(2)	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.

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(1)

DPL's GWh sold in 2019 represent DP&L's (DPL's subsidiary) total transmission and distribution sales. DPL's wholesale revenues and DP&L's Standard Service Offer (SSO) utility revenues, which are sales to utility customers who use DP&L to source their electricity through a competitive bid process, were 3,913 GWh in 2019. DPL's other primary subsidiary, AES Ohio Generation, LLC, owns an undivided interest in Conesville Unit 4. In October 2018, the co-owner of Conesville Unit 4 announced that the plant will be retired by May 2020. 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 is approximately 103 MW.

(2)

CDPQ owns direct and indirect interests in IPALCO which total approximately 30%. AES owns 85% of AES US Investments and AES US Investments owns 82.35% of IPALCO. IPL plants: Georgetown, Harding Street, Petersburg and Eagle Valley. 20 MW of IPL total is considered a transmission asset. In December 2019, IPL announced it would be retiring Petersburg Unit 1 in June 2021 and Petersburg Unit 2 in June 2023, a total of 630 MW. IPL issued an all-source Request for Proposal in December 2019 in order to competitively procure replacement capacity.

(1)	Project achieved commercial operations in February 2020.

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•	regulatory outcomes;

•	the passage of new legislation, implementation of regulations or other changes in regulation; and

•	the timely recovery of capital expenditures.

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•	the passage of new legislation, new regulations or other changes in regulation;

•	timely recovery of transmission and distribution expenditures; and

•	exiting remaining generation assets currently owned by AES Ohio Generation.

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•	improved operational performance; and

•	plant availability.

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•	improved operational performance;

•	variability in energy demand driven by weather; and

•	fuel oil prices impact energy tariff prices, which affect cash flow due to a three month delay in the passthrough of energy costs to the tariffs charged to customers.

•	The National Energy Council is the highest authority on energy policy and strategy, and the coordinating body for the different energy sectors. One of its main objectives is to promote investment in non-conventional renewable sources to diversify the energy matrix.

•	The General Superintendence of Electricity and Telecommunications regulates the market and sets consumer prices, and, jointly with the distribution companies in El Salvador, developed the tariff calculation applicable from 2018 until 2022. The next tariff calculation is scheduled for 2022, and will be effective starting 2023.

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(1)	Gener - Chile plants: Alfalfal, Andes Solar, Laguna Verde, Laja, Los Cururos, Maitenes, Norgener 1, Norgener 2, Queltehues, Ventanas 1, Ventanas 2, Ventanas 3, Ventanas 4 and Volcán.

(2)	Guacolda is comprised of five coal-fired units under Guacolda Energia S.A., an unconsolidated entity for which the results of operations are reflected in Net equity in earnings of affiliates. The Company's ownership in Guacolda is held through AES Gener, a 67%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 33%.

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

(4)	AES operates this facility through management or O&M agreements and to date owns no equity interest in the business.

(5)	Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mogi-Guaçu, Nova Avanhandava, Promissão, Sao Joaquim and Sao Jose.

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(1)	Project achieved commercial operations in February 2020.

(2)	Alto Maipo is the largest project in construction in the Chilean market. When completed, it will include 75 km of tunnels, two power houses and 17 km of transmission lines.

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•	dry hydrology scenarios;

•	forced outages;

•	changes in current regulatory rulings altering the ability to pass through or recover certain costs;

•	fluctuations of the Chilean peso;

•	tax policy changes;

•	legislation promoting renewable energy and/or more restrictive regulations on thermal generation assets; and

•	market price risk when re-contracting.

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•	forced outages;

•	fluctuations of the Colombian peso; and

•	spot market prices.

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•	forced outages;

•	exposure to fluctuations of the Argentine peso;

•	changes in hydrology;

•	timely collection of FONINVEMEM installments and outstanding receivables (see Regulatory Framework and Market Structure below); and

•	natural gas prices and availability for contracted generation.

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•	hydrology, impacting quantity of energy generated in MRE (see Regulatory Framework and Market Structure below for further information);

•	growth in demand for energy;

•	market price risk when re-contracting;

•	asset management;

•	cost management; and

•	ability to execute on its growth strategy.

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(1)	Plant also includes an adjacent regasification facility, as well as a 70 TBTU LNG storage tank.

(2)	Unconsolidated entity, accounted for as an equity affiliate.

(3)	Plant also includes an adjacent regasification facility, as well as an 80 TBTU LNG storage tank in operation since August 2019.

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

•	contracting levels and the extent of capacity awarded;

•	supply shortages in the near term (next two to three years) may provide opportunities for short-term upside, but new generation came online in 2019; and

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

•	The National Energy Commission drafts and coordinates the legal framework and regulatory legislation. They propose and adopt policies and procedures to implement best practices, support the proper functioning and development of the energy sector, and promote investment.

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The Superintendence of Electricity's main responsibilities include monitoring compliance with legal provisions, rules, and technical procedures governing generation, transmission, distribution and commercialization of electricity. They monitor behavior in the electricity market in order to avoid monopolistic practices. In addition to the two agencies responsible for monitoring compliance with the General Electricity Law, the Ministry of Industry and Commerce supervises commercial and industrial activities in the Dominican Republic as well as the fuels and natural gas commercialization to end users.

•	changes in hydrology which impacts commodity prices and exposes the business to variability in the cost of replacement power;

•	fluctuations in commodity prices, mainly oil and natural gas, affect the cost of thermal generation and spot prices;

•	constraints imposed by the capacity of transmission lines connecting the west side of the country with the load, keeping surplus power trapped during the wet season; and

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

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•	The SNE has the responsibilities of planning, supervising and controlling policies of the energy sector within Panama. With these responsibilities, the SNE proposes laws and regulations to the executive agencies that regulate the procurement of energy and hydrocarbons for the country.

•	The regulator of public services, known as the ASEP, is an autonomous agency of the government. ASEP is responsible for the control and oversight of public services, including electricity, the transmission and distribution of natural gas utilities, and the companies that provide such services.

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The National Dispatch Center implements the economic dispatch of electricity in the wholesale market. The National Dispatch Center's objectives are to minimize the total cost of generation and maintain the reliability and security of the electric power system. Short-term power prices are determined on an hourly basis by the last dispatched generating unit. Physical generation of energy is determined by the National Dispatch Center regardless of contractual arrangements.

•	as the companies are fully contracted, improved operational performance provides additional benefits, including performance incentives and/or excess energy sales; and

•	changes in the methodology to calculate spot energy prices or Locational Marginal Prices, which impacts the excess energy sales to the CFE (see Regulatory Framework and Market Structure below) in (i) TEG and TEP under self-supply scheme, and (ii) Mesa La Paz under the New Market Rules.

•	The Energy Regulatory Commission is responsible for the establishment of directives, orders, methodologies and standards to regulate the electric and fuel markets.

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

•	The CFE owns the transmission and distribution grids and it is also the country's basic supplier. CFE is the offtaker for IPP generators, and together with its own power units has more than 50% of the current generation market share.

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(1)	Unconsolidated entity, accounted for as an equity affiliate.

(2)	Entered into an agreement to sell these businesses in 2019.

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•	regulatory changes in the Bulgaria power market;

•	results of the DG Comp review;

•	availability of the operating units;

•	the level of wind resources for St. Nikola;

•	spot market price volatility beyond the level of compensation through the Contract for Premium for St. Nikola; and

•	NEK's ability to meet the payment terms of the PPA contract with Maritza.

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•	operating performance of the facility;

•	regulatory and environmental policy changes;

•	tariff determination by the OERC; and

•	PPA provisions and energy trading.

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•	Redondo Beach Unit 7 - September 30, 2019

•	Huntington Beach Unit 1 - December 31, 2019

•	Alamitos Units 1, 2, and 6 - December 31, 2019

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•	risks associated with our operations;

•	risks associated with governmental regulation and laws; and

•	risks related to our indebtedness and financial condition.

•	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

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•	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.

•	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, fiscal or environmental policies;

•	high inflation and monetary fluctuations;

•	restrictions on imports of solar panels, wind turbines, 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;

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•	unexpected delays in permitting and governmental approvals;

•	unexpected changes or instability affecting our strategic partners in developing countries;

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risks relating to the failure to comply with the U.S. Foreign Corrupt Practices Act, UK Bribery Act or other anti-bribery laws applicable to our operations, including, among other things, cost and disruption in responding to allegations or investigations (regardless of ultimate finding), civil and/or criminal fines, criminal prosecution of individuals, revocation or suspension of permits and/or licenses, civil litigation, reputational damage, loss in share price, and loss of business;

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

•	unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and less beneficial 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;

•	potentially adverse tax consequences of operating in multiple jurisdictions; and

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

•	plant availability in the markets generally;

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

•	competition;

•	seasonality;

•	hydrology and other weather conditions;

•	illiquid markets;

•	transmission, transportation constraints, inefficiencies and/or availability;

•	renewables source contribution to the supply stack;

•	new entrants;

•	increased adoption of distributed generation;

•	energy efficiency and demand side resources;

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

•	generating unit performance;

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

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

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•	general economic conditions globally as well as in areas where we operate that impact demand and energy consumption; and

•	bidding behavior and market bidding rules.

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•	technologies that change the utilization of electric generation, transmission and distribution assets, including the expanded cost-effective utilization of distributed generation (e.g., rooftop solar and community solar projects), and energy storage technology;

•	advances in distributed and local power generation and energy storage that reduce the demand for large-scale renewable electricity generation and/or impact our customers’ ability to perform under long-term agreements; and

•	more cost-effective batteries for energy storage, advances in solar or wind technology, and advances in alternative fuels and other alternative energy sources.

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•	impact our operations and strategic objectives;

•	impact our customer and vendor relationships;

•	result in substantial revenue loss;

•	expose us to legal claims and/or regulatory investigations and proceedings;

•	require extensive repair and restoration costs for additional security measures to avert future cyber-attacks; and

•	impair our reputation and limit our competitiveness for future opportunities.

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

•	such businesses will perform as expected;

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

•	we will not incur unforeseen obligations or liabilities;

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

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

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

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

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

•	adverse changes in tax law;

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

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

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

•	changes in the timing of tariff increases;

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

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

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

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

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

•	reducing available 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 may have provided to or on behalf of such subsidiary;

•	triggering defaults in The AES Corporation's outstanding debt. For example, The AES Corporation's senior secured credit facility, secured term loan, and outstanding senior notes include events of default for certain

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

•	principal repayments of debt;

•	interest;

•	acquisitions;

•	construction and other project commitments;

•	other equity commitments, including business development investments;

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

•	taxes; and

•	Parent Company overhead costs.

•	dividends and other distributions from its subsidiaries;

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

•	proceeds from asset sales.

•	general economic and capital market conditions;

•	the availability of bank credit;

•	the financial condition, performance and prospects of The AES Corporation in general and/or that of any subsidiary requiring the financing;

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•	the financial condition, performance and prospects of other companies in our industry or with similar financial circumstances; and

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

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(1)

Includes pre-tax gains on sales of business interests of $28 million, $984 million, $29 million, and $29 million for the years ended December 31, 2019, 2018, 2016, and 2015, respectively, and pre-tax losses of $52 million for the year ended December 31, 2017; pre-tax impairment expense of $185 million, $208 million, $537 million, $1.1 billion, and $602 million for the years ended December 31, 2019, 2018, 2017, 2016, and 2015, respectively; other-than-temporary impairment of equity method investments of $92 million and $147 million for the years ended December 31, 2019 and 2018; income tax expense of $194 million and $675 million related to the one-time transition tax on foreign earnings, and income tax benefit of $77 million and expense of $39 million related to the remeasurement of deferred tax assets and liabilities to the lower corporate tax rate for the years ended December 31, 2018 and 2017, respectively; and net equity in losses of affiliates, primarily at Guacolda, of $172 million, for the year ended December 31, 2019. See Note 25—Held-for-Sale and Dispositions, Note 22—Asset Impairment Expense, Note 8—Investments in and Advances to Affiliates and Note 23—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

(2)

Includes gain on sale of $199 million and loss on deconsolidation of $611 million related to Eletropaulo for the years ended December 31, 2018 and 2017, respectively, and impairment expense of $382 million and loss on sale of $737 million related to Sul for the year ended December 31, 2016. See Note 24—Discontinued Operations included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

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•	$229 million in South America primarily driven by lower generation and prices in Argentina and lower contract sales and generation in Chile;

•	$173 million in Eurasia primarily due to the sales of the Masinloc power plant in March 2018 and the Northern Ireland businesses in June 2019; and

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$172 million in US and Utilities primarily driven by the closure of generation facilities at DPL in the first half of 2018 and Shady Point in May 2019, and lower energy prices and sales due to higher temperatures and other favorable market conditions present in 2018 as compared to 2019 at Southland, partially offset by price increases due to the 2018 rate orders at IPL and DPL and an increase in energy pass-through costs in El Salvador.

•	$107 million in South America primarily due to the drivers discussed above;

•	$46 million in MCAC due to the outage at Changuinola as a result of upgrading the tunnel lining and lower hydrology in Panama as compared to the prior year, partially offset by the business interruption insurance

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•	$31 million in Eurasia primarily due to the drivers discussed above, partially offset by lower depreciation at the Jordan plants due to their classification as held-for-sale.

•	$357 million in South America primarily due to higher contract sales and prices in Colombia and the commencement of new PPAs at Angamos and Cochrane in Chile, as well as higher capacity prices in Argentina resulting from market reforms enacted in 2017;

•	$215 million in MCAC primarily due to to the commencement of operations at the Colon combined cycle facility as well as improved hydrology at Panama, higher pass-through fuel prices in Mexico, higher contracted energy sales due to commencement of operations at the Los Mina combined cycle facility in June 2017, and higher spot prices in the Dominican Republic; and

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$68 million in US and Utilities driven primarily by higher market energy sales at Southland, higher regulated rates commencing in November 2017 at DPL, higher wholesale volume due to the new CCGT coming online as well as higher retail demand at IPL, and higher prices due to tariff reset and higher energy prices in El Salvador, partially offset by the sale and closure of several generation facilities at DPL.

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•	$154 million in South America primarily due to the drivers discussed above and the absence of maintenance costs for planned outages in 2018 versus maintenance performed in Q3 2017 at Gener Chile;

•	$70 million in MCAC primarily due to drivers discussed above; and

•	$40 million in US and Utilities mostly due to the drivers discussed above and the favorable impact of a one time reduction in the ARO liability at DPL's closed plants, Stuart and Killen.

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(1)	Primarily associated with the peso-denominated energy receivable indexed to the USD through the FONINVEMEM agreement which is considered a foreign currency derivative. See Note 7—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

(2)	Includes losses of $31 million, gains of $23 million, and losses of $21 million on foreign currency derivative contracts for the years ended December 31, 2019, 2018 and 2017, respectively.

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•	Prior year gains on sales of Electrica Santiago and CTNG in Chile;

•	Lower earnings in Chile primarily due to current year long-lived asset impairment at Guacolda, losses on extinguishment of debt and lower contracted energy sales and prices;

•	HLBV allocation of losses to noncontrolling interests at Distributed Energy as a result of renewable projects reaching COD in 2019; and

•	Lower earnings in Panama primarily due to lower hydrology and the outage at Changuinola as a result of upgrading the tunnel lining.

•	Prior year other-than-temporary impairment of Guacolda.

•	Other-than-temporary impairment of Guacolda;

•	Favorable impact of a legal settlement at Uruguaiana in 2017; and

•	Lower earnings due to deconsolidation of Eletropaulo in November 2017 and the sale of Masinloc in March 2018.

•	Gains on sales of Electrica Santiago and CTNG in Chile;

•	Higher earnings in Colombia primarily due to higher contract sales and prices; and

•	Higher earnings in Vietnam due to the adoption of the new revenue recognition standard.

•	Prior year gains on the sales of Masinloc, Eletropaulo (reflected within discontinued operations), CTNG and Electrica Santiago, net of tax;

•	Current year long-lived asset impairments at Guacolda, Hawaii, Kilroot and Ballylumford, and other-than-temporary impairment at OPGC;

•	Current year loss on sale at Kilroot and Ballylumford;

•	Current year losses on extinguishment of debt at DPL, AES Gener, Mong Duong and Colon;

•	Current year losses recognized at commencement of sales-type leases at Distributed Energy;

•	The impact of sold businesses in our Eurasia SBU;

•	Lower margins at Argentina and Chile, primarily due to lower generation; and

•	Lower margins at Changuinola, driven by the outage as a result of upgrading the tunnel lining and lower hydrology in Panama.

•	Prior year income tax expense to finalize the initial impact of U.S. tax reform enacted in December 2017;

•	Prior year loss on extinguishment of debt at the Parent Company;

•	Prior year long-lived asset impairments at Shady Point and Nejapa, and other-than-temporary impairment at Guacolda;

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•	Current year gains on insurance proceeds associated with the lightning incident at the Andres facility in 2018 and the Changuinola tunnel leak;

•	Current year gain on sale of a portion of our interest in sPower’s operating assets and gain on disposal of Stuart and Killen at DPL; and

•	Higher earnings at our US and Utilities SBU, primarily as a result of renewable projects that came online in the current year.

•	Gains on the sales of Masinloc, Eletropaulo (reflected within discontinued operations), CTNG, and Electrica Santiago in 2018, and losses on the sales of Kazakhstan CHPs and HPPs in 2017;

•	Loss on deconsolidation of Eletropaulo (reflected within discontinued operations) in 2017;

•	Impact of U.S. tax reform enacted in December 2017;

•	Asset impairments at DPL, Laurel Mountain and in Kazakhstan in 2017;

•	Lower interest expense at the Parent Company and Gener; and

•	Higher margins at our South America, MCAC and US and Utilities SBUs.

•	Higher tax expense in 2018 due to the new GILTI rules in the U.S.;

•	Asset impairment at Shady Point and other-than-temporary impairment of Guacolda;

•	Higher losses on extinguishment of debt;

•	Foreign exchange losses in 2018 primarily due to the devaluation of the Argentine peso and foreign currency gains in 2017;

•	Favorable impact of a legal settlement at Uruguaiana in 2017; and

•	Lower margins at our Eurasia SBU as a result of the sales of Masinloc and Kazakhstan.

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(1)	The allocation of HLBV earnings to noncontrolling interests is not adjusted out of Adjusted Operating Margin.

(2)	In February 2018, the Company announced a reorganization as a part of its ongoing strategy to simplify its portfolio, optimize its cost structure and reduce its carbon intensity.

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(1)	In February 2018, the Company announced a reorganization as a part of its ongoing strategy to simplify its portfolio, optimize its cost structure and reduce its carbon intensity.

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(1)	Amount primarily relates to unrealized derivative losses in Argentina of $89 million, or $0.13 per share, mainly associated with foreign currency derivatives on government receivables.

(2)	Amount primarily relates to unrealized FX losses in Argentina of $25 million, or $0.04 per share, mainly associated with the devaluation of long-term receivables denominated in Argentine pesos, and unrealized FX losses at the Parent Company of $12 million, or $0.02 per share, mainly associated with intercompany receivables denominated in Euro.

(3)	Amount primarily relates to unrealized FX losses of $22 million, or $0.03 per share, associated with the devaluation of long-term receivables denominated in Argentine pesos, and unrealized FX losses of $14 million, or $0.02 per share, on intercompany receivables denominated in Euro and British pounds at the Parent Company.

(4)

Amount primarily relates to losses recognized at commencement of sales-type leases at Distributed Energy of $36 million, or $0.05 per share, and loss on sale of Kilroot and Ballylumford of $31 million, or $0.05 per share; partially offset by gain on sale of a portion of our interest in sPower’s operating assets of $28 million, or $0.04 per share, gain on disposal of Stuart and Killen at DPL of $20 million, or $0.03 per share, and gain on sale of ownership interest in Simple Energy as part of the Uplight merger of $12 million, or $0.02 per share.

(5)

Amount primarily relates to gain on sale of Masinloc of $772 million, or $1.16 per share, gain on sale of CTNG of $86 million, or $0.13 per share, gain on sale of Electrica Santiago of $36 million, or $0.05 per share, gain on remeasurement of contingent consideration at AES Oahu of $32 million, or $0.05 per share, gain on sale related to the Company's contribution of AES Advancion energy storage to the Fluence joint venture of $23 million, or $0.03 per share, and realized derivative gains associated with the sale of Eletropaulo of $21 million, or $0.03 per share; partially offset by loss on disposal of the Beckjord facility and additional shutdown costs related to Stuart and Killen at DPL of $21 million, or $0.03 per share.

(6)

Amount primarily relates to loss on sale of Kazakhstan CHPs of $49 million, or $0.07 per share, realized derivative losses associated with the sale of Sul of $38 million, or $0.06 per share, loss on sale of Kazakhstan HPPs of $33 million, or $0.05 per share, and costs associated with early plant closures at DPL of $24 million, or $0.04 per share; partially offset by gain on Masinloc contingent consideration of $23 million, or $0.03 per share, and gain on sale of Miami Fort and Zimmer of $13 million, or $0.02 per share.

(7)

Amount primarily relates to asset impairments at Kilroot and Ballylumford of $115 million, or $0.17 per share, and Hawaii of $60 million, or $0.09 per share; impairments at our Guacolda and sPower equity affiliates, impacting equity earnings by $105 million, or $0.16 per share, and $21 million, or $0.03 per share, respectively; and other-than-temporary impairment of OPGC of $92 million, or $0.14 per share.

(8)	Amount primarily relates to asset impairments at Shady Point of $157 million, or $0.24 per share, and Nejapa of $37 million, or $0.06 per share, and other-than-temporary impairment of Guacolda of $96 million, or $0.14 per share.

(9)	Amount primarily relates to asset impairments at Kazakhstan CHPs of $94 million, or $0.14 per share, Kazakhstan HPPs of $92 million, or $0.14 per share, Laurel Mountain of $121 million, or $0.18 per share, DPL of $175 million, or $0.27 per share, and Kilroot of $37 million, or $0.05 per share.

(10)	Amount primarily relates to losses on early retirement of debt at DPL of $45 million, or $0.07 per share, AES Gener of $35 million, or $0.05 per share, Mong Duong of $17 million, or $0.03 per share, and Colon of $14 million, or $0.02 per share.

(11)	Amount primarily relates to loss on early retirement of debt at the Parent Company of $171 million, or $0.26 per share.

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(12)	Amount primarily relates to losses on early retirement of debt at the Parent Company of $92 million, or $0.14 per share, AES Gener of $20 million, or $0.02 per share, and IPALCO of $9 million, or $0.01 per share; partially offset by a gain on early retirement of debt at AES Argentina of $65 million, or $0.10 per share.

(13)	Amount relates to a SAB 118 charge to finalize the provisional estimate of one-time transition tax on foreign earnings of $194 million, or $0.29 per share, partially offset by a SAB 118 income tax benefit to finalize the provisional estimate of remeasurement of deferred tax assets and liabilities to the lower corporate tax rate of $77 million, or $0.11 per share.

(14)	Amount relates to a one-time transition tax on foreign earnings of $675 million, or $1.02 per share, and the remeasurement of deferred tax assets and liabilities to the lower corporate tax rate of $39 million, or $0.06 per share.

(15)

Amount primarily relates to the income tax benefits associated with the impairments at OPGC of $23 million, or $0.03 per share, Guacolda of $13 million, or $0.02 per share, Hawaii of $13 million, or $0.02 per share, and Kilroot and Ballylumford of $11 million, or $0.02 per share, and income tax benefits associated with losses on early retirement of debt of $24 million, or $0.04 per share; partially offset by an adjustment to income tax expense related to 2018 gains on sales of business interests, primarily Masinloc, of $25 million, or $0.04 per share.

(16)

Amount primarily relates to the income tax expense under the GILTI provision associated with the gains on sales of business interests, primarily Masinloc, of $97 million, or $0.15 per share, and income tax expense associated with gains on sale of CTNG of $36 million, or $0.05 per share, and Electrica Santiago of $13 million, or $0.02 per share; partially offset by income tax benefits associated with the loss on early retirement of debt at the Parent Company of $36 million, or $0.05 per share, and income tax benefits associated with the impairment at Shady Point of $33 million, or $0.05 per share.

(17)	Amount primarily relates to the income tax benefits associated with asset impairments of $148 million, or $0.22 per share.

(1)	A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business for the respective ownership interest for key businesses.

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(1)	A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business for the respective ownership interest for key businesses.

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(1)	A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business for the respective ownership interest for key businesses.

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(1)	A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business for the respective ownership interest for key businesses.

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(1)	The change in adjusted net income is defined as the variance in net income, net of the total adjustments to net income as shown on the Consolidated Statements of Cash Flows in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.

(2)	The change in working capital is defined as the variance in total changes in operating assets and liabilities as shown on the Consolidated Statements of Cash Flows in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.

	Amounts included in the chart above include the results of discontinued operations, where applicable.

•	Adjusted net income decreased $24 million primarily due to lower margins at our South America and MCAC SBUs. These impacts were partially offset by the current year gains on insurance recoveries associated with the lightning incident at the Andres facility in 2018 and the Changuinola tunnel leak, and higher margins at our US and Utilities SBU.

•

Working capital requirements decreased $147 million, primarily due to higher collections of overdue receivables from distribution companies in the Dominican Republic, higher collections of insurance receivables at Andres, and lower supplier payments and VAT recoveries at Gener. These impacts were partially offset by a decrease in income tax liabilities at Argentina as a result of lower operating margin and income tax rates, and higher supplier payments and prior year collections at Puerto Rico.

(1)	The change in adjusted net income is defined as the variance in net income, net of the total adjustments to net income as shown on the Consolidated Statements of Cash Flows in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.

(2)	The change in working capital is defined as the variance in total changes in operating assets and liabilities as shown on the Consolidated Statements of Cash Flows in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.

	Amounts included in the chart above include the results of discontinued operations, where applicable.

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•	Adjusted net income decreased $40 million primarily due to lower margins at our Eurasia SBU and a 2017 favorable impact at Uruguaiana as a result of a legal settlement. These impacts were partially offset by higher margins in 2018 at our South America, MCAC and US and Utilities SBUs.

•

Working capital requirements increased $121 million, primarily due to higher insurance receivables at Andres, deconsolidation of Eletropaulo, lower collections at Los Mina and Itabo, and the timing of payments on coal purchases at Gener. These impacts were partially offset by the collections on the construction performance obligation from the offtaker at Vietnam, higher CAMMESA collections at Alicura, and the timing of payments on coal purchases at Puerto Rico.

•	Proceeds from dispositions decreased $1.8 billion, primarily due to the sales of Masinloc, Electrica Santiago, CTNG, Eletropaulo, and the DPL Peaker assets in 2018; partially offset by the sale of a portion of our interest in a portfolio of sPower’s operating assets and the sale of the Kilroot and Ballylumford plants in the United Kingdom in 2019.

•	Contributions and loans to equity affiliates increased $179 million, primarily due to project funding requirements at sPower.

•	Capital expenditures increased $284 million, discussed further below.

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•	Growth expenditures increased $130 million, primarily due to higher investments in solar projects at Distributed Energy and renewable energy projects in Argentina; partially offset by a decrease in payments for the Southland re-powering projects.

•	Maintenance expenditures increased $173 million, primarily at Andres as a result of the steam turbine lightning damage, at DPL from storm damages, and at Changuinola due to the upgrade of the tunnel lining.

•	Environmental expenditures decreased $19 million, primarily at IPALCO due to lower spending for NAAQS, NPDES and CCR rule compliance.

•	Proceeds from dispositions increased by $1.9 billion, primarily due to the sales of Masinloc, Electrica Santiago, Eletropaulo, CTNG and the DPL Peaker assets in 2018, partially offset by the sale of the Kazakhstan CHPs in 2017 and transaction costs incurred for the Beckjord sale.

•	Payments for the acquisitions of business interests decreased by $543 million, primarily due to the acquisitions of sPower and Alto Sertão II in 2017.

•	Cash resulting from net purchases of short-term investments decreased by $339 million, primarily due to the sale of Eletropaulo.

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•	Capital expenditures decreased $56 million, discussed further below.

•	Growth expenditures increased $114 million, primarily due to higher spending for the Southland re-powering project; partially offset by lower spending resulting from the completion of the Colon project and the completion of the combined cycle project at Los Mina.

•	Maintenance expenditures decreased $129 million, primarily due to the deconsolidation of Eletropaulo in Q4 2017.

•	Environmental expenditures decreased $41 million, primarily at IPALCO due to lower spending for NPDES compliance.

•	The $483 million impact from recourse debt activity is primarily due to higher net repayments of Parent Company debt in the prior year.

•	The $387 million impact from Parent Company revolver transactions is primarily from higher repayments in the prior year, and higher borrowings in 2019 for general corporate cash management activities.

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•	The $480 million impact from non-recourse debt transactions is primarily due to net issuances at Gener, Alto Maipo and DPL, which were partially offset by net repayments at Tietê, and lower net issuances in 2018 at IPALCO.

•	The $278 million impact from non-recourse revolver transactions is primarily due to higher net borrowings at DPL and prior year net repayments at IPALCO.

•	The $605 million impact from recourse debt activity is primarily due to higher net repayments of Parent Company debt.

•	The $413 million impact from Parent Company revolver transactions is primarily from lower borrowings for general corporate cash management activities.

•	The $269 million impact from non-recourse debt transactions is primarily due to lower net issuances at AES Argentina, Tietê, Colon, Alto Maipo, U.S. Generation and Los Mina, which were partially offset by 2017 net repayments at Gener and IPALCO.

•	The $370 million impact from non-recourse revolver transactions is primarily due to higher net repayments at IPALCO and Gener.

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•	reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default;

•	triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;

•	causing us to record a loss in the event the lender forecloses on the assets; and

•	triggering defaults in our outstanding debt at the Parent Company.

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

(2)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 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, 2019.

(3)

These amounts do not include current liabilities on the Consolidated Balance Sheet except for the current portion of uncertain tax obligations. Noncurrent uncertain tax obligations are reflected in the "Other" column of the table above as the Company is not able to reasonably estimate the timing of the future payments. In addition, these amounts do not include: (1) regulatory liabilities (See Note 10—Regulatory Assets and Liabilities), (2) contingencies (See Note 13—Contingencies), (3) pension and other postretirement employee benefit liabilities (see Note 15—Benefit Plans), (4) derivatives and incentive compensation (See Note 6—Derivative Instruments and Hedging Activities) or (5) any taxes (See Note 23—Income Taxes) except for uncertain tax obligations, as the Company is not able to reasonably estimate the timing of future payments. See the indicated notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on the items excluded.

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

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

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•	Level 1: Quoted prices in active markets for identical assets or liabilities;

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Level 2: Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; or

•	Level 3: Unobservable inputs that are supported by little or no market activity and that are significant to the fair values of the assets or liabilities.

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•	The package of practical expedients (applied to all leases) that allowed lessees and lessors not to reassess:

a.	whether any expired or existing contracts are or contain leases,

b.	lease classification for any expired or existing leases, and

c.	whether initial direct costs for any expired or existing leases qualify for capitalization under ASC 842.

•	The transition practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements, and

•	The transition practical expedient for lessees that allowed businesses to not separate lease and non-lease components. The Company applied the practical expedient to all classes of underlying assets when valuing right-of-use assets and lease liabilities. Contracts where the Company is the lessor were separated between the lease and non-lease components.

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(1)	Proceeds in the year ended December 31, 2018 include $119 million of non-cash proceeds from non-convertible debentures at Guaimbê Solar Complex. See Note 26—Acquisitions for further information.

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

(2)	See Note 22—Asset Impairment Expense for further information.

(3)	Per the Company's policy, pre-tax loss is limited to the impairment of long-lived assets. Any additional loss will be recognized on completion of the sale. See Note 22—Asset Impairment Expense and Note 25—Held-for-Sale and Dispositions for further information.

(1)

These amounts primarily relate to amounts due from CAMMESA, the administrator of the wholesale electricity market in Argentina, and amounts impacted by the Stabilization Fund enacted by the Chilean government and are included in Other noncurrent assets in the accompanying Consolidated Balance Sheets. The fair value and carrying amount of the Argentina receivables exclude VAT of $11 million and $16 million as of December 31, 2019 and 2018, respectively.

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(1)	Cash flow hedge was discontinued on a cross-currency swap in 2019 because the underlying debt was prepaid. Cash flow hedge was discontinued in 2017 because it was probable the forecasted transaction will not occur.

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

(2)	Simple Energy merged with Tendril on July 1, 2019 to form Uplight. Prior year information reported relates to Simple Energy.

(3)	The Eólica Mesa La Paz project received funding throughout 2019 and began operations during December 2019.

(4)	Represents a VIE in which the Company holds a variable interest, but is not the primary beneficiary.

(5)	Includes Bosforo, Fluence, Distributed Energy equity method investments, and others.

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(1)	Goodwill and accumulated impairment losses at the Eurasia reportable segment were reduced by $122 million due to the sale of Kilroot in 2019.

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

(2)	Acquired or purchased emissions allowances are finite-lived intangible assets that are expensed when utilized and included in net income for the year.

(3)	Includes management rights, sales concessions, renewable energy credits and incentives, and other individually insignificant intangible assets.

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(1)	Past expenditures on which the Company earns a rate of return.

•	Undercollections on rate riders such as wholesale margin sharing and MISO costs at IPL and storm costs at DPL;

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

•	OVEC costs at DPL.

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

(2)	Excludes $3 million (current) and $67 million (noncurrent) finance lease liabilities included in the respective non-recourse debt line items on the Consolidated Balance Sheet as of December 31, 2019. See Note 14—Leases for further information.

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(1)	Issuances relate to the June 2017 long-term non-recourse debt financing to fund the Southland re-powering construction projects, a non-recourse bridge loan in September 2019, and long-term non-recourse debt financing issued in December 2019 to settle the bridge loan.

(2)	Includes transactions at DPL and its subsidiary, DP&L.

(3)	Non-cash transaction via an equity affiliate. See below for further information.

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(1)	Classified as current held-for-sale liability on the Consolidated Balance Sheets.

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

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

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

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

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

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

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

(2)

In 2019, the U.S. plans moved all investments except cash and cash equivalents into collective trusts; therefore, the 2019 balances under the equity securities, debt securities, and real estate categories shown above represent investments through collective trusts. The plans have chosen collective trusts for which the underlying investments are mutual funds, mutual funds for which debt securities are the primary underlying investment, or real estate in alignment with the target asset allocation.

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

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

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(1)	Includes Puerto Rico revenues of $294 million, $257 million and $247 million for the years ended December 31, 2019, 2018 and 2017, respectively, and property, plant & equipment of $538 million and $553 million as of December 31, 2019 and 2018, respectively.

(2)	The Mong Duong II power project is operated under a build, operate and transfer contract. Future expected payments for the construction performance obligation are recognized in Loan receivable on the Consolidated Balance Sheets. See Note 20—Revenue for further information.

(3)	The Kilroot and Ballylumford property, plant and equipment was deconsolidated upon completion of the sale in June 2019. See Note 25—Held-For-Sale and Dispositions for further information.

(4)	The property, plant and equipment in Jordan was classified as held-for-sale as of December 31, 2019. See Note 25—Held-For-Sale and Dispositions for further information.

(5)	The Masinloc property, plant and equipment was classified as held-for-sale as of December 31, 2017, and deconsolidated upon completion of the sale in March 2018. See Note 25—Held-For-Sale and Dispositions for further information.

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

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(1)	Other non-regulated revenue primarily includes lease and derivative revenue not accounted for under ASC 606.

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(1)	Associated with recoveries for property damage at the Andres facility in the Dominican Republic from a lightning incident in September 2018 and the upgrade of the tunnel lining at Changuinola.

(2)	Related to the amendment of the Oahu purchase agreement. See Note 26 —Acquisitions for further information.

(3)	In December 2016, the Company and YPF entered into a settlement in which all parties agreed to give up any and all legal action related to gas supply contracts that were terminated in 2008 and have been in dispute since 2009. In January 2017, the YPF board approved the agreement and paid the Company $60 million, thereby resolving all uncertainties around the dispute.

(4)	Related to losses recognized at commencement of sales-type leases at Distributed Energy. See Note 14—Leases for further information.

(5)	Associated with a loss due to damage from a lightning incident at the Andres facility in the Dominican Republic in September 2018 and a loss associated with upgrading the tunnel lining at Changuinola in 2019.

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(1)	Includes a loss contingency recognized by our equity method investment in discontinued operations.

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(1)	After the retirement of Stuart and Killen in 2018, the Company entered into contracts to buy back all open capacity years for the plants at prices lower than the PJM capacity revenue prices. As such, the Company continued to earn capacity margin until the plants were transferred in December 2019.

(2)	Reductions in the asset retirement obligations for ash ponds and landfills at Stuart and Killen in 2018 resulted in a $32 million reduction to cost of sales. See Note 4—Asset Retirement Obligations for further information.

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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 solar panels, wind turbines, coal, oil, gas, or other raw materials required by our generation businesses to operate;

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

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

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

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

•	adverse changes in government tax policy;

•	potentially adverse tax consequences of operating in multiple jurisdictions; and

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

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•	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 $1.1 billion of debt to Mong Duong Finance Holdings B.V., an SPV accounted for as an equity affiliate as of December 31, 2019 (See Note 11—Debt); $415 million and $382 million of debt to Banco General S.A., a bank in Panama where our minority partner in Colon is part of its board of directors as of December 31, 2019 and 2018, respectively; and $287 million and $165 million of debt to Strabag, our EPC contractor and minority partner in Alto Maipo as of December 31, 2019 and 2018, respectively.

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(1)	Includes pre-tax impairment expense of $116 million and $69 million, in the second and fourth quarters of 2019, respectively (See Note 22—Asset Impairment Expense), other-than-temporary impairment of OPGC of $92 million and net equity in losses of affiliates, primarily at Guacolda, of $175 million, in the fourth quarter of 2019 (See Note 8—Investments in and Advances to Affiliates).

(2)

Includes pre-tax gains on sales of business interests of $788 million, $89 million and $128 million, in the first, second and fourth quarters of 2018, respectively, and pre-tax losses of $21 million in the third quarter of 2018 (See Note 25—Held-for-Sale and Dispositions), pre-tax impairment expense of $92 million, $74 million and $42 million, in the second, third and fourth quarters of 2018, respectively (See Note 22—Asset Impairment Expense), other-than-temporary impairment of Guacolda of $144 million in the fourth quarter of 2018 (See Note 8—Investments in and Advances to Affiliates), SAB 118 charges to finalize the provisional estimate of one-time transition tax on foreign earnings of $33 million and $161 million in the third and fourth quarters of 2018, respectively, and a SAB 118 income tax benefit to finalize the provisional estimate of remeasurement of deferred tax assets and liabilities to the lower corporate tax rate of $77 million in the fourth quarter of 2018 (See Note 23—Income Taxes).

(3)	Includes gain on sale of Eletropaulo of $199 million in the second quarter of 2018 (See Note 24—Discontinued Operations).

•	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

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

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

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

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

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

(a)	Security Ownership of Certain Beneficial Owners and Management.

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

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

(A)

The AES Corporation 2003 Long Term Compensation Plan was adopted in 2003 and provided for 17,000,000 shares authorized for issuance thereunder. In 2008, an amendment to the Plan to provide an additional 12,000,000 shares was approved by AES' stockholders, bringing the total authorized shares to 29,000,000. In 2010, an additional amendment to the Plan to provide an additional 9,000,000 shares was approved by AES' stockholders, bringing the total authorized shares to 38,000,000. In 2015, an additional amendment to the Plan to provide an additional 7,750,000 shares was approved by AES' stockholders, bringing the total authorized shares to 45,750,000. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $12.54 (excluding performance stock units, restricted stock units and director stock units), with 13,964,029 shares available for future issuance.

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(B)

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 142,811 shares is not included in Column (c) above.

(2)	Includes 3,214,738 (of which 477,532 are vested and 2,737,206 are unvested) shares underlying PSU and RSU awards (assuming 2017 and 2018 PSUs median performance and 2019 PSU maximum performance), 1,654,985 shares underlying Director stock unit awards, and 3,177,764 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 8,047,487 shares.

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(a)	Financial Statements.

(b)	Exhibits.

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(c)	Schedule

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