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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.

•

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.

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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.

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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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The AES Corporation is a holding company (the "Parent Company") that, through its subsidiaries and affiliates, (collectively, "AES" or "the Company") operates a geographically diversified portfolio of electricity generation and distribution businesses. Generally, the liabilities of individual operating entities are non-recourse to the Parent Company and are isolated to the operating entities. Most of our operating entities are structured as limited liability entities, which limit the liability of shareholders. The structure is generally the same regardless of whether a subsidiary is consolidated under a voting or variable interest model. The preparation of these consolidated financial statements is in conformity with accounting principles generally accepted in the United States of America ("U.S. GAAP").

PRINCIPLES OF CONSOLIDATION — The consolidated financial statements of the Company include the accounts of The AES Corporation and its controlled subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, have been consolidated. Intercompany transactions and balances are eliminated in consolidation. Investments in entities where the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting.

NONCONTROLLING INTERESTS — Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income and comprehensive income attributable to noncontrolling interests are reflected separately from consolidated net income and comprehensive income on the Consolidated Statements of Operations and Consolidated Statements of Changes in Equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests (unless the transaction qualified as a sale of in-substance real estate). Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.

Equity securities with redemption features that are not solely within the control of the issuer are classified outside of permanent equity.  Generally, initial measurement will be at fair value. Subsequent measurement and classification vary depending on whether the instrument is probable of becoming redeemable. When the equity instrument is not probable of becoming redeemable, subsequent allocation of income and dividends is classified in permanent equity. For those securities where it is probable that the instrument will become redeemable or that are currently redeemable, AES recognizes changes in the fair value at each accounting period against retained earnings or additional paid-in-capital in the absence of retained earnings, subject to the floor of the initial fair value. Further, the allocation of income and dividends, as well as the adjustment to fair value, is classified outside permanent equity. Instruments that are mandatorily redeemable are classified as a liability.

EQUITY METHOD INVESTMENTS — Investments in entities over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting and reported in Investments in and advances to affiliates on the Consolidated Balance Sheets. The Company’s proportionate share of the net income or loss of these companies is included in Net equity in earnings (losses) of affiliates on the Consolidated Statements of Operations.

The Company utilizes the cumulative earning approach to determine whether distributions received from equity method investees are returns on investment or returns of investment. The Company discontinues the application of the equity method when an investment is reduced to zero and the Company is not otherwise committed to provide further financial support to the investee. The Company resumes the application of the equity method accounting to the extent that net income is greater than the share of net losses not previously recorded.

Upon acquiring the investment, we determine the fair value of the identifiable assets and assumed liabilities and the basis difference between each fair value and the carrying amount of the corresponding asset or liability in the financial statements of the investee. The AES share of the amortization of the basis difference is recognized in Net equity in earnings of affiliates in the Consolidated Statements of Operations over the life of the asset or liability.

The Company periodically assesses if impairment indicators exist at our equity method investments. When an impairment is observed, any excess of the carrying amount over its estimated fair value is recognized as impairment expense when the loss in value is deemed other-than-temporary and included in Other non-operating expense in the Consolidated Statements of Operations.

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BUSINESS INTERESTS — Acquisitions and disposals of business interests are generally transactions pertaining to operational legal entities, which may be accounted for as a consolidated business, an asset, or an equity method investment. Losses on expected sales of business interests are limited to the impairment of long-lived assets as of the date of execution of the sales agreement, which are recognized in Asset impairment expense in the Consolidated Statements of Operations. Any additional gains/(losses) on sales, which are primarily due to reclassification of cumulative translation adjustments, are recognized in Gain (loss) on disposal and sale of business interests in the Consolidated Statements of Operations upon completion of the sale.

ALLOCATION OF EARNINGS — Certain of the Company's businesses are subject to profit-sharing arrangements where the allocation of cash distributions and the sharing of tax benefits are not based on fixed ownership percentages. These arrangements exist for certain U.S. renewable generation partnerships to designate different allocations of value among investors, where the allocations change in form or percentage over the life of the partnership. For these businesses, the Company uses the hypothetical liquidation at book value (“HLBV”) method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions.

The HLBV method is used both to allocate the equity earnings attributable to AES when the Company accounts for the renewable business as an equity method investment and to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.

USE OF ESTIMATES — U.S. GAAP requires the Company to make estimates and assumptions that affect the asset and liability balances reported as of the date of the consolidated financial statements, as well as the revenues and expenses recognized during the reporting period. Actual results could differ from those estimates. Items subject to such estimates and assumptions include: the carrying amount and estimated useful lives of long-lived assets; asset retirement obligations; impairment of goodwill, long-lived assets and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of regulatory assets; regulatory liabilities; the fair value of financial instruments; the fair value of assets and liabilities acquired as business combinations or as asset acquisitions by variable interest entities; contingent consideration arising from business combinations or asset acquisitions by variable interest entities; the measurement of equity method investments or noncontrolling interest using the HLBV method for certain renewable generation partnerships; the determination of whether a sale of noncontrolling interests is considered to be a sale of in-substance real estate (as opposed to an equity transaction); pension liabilities; the incremental borrowing rates used in the determination of lease liabilities; the determination of lease and non-lease components in certain generation contracts; environmental liabilities; and potential litigation claims and settlements.

HELD-FOR-SALE DISPOSAL GROUPS— A disposal group classified as held-for-sale is reflected on the balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the carrying amount of the disposal group exceeds its estimated fair value less cost to sell. This loss is limited to the carrying value of long-lived assets until the completion of the sale, at which point, any additional loss is recognized. If the fair value of the disposal group subsequently exceeds the carrying amount while the disposal group is still held-for-sale, any impairment expense previously recognized will be reversed up to the lesser of the previously recognized expense or the subsequent excess.

Assets and liabilities related to a disposal group classified as held-for-sale are segregated in the current balance sheet in the period in which the disposal group is classified as held-for-sale. Assets and liabilities of held-for-sale disposal groups are classified as current when they are expected to be disposed of within twelve months. Transactions between the held-for-sale disposal group and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See Note 25—Held-for-Sale and Dispositions for further information.

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DISCONTINUED OPERATIONS — Discontinued operations reporting occurs only when the disposal of a business or a group of businesses represents a strategic shift that has (or will have) a major effect on the Company's operations and financial results. The Company reports financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the Consolidated Statements of Operations and Consolidated Balance Sheets are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the Consolidated Statements of Cash Flows. 

Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value less cost to sell, including gains or losses associated with noncontrolling interests upon completion of the disposal transaction. Adjustments related to components previously reported as discontinued operations under prior accounting guidance are presented as discontinued operations in the current period even if the disposed-of component to which the adjustments are related would not meet the criteria for presentation as a discontinued operation under current guidance. See Note 24—Discontinued Operations for further information.

FAIR VALUE — Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly, hypothetical transaction between market participants at the measurement date, or exit price. The Company applies the fair value measurement accounting guidance to financial assets and liabilities in determining the fair value of investments in marketable debt and equity securities, included in the Consolidated Balance Sheet line items Short-term investments and Other noncurrent assets; derivative assets, included in Other current assets and Other noncurrent assets; and, derivative liabilities, included in Accrued and other liabilities (current) and Other noncurrent liabilities. The Company applies the fair value measurement guidance to nonfinancial assets and liabilities upon the acquisition of a business or an asset acquisition by a variable interest entity, or in conjunction with the measurement of an asset retirement obligation or a potential impairment loss on an asset group, equity method investments, or goodwill.

When determining the fair value measurements for assets and liabilities required to be reflected at their fair values, the Company considers the principal or most advantageous market in which it would transact and considers assumptions that market participants would use when pricing the assets or liabilities, such as inherent risk, transfer restrictions and risk of nonperformance. The Company is prohibited from including transaction costs and any adjustments for blockage factors in determining fair value.

In determining fair value measurements, the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs. Assets and liabilities are categorized within a fair value hierarchy based upon the lowest level of input that is significant to the fair value measurement:

•	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.

Any transfers between all levels within the fair value hierarchy levels are recognized at the end of the reporting period.

CASH AND CASH EQUIVALENTS — The Company considers unrestricted cash on hand, cash balances not restricted as to withdrawal or usage, deposits in banks, certificates of deposit and short-term marketable securities with original maturities of three months or less to be cash and cash equivalents.

RESTRICTED CASH AND DEBT SERVICE RESERVES — Cash balances restricted as to withdrawal or usage, primarily via contract, are considered restricted cash.

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The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows (in millions):

	December 31, 2019				December 31, 2018
Cash and cash equivalents	$	1,029			$	1,166
Restricted cash	336				370
Debt service reserves and other deposits	207				467
Cash, Cash Equivalents and Restricted Cash	$	1,572			$	2,003

INVESTMENTS IN MARKETABLE SECURITIES — The Company's marketable investments are primarily unsecured debentures, certificates of deposit, government debt securities and money market funds.

Short-term investments consist of marketable equity securities and debt securities with original maturities in excess of three months with remaining maturities of less than one year. Marketable debt securities where the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at amortized cost. Remaining marketable debt securities are classified as available-for-sale or trading and are carried at fair value.

Unrealized gains or losses on available-for-sale debt securities are reflected in AOCL, a separate component of equity, and the Consolidated Statements of Operations, respectively. Unrealized gains or losses on equity investments are reported in Other income. Interest and dividends on investments are reported in Interest income and Other income, respectively. Gains and losses on sales of investments are determined using the specific identification method.

ACCOUNTS AND NOTES RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS — Accounts and notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable, considering factors such as historical collection experience, the age of accounts receivable and other currently available evidence supporting collectability, and records an allowance for doubtful accounts for the estimated uncollectible amount as appropriate. Certain of our businesses charge interest on accounts receivable. Interest income is recognized on an accrual basis. When collection of such interest is not reasonably assured, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectible.

INVENTORY — Inventory primarily consists of fuel and other raw materials used to generate power, and operational spare parts and supplies used to maintain power generation and distribution facilities. Inventory is carried at lower of cost or net realizable value. Cost is the sum of the purchase price and expenditures incurred to bring the inventory to its existing location. Inventory is primarily valued using the average cost method. Generally, if it is expected fuel inventory will not be recovered through revenue earned from power generation, an impairment is recognized to reflect the fuel at market value. The carrying amount of spare parts and supplies is typically reduced only in instances where the items are considered obsolete.

LONG-LIVED ASSETS — Long-lived assets include property, plant and equipment, assets under finance leases and intangible assets subject to amortization (i.e., finite-lived intangible assets).

Property, plant and equipment — Property, plant and equipment are stated at cost, net of accumulated depreciation. The cost of renewals and improvements that extend the useful life of property, plant and equipment are capitalized.

Construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction in progress are capitalized during the construction period, provided the completion of the construction project is deemed probable, or expensed at the time construction completion is determined to no longer be probable. The continued capitalization of such costs is subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. Construction-in-progress balances are transferred to electric generation and distribution assets when an asset group is ready for its intended use. Government subsidies, liquidated damages recovered for construction delays, and income tax credits are recorded as a reduction to property, plant and equipment and reflected in cash flows from investing activities. Maintenance and repairs are charged to expense as incurred.

Depreciation, after consideration of salvage value and asset retirement obligations, is computed using the straight-line method over the estimated useful lives of the assets, which are determined on a composite or component basis. Capital spare parts, including rotable spare parts, are included in electric generation and

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distribution assets. If the spare part is considered a component, it is depreciated over its useful life after the part is placed in service. If the spare part is deemed part of a composite asset, the part is depreciated over the composite useful life even when being held as a spare part.

Certain of the Company's subsidiaries operate under concession contracts. Certain estimates are utilized to determine depreciation expense for the subsidiaries, including the useful lives of the property, plant and equipment and the amounts to be recovered at the end of the concession contract. The amounts to be recovered under these concession contracts are based on estimates that are inherently uncertain and actual amounts recovered may differ from those estimates. These concession contracts are not within the scope of ASC 853—Service Concession Arrangements.

Intangible Assets Subject to Amortization — Finite-lived intangible assets are amortized over their useful lives which range from 1 – 50 years and are included in the Consolidated Balance Sheet line item Other intangible assets. The Company accounts for purchased emission allowances as intangible assets and records an expense when they are utilized or sold. Granted emission allowances are valued at zero.

Impairment of Long-lived Assets — When circumstances indicate the carrying amount of long-lived assets in a held-for-use asset group may not be recoverable, the Company evaluates the assets for potential impairment using internal projections of undiscounted cash flows resulting from the use and eventual disposal of the assets. Events or changes in circumstances that may necessitate a recoverability evaluation include, but are not limited to, adverse changes in the regulatory environment, unfavorable changes in power prices or fuel costs, increased competition due to additional capacity in the grid, technological advancements, declining trends in demand, or an expectation it is more likely than not that the asset will be disposed of before the end of its previously estimated useful life. If the carrying amount of the assets exceeds the undiscounted cash flows, an impairment expense is recognized for the amount by which the carrying amount of the asset group exceeds its fair value (subject to the carrying amount not being reduced below fair value for any individual long-lived asset that is determinable without undue cost and effort). An impairment expense for certain assets may be reduced by the establishment of a regulatory asset if recovery through approved rates is probable.

SERVICE CONCESSION ASSETS — Service concession assets are stated at cost, net of accumulated amortization, in accordance with ASC 853. Service concession assets represent the cost of all infrastructure to be transferred to the public-sector entity grantors at the end of the concession. These costs primarily represent construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction of the service concession infrastructure. Government subsidies, liquidated damages recovered for construction delays and income tax credits are recorded as a reduction to Service Concession Assets. Service concession assets are amortized and recognized in earnings as a cost of goods sold as infrastructure construction revenue is recognized. Services provided under concession arrangements are recognized on a straight line basis.

DEBT ISSUANCE COSTS — Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows used in financing activities.

GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS — The Company evaluates goodwill and indefinite-lived intangible assets for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. The Company's annual impairment testing date is October 1^st.

Goodwill — Goodwill represents the excess of the purchase price of the business acquisition over the fair value of identifiable net assets acquired. Goodwill resulting from an acquisition is assigned to the reporting units that are expected to benefit from the synergies of the acquisition. Generally, each AES business with a goodwill balance constitutes a reporting unit as they are not similar to other businesses in a segment nor are they reported to segment management together with other businesses.

Goodwill is evaluated for impairment either under the qualitative assessment option or the quantitative test option to determine the fair value of the reporting unit. If goodwill is determined to be impaired, an impairment loss measured at the amount by which the reporting unit’s carrying amount exceeds its fair value, not to exceed the carrying amount of goodwill, is recorded.

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Indefinite-Lived Intangible Assets — The Company's indefinite-lived intangible assets primarily include land-use rights and water rights. Indefinite-lived intangible assets are evaluated for impairment either under the qualitative assessment option or the two-step quantitative test. If the carrying amount of an intangible asset being tested for impairment exceeds its fair value, the excess is recognized as impairment expense.

ACCOUNTS PAYABLE AND OTHER ACCRUED LIABILITIES — Accounts payable consists of amounts due to trade creditors related to the Company's core business operations. These payables include amounts owed to vendors and suppliers for items such as energy purchased for resale, fuel, maintenance, inventory and other raw materials. Other accrued liabilities include items such as income taxes, regulatory liabilities, legal contingencies and employee-related costs, including payroll, and benefits.

REGULATORY ASSETS AND LIABILITIES — The Company recognizes assets and liabilities that result from regulated ratemaking processes. Regulatory assets generally represent incurred costs which have been deferred due to the probable future recovery via customer rates. Generally, returns earned on regulatory assets are reflected in the Consolidated Statement of Operations within Interest Income. Regulatory liabilities generally represent obligations to refund customers. Management continually assesses whether regulatory assets are probable of future recovery and regulatory liabilities are probable of future payment by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities, and the status of any pending or potential deregulation legislation. If future recovery of costs previously deferred ceases to be probable, the related regulatory assets are written off and recognized in income from continuing operations.

PENSION AND OTHER POSTRETIREMENT PLANS — The Company recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in actuarial gains or losses recognized in AOCL, except for those plans at certain of the Company's regulated utilities that can recover portions of their pension and postretirement obligations through future rates. All plan assets are recorded at fair value. AES follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

INCOME TAXES — Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax basis. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company's tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company's policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

The Company has elected to treat GILTI as an expense in the period in which the tax is accrued. Accordingly, no deferred tax assets or liabilities are recorded related to GILTI.

ASSET RETIREMENT OBLIGATIONS — The Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.

FOREIGN CURRENCY TRANSLATION — A business's functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is a currency other than the U.S. dollar translate their assets and liabilities into U.S. dollars at the current exchange rates in effect at the end of the fiscal period. Adjustments arising from the translation of the balance sheet of such subsidiaries are included in AOCL. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. dollars at the average exchange rates for the period. Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in AOCL. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency

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other than the functional currency are included in determining net income. Accumulated foreign currency translation adjustments are reclassified from AOCL to net income only when realized upon sale or upon complete or substantially complete liquidation of the investment in a foreign entity. The accumulated adjustments are included in carrying amounts in impairment assessments where the Company has committed to a plan that will cause the accumulated adjustments to be reclassified to earnings.

REVENUE RECOGNITION — Revenue is earned from the sale of electricity from our utilities and the production and sale of electricity and capacity from our generation facilities. Revenue is recognized upon the transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.

Utilities — Our utilities sell electricity directly to end-users, such as homes and businesses, and bill customers directly. The majority of our utility contracts have a single performance obligation, as the promises to transfer energy, capacity, and other distribution and/or transmission services are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. Utility revenue is classified as regulated on the Consolidated Statements of Operations.

In exchange for the right to sell or distribute electricity in a service territory, our utility businesses are subject to government regulation. This regulation sets the framework for the prices (“tariffs”) that our utilities are allowed to charge customers for electricity. Since tariffs are determined by the regulator, the price that our utilities have the right to bill corresponds directly with the value to the customer of the utility's performance completed in each period. The Company also has some month-to-month contracts. Revenue under these contracts is recognized using an output method measured by the MWh delivered each month, which best depicts the transfer of goods or services to the customer, at the approved tariff.

The Company has businesses where it sells and purchases power to and from ISOs and RTOs. Our utility businesses generally purchase power to satisfy the demand of customers that is not contracted through separate PPAs. In these instances, the Company accounts for these transactions on a net hourly basis because the transactions are settled on a net hourly basis. In limited situations, a utility customer may choose to receive generation services from a third-party provider, in which case the Company may serve as a billing agent for the provider and recognize revenue on a net basis.

Generation — Most of our generation fleet sells electricity under contracts to customers such as utilities, industrial users, and other intermediaries. Our generation contracts, based on specific facts and circumstances, can have one or more performance obligations as the promise to transfer energy, capacity, and other services may or may not be distinct depending on the nature of the market and terms of the contract. As the performance obligations are generally satisfied over time and use the same method to measure progress, the performance obligations meet the criteria to be considered a series. In measuring progress toward satisfaction of a performance obligation, the Company applies the "right to invoice" practical expedient when available, and recognizes revenue in the amount to which the Company has a right to consideration from a customer that corresponds directly with the value of the performance completed to date. Revenue from generation businesses is classified as non-regulated on the Consolidated Statements of Operations.

For contracts determined to have multiple performance obligations, we allocate revenue to each performance obligation based on its relative standalone selling price using a market or expected cost plus margin approach. Additionally, the Company allocates variable consideration to one or more, but not all, distinct goods or services that form part of a single performance obligation when (1) the variable consideration relates specifically to the efforts to transfer the distinct good or service and (2) the variable consideration depicts the amount to which the Company expects to be entitled in exchange for transferring the promised good or service to the customer.

Revenue from generation contracts is recognized using an output method, as energy and capacity delivered best depicts the transfer of goods or services to the customer. Performance obligations including energy or ancillary services (such as operations and maintenance and dispatch services) are generally measured by the MWh delivered. Capacity, which is a stand-ready obligation to deliver energy when required by the customer, is measured using MWs. In certain contracts, if plant availability exceeds a contractual target, the Company may receive a performance bonus payment, or if the plant availability falls below a guaranteed minimum target, we may incur a non-availability penalty. Such bonuses or penalties represent a form of variable consideration and are estimated and recognized when it is probable that there will not be a significant reversal.

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In assessing whether variable quantities are considered variable consideration or an option to acquire additional goods and services, the Company evaluates the nature of the promise and the legally enforceable rights in the contract. In some contracts, such as requirement contracts, the legally enforceable rights merely give the customer a right to purchase additional goods and services which are distinct. In these contracts, the customer's action results in a new obligation, and the variable quantities are considered an option.

When energy or capacity is sold or purchased in the spot market or to ISOs, the Company assesses the facts and circumstances to determine gross versus net presentation of spot revenues and purchases. Generally, the nature of the performance obligation is to sell surplus energy or capacity above contractual commitments, or to purchase energy or capacity to satisfy deficits. Generally, on an hourly basis, a generator is either a net seller or a net buyer in terms of the amount of energy or capacity transacted with the ISO. In these situations, the Company recognizes revenue for the hours where the generator is a net seller and cost of sales for the hours where the generator is a net buyer.

Certain generation contracts contain operating leases where capacity payments are generally considered lease elements. In such cases, the allocation between the lease and non-lease elements is made at the inception of the lease following the guidance in ASC 842.

The transaction price allocated to a construction performance obligation is recognized as revenue over time as construction activity occurs, with revenue being fully recognized upon completion of construction. These contracts may include a difference in timing between revenue recognition and the collection of cash receipts, which may be collected over the term of the entire arrangement. The timing difference could result in a significant financing component for the construction performance obligation if determined to be a material component of the transaction price. The Company accounts for a significant financing component under the effective interest rate method, recognizing a long-term receivable for the expected future payments related to the construction performance obligation in the Loan Receivable line item on the Consolidated Balance Sheets. As payments are collected from the customer over the term of the contract, consideration related to the construction performance obligation is bifurcated between the principal repayment of the long-term receivable and the related interest income, recognized in the Consolidated Statements of Operations.

Contract Balances — The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. Accounts receivable represent unconditional rights to consideration and consist of both billed amounts and unbilled amounts typically resulting from sales under long-term contracts when revenue recognized exceeds the amount billed to the customer. We bill both generation and utilities customers on a contractually agreed-upon schedule, typically at periodic intervals (e.g., monthly). The calculation of revenue earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month.

Our contract liabilities consist of deferred revenue which is classified as current or noncurrent based on the timing of when we expect to recognize revenue. The current portion of our contract liabilities is reported in Accrued and other liabilities and the noncurrent portion is reported in Other noncurrent liabilities on the Consolidated Balance Sheets.

Remaining Performance Obligations — The transaction price allocated to remaining performance obligations represents future consideration for unsatisfied (or partially unsatisfied) performance obligations at the end of the reporting period. The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the amount disclosed in Note 20—Revenue excludes contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled. As such, consideration for energy is excluded from the amount disclosed as the variable consideration relates to the amount of energy delivered and reflects the value the Company expects to receive for the energy transferred. Estimates of revenue expected to be recognized in future periods also exclude unexercised customer options to purchase additional goods or services that do not represent material rights to the customer.

LEASES — The Company has operating and finance leases for energy production facilities, land, office space, transmission lines, vehicles and other operating equipment in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.

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Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the subsidiaries’ incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its unsecured borrowings, which are then adjusted for the appropriate lease term and currency. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes the option to extend or terminate the lease if it is reasonably certain that the option will be exercised.

The Company has operating leases for certain generation contracts that contain provisions to provide capacity to a customer, which is a stand-ready obligation to deliver energy when required by the customer in which the Company is the lessor. Capacity payments are generally considered lease elements as they cover the majority of available output from a facility. The allocation of contract payments between the lease and non-lease elements is made at the inception of the lease. Lease payments from such contracts are recognized as lease revenue on a straight-line basis over the lease term, whereas variable lease payments are recognized when earned.

The Company has sales-type leases for battery energy storage systems ("BESS") in which the Company is the lessor. These arrangements allow customers the ability to determine when to charge and discharge the BESS, representing the transfer of control and constitutes the arrangement as a sales-type lease. Upon commencement of the lease, the book value of the leased asset is removed from the balance sheet and a net investment in sales-type lease is recognized based on the present value of fixed payments under the contract and the residual value of the underlying asset.

SHARE-BASED COMPENSATION — The Company grants share-based compensation in the form of stock options, restricted stock units, performance stock units, and performance cash units. The expense is based on the grant-date fair value of the equity or liability instrument issued and is recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. The Company uses a Black-Scholes option pricing model to estimate the fair value of stock options granted to its employees.

GENERAL AND ADMINISTRATIVE EXPENSES — General and administrative expenses include corporate and other expenses related to corporate staff functions and initiatives, primarily executive management, finance, legal, human resources and information systems, which are not directly allocable to our business segments. Additionally, all costs associated with corporate business development efforts are classified as general and administrative expenses.

DERIVATIVES AND HEDGING ACTIVITIES — Under the accounting standards for derivatives and hedging, the Company recognizes all contracts that meet the definition of a derivative, except those designated as normal purchase or normal sale at inception, as either assets or liabilities in the Consolidated Balance Sheets and measures those instruments at fair value. See Note 5—Fair Value and Fair value in this section for additional discussion regarding the determination of fair value.

PPAs and fuel supply agreements are evaluated to assess if they contain either a derivative or an embedded derivative requiring separate valuation and accounting. Generally, these agreements do not meet the definition of a derivative, often due to the inability to be net settled. On a quarterly basis, we evaluate the markets for commodities to be delivered under these agreements to determine if facts and circumstances have changed such that the agreements could be net settled and meet the definition of a derivative.

The Company typically designates its derivative instruments as cash flow hedges if they meet the criteria specified in ASC 815, Derivatives and Hedging. The Company enters into interest rate swap agreements in order to hedge the variability of expected future cash interest payments. Foreign currency contracts are used to reduce risks arising from the change in fair value of certain foreign currency denominated assets and liabilities. The objective of these practices is to minimize the impact of foreign currency fluctuations on operating results. The Company also enters into commodity contracts to economically hedge price variability inherent in electricity sales arrangements. The objectives of the commodity contracts are to minimize the impact of variability in spot electricity prices and stabilize estimated revenue streams. The Company does not use derivative instruments for speculative purposes.

For our hedges, changes in fair value are deferred in AOCL and are recognized into earnings as the hedged transactions affect earnings. If a derivative is no longer highly effective, hedge accounting will be discontinued

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prospectively. For cash flow hedges of forecasted transactions, AES estimates the future cash flows of the forecasted transactions and evaluates the probability of the occurrence and timing of such transactions.

Changes in the fair value of derivatives not designated and qualifying as cash flow hedges are immediately recognized in earnings. Regardless of when gains or losses on derivatives are recognized in earnings, they are generally classified as interest expense for interest rate and cross-currency derivatives, foreign currency transaction gains or losses for foreign currency derivatives, and non-regulated revenue or non-regulated cost of sales for commodity and other derivatives. Cash flows arising from derivatives are included in the Consolidated Statements of Cash Flows as an operating activity given the nature of the underlying risk being economically hedged and the lack of significant financing elements, except that cash flows on designated and qualifying hedges of variable-rate interest during construction are classified as an investing activity. The Company has elected not to offset net derivative positions in the financial statements.

NEW ACCOUNTING PRONOUNCEMENTS — The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on the Company’s consolidated financial statements.

New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606)	See discussion of the ASU below.	January 1, 2018	See impact upon adoption of the standard below.
2018-02, Income Statement — Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from AOCI	This amendment allows a reclassification of the stranded tax effects resulting from the implementation of the Tax Cuts and Jobs Act from AOCI to retained earnings at the election of the filer. Because this amendment only relates to the reclassification of the income tax effects of the Tax Cuts and Jobs Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected.	January 1, 2019	The Company has not elected to reclassify any amounts to retained earnings. The Company’s accounting policy for releasing the income tax effects from AOCI occurs on a portfolio basis.
2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities	The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.	January 1, 2019	The adoption of this standard resulted in a $4 million decrease to accumulated deficit.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606)	ASC 606 was adopted by sPower on January 1, 2019. sPower was not required to adopt ASC 606 using the public adoption date, as sPower is an equity method investee that meets the definition of a public business entity only by virtue of the inclusion of its summarized financial information in the Company’s SEC filings. Under the previous revenue standard, the payment received by sPower for the transfer of Incentive Tax Credits related to projects was deferred and recognized in revenue over time. Under ASC 606, this payment is recognized at a point in time.	January 1, 2019	The adoption of this standard resulted in a $6 million decrease to accumulated deficit attributable to the AES Corporation stockholders’ equity.
2016-02, 2018-01, 2018-10, 2018-11, 2018-20, 2019-01, Leases (Topic 842)	See discussion of the ASU below.	January 1, 2019	See impact upon adoption of the standard below.

ASC 842 — Leases

On January 1, 2019, the Company adopted ASC 842 Leases and its subsequent corresponding updates (“ASC 842”). Under this standard, lessees are required to recognize assets and liabilities for most leases on the balance sheet, and recognize expenses in a manner similar to the prior accounting method. For lessors, the guidance

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modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance eliminates previous real estate-specific provisions.

Under ASC 842, fewer of our contracts contain a lease. However, due to the elimination of the real estate-specific guidance and changes to certain lessor classification criteria, more leases qualify as sales-type leases and direct financing leases. Under these two models, a lessor derecognizes the asset and recognizes a lease receivable. According to ASC 842, the net investment in the lease includes the fair value of residual interest in the asset after the contract period as well as the present value of the fixed lease payments, but does not include any variable payments under the lease. Therefore, the net investment in the lease could be significantly different than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized net investment in the lease and the carrying amount of the underlying asset is recognized as a gain/loss at lease commencement.

During the course of adopting ASC 842, the Company applied various practical expedients including:

•	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.

The Company applied the modified retrospective method of adoption and elected to continue to apply the guidance in ASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, the Company applied the transition provisions starting at the date of adoption. The cumulative effect of the adoption of ASC 842 on our January 1, 2019 Consolidated Balance Sheet was as follows (in millions):

Consolidated Balance Sheet	Balance at December 31, 2018				Adjustments Due to ASC 842				Balance at January 1, 2019
Assets
Other noncurrent assets	$	1,514			$	253			$	1,767
Liabilities
Accrued and other liabilities	962				27				989
Other noncurrent liabilities	2,723				226				2,949

The primary impact of adoption was due to the recognition of a right-of-use-asset and lease liability for an operating land lease in Panama associated with the Colon LNG power plant and regasification terminal.

ASC 606 — Revenue from Contracts with Customers

On January 1, 2018, the Company adopted ASU 2014-09, "Revenue from Contracts with Customers," and its subsequent corresponding updates ("ASC 606"). Under this standard, an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company applied the modified retrospective method of adoption to the contracts that were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018 are presented under ASC 606, while prior period amounts were not adjusted and continue to be reported in accordance with the previous revenue recognition standard. For contracts that were modified before January 1, 2018, the Company reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price.

The cumulative effect to our January 1, 2018 Consolidated Balance Sheet resulting from the adoption of ASC 606 was as follows (in millions):

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Consolidated Balance Sheet	Balance at December 31, 2017				Adjustments Due to ASC 606				Balance at January 1, 2018
Assets
Other current assets	$	630			$	61			$	691
Deferred income taxes	130				(24		)		106
Service concession assets, net	1,360				(1,360		)		—
Loan receivable	—				1,490				1,490
Equity
Accumulated deficit	(2,276		)		67				(2,209		)
Accumulated other comprehensive loss	(1,876		)		19				(1,857		)
Noncontrolling interest	2,380				81				2,461

The Mong Duong II power plant in Vietnam is the primary driver of changes in revenue recognition under the new standard. This plant is operated under a build, operate, and transfer contract and will be transferred to the Vietnamese government after the completion of a 25-year PPA. Under the previous revenue recognition standard, construction costs were deferred to a service concession asset, which was expensed in proportion to revenue recognized for the construction element over the term of the PPA. Under ASC 606, construction revenue and associated costs are recognized as construction activity occurs. As construction of the plant was substantially completed in 2015, revenues and costs associated with the construction were recognized through retained earnings, and the service concession asset was derecognized. A loan receivable was recognized for the future expected payments for the construction performance obligation. As the payments for the construction performance obligation occur over a 25-year term, a significant financing element was determined to exist which is accounted for under the effective interest rate method. The other performance obligation to operate and maintain the facility is measured based on the capacity made available.

The impact to our Consolidated Balance Sheet as of December 31, 2018 resulting from the adoption of ASC 606 as compared to the previous revenue recognition standard was as follows (in millions):

	December 31, 2018
Consolidated Balance Sheet	As Reported				Balances Without Adoption of ASC 606				Adoption Impact
Assets
Other current assets	$	807			$	741			$	66
Deferred income taxes	97				122				(25		)
Service concession assets, net	—				1,261				(1,261		)
Loan receivable	1,423				—				1,423
TOTAL ASSETS	32,521				32,318				203
Equity
Accumulated deficit	(1,005		)		(1,112		)		107
Accumulated other comprehensive loss	(2,071		)		(2,088		)		17
Noncontrolling interest	2,396				2,317				79
TOTAL LIABILITIES AND EQUITY	32,521				32,318				203

The impact to our Consolidated Statement of Operations for the year ended December 31, 2018 resulting from the adoption of ASC 606 as compared to the previous revenue recognition standard was as follows (in millions):

	Year Ended December 31, 2018
Consolidated Statement of Operations	As Reported				Balances Without Adoption of ASC 606				Adoption Impact
Total revenue	$	10,736			$	10,800			$	(64	)
Total cost of sales	(8,163		)		(8,207		)		44
Operating margin	2,573				2,593				(20		)
Interest income	310				252				58
Other Income	72				70				2
Income from continuing operations before taxes and equity in earnings of affiliates	2,018				1,978				40
INCOME FROM CONTINUING OPERATIONS	1,349				1,309				40
NET INCOME	1,565				1,525				40
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	1,203				1,163				40

New Accounting Pronouncements Issued But Not Yet Effective — The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company’s consolidated financial statements once adopted. Accounting pronouncements not listed below were assessed and determined to

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be either not applicable or are expected to have no material impact on the Company’s consolidated financial statements.

New Accounting Standards Issued But Not Yet Effective
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2019-12, Income Taxes (Topic 740): Simplifying the Accounting For Income Taxes	The standard removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. It also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. Transition Method: various	January 1, 2021. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-13, 2018-19, 2019-04, 2019-05, 2019-10, 2019-11, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	See discussion of the ASU below.	January 1, 2020. Early adoption is permitted only as of January 1, 2019.	The Company will adopt the standard on January 1, 2020; see below for the evaluation of the impact of the adoption on the consolidated financial statements.

ASU 2016-13 and its subsequent corresponding updates will update the impairment model for financial assets measured at amortized cost, known as the Current Expected Credit Loss (“CECL”) model. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, there will be no change to the measurement of credit losses, except that unrealized losses due to credit-related factors will be recognized as an allowance on the balance sheet with a corresponding adjustment to earnings in the income statement. There are various transition methods available upon adoption.

The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements; however, it is expected that the new current expected credit loss model will primarily impact the calculation of the Company’s expected credit losses on $1.5 billion in gross trade accounts receivable, the $1.4 billion loan receivable at Mong Duong, $64 million in financing receivables in Argentina, and $33 million in financing receivables in Chile. The Company does not expect a material impact to result from the application of CECL on our trade accounts receivable; however, we are continuing to evaluate the potential impacts on our Mong Duong loan receivable and our financing receivables. In particular, the Company is finalizing our determination of the reasonable and supportable forecast period and the appropriate mix of relevant internal and external credit quality information for these types of financial assets, where we have no historical loss experience and limited external market data available. Estimated credit losses, if material, will be presented on the face of the balance sheet as an allowance that reduces the amortized cost basis of affected financial assets. The standard will also impact the presentation of expected credit-related losses (if any) for the Company’s $326 million of available-for-sale debt securities, which will be presented parenthetically as an allowance on the consolidated balance sheet.

Inventory is valued primarily using the average-cost method. The following table summarizes the Company's inventory balances as of the dates indicated (in millions):

December 31,		2019				2018
Fuel and other raw materials		$	230			$	300
Spare parts and supplies		257				277
Total		$	487			$	577

The following table summarizes the components of the electric generation and distribution assets and other property, plant and equipment (in millions) with their estimated useful lives (in years). The amounts are stated net of all prior asset impairment losses recognized.

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			December 31,
	Estimated Useful Life		2019				2018
Electric generation and distribution facilities	5-40		$	22,869			$	22,875
Other buildings	5-50		1,612				1,651
Furniture, fixtures and equipment	3-27		319				310
Other	5-40		583				406
Total electric generation and distribution assets and other			25,383				25,242
Accumulated depreciation			(8,505		)		(8,227		)
Net electric generation and distribution assets and other			$	16,878			$	17,015

The following table summarizes depreciation expense (including the amortization of assets recorded under finance leases in 2019 or capital leases in prior periods, and the amortization of asset retirement obligations) and interest capitalized during development and construction on qualifying assets for the periods indicated (in millions):

Years Ended December 31,		2019				2018				2017
Depreciation expense		$	977			$	960			$	1,005
Interest capitalized during development and construction		238				199				139

Property, plant and equipment, net of accumulated depreciation, of $10 billion and $11 billion was mortgaged, pledged or subject to liens as of December 31, 2019 and 2018, respectively, including assets classified as held-for-sale.

The following table summarizes regulated and non-regulated generation and distribution property, plant and equipment and accumulated depreciation as of the dates indicated (in millions):

December 31,		2019				2018
Regulated generation and distribution assets and other, gross		$	9,246			$	8,959
Regulated accumulated depreciation		(3,707		)		(3,504		)
Regulated generation and distribution assets and other, net		5,539				5,455
Non-regulated generation and distribution assets and other, gross		16,137				16,283
Non-regulated accumulated depreciation		(4,798		)		(4,723		)
Non-regulated generation and distribution assets and other, net		11,339				11,560
Net electric generation and distribution assets and other		$	16,878			$	17,015

4. ASSET RETIREMENT OBLIGATIONS

The following table presents amounts recognized related to asset retirement obligations for the periods indicated (in millions):

		2019				2018
Balance at January 1		$	415			$	368
Additional liabilities incurred		19				19
Liabilities settled		(12		)		(14		)
Accretion expense		21				18
Change in estimated cash flows		58				24
Sale of plants		(71		)		—
Other		(2		)		—
Balance at December 31		$	428			$	415

The Company's asset retirement obligations include active ash landfills, water treatment basins and the removal or dismantlement of certain plants and equipment. The Company uses the cost approach to determine the initial value of ARO liabilities, which is estimated by discounting expected cash outflows to their present value using market-based rates at the initial recording of the liabilities. Cash outflows are based on the approximate future disposal costs as determined by market information, historical information or other management estimates. Subsequent downward revisions of ARO liabilities are discounted using the market-based rates that existed when the liability was initially recognized. These inputs to the fair value of the ARO liabilities are considered Level 3 inputs under the fair value hierarchy.

During the year ended December 31, 2019, the Company increased the asset retirement obligation and corresponding asset at IPL by $75 million and decreased the asset retirement obligation at DPL by $87 million. The increase at IPL reflects an increase to estimated ash pond closure costs, including groundwater remediation as required by the EPA under the Resource Conservation and Recovery Act. The decrease at DPL was attributable to a revision of the estimated liabilities resulting from the retirement of the Stuart and Killen facilities, and their subsequent transfer in December 2019.

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During the year ended December 31, 2018, the $24 million increase in estimated cash flows was primarily attributable to an increase of $55 million in estimated ash pond closure costs and revised closure dates associated with an EPA rule regulating CCR at IPL and an increase in coal pile remediation costs at DPL. These were partially offset by a decrease of $32 million due to reductions in estimated closure costs associated with ash ponds and landfills at DPL resulting in a reduction to Cost of Sales on the Consolidated Statements of Operations.

The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The estimated fair values of the Company's assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Valuation Techniques — The fair value measurement accounting guidance describes three main approaches to measuring the fair value of assets and liabilities: (1) market approach, (2) income approach and (3) cost approach. The market approach uses prices and other relevant information generated from market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future amounts to a single present value amount. The measurement is based on current market expectations of the return on those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company measures its investments and derivatives at fair value on a recurring basis. Additionally, in connection with annual or event-driven impairment evaluations, certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis. These include long-lived tangible assets (i.e., property, plant and equipment), goodwill and intangible assets (e.g., sales concessions, land use rights and water rights, etc.). In general, the Company determines the fair value of investments and derivatives using the market approach and the income approach, respectively. In the nonrecurring measurements of nonfinancial assets and liabilities, all three approaches are considered; however, the value estimated under the income approach is often the most representative of fair value.

Investments — The Company's investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are either measured at fair value using quoted market prices or based on comparisons to market data obtained for similar assets. Debt securities primarily consist of unsecured debentures and certificates of deposit held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the market interest rates in Brazil. Debt securities are measured at fair value based on comparisons to market data obtained for similar assets.

Derivatives — Derivatives are measured at fair value using quoted market prices or the income approach utilizing volatilities, spot and forward benchmark interest rates (such as LIBOR and EURIBOR), foreign exchange rates, credit data, and commodity prices, as applicable. When significant inputs are not observable, the Company uses relevant techniques to determine the inputs, such as regression analysis or prices for similarly traded instruments available in the market.

The Company's methodology to fair value its derivatives is to start with any observable inputs; however, in certain instances the published forward rates or prices may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable inputs, such as proxy commodity prices or historical settlements to forecast forward prices. Specifically, where there is limited forward curve data with respect to foreign exchange contracts, beyond the traded points, the Company utilizes the interest rate differential approach to construct the remaining portion of the forward curve. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable requiring the use of proxy yield curves of similar credit quality.

To determine the fair value of a derivative, cash flows are discounted using the relevant spot benchmark interest rate. The Company then makes a credit valuation adjustment ("CVA"), as applicable, by further discounting the cash flows for nonperformance or credit risk based on the observable or estimated debt spread of the Company's subsidiary or its counterparty and the tenor of the respective derivative instrument. The CVA for potential future scenarios in which the derivative is in an asset position is based on the counterparty's credit ratings, credit default swap spreads, and debt spreads, as available. The CVA for potential future scenarios in which the derivative is in a liability position is based on the Parent Company's or the subsidiary's current debt spread. In the absence of readily obtainable credit information, the Parent Company's or the subsidiary's estimated credit rating (based on

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applying a standard industry model to historical financial information and then considering other relevant information) and spreads of comparably rated entities or the respective country's debt spreads are used as a proxy. All derivative instruments are analyzed individually and are subject to unique risk exposures.

The fair value hierarchy of an asset or a liability is based on the level of significance of the input assumptions. An input assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are classified as Level 3 when the use of unobservable inputs is significant. When the use of unobservable inputs is insignificant, assets and liabilities are classified as Level 2. Transfers between Level 3 and Level 2 result from changes in significance of unobservable inputs used to calculate the CVA.

Debt — Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated based upon interest rates and other features of the loan. In general, the carrying amount of variable rate debt is a close approximation of its fair value. For fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow ("DCF") analyses. The fair value of recourse and non-recourse debt excludes accrued interest at the valuation date. The fair value was determined using available market information as of December 31, 2019. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to December 31, 2019.

Nonrecurring measurements — For nonrecurring measurements derived using the income approach, fair value is generally determined using valuation models based on the principles of DCF. The income approach is most often used in the impairment evaluation of long-lived tangible assets, equity method investments, goodwill, and intangible assets. Where the use of market observable data is limited or not available for certain input assumptions, the Company develops its own estimates using a variety of techniques such as regression analysis and extrapolations. Depending on the complexity of a valuation, an independent valuation firm may be engaged to assist management in the valuation process.

For nonrecurring measurements derived using the market approach, recent market transactions involving the sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to identify sale transactions of identical or similar assets. This approach is used in impairment evaluations of certain intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.

For nonrecurring measurements derived using the cost approach, fair value is typically based upon a replacement cost approach. This approach involves a considerable amount of judgment, which is why its use is limited to the measurement of long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach.

Fair Value Considerations — In determining fair value, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk of the counterparty and the risk of the Company's or its counterparty's nonperformance. The conditions and criteria used to assess these factors are:

Sources of market assumptions — The Company derives most of its market assumptions from market efficient data sources (e.g., Bloomberg and Reuters). To determine fair value, where market data is not readily available, management uses comparable market sources and empirical evidence to develop its own estimates of market assumptions.

Market liquidity — The Company evaluates market liquidity based on whether the financial or physical instrument, or the underlying asset, is traded in an active or inactive market. An active market exists if the prices are fully transparent to market participants, can be measured by market bid and ask quotes, the market has a relatively large proportion of trading volume as compared to the Company's current trading volume and the market has a significant number of market participants that will allow the market to rapidly absorb the quantity of assets traded without significantly affecting the market price. Another factor the Company considers when determining whether a market is active or inactive is the presence of government or regulatory controls over pricing that could make it difficult to establish a market-based price when entering into a transaction.

Nonperformance risk — Nonperformance risk refers to the risk that an obligation will not be fulfilled and affects the value at which a liability is transferred or an asset is sold. Nonperformance risk includes, but may not be limited to, the Company or its counterparty's credit and settlement risk. Nonperformance risk adjustments are dependent on credit spreads, letters of credit, collateral, other arrangements available and the nature of master netting arrangements. The Company is party to various interest rate swaps and options; foreign currency options and forwards; and derivatives and embedded derivatives, which subject the Company to nonperformance risk. The financial and physical instruments held at the subsidiary level are generally non-recourse to the Parent Company.

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Nonperformance risk on the investments held by the Company is incorporated in the fair value derived from quoted market data to mark the investments to fair value.

Recurring Measurements — The following table presents, by level within the fair value hierarchy as described in Note 1—General and Summary of Significant Accounting Policies, the Company's financial assets and liabilities that were measured at fair value on a recurring basis as of the dates indicated (in millions). For the Company's investments in marketable debt securities, the security classes presented were determined based on the nature and risk of the security and are consistent with how the Company manages, monitors and measures its marketable securities:

		December 31, 2019																December 31, 2018
		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Assets
DEBT SECURITIES:
Available-for-sale:
Unsecured debentures		$	—			$	—			$	—			$	—			$	—			$	5			$	—			$	5
Certificates of deposit		—				326				—				326				—				243				—				243
Total debt securities		—				326				—				326				—				248				—				248
EQUITY SECURITIES:
Mutual funds		22				61				—				83				19				49				—				68
Total equity securities		22				61				—				83				19				49				—				68
DERIVATIVES:
Interest rate derivatives		—				31				—				31				—				28				1				29
Cross-currency derivatives		—				—				—				—				—				6				—				6
Foreign currency derivatives		—				17				93				110				—				18				199				217
Commodity derivatives		—				28				2				30				—				6				4				10
Total derivatives — assets		—				76				95				171				—				58				204				262
TOTAL ASSETS		$	22			$	463			$	95			$	580			$	19			$	355			$	204			$	578
Liabilities
DERIVATIVES:
Interest rate derivatives		$	—			$	144			$	184			$	328			$	—			$	67			$	141			$	208
Cross-currency derivatives		—				10				11				21				—				5				—				5
Foreign currency derivatives		—				44				—				44				—				41				—				41
Commodity derivatives		—				29				2				31				—				3				—				3
Total derivatives — liabilities		—				227				197				424				—				116				141				257
TOTAL LIABILITIES		$	—			$	227			$	197			$	424			$	—			$	116			$	141			$	257

As of December 31, 2019, all AFS debt securities had stated maturities within one year. For the years ended December 31, 2019, 2018, and 2017, no other-than-temporary impairment of marketable securities were recognized in earnings or Other Comprehensive Income (Loss). Gains and losses on the sale of investments are determined using the specific-identification method. The following table presents gross proceeds from sale of AFS securities for the periods indicated (in millions):

Year Ended December 31,		2019				2018				2017
Gross proceeds from sale of AFS securities (1)		$	663			$	1,403			$	1,398

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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.

The following tables present a reconciliation of net derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2019 and 2018 (presented net by type of derivative in millions). Transfers between Level 3 and Level 2 principally result from changes in the significance of unobservable inputs used to calculate the credit valuation adjustment.

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Year Ended December 31, 2019	Interest Rate				Cross Currency				Foreign Currency				Commodity				Total
Balance at January 1	$	(140	)		$	—			$	199			$	4			$	63
Total realized and unrealized gains (losses):
Included in earnings	(1		)		—				(65		)		(2		)		(68		)
Included in other comprehensive income — derivative activity	(97		)		—				(17		)		—				(114		)
Included in regulatory (assets) liabilities	—				—				—				(5		)		(5		)
Settlements	8				—				(23		)		2				(13		)
Transfers of assets/(liabilities), net into Level 3	(2		)		(11		)		—				—				(13		)
Transfers of (assets)/liabilities, net out of Level 3	48				—				—				—				48
Balance at December 31	$	(184	)		$	(11	)		$	94			$	(1	)		$	(102	)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	—			$	—			$	(67	)		$	(2	)		$	(69	)

Year Ended December 31, 2018	Interest Rate				Cross Currency				Foreign Currency				Commodity				Total
Balance at January 1	$	(151	)		$	—			$	240			$	4			$	93
Total realized and unrealized gains (losses):
Included in earnings	22				—				(14		)		(1		)		7
Included in other comprehensive income — derivative activity	(8		)		—				—				—				(8		)
Included in regulatory (assets) liabilities	—				—				—				5				5
Settlements	14				—				(27		)		(4		)		(17		)
Transfers of assets/(liabilities), net into Level 3	(8		)		—				—				—				(8		)
Transfers of (assets)/liabilities, net out of Level 3	(9		)		—				—				—				(9		)
Balance at December 31	$	(140	)		$	—			$	199			$	4			$	63
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	29			$	—			$	(41	)		$	(1	)		$	(13	)

The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) as of December 31, 2019 (in millions, except range amounts):

Type of Derivative		Fair Value				Unobservable Input		Amount or Range (Weighted Average)
Interest rate		$	(184	)		Subsidiaries’ credit spreads		0.8% - 4.94% (3.7%)
Cross-currency		(11		)		Subsidiaries’ credit spreads		2.1	%
Foreign currency:
Argentine peso		94				Argentine peso to USD currency exchange rate after one year		61 - 495 (250)
Commodity:
Other		(1		)
Total		$	(102	)

For interest rate derivatives and foreign currency derivatives, increases (decreases) in the estimates of the Company's own credit spreads would decrease (increase) the value of the derivatives in a liability position. For foreign currency derivatives, increases (decreases) in the estimate of the above exchange rate would increase (decrease) the value of the derivative.

Nonrecurring Measurements

The Company measures fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the then-latest available carrying amount. The following table summarizes our major categories of assets measured at fair value on a nonrecurring basis and their level within the fair value hierarchy (in millions):

Year Ended December 31, 2019		Measurement Date		Carrying Amount (1)			Fair Value									Pre-tax Loss
Assets							Level 1			Level 2			Level 3
Long-lived assets held and used: (2)
Hawaii		12/31/2019		163			—			—			103			60
Equity method investments:
OPGC		12/31/2019		304			—			—			212			92
Dispositions and held-for-sale businesses: (3)
Kilroot and Ballylumford		04/12/2019		232			—			118			—			115

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Year Ended December 31, 2018		Measurement Date		Carrying Amount (1)				Fair Value												Pre-tax Loss
Assets								Level 1				Level 2				Level 3
Dispositions and held-for-sale businesses: (3)
Shady Point		12/31/2018		211				—				—				30				157
Long-lived assets held and used: (2)
Nejapa		12/31/2018		$	42			$	—			$	—			$	5			$	37
Equity method investments:
Guacolda		10/01/2018		354				—				—				209				144
Elsta		09/30/2018		19				—				16				—				3

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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.

The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets held and used measured on a nonrecurring basis during the year ended December 31, 2019 (in millions, except range amounts):

December 31, 2019		Fair Value				Valuation Technique		Unobservable Input		Range (Weighted Average)
Long-lived assets held and used:
Hawaii		$	103			Discounted cash flow		Annual revenue growth		-11% to 1% (-6%)
								Pre-tax operating margin		5% to 35% (29%)
								Weighted-average cost of capital		5% to 15%
Equity method investments:
OPGC		212				Expected present value		Annual dividend growth		-27% to 41% (2%)
								Weighted-average cost of equity		9	%
Total		$	315

Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

The following table presents (in millions) the carrying amount, fair value and fair value hierarchy of the Company's financial assets and liabilities that are not measured at fair value in the Consolidated Balance Sheets as of the periods indicated, but for which fair value is disclosed:

			December 31, 2019
			Carrying Amount				Fair Value
							Total				Level 1				Level 2				Level 3
Assets:	Accounts receivable — noncurrent (1)		$	98			$	145			$	—			$	—			$	145
Liabilities:	Non-recourse debt		16,712				16,579				—				15,804				775
	Recourse debt		3,396				3,529				—				3,529				—

			December 31, 2018
			Carrying Amount				Fair Value
							Total				Level 1				Level 2				Level 3
Assets:	Accounts receivable — noncurrent (1)		$	100			$	209			$	—			$	—			$	209
Liabilities:	Non-recourse debt		15,645				16,225				—				13,524				2,701
	Recourse debt		3,655				3,621				—				3,621				—

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(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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Volume of Activity — The following table presents the Company's maximum notional (in millions) over the remaining contractual period by type of derivative as of December 31, 2019, regardless of whether they are in qualifying cash flow hedging relationships, and the dates through which the maturities for each type of derivative range:

Interest Rate and Foreign Currency Derivatives		Maximum Notional Translated to USD				Latest Maturity
Interest Rate (LIBOR and EURIBOR)		$	5,014			2044
Cross-currency swaps (Chilean Unidad de Fomento and Chilean peso)		260				2029
Foreign Currency:
Argentine peso		30				2026
Chilean peso		163				2022
Colombian peso		139				2022
Brazilian real		5				2020
Others, primarily with weighted average remaining maturities of a year or less		90				2022

Commodity Derivatives		Maximum Notional			Latest Maturity
Natural Gas (in MMBtu)		71			2020
Power (in MWhs)		1			2020
Coal (in Tons or Metric Tonnes)		10			2027

Accounting and Reporting — Assets and Liabilities — The following tables present the fair value of assets and liabilities related to the Company's derivative instruments as of the periods indicated (in millions):

Fair Value		December 31, 2019												December 31, 2018
Assets		Designated				Not Designated				Total				Designated				Not Designated				Total
Interest rate derivatives		$	31			$	—			$	31			$	29			$	—			$	29
Cross-currency derivatives		—				—				—				6				—				6
Foreign currency derivatives		31				79				110				—				217				217
Commodity derivatives		—				30				30				—				10				10
Total assets		$	62			$	109			$	171			$	35			$	227			$	262
Liabilities
Interest rate derivatives		$	323			$	5			$	328			$	205			$	3			$	208
Cross-currency derivatives		21				—				21				5				—				5
Foreign currency derivatives		22				22				44				28				13				41
Commodity derivatives		2				29				31				—				3				3
Total liabilities		$	368			$	56			$	424			$	238			$	19			$	257

		December 31, 2019								December 31, 2018
Fair Value		Assets				Liabilities				Assets				Liabilities
Current		$	72			$	126			$	75			$	51
Noncurrent		99				298				187				206
Total		$	171			$	424			$	262			$	257

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As of December 31, 2019 and 2018, all derivative instruments subject to credit risk-related contingent features were in an asset position.

Earnings and Other Comprehensive Income (Loss) — The following table presents the pre-tax gains (losses) recognized in AOCL and earnings related to all derivative instruments for the periods indicated (in millions):

		Years Ended December 31,
		2019				2018				2017
Cash flow hedges
Gains (losses) recognized in AOCL
Interest rate derivatives		$	(290	)		$	(16	)		$	(66	)
Cross-currency derivatives		(26		)		(26		)		31
Foreign currency derivatives		(23		)		(52		)		(5		)
Commodity derivatives		—				—				18
Total		$	(339	)		$	(94	)		$	(22	)
Gains (losses) reclassified from AOCL to earnings
Interest rate derivatives		$	(28	)		$	(52	)		$	(82	)
Cross-currency derivatives		(12		)		(43		)		34
Foreign currency derivatives		(13		)		(16		)		(20		)
Commodity derivatives		(1		)		(6		)		17
Total		$	(54	)		$	(117	)		$	(51	)
Loss reclassified from AOCL to earnings due to discontinuance of hedge accounting (1)		$	(2	)		$	—			$	(13	)
Gain (losses) recognized in earnings related to
Ineffective portion of cash flow hedges		$	—			$	(7	)		$	3
Not designated as hedging instruments:
Foreign currency derivatives		(46		)		148				1
Commodity derivatives and other		(6		)		25				14
Total		$	(52	)		$	173			$	15

_____________________________

(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.

AOCL is expected to decrease pre-tax income from continuing operations for the twelve months ended December 31, 2020 by $73 million, primarily due to interest rate derivatives.

Receivables with contractual maturities of greater than one year are considered financing receivables. The Company's financing receivables are primarily related to amended agreements or government resolutions that are due from CAMMESA, the administrator of the wholesale electricity market in Argentina. The following table presents financing receivables by country as of the dates indicated (in millions):

December 31,		2019				2018
Argentina		$	64			$	93
Chile		33				—
Other		12				23
Total		$	109			$	116

Argentina

Collection of the principal and interest on these receivables is subject to various business risks and uncertainties, including, but not limited to, the continued operation of power plants which generate cash for payments of these receivables, regulatory changes that could impact the timing and amount of collections, and economic conditions in Argentina. The Company monitors these risks, including the credit ratings of the Argentine government, on a quarterly basis to assess the collectability of these receivables. The Company accrues interest on these receivables once the recognition criteria have been met. The Company's collection estimates are based on assumptions that it believes to be reasonable, but are inherently uncertain. Actual future cash flows could differ from these estimates. The decrease in Argentina financing receivables was primarily due to planned collections and unfavorable FX impacts.

FONINVEMEM Agreements — As a result of energy market reforms in 2004 and 2010, AES Argentina entered into three agreements with the Argentine government, referred to as the FONINVEMEM Agreements, to contribute a portion of their accounts receivable into a fund for financing the construction of combined cycle and gas-fired plants. These receivables accrue interest and are collected in monthly installments over 10 years once the related plant

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begins operations. In addition, AES Argentina receives an ownership interest in these newly built plants once the receivables have been fully repaid.

The FONINVEMEM receivables are denominated in Argentine pesos, but indexed to USD, which represents a foreign currency derivative. Due to differences between spot rates, used to remeasure the receivables, and discounted forward rates, used to value the foreign currency derivative, these two items will not perfectly offset over the life of the receivable. Once settled, the foreign currency derivative will offset the accumulated unrealized foreign currency losses resulting from the devaluation of the FONINVEMEM receivable. As of December 31, 2019 and 2018, the amount of the foreign currency-related derivative assets associated with the FONINVEMEM financing receivables that were excluded from the table above had a fair value of $94 million and $199 million, respectively.

The receivables under the FONINVEMEM Agreements have been actively collected since the related plants commenced operations in 2010 and 2016. In assessing the collectability of the receivables under these agreements, the Company also considers historic collection evidence in accordance with the agreements.

Other Agreements — Other agreements primarily consist of resolutions passed by the Argentine government in which AES Argentina will receive compensation for investments in new generation plants and technologies. The timing of collections depend on corresponding agreements and collectability of these receivables are assessed on an ongoing basis.

Chile

AES Gener has recorded noncurrent receivables pertaining to revenues recognized on regulated energy contracts that were impacted by the Stabilization Fund created by the Chilean government in October 2019. Historically, the government updated the prices for these contracts every six months to reflect the indexation the contracts have to exchange rates and commodities prices. The Stabilization Fund does not allow the pass-through of these contractual indexation updates to customers beyond the pricing in effect at July 1, 2019, until new lower-cost renewable contracts are incorporated into pricing in 2023. Consequently, costs incurred in excess of the July 1, 2019 price will be accumulated and borne by generators. It is expected that these noncurrent receivables will be collected prior to December 31, 2027.

The following table summarizes the relevant effective equity ownership interest and carrying values for the Company's investments accounted for under the equity method as of the periods indicated:

December 31,			2019				2018				2019			2018
Affiliate	Country		Carrying Value (in millions)								Ownership Interest %
sPower	United States		$	442			$	515			50	%		50	%
OPGC	India		212				293				49	%		49	%
Guacolda (1)	Chile		74				209				33	%		33	%
Uplight (2)	United States		91				33				32	%		63	%
Eólica Mesa La Paz (3)	Mexico		66				8				50	%		50	%
Gas Natural del Este	Dominican Republic		48				—				43	%		—	%
Barry (4)	United Kingdom		—				—				100	%		100	%
Other affiliates (5)	Various		33				56
Total			$	966			$	1,114

_____________________________

(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.

OPGC — In December 2019, an other-than-temporary impairment was identified at OPGC primarily due to the estimated market value of the Company's investment and other negative developments impacting future expected cash flows at the investee. A calculation of the fair value of the Company’s investment in OPGC was required to evaluate whether there was a loss in the carrying value of the investment. Based on management’s estimate of fair value of $212 million, the Company recognized an other-than-temporary impairment of $92 million in Other non-operating expense. The OPGC equity method investment is reported in the Eurasia SBU reportable segment.

Guacolda — In October 2019, Guacolda management reviewed the recoverability of the Guacolda asset group and determined the undiscounted cash flows did not exceed the carrying amount. Guacolda recognized a long-lived

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asset impairment at the investee level, which negatively impacted the Company's Net equity in earnings (losses) of affiliates by $158 million. The Guacolda equity method investment is reported in the South America SBU reportable segment.

In October 2018, an other-than-temporary impairment was identified at Guacolda primarily as a result of increased renewable generation in Chile lowering energy prices, impacting management's ability to re-contract Guacolda's generation after expiration of existing PPAs. A calculation of the fair value of Gener's investment in Guacolda was required to evaluate whether there was a loss in the carrying value of the investment. Based on management's estimate of fair value of $209 million, the Company recognized an other-than-temporary impairment of $144 million in Other non-operating expense.

Gas Natural del Este — In September 2019, AES Andres completed an agreement with Energas Group to establish a joint venture for the purpose of selling natural gas and related terminal services, storage, regasification, and transportation to customers in the Dominican Republic. Gas Natural del Este, a wholly-owned subsidiary of the joint venture, acquired the Eastern Pipeline development project from AES Andres for total consideration of $55 million, resulting in a gain of $2 million. The transaction was considered a contribution of a nonfinancial asset in exchange for a noncontrolling interest in the joint venture. As the Company does not control the joint venture, it is accounted for as an equity method investment and is reported in the MCAC SBU reportable segment.

Simple Energy — On July 1, 2019, Simple Energy merged with Tendril, a previously unrelated party, to form Uplight, a new company that offers a comprehensive platform for utility customer engagement. As part of this merger, the Company contributed its ownership interest in Simple Energy and $53 million of cash in exchange for an ownership interest in the merged company. This transaction resulted in a gain on sale of $12 million and a total investment in Uplight of $98 million. As the Company does not control Uplight, it is accounted for as an equity method investment and reported as part of Corporate and Other.

In April 2018, the Company invested $35 million in Simple Energy, a provider of utility-branded marketplaces and omni-channel instant rebates, accounted for as an equity method investment.

sPower — In April 2019, the Company closed on the sale of approximately 48% of its interest in a portfolio of sPower’s operating assets for $173 million, subject to customary purchase price adjustments, of which $58 million was retained at sPower to pay down debt. This sale resulted in a pre-tax gain on sale of business interests of $28 million. After the sale, the Company’s ownership interest in this portfolio of sPower’s operating assets decreased from 50% to approximately 26%. The sPower equity method investment is reported in the US and Utilities SBU reportable segment.

Distributed Energy — In December 2018, Distributed Energy acquired the remaining equity interest in a partnership holding various solar projects for consideration of $23 million. This transaction resulted in a loss of $5 million, reported in Other expense in the Consolidated Statement of Operations. The projects, previously recorded as equity method investments, have been consolidated. See Note 26—Acquisitions for further discussion.

Fluence — On January 1, 2018, Siemens and AES closed on the creation of the Fluence joint venture with each party holding a 50% ownership interest. The Company contributed $7 million in cash and $20 million in non-cash assets from the AES Advancion energy storage development business as consideration for the transaction, and received an equity interest in Fluence with a fair value of $50 million. See Note 25—Held-for-Sale and Dispositions for further discussion. Fluence is a global energy storage technology and services company. As the Company does not control Fluence, the investment is accounted for as an equity method investment. The Fluence equity method investment is reported as part of Corporate and Other.

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AES Barry Ltd. — The Company holds a 100% ownership interest in AES Barry Ltd. ("Barry"), a dormant entity in the U.K. that disposed of its generation and other operating assets. Due to a debt agreement, no material financial or operating decisions can be made without the banks' consent, and the Company does not control Barry. As of December 31, 2019 and 2018, other long-term liabilities included $44 million and $43 million related to this debt agreement.

Summarized Financial Information — The following tables summarize financial information of the Company's 50%-or-less-owned affiliates and majority-owned unconsolidated subsidiaries that are accounted for using the equity method (in millions):

	50%-or-less Owned Affiliates												Majority-Owned Unconsolidated Subsidiaries
Years ended December 31,	2019				2018				2017				2019				2018				2017
Revenue	$	1,122			$	962			$	762			$	49			$	40			$	16
Operating margin (loss)	124				135				165				(5		)		3				5
Net income (loss)	(724		)		14				72				(7		)		(3		)		(15		)
December 31,	2019				2018								2019				2018
Current assets	$	831			$	558							$	166			$	89
Noncurrent assets	7,220				5,918								982				41
Current liabilities	1,271				546								141				35
Noncurrent liabilities	3,966				3,309								1,052				122
Stockholders' equity	2,814				2,622								(45		)		(27		)

At December 31, 2019, retained earnings included $14 million related to the undistributed earnings of the Company's 50%-or-less owned affiliates. Distributions received from these affiliates were $23 million, $83 million, and $69 million for the years ended December 31, 2019, 2018, and 2017, respectively. As of December 31, 2019, the underlying equity in the net assets of our equity affiliates exceeded the aggregate carrying amount of our investments in equity affiliates by $225 million.

Goodwill — The following table summarizes the carrying amount of goodwill by reportable segment for the years ended December 31, 2019 and 2018 (in millions):

	US and Utilities				South America				MCAC				Eurasia				Total
Balance as of December 31, 2018
Goodwill	$	2,786			$	868			$	16			$	122			$	3,792
Accumulated impairment losses	(2,611		)		—				—				(122		)		(2,733		)
Net balance	175				868				16				—				1,059
Balance as of December 31, 2019
Goodwill	2,786				868				16				—			(1)	3,670
Accumulated impairment losses	(2,611		)		—				—				—			(1)	(2,611		)
Net balance	$	175			$	868			$	16			$	—			$	1,059

_____________________________

(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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Other Intangible Assets — The following table summarizes the balances comprising Other intangible assets in the accompanying Consolidated Balance Sheets (in millions) as of the periods indicated:

	December 31, 2019												December 31, 2018
	Gross Balance				Accumulated Amortization				Net Balance				Gross Balance				Accumulated Amortization				Net Balance
Subject to Amortization
Internal-use software	$	367			$	(228	)		$	139			$	467			$	(344	)		$	123
Contracts	134				(29		)		105				137				(24		)		113
Project development rights	100				(1		)		99				93				(1		)		92
Contractual payment rights (1)	—				—				—				57				(44		)		13
Emissions allowances (2)	24				—				24				15				—				15
Other (3)	82				(49		)		33				78				(44		)		34
Subtotal	707				(307		)		400				847				(457		)		390
Indefinite-Lived Intangible Assets
Land use rights	21				—				21				21				—				21
Water rights	20				—				20				20				—				20
Transmission rights	23				—				23				—				—				—
Other	5				—				5				5				—				5
Subtotal	69				—				69				46				—				46
Total	$	776			$	(307	)		$	469			$	893			$	(457	)		$	436

_____________________________

(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.

The following tables summarize other intangible assets acquired during the periods indicated (in millions):

December 31, 2019	Amount				Subject to Amortization/Indefinite-Lived		Weighted Average Amortization Period (in years)		Amortization Method
Internal-use software	$	61			Subject to Amortization		5		Straight-line
Contracts	2				Subject to Amortization		35		Straight-line
Project development rights	8				Subject to Amortization		29		Straight-line
Emissions allowances	22				Subject to Amortization		Various		As utilized
Transmission rights	23				Indefinite-Lived		N/A		N/A
Other	5				Various		N/A		N/A
Total	$	121

December 31, 2018	Amount				Subject to Amortization/Indefinite-Lived		Weighted Average Amortization Period (in years)		Amortization Method
Internal-use software	$	67			Subject to Amortization		6		Straight-line
Contracts	50				Subject to Amortization		24		Straight-line
Project development rights	35				Subject to Amortization		23		Straight-line
Emissions allowances	16				Subject to Amortization		Various		As utilized
Other	11				Various		N/A		N/A
Total	$	179

The following table summarizes the estimated amortization expense by intangible asset category for 2020 through 2024:

(in millions)	2020				2021				2022				2023				2024
Internal-use software	$	34			$	31			$	22			$	17			$	15
Contracts	4				4				4				4				4
Other	6				5				5				5				5
Total	$	44			$	40			$	31			$	26			$	24

Intangible asset amortization expense was $45 million, $47 million and $34 million for the years ended December 31, 2019, 2018 and 2017, respectively.

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The Company has recorded regulatory assets and liabilities (in millions) that it expects to pass through to its customers in accordance with, and subject to, regulatory provisions as follows:

December 31,	2019				2018				Recovery/Refund Period
Regulatory assets
Current regulatory assets:
El Salvador energy pass through costs recovery	$	56			$	87			Quarterly
Other	57				69				1 year
Total current regulatory assets	113				156
Noncurrent regulatory assets:
IPL and DPL defined benefit pension obligations (1)	262				283				Various
IPL deferred Midwest ISO costs	75				88				9 years
IPL environmental costs	85				89				Various
Other	108				87				Various
Total noncurrent regulatory assets	530				547
Total regulatory assets	$	643			$	703
Regulatory liabilities
Current regulatory liabilities:
Overcollection of costs to be passed back to customers	$	80			$	83			1 year
Other	1				3				Various
Total current regulatory liabilities	81				86
Noncurrent regulatory liabilities:
IPL and DPL accrued costs of removal and AROs	863				847				Over life of assets
IPL and DPL income taxes payable to customers through rates	209				246				Various
Other	18				53				Various
Total noncurrent regulatory liabilities	1,090				1,146
Total regulatory liabilities	$	1,171			$	1,232

_____________________________

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

Our regulatory assets and current regulatory liabilities primarily consist of under or overcollection of costs that are generally non-controllable, such as purchased electricity, energy transmission, fuel costs, and other sector costs. These costs are recoverable or refundable as defined by the laws and regulations in our markets. Our regulatory assets also include defined pension and postretirement benefit obligations equal to the previously unrecognized actuarial gains and losses and prior service costs that are expected to be recovered through future rates. Other current and noncurrent regulatory assets primarily consist of:

•	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.

Our noncurrent regulatory liabilities primarily consist of obligations for removal costs which do not have an associated legal retirement obligation. Our noncurrent regulatory liabilities also include deferred income taxes related to differences in income recognition between tax laws and accounting methods, which will be passed through to our regulated customers via a decrease in future retail rates. See Note 23—Income Taxes for further information.

In the accompanying Consolidated Balance Sheets the current regulatory assets and liabilities are reflected in Other current assets and Accrued and other liabilities, respectively, and the noncurrent regulatory assets and liabilities are reflected in Other noncurrent assets and Other noncurrent liabilities, respectively. All of the regulatory assets and liabilities as of December 31, 2019 and December 31, 2018 related to the US and Utilities SBU.

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NON-RECOURSE DEBT — The following table summarizes the carrying amount and terms of non-recourse debt at our subsidiaries as of the periods indicated (in millions):

NON-RECOURSE DEBT	Weighted Average Interest Rate		Maturity		December 31,
					2019				2018
Variable Rate:
Bank loans	4.25%		2020 – 2050		$	3,389			$	2,600
Notes and bonds	3.99%		2020 – 2030		1,056				821
Debt to (or guaranteed by) multilateral, export credit agencies or development banks (1)	1.73%		2023 – 2033		460				3,292
Fixed Rate:
Bank loans	5.19%		2020 – 2040		2,900				1,684
Notes and bonds	5.51%		2020 – 2079		8,098				7,346
Debt to (or guaranteed by) multilateral, export credit agencies or development banks (1)	6.09%		2023 – 2029		1,110				246
Other	4.20%		2061		17				24
Unamortized (discount) premium & debt issuance (costs), net					(318		)		(368		)
Subtotal					$	16,712			$	15,645
Less: Current maturities (2)					(1,865		)		(1,659		)
Noncurrent maturities (2)					$	14,847			$	13,986

_____________________________

(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.

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 that economically fix the variable component of the interest rates on the portion of the variable rate debt being hedged in an aggregate notional principal amount of approximately $1.8 billion on non-recourse debt outstanding at December 31, 2019.

Non-recourse debt as of December 31, 2019 is scheduled to reach maturity as shown below (in millions):

December 31,	Annual Maturities
2020	$	1,883
2021	1,648
2022	999
2023	1,125
2024	1,180
Thereafter	10,195
Unamortized (discount) premium & debt issuance (costs), net	(318		)
Total	$	16,712

As of December 31, 2019, AES subsidiaries with facilities under construction had a total of approximately $470 million of committed but unused credit facilities available to fund construction and other related costs. Excluding these facilities under construction, AES subsidiaries had approximately $1.1 billion in various unused committed credit lines to support their working capital, debt service reserves and other business needs. These credit lines can be used for borrowings, letters of credit, or a combination of these uses.

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Significant transactions — During the year ended December 31, 2019, the Company's subsidiaries had the following significant debt transactions:

Subsidiary	Transaction Period		Issuances				Repayments				Gain (Loss) on Extinguishment of Debt
Southland (1)	Q1, Q2, Q3, Q4		$	930			$	(210	)		$	(1	)
Gener	Q1, Q2, Q4		1,000				(697		)		(29		)
DPL (2)	Q2		825				(835		)		(43		)
Tietê	Q2		561				(533		)		(3		)
Mong Duong (3)	Q3		1,120				(1,081		)		(31		)
Colon	Q3		610				(579		)		(28		)
Cochrane	Q4		875				(833		)		(24		)
TEGTEP	Q4		280				(248		)		(1		)

_____________________________

(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.

Cochrane — In November 2019, Cochrane issued $430 million aggregate principal of 5.50% senior unsecured notes due in 2027 and entered into a $445 million 6.25% senior secured facility agreement due in 2034. The net proceeds from the issuance and draw down were used to prepay the outstanding principal of $833 million under its variable rate notes due in 2030. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $24 million.

Gener — In March 2019, Gener issued $550 million aggregate principal of 7.125% senior unsecured notes due in 2079. The net proceeds from the issuance were used to purchase via tender offer the outstanding principal of $450 million of its 8.375% senior unsecured notes due in 2073.

In October 2019, Gener issued $450 million aggregate principal of 6.35% senior unsecured notes due in 2079. The net proceeds from the issuance were used to fund the acquisition of Los Cururos, purchase via tender offer $73 million and $55 million aggregate principal of its senior unsecured notes due in 2021 and 2025, respectively, and prepay the remaining outstanding principal of $119 million of its senior unsecured notes due in 2021. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $29 million.

Mong Duong — In August 2019, Mong Duong refinanced $1.1 billion aggregate principal of its existing senior secured notes due in 2029 with variable interest rates ranging from LIBOR + 2.25% to LIBOR + 4.15% in exchange for a fixed rate loan with a newly formed SPV, accounted for as an equity affiliate, due in 2029 with interest rates that vary from 4.41% to 7.18%. This refinancing was a non-cash transaction as the SPV acquired all of the outstanding rights and obligations of the original Mong Duong lenders. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $31 million.

DP&L — In June 2019, DP&L issued $425 million aggregate principal of 3.95% First Mortgage Bonds due in 2049. The net proceeds from the issuance were used to prepay the outstanding principal of $435 million under its variable rate $445 million credit agreement due in 2022.

DPL — In April 2019, DPL issued $400 million aggregate principal of 4.35% senior unsecured notes due in 2029. The net proceeds from the issuance were used to redeem $400 million of the $780 million aggregate principal outstanding of its 7.25% senior unsecured notes due in 2021. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $43 million.

Non-Recourse Debt Covenants, Restrictions and Defaults — The terms of the Company's non-recourse debt include certain financial and nonfinancial covenants. These covenants are limited to subsidiary activity and vary among the subsidiaries. These covenants may include, but are not limited to, maintenance of certain reserves and financial ratios, minimum levels of working capital and limitations on incurring additional indebtedness.

As of December 31, 2019 and 2018, approximately $372 million and $627 million, respectively, of restricted cash was maintained in accordance with certain covenants of the non-recourse debt agreements, and these amounts were included within Restricted cash and Debt service reserves and other deposits in the accompanying Consolidated Balance Sheets.

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Various lender and governmental provisions restrict the ability of certain of the Company's subsidiaries to transfer their net assets to the Parent Company. Such restricted net assets of subsidiaries amounted to approximately $1.2 billion at December 31, 2019.

The following table summarizes the Company's subsidiary non-recourse debt in default (in millions) as of December 31, 2019. Due to the defaults, these amounts are included in the current portion of non-recourse debt:

	Primary Nature of Default		December 31, 2019
Subsidiary			Default				Net Assets
AES Puerto Rico	Covenant		$	287			$	151
AES Ilumina (Puerto Rico)	Covenant		33				19
AES Jordan Solar (1)	Covenant		5				4
Total			$	325

_____________________________

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

The above defaults are not payment defaults. In Puerto Rico, the subsidiary non-recourse debt defaults were triggered by failure to comply with covenants or other requirements contained in the non-recourse debt documents due to the bankruptcy of the offtaker.

The AES Corporation's recourse debt agreements include cross-default clauses that will trigger if a subsidiary or group of subsidiaries for which the non-recourse debt is in default provides 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of December 31, 2019, the Company had no defaults which resulted in or were at risk of triggering a cross-default under the recourse debt of the Parent Company. In the event the Parent Company is not in compliance with the financial covenants of its senior secured revolving credit facility, restricted payments will be limited to regular quarterly shareholder dividends at the then-prevailing rate. Payment defaults and bankruptcy defaults would preclude the making of any restricted payments.

RECOURSE DEBT — The following table summarizes the carrying amount and terms of recourse debt of the Company as of the periods indicated (in millions):

	Interest Rate		Final Maturity		December 31, 2019				December 31, 2018
Senior Unsecured Note	4.00%		2021		500				500
Senior Secured Term Loan	LIBOR + 1.75%		2022		18				366
Senior Unsecured Note	4.875%		2023		613				713
Senior Unsecured Note	4.50%		2023		500				500
Drawings on secured credit facility	LIBOR + 1.75%		2024		180				—
Senior Unsecured Note	5.50%		2024		63				63
Senior Unsecured Note	5.50%		2025		544				544
Senior Unsecured Note	6.00%		2026		500				500
Senior Unsecured Note	5.125%		2027		500				500
Unamortized (discount) premium & debt issuance (costs), net					(22		)		(31		)
Subtotal					$	3,396			$	3,655
Less: Current maturities					(5		)		(5		)
Noncurrent maturities					$	3,391			$	3,650

The following table summarizes the principal amounts due under our recourse debt for the next five years and thereafter (in millions):

December 31,	Net Principal Amounts Due
2020	$	5
2021	505
2022	8
2023	1,113
2024	243
Thereafter	1,544
Unamortized (discount) premium & debt issuance (costs), net	(22		)
Total recourse debt	$	3,396

In September 2019, the Company prepaid $343 million aggregate principal of its LIBOR + 1.75% existing senior secured term loan due in 2022 and $100 million of its 4.875% senior unsecured notes due in 2023. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $5 million.

In December 2018, the Company prepaid $150 million aggregate principal of its existing senior secured term

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loan due in 2022. As a result of the transaction, the Company recognized a loss on extinguishment of debt of $1 million.

In March 2018, the Company purchased via tender offers $671 million aggregate principal of its existing 5.50% senior unsecured notes due in 2024 and $29 million of its existing 5.50% senior unsecured notes due in 2025. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $44 million.

In March 2018, the Company issued $500 million aggregate principal of 4.00% senior notes due in 2021 and $500 million of 4.50% senior notes due in 2023. The Company used the proceeds from these issuances to purchase via tender offer in full the $228 million balance of its 8.00% senior notes due in 2020 and the $690 million balance of its 7.375% senior notes due in 2021. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $125 million.

Recourse Debt Covenants and Guarantees — The Company's obligations under the senior secured credit facility and senior secured term loan are, subject to certain exceptions, secured by (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.

The senior secured credit facility and senior secured term loan are subject to mandatory prepayment under certain circumstances, including the sale of certain assets. In such a situation, the net cash proceeds from the sale must be applied pro rata to repay the term loan, if any, using 60% of net cash proceeds, reduced to 50% when and if the Parent Company's recourse debt to cash flow ratio is less than 5:1. The lenders have the option to waive their pro rata redemption.

The senior secured credit facility contains customary covenants and restrictions on the Company's ability to engage in certain activities, including, but not limited to, limitations on other indebtedness, liens, investments and guarantees; limitations on restricted payments such as shareholder dividends and equity repurchases; restrictions on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet or derivative arrangements; and other financial reporting requirements.

The senior secured credit facility also contains financial covenants, evaluated quarterly, requiring the Company to maintain a minimum ratio of adjusted operating cash flow to interest charges on recourse debt of 2.5 times and a maximum ratio of recourse debt to adjusted operating cash flow of 5.75 times.

The terms of the Company's senior unsecured notes and senior secured term loan contain certain covenants including limitations on the Company's ability to incur liens or enter into sale and leaseback transactions.

The Company enters into long-term contracts for construction projects, maintenance and service, transmission of electricity, operations services and purchases of electricity and fuel. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances. The following table shows the future minimum commitments for continuing operations under these contracts as of December 31, 2019 for 2020 through 2024 and thereafter as well as actual purchases under these contracts for the years ended December 31, 2019, 2018, and 2017 (in millions):

Actual purchases during the year ended December 31,	Electricity Purchase Contracts				Fuel Purchase Contracts				Other Purchase Contracts
2017	$	747			$	1,619			$	1,945
2018	827				1,838				1,671
2019	1,597				1,824				1,684
Future commitments for the year ending December 31,
2020	$	699			$	1,385			$	1,551
2021	509				1,086				723
2022	406				756				538
2023	439				643				538
2024	459				568				529
Thereafter	5,110				2,601				1,745
Total	$	7,622			$	7,039			$	5,624

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Guarantees and Letters of Credit — In connection with certain project financings, acquisitions and dispositions, power purchases and other agreements, the Parent Company has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, the Parent Company has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations relate to future performance commitments which the Company or its businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 15 years.

The following table summarizes the Parent Company's contingent contractual obligations as of December 31, 2019. Amounts presented in the following table represent the Parent Company's current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. There were no obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of its businesses.

Contingent Contractual Obligations		Amount (in millions)				Number of Agreements		Maximum Exposure Range for Each Agreement (in millions)
Guarantees and commitments		$	853			37		$0 — 157
Letters of credit under the unsecured credit facility		342				11		$1 — 296
Letters of credit under the senior secured credit facility		19				28		$0 — 4
Asset sale related indemnities (1)		12				1		$12
Total		$	1,226			77

_____________________________

(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.

During the year ended December 31, 2019, the Company paid letter of credit fees ranging from 1% to 3% per annum on the outstanding amounts of letters of credit.

Environmental — The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. For the periods ended December 31, 2019 and 2018, the Company recognized liabilities of $4 million and $5 million for projected environmental remediation costs, respectively. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Moreover, where no liability has been recognized, it is reasonably possible that the Company may be required to incur remediation costs or make expenditures in amounts that could be material but could not be estimated as of December 31, 2019. In aggregate, the Company estimates the range of potential losses related to environmental matters, where estimable, to be up to $15 million. The amounts considered reasonably possible do not include amounts accrued as discussed above.

Litigation — The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has recognized aggregate liabilities for all claims of approximately $55 million and $53 million as of December 31, 2019 and 2018, respectively. These amounts are reported on the Consolidated Balance Sheets within Accrued and other liabilities and Other noncurrent liabilities. A significant portion of these accrued liabilities relate to regulatory matters and commercial disputes in international jurisdictions. There can be no assurance that these accrued liabilities will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

Where no accrued liability has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of December 31, 2019. The material contingencies where a loss is reasonably possible primarily include disputes with offtakers, suppliers and EPC contractors; alleged breaches of contract; alleged violation of laws and regulations; income tax and non-income tax matters with tax authorities; and regulatory matters. In aggregate, the Company estimates the range of potential losses, where estimable, related to these reasonably possible material contingencies to be between $75 million and $503 million. The amounts

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considered reasonably possible do not include amounts accrued, as discussed above. These material contingencies do not include income tax-related contingencies which are considered part of our uncertain tax positions.

LESSEE — Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the period indicated (in millions):

		Consolidated Balance Sheet Classification		December 31, 2019
Assets
Right-of-use assets — finance leases		Electric generation, distribution assets and other		$	67
Right-of-use assets — operating leases		Other noncurrent assets		248
Total right-of-use assets				$	315
Liabilities
Finance lease liabilities (current)		Non-recourse debt (current liabilities)		$	3
Finance lease liabilities (noncurrent)		Non-recourse debt (noncurrent liabilities)		67
Total finance lease liabilities				70
Operating lease liabilities (current)		Accrued and other liabilities		16
Operating lease liabilities (noncurrent)		Other noncurrent liabilities		261
Total operating lease liabilities				277
Total lease liabilities				$	347

The following table summarizes supplemental balance sheet information related to leases as of the period indicated:

Lease Term and Discount Rate	December 31, 2019
Weighted-average remaining lease term — finance leases	32 years
Weighted-average remaining lease term — operating leases	23 years
Weighted-average discount rate — finance leases	4.99	%
Weighted-average discount rate — operating leases	6.99	%

The following table summarizes the components of lease expense recognized in Cost of Sales on the Consolidated Statements of Operations for the year ended (in millions):

Components of Lease Cost	December 31, 2019
Operating lease cost	$	46
Finance lease cost:
Amortization of right-of-use assets	2
Interest on lease liabilities	2
Short-term lease costs	38
Variable lease cost	1
Total lease cost	$	89

Operating cash outflows from operating leases included in the measurement of lease liabilities were $48 million for the twelve months ended December 31, 2019.

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The following table shows the future lease payments under operating and finance leases for continuing operations together with the present value of the net lease payments as of December 31, 2019 for 2020 through 2024 and thereafter (in millions):

	Maturity of Lease Liabilities
	Finance Leases				Operating Leases
2020	$	4			$	29
2021	4				27
2022	4				27
2023	4				26
2024	4				26
Thereafter	119				460
Total	139				595
Less: Imputed interest	(69		)		(318		)
Present value of lease payments	$	70			$	277

LESSOR — Lease revenue included in the Consolidated Statements of Operations was $600 million for the twelve months ended December 31, 2019, of which $130 million was related to variable lease payments. Underlying gross assets and accumulated depreciation of operating leases included in Property, Plant and Equipment on the Consolidated Balance Sheets were $2.9 billion and $707 million, respectively, as of December 31, 2019.

The option to extend or terminate a lease is based on customary early termination provisions in the contract, such as payment defaults, bankruptcy, and lack of performance on energy delivery. The Company has not recognized any early terminations as of December 31, 2019. Certain leases may provide for variable lease payments based on usage or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments.

The following table shows the future lease receipts as of December 31, 2019 for 2020 through 2024 and thereafter (in millions):

	Future Cash Receipts for
	Sales-Type Leases				Operating Leases
2020	$	2			$	504
2021	2				474
2022	2				459
2023	2				395
2024	2				396
Thereafter	38				1,463
Total	48				$	3,691
Less: Imputed interest	(26		)
Present value of total lease receipts	$	22

The Company is constructing and operating projects that pair battery energy storage systems ("BESS") with solar energy systems, which allows the project more flexibility on when to provide energy to the grid. The Company will enter into PPAs for the full output of the facility that allow customers the ability to determine when to charge and discharge the BESS. These arrangements include both lease and non-lease elements under ASC 842, with the BESS component constituting a sales-type lease. Upon commencement of the lease, the book value of the leased asset is removed from the balance sheet and a net investment in sales-type lease is recognized based on the present value of fixed payments under the contract and the residual value of the underlying asset. Due to the variable nature of lease payments under these contracts, the Company recorded losses at commencement of sales-type leases of $36 million for the year ended December 31, 2019. These amounts are recognized in Other expense in the Consolidated Statement of Operations. See Note 21—Other Income and Expense for further information.

Defined Contribution Plan — The Company sponsors four defined contribution plans ("the DC Plans"). Two plans cover U.S. non-union employees; one for Parent Company and certain US and Utilities SBU business employees, and one for DPL employees. The remaining two plans include union and non-union employees at IPL and union employees at DPL. The DC Plans are qualified under section 401 of the Internal Revenue Code. Most U.S. employees of the Company are eligible to participate in the appropriate plan except for those employees who are covered by a collective bargaining agreement, unless such agreement specifically provides that the employee is

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considered an eligible employee under a plan. Within the DC Plans, the Company provides matching contributions in addition to other non-matching contributions. Participants are fully vested in their own contributions. The Company's contributions vest over various time periods ranging from immediate up to five years. For the years ended December 31, 2019, 2018 and 2017, costs for defined contribution plans were approximately $19 million, $21 million and $23 million, respectively.

Defined Benefit Plans — Certain of the Company's subsidiaries have defined benefit pension plans covering substantially all of their respective employees ("the DB Plans"). Pension benefits are based on years of credited service, age of the participant, and average earnings. Of the 28 active DB Plans as of December 31, 2019, five are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries.

The following table reconciles the Company's funded status, both domestic and foreign, as of the periods indicated (in millions):

		2019								2018
		U.S.				Foreign				U.S.				Foreign
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Benefit obligation as of January 1		$	1,118			$	417			$	1,257			$	470
Service cost		11				8				15				12
Interest cost		44				19				40				22
Employee contributions		—				—				—				1
Plan amendments		—				—				10				—
Plan settlements		—				—				—				(21		)
Benefits paid		(65		)		(9		)		(105		)		(17		)
Plan combinations		—				—				—				(4		)
Divestitures		—				(244		)		—				—
Actuarial (gain) loss		134				37				(99		)		(8		)
Effect of foreign currency exchange rate changes		—				(4		)		—				(38		)
Benefit obligation as of December 31		$	1,242			$	224			$	1,118			$	417
CHANGE IN PLAN ASSETS:
Fair value of plan assets as of January 1		$	1,026			$	410			$	1,127			$	455
Actual return on plan assets		185				19				(35		)		6
Employer contributions		8				5				39				21
Employee contributions		—				—				—				1
Plan settlements		—				—				—				(21		)
Benefits paid		(65		)		(9		)		(105		)		(17		)
Divestitures		—				(296		)		—				—
Effect of foreign currency exchange rate changes		—				—				—				(35		)
Fair value of plan assets as of December 31		$	1,154			$	129			$	1,026			$	410
RECONCILIATION OF FUNDED STATUS
Funded status as of December 31		$	(88	)		$	(95	)		$	(92	)		$	(7	)

The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to the funded status of the DB Plans, both domestic and foreign, as of the periods indicated (in millions):

December 31,		2019								2018
Amounts Recognized on the Consolidated Balance Sheets		U.S.				Foreign				U.S.				Foreign
Noncurrent assets		$	—			$	—			$	—			$	64
Accrued benefit liability—current		—				(7		)		—				(6		)
Accrued benefit liability—noncurrent		(88		)		(88		)		(92		)		(65		)
Net amount recognized at end of year		$	(88	)		$	(95	)		$	(92	)		$	(7	)

The following table summarizes the Company's U.S. and foreign accumulated benefit obligation as of the periods indicated (in millions):

December 31,	2019								2018
	U.S.				Foreign				U.S.				Foreign
Accumulated Benefit Obligation	$	1,224			$	188			$	1,101			$	376
Information for pension plans with an accumulated benefit obligation in excess of plan assets:
Projected benefit obligation	$	1,242			$	197			$	1,118			$	89
Accumulated benefit obligation	1,224				178				1,101				79
Fair value of plan assets	1,154				114				1,026				33
Information for pension plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	$	1,242			$	224			$	1,118			$	220
Fair value of plan assets	1,154				129				1,026				150

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The following table summarizes the significant weighted average assumptions used in the calculation of benefit obligation and net periodic benefit cost, both domestic and foreign, as of the periods indicated:

December 31,		2019						2018
		U.S.			Foreign			U.S.			Foreign
Benefit Obligation:	Discount rate	3.32	%		7.58	%		4.35	%		5.63	%
	Rate of compensation increase	3.33	%		6.11	%		3.34	%		4.79	%
Periodic Benefit Cost:	Discount rate	4.35	%		5.62	%	(1)	3.67	%		5.23	%	(1)
	Expected long-term rate of return on plan assets	5.08	%		4.10	%		5.73	%		3.94	%
	Rate of compensation increase	3.34	%		4.78	%		3.34	%		4.65	%

_____________________________

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

The Company establishes its estimated long-term return on plan assets considering various factors, which include the targeted asset allocation percentages, historic returns, and expected future returns.

The measurement of pension obligations, costs, and liabilities is dependent on a variety of assumptions. These assumptions include estimates of the present value of projected future pension payments to all plan participants, taking into consideration the likelihood of potential future events such as salary increases and demographic experience. These assumptions may have an effect on the amount and timing of future contributions.

The assumptions used in developing the required estimates include the following key factors: discount rates, salary growth, retirement rates, inflation, expected return on plan assets, and mortality rates. The effects of actual results differing from the Company's assumptions are accumulated and amortized over future periods and, therefore, generally affect the Company's recognized expense in such future periods. Unrecognized gains or losses are amortized using the “corridor approach,” under which the net gain or loss in excess of 10% of the greater of the projected benefit obligation or the market-related value of the assets, if applicable, is amortized.

Sensitivity of the Company's pension funded status to the indicated increase or decrease in the discount rate and long-term rate of return on plan assets assumptions is shown below. Note that these sensitivities may be asymmetric and are specific to the base conditions at year-end 2019. They also may not be additive, so the impact of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown. The funded status as of December 31, 2019 is affected by the assumptions as of that date. Pension expense for 2019 is affected by the December 31, 2018 assumptions. The impact on pension expense from a one percentage point change in these assumptions is shown in the following table (in millions):

Increase of 1% in the discount rate		$	(14	)
Decrease of 1% in the discount rate		10
Increase of 1% in the long-term rate of return on plan assets		(11		)
Decrease of 1% in the long-term rate of return on plan assets		11

The following table summarizes the components of the net periodic benefit cost, both domestic and foreign, for the years indicated (in millions):

December 31,		2019								2018								2017
Components of Net Periodic Benefit Cost:		U.S.				Foreign				U.S.				Foreign				U.S.				Foreign
Service cost		$	11			$	8			$	15			$	12			$	13			$	10
Interest cost		44				19				40				22				41				23
Expected return on plan assets		(52		)		(14		)		(64		)		(17		)		(69		)		(21		)
Amortization of prior service cost		5				—				5				—				6				—
Amortization of net loss		15				1				18				3				18				2
Curtailment loss recognized		—				—				1				—				4				—
Settlement loss recognized		—				—				—				4				—				—
Total pension cost		$	23			$	14			$	15			$	24			$	13			$	14

The following table summarizes the amounts reflected in AOCL, including AOCL attributable to noncontrolling interests, on the Consolidated Balance Sheet as of December 31, 2019, that have not yet been recognized as components of net periodic benefit cost (in millions):

December 31, 2019	Accumulated Other Comprehensive Income (Loss)
	U.S.				Foreign
Prior service cost	$	(4	)		$	1
Unrecognized net actuarial loss	(23		)		(63		)
Total	$	(27	)		$	(62	)

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The following table summarizes the Company's target allocation for 2019 and pension plan asset allocation, both domestic and foreign, as of the periods indicated:

					Percentage of Plan Assets as of December 31,
	Target Allocations				2019						2018
Asset Category	U.S.		Foreign		U.S.			Foreign			U.S.			Foreign
Equity securities	33%		13%		32.22	%		15.37	%		16.85	%		3.75	%
Debt securities	65%		81%		67.17	%		81.67	%		80.20	%		93.57	%
Real estate	2%		2%		0.22	%		1.16	%		2.35	%		0.44	%
Other	—%		4%		0.39	%		1.80	%		0.60	%		2.24	%
Total pension assets					100.00	%		100.00	%		100.00	%		100.00	%

The U.S. DB Plans seek to achieve the following long-term investment objectives:

•	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.

The asset allocation is reviewed periodically to determine a suitable asset allocation which seeks to manage risk through portfolio diversification and takes into account the above-stated objectives, in conjunction with current funding levels, cash flow conditions, and economic and industry trends. The following table summarizes the Company's U.S. DB Plan assets by category of investment and level within the fair value hierarchy as of the periods indicated (in millions):

		December 31, 2019																December 31, 2018
U.S. Plans		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Equity securities (2):	Mutual funds	$	—			$	372			$	—			$	372			$	173			$	—			$	—			$	173
Debt securities (2):	Government debt securities	—				—				—				—				170				—				—				170
	Mutual funds (1)	—				775				—				775				653				—				—				653
Real estate (2):	Real estate	—				3				—				3				—				24				—				24
Other:	Cash and cash equivalents	4				—				—				4				6				—				—				6
	Total plan assets	$	4			$	1,150			$	—			$	1,154			$	1,002			$	24			$	—			$	1,026

_____________________________

(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.

The investment strategy of the foreign DB Plans seeks to maximize return on investment while minimizing risk. The assumed asset allocation has less exposure to equities in order to closely match market conditions and near term forecasts. The following table summarizes the Company's foreign DB plan assets by category of investment and level within the fair value hierarchy as of the periods indicated (in millions):

		December 31, 2019																December 31, 2018
Foreign Plans		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Equity securities:	Mutual funds	$	19			$	—			$	—			$	19			$	14			$	—			$	—			$	14
	Private equity	—				—				1				1				—				—				1				1
Debt securities:	Government debt securities	—				—				—				—				13				—				—				13
	Mutual funds (1)	17				88				—				105				287				84				—				371
Real estate:	Real estate	—				—				2				2				—				—				2				2
Other:	Cash and cash equivalents	—				—				—				—				2				—				—				2
	Other assets	1				—				1				2				1				—				6				7
	Total plan assets	$	37			$	88			$	4			$	129			$	317			$	84			$	9			$	410

_____________________________

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

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The following table summarizes the estimated cash flows for U.S. and foreign expected employer contributions and expected future benefit payments, both domestic and foreign (in millions):

		U.S.				Foreign
Expected employer contribution in 2020		$	8			$	8
Expected benefit payments for fiscal year ending:
2020		71				15
2021		72				13
2022		73				14
2023		73				15
2024		73				17
2025 - 2029		365				105

The following table is a reconciliation of changes in redeemable stock of subsidiaries (in millions):

December 31,	2019				2018
Balance at the beginning of the period	$	879			$	837
Contributions from holders of redeemable stock of subsidiaries	10				34
Net income (loss) attributable to redeemable stock of subsidiaries	(7		)		2
Fair value adjustment	6				4
Other comprehensive income (loss) attributable to redeemable stock of subsidiaries	—				2
Balance at the end of the period	$	888			$	879

The following table summarizes the Company's redeemable stock of subsidiaries balances as of the periods indicated (in millions):

December 31,	2019				2018
IPALCO common stock	$	618			$	618
Colon quotas (1)	210				201
IPL preferred stock	60				60
Total redeemable stock of subsidiaries	$	888			$	879

 _____________________________

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

Colon — Our partner in Colon made capital contributions of $10 million and $34 million during the year ended December 31, 2019 and 2018, respectively. Any subsequent adjustments to allocate earnings and dividends to our partner, or measure the investment at fair value, will be classified as temporary equity each reporting period as it is probable that the shares will become redeemable.

Equity Transactions with Noncontrolling Interests

Distributed Energy — In 2019 and 2018, Distributed Energy, through multiple transactions, sold noncontrolling interests in multiple project companies to tax equity partners. These transactions resulted in a $133 million and $98 million increase to noncontrolling interest in 2019 and 2018, respectively. Distributed Energy is reported in the US and Utilities SBU reportable segment.

Alto Maipo — In March 2017, AES Gener completed the legal and financial restructuring of Alto Maipo. As part of this restructuring, AES indirectly acquired the 40% ownership interest of the noncontrolling shareholder for a de minimis payment, and sold a 6.7% interest in the project to the construction contractor. This transaction resulted in a $196 million increase to the Parent Company’s Stockholders’ Equity due to an increase in additional paid-in-capital of $229 million, offset by the reclassification of accumulated other comprehensive losses from NCI to the Parent

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Company Stockholders’ Equity of $33 million. No gain or loss was recognized in net income as the sale was not considered to be a sale of in-substance real estate. After completion of the sale, the Company has an effective 62% economic interest in Alto Maipo. As the Company maintained control of the partnership after the sale, Alto Maipo continues to be consolidated by the Company within the South America SBU reportable segment.

Dominican Republic — In September 2017, Linda Group acquired 5% of our Dominican Republic business for $60 million, pre-tax. This transaction resulted in a net increase of $25 million to the Company’s additional paid-in-capital and noncontrolling interest, respectively. No gain or loss was recognized in net income as the sale was not considered a sale of in-substance real estate. As the Company maintained control after the sale, our businesses in the Dominican Republic continue to be consolidated by the Company within the MCAC SBU reportable segment.

The following table summarizes the net income attributable to The AES Corporation and all transfers (to) from noncontrolling interests for the periods indicated (in millions):

		December 31,
		2019				2018				2017
Net income (loss) attributable to The AES Corporation		$	303			$	1,203			$	(1,161	)
Transfers from noncontrolling interest:
Increase (decrease) in The AES Corporation's paid-in capital for sale of subsidiary shares		(5		)		(3		)		13
Increase (decrease) in The AES Corporation's paid-in-capital for purchase of subsidiary shares		—				—				240
Net transfers (to) from noncontrolling interest		(5		)		(3		)		253
Change from net income (loss) attributable to The AES Corporation and transfers (to) from noncontrolling interests		$	298			$	1,200			$	(908	)

Accumulated Other Comprehensive Loss — The changes in AOCL by component, net of tax and noncontrolling interests, for the periods indicated were as follows (in millions):

	Foreign currency translation adjustment, net				Derivative gains (losses), net				Unfunded pension obligations, net				Total
Balance at December 31, 2017	$	(1,486	)		$	(333	)		$	(57	)		$	(1,876	)
Other comprehensive loss before reclassifications	(214		)		(64		)		—				(278		)
Amount reclassified to earnings	(21		)		78				7				64
Other comprehensive income (loss)	$	(235	)		$	14			$	7			$	(214	)
Cumulative effect of a change in accounting principle	—				19				—				19
Balance at December 31, 2018	$	(1,721	)		$	(300	)		$	(50	)		$	(2,071	)
Other comprehensive loss before reclassifications	$	(23	)		$	(202	)		$	(15	)		$	(240	)
Amount reclassified to earnings	23				36				27				86
Other comprehensive income (loss)	$	—			$	(166	)		$	12			$	(154	)
Cumulative effect of a change in accounting principle	—				(4		)		—				(4		)
Balance at December 31, 2019	$	(1,721	)		$	(470	)		$	(38	)		$	(2,229	)

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Reclassifications out of AOCL are presented in the following table. Amounts for the periods indicated are in millions and those in parenthesis indicate debits to the Consolidated Statements of Operations:

Details About				December 31,
AOCL Components		Affected Line Item in the Consolidated Statements of Operations		2019				2018				2017
Foreign currency translation adjustments, net
		Gain (loss) on disposal and sale of business interests		$	(23	)		$	19			$	(188	)
		Net gain from disposal of discontinued operations		—				2				(455		)
		Net income (loss) attributable to The AES Corporation		$	(23	)		$	21			$	(643	)
Derivative gains (losses), net
		Non-regulated revenue		$	(1	)		$	(6	)		$	25
		Non-regulated cost of sales		(12		)		(3		)		(12		)
		Interest expense		(26		)		(49		)		(79		)
		Gain (loss) on disposal and sale of business interests		1				—				—
		Foreign currency transaction gains (losses)		(12		)		(59		)		15
		Income from continuing operations before taxes and equity in earnings of affiliates		(50		)		(117		)		(51		)
		Income tax expense		13				24				1
		Net equity in earnings (losses) of affiliates		(5		)		—				—
		Income (loss) from continuing operations		(42		)		(93		)		(50		)
		Less: Income from continuing operations attributable to noncontrolling interests and redeemable stock of subsidiaries		6				15				13
		Net income (loss) attributable to The AES Corporation		$	(36	)		$	(78	)		$	(37	)
Amortization of defined benefit pension actuarial losses, net
		Non-regulated cost of sales		—				—				1
		General and administrative expenses		—				—				(1		)
		Other expense		(2		)		(6		)		—
		Gain (loss) on disposal and sale of business interests		(26		)		—				—
		Income from continuing operations before taxes and equity in earnings of affiliates		(28		)		(6		)		—
		Income tax expense		—				2				—
		Income (loss) from continuing operations		(28		)		(4		)		—
		Net gain (loss) from disposal of discontinued operations		—				(2		)		(266		)
		Net income (loss)		(28		)		(6		)		(266		)
		Less: Income from continuing operations attributable to noncontrolling interests and redeemable stock of subsidiaries		1				(1		)		—
		Add: Loss from discontinued operations attributable to noncontrolling interests		—				—				18
		Net income (loss) attributable to The AES Corporation		$	(27	)		$	(7	)		$	(248	)
Total reclassifications for the period, net of income tax and noncontrolling interests				$	(86	)		$	(64	)		$	(928	)

Common Stock Dividends — The Parent Company paid dividends of $0.1365 per outstanding share to its common stockholders during the first, second, third and fourth quarters of 2019 for dividends declared in December 2018, February, July and October 2019, respectively.

On December 6, 2019, the Board of Directors declared a quarterly common stock dividend of $0.1433 per share payable on February 14, 2020 to shareholders of record at the close of business on January 31, 2020.

Stock Repurchase Program — No shares were repurchased in 2019. The cumulative repurchases from the commencement of the Program in July 2010 through December 31, 2019 totaled 154.3 million shares for a total cost of $1.9 billion, at an average price per share of $12.12 (including a nominal amount of commissions). As of December 31, 2019, $264 million remained available for repurchase under the Program.

The common stock repurchased has been classified as treasury stock and accounted for using the cost method. A total of 153,891,260 and 154,905,595 shares were held as treasury stock at December 31, 2019 and 2018, respectively. Restricted stock units under the Company's employee benefit plans are issued from treasury stock. The Company has not retired any common stock repurchased since it began the Program in July 2010.

The segment reporting structure uses the Company's management reporting structure as its foundation to reflect how the Company manages the businesses internally and is mainly organized by geographic regions which provides a socio-political-economic understanding of our business. The management reporting structure is organized by four SBUs led by our President and Chief Executive Officer: US and Utilities, South America, MCAC, and Eurasia SBUs. Using the accounting guidance on segment reporting, the Company determined that its four operating segments are aligned with its four reportable segments corresponding to its SBUs.

Corporate and Other — Included in "Corporate and Other" are the results of the AES self-insurance company

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and certain equity affiliates, corporate overhead costs which are not directly associated with the operations of our four reportable segments, and certain intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

The Company uses Adjusted PTC as its primary segment performance measure. Adjusted PTC, a non-GAAP measure, is defined by the Company as pre-tax income from continuing operations attributable to The AES Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; and (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations and office consolidation. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis adjusted for the same gains or losses excluded from consolidated entities. The Company has concluded Adjusted PTC better reflects the underlying business performance of the Company and is the most relevant measure considered in the Company's internal evaluation of the financial performance of its segments. Additionally, given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure that better assists investors in determining which businesses have the greatest impact on the Company's results.    

Revenue and Adjusted PTC are presented before inter-segment eliminations, which includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees, and the write-off of intercompany balances, as applicable. All intra-segment activity has been eliminated within the segment. Inter-segment activity has been eliminated within the total consolidated results.

The following tables present financial information by segment for the periods indicated (in millions):

	Total Revenue
Year Ended December 31,	2019				2018				2017
US and Utilities SBU	$	4,058			$	4,230			$	4,162
South America SBU	3,208				3,533				3,252
MCAC SBU	1,882				1,728				1,519
Eurasia SBU	1,047				1,255				1,590
Corporate and Other	46				41				35
Eliminations	(52		)		(51		)		(28		)
Total Revenue	$	10,189			$	10,736			$	10,530

Reconciliation from Income from Continuing Operations before Taxes and Equity in Earnings of Affiliates:	Total Adjusted PTC
Year Ended December 31,	2019				2018				2017
Income from continuing operations before taxes and equity in earnings of affiliates	$	1,001			$	2,018			$	771
Add: Net equity in earnings (losses) of affiliates	(172		)		39				71
Less: Income from continuing operations before taxes, attributable to noncontrolling interests	(277		)		(509		)		(521		)
Pre-tax contribution	552				1,548				321
Unrealized derivative and equity securities losses (gains)	113				33				(3		)
Unrealized foreign currency losses (gains)	36				51				(59		)
Disposition/acquisition losses (gains)	12				(934		)		123
Impairment expense	406				307				542
Loss on extinguishment of debt	121				180				62
Restructuring costs	—				—				31
Total Adjusted PTC	$	1,240			$	1,185			$	1,017

	Total Adjusted PTC
Year Ended December 31,	2019				2018				2017
US and Utilities SBU	$	569			$	511			$	424
South America SBU	504				519				446
MCAC SBU	367				300				277
Eurasia SBU	159				222				290
Corporate and Other	(347		)		(346		)		(411		)
Eliminations	(12		)		(21		)		(9		)
Total Adjusted PTC	$	1,240			$	1,185			$	1,017

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	Total Assets												Depreciation and Amortization												Capital Expenditures
Year Ended December 31,	2019				2018				2017				2019				2018				2017				2019				2018					2017
US and Utilities SBU	$	13,334			$	12,286			$	11,548			$	465			$	449			$	487			$	1,484			$	1,373				$	905
South America SBU	11,314				10,941				11,126				315				300				301				692				662					477
MCAC SBU	4,770				4,462				4,087				183				141				122				344				302					435
Eurasia SBU	3,990				4,538				6,002				67				99				127				30				51			—		211
Discontinued operations	—				—				86				—				—				123				—				—					315
Corporate and Other	240				294				263				15				14				9				1				8					13
Total	$	33,648			$	32,521			$	33,112			$	1,045			$	1,003			$	1,169			$	2,551			$	2,396				$	2,356

	Interest Income												Interest Expense
Year Ended December 31,	2019				2018				2017				2019				2018				2017
US and Utilities SBU	$	18			$	10			$	5			$	301			$	287			$	315
South America SBU	95				92				95				285				283				297
MCAC SBU	22				20				13				142				124				111
Eurasia SBU	180				186				130				127				145				167
Corporate and Other	3				2				1				195				217				280
Total	$	318			$	310			$	244			$	1,050			$	1,056			$	1,170

	Investments in and Advances to Affiliates												Net Equity in Earnings (Losses) of Affiliates
Year Ended December 31,	2019				2018				2017				2019				2018				2017
US and Utilities SBU	$	465			$	538			$	535			$	11			$	35			$	41
South America SBU	77				213				358				(129		)		15				28
MCAC SBU	107				5				(5		)		(13		)		(7		)		(4		)
Eurasia SBU	215				293				307				(9		)		14				9
Corporate and Other	102				65				2				(32		)		(18		)		(3		)
Total	$	966			$	1,114			$	1,197			$	(172	)		$	39			$	71

The following table presents information, by country, about the Company's consolidated operations for each of the three years ended December 31, 2019, 2018, and 2017, and as of December 31, 2019 and 2018 (in millions). Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.

	Total Revenue												Property, Plant & Equipment, net
Year Ended December 31,	2019				2018				2017				2019				2018
United States (1)	$	3,230			$	3,462			$	3,487			$	9,706			$	8,731
Non-U.S.:
Chile	1,839				2,087				1,944				5,939				5,453
Dominican Republic	877				884				826				1,002				903
El Salvador	824				768				686				343				334
Panama	601				438				338				1,819				1,777
Brazil	525				527				541				1,260				1,287
Colombia	472				428				332				340				302
Bulgaria	459				426				367				1,104				1,183
Mexico	402				399				352				648				666
Argentina	373				487				435				392				234
Vietnam (2)	343				245				278				2				2
United Kingdom (3)	147				390				328				—				90
Jordan (4)	95				95				95				—				418
Philippines (5)	—				93				449				—				—
Kazakhstan	—				—				67				—				—
Other Non-U.S.	2				7				5				19				16
Total Non-U.S.	6,959				7,274				7,043				12,868				12,665
Total	$	10,189			$	10,736			$	10,530			$	22,574			$	21,396

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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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RESTRICTED STOCK

Restricted Stock Units — The Company issues RSUs under its long-term compensation plan. The RSUs are generally granted based upon a percentage of the participant's base salary. The units have a three-year vesting schedule and vest in one-third increments over the three-year period. In all circumstances, RSUs granted by AES do not entitle the holder the right, or obligate AES, to settle the RSU in cash or other assets of AES.

For the years ended December 31, 2019, 2018, and 2017, RSUs issued had a grant date fair value equal to the closing price of the Company's stock on the grant date. The Company does not discount the grant date fair values to reflect any post-vesting restrictions. RSUs granted to employees during the years ended December 31, 2019, 2018, and 2017 had grant date fair values per RSU of $17.53, $10.55 and $11.93, respectively.

The following table summarizes the components of the Company's stock-based compensation related to its employee RSUs recognized in the Company's consolidated financial statements (in millions):

December 31,		2019				2018				2017
RSU expense before income tax		$	10			$	11			$	17
Tax benefit		(1		)		(2		)		(4		)
RSU expense, net of tax		$	9			$	9			$	13
Total value of RSUs converted (1)		$	12			$	10			$	10
Total fair value of RSUs vested		$	10			$	16			$	15

_____________________________

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

Cash was not used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2019, 2018, and 2017. As of December 31, 2019, total unrecognized compensation cost related to RSUs of $10 million is expected to be recognized over a weighted average period of approximately 1.8 years. There were no modifications to RSU awards during the year ended December 31, 2019.

A summary of the activity of RSUs for the year ended December 31, 2019 follows (RSUs in thousands):

		RSUs			Weighted Average Grant Date Fair Values				Weighted Average Remaining Vesting Term
Nonvested at December 31, 2018		1,923			$	10.80
Vested		(996	)		10.37
Forfeited and expired		(68	)		11.97
Granted		625			17.53
Nonvested at December 31, 2019		1,484			$	13.73			1.4
Vested and expected to vest at December 31, 2019		1,360			$	13.57

The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2019, AES has estimated a weighted average forfeiture rate of 11.95% for RSUs granted in 2019. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $10 million on a straight-line basis over a three-year period.

The following table summarizes the RSUs that vested and were converted during the periods indicated (RSUs in thousands):

Year Ended December 31,		2019			2018			2017
RSUs vested during the year		996			1,428			1,337
RSUs converted during the year, net of shares withheld for taxes		666			950			865
Shares withheld for taxes		329			478			472

OTHER SHARE BASED COMPENSATION

The Company has three other share-based award programs. The Company has recorded expenses of $22 million, $20 million and $8 million for 2019, 2018 and 2017, respectively, related to these programs.

Stock options — AES grants options to purchase shares of common stock under stock option plans to non-employee directors. Under the terms of the plans, the Company may issue options to purchase shares of the Company's common stock at a price equal to 100% of the market price at the date the option is granted. Stock options issued in 2017, 2018 and 2019 have a three-year vesting schedule and vest in one-third increments over

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the three-year period. The stock options have a contractual term of 10 years. In all circumstances, stock options granted by AES do not entitle the holder the right, or obligate AES, to settle the stock option in cash or other assets of AES.

Performance Stock Units — In 2017, 2018 and 2019, the Company issued PSUs to officers under its long-term compensation plan. PSUs are stock units which include performance conditions. Performance conditions are based on the Company's Proportional Free Cash Flow targets for 2017, 2018 and 2019. The performance conditions determine the vesting and final share equivalent per PSU and can result in earning an award payout range of 0% to 200%, depending on the achievement. The Company believes that it is probable that the performance condition will be met and will continue to be evaluated throughout the performance period. In all circumstances, PSUs granted by AES do not entitle the holder the right, or obligate AES, to settle the stock units in cash or other assets of AES.

The following table presents our revenue from contracts with customers and other revenue for the periods indicated (in millions):

	Year Ended December 31, 2019
	US and Utilities SBU				South America SBU				MCAC SBU				Eurasia SBU				Corporate, Other and Eliminations				Total
Regulated Revenue
Revenue from contracts with customers	$	2,979			$	—			$	—			$	—			$	—			$	2,979
Other regulated revenue	49				—				—				—				—				49
Total regulated revenue	3,028				—				—				—				—				3,028
Non-Regulated Revenue
Revenue from contracts with customers	767				3,205				1,788				799				(4		)		6,555
Other non-regulated revenue (1)	263				3				94				248				(2		)		606
Total non-regulated revenue	1,030				3,208				$	1,882			1,047				(6		)		7,161
Total revenue	$	4,058			$	3,208			$	1,882			$	1,047			$	(6	)		$	10,189

	Year Ended December 31, 2018
	US and Utilities SBU				South America SBU				MCAC SBU				Eurasia SBU				Corporate, Other and Eliminations				Total
Regulated Revenue
Revenue from contracts with customers	$	2,885			$	—			$	—			$	—			$	—			$	2,885
Other regulated revenue	54				—				—				—				—				54
Total regulated revenue	2,939				—				$	—			—				$	—			2,939
Non-Regulated Revenue
Revenue from contracts with customers	972				3,529				1,642				$	943			(11		)		$	7,075
Other non-regulated revenue (1)	319				4				86				312				1				722
Total non-regulated revenue	1,291				$	3,533			1,728				$	1,255			(10		)		$	7,797
Total revenue	$	4,230			$	3,533			$	1,728			$	1,255			$	(10	)		$	10,736

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

Contract Balances — The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. The contract liabilities from contracts with customers were $117 million and $109 million as of December 31, 2019 and December 31, 2018, respectively.

During the years ended December 31, 2019 and 2018, we recognized revenue of $13 million and $36 million, respectively, that was included in the corresponding contract liability balance at the beginning of the periods.

A significant financing arrangement exists for our Mong Duong plant in Vietnam. The plant was constructed under a build, operate, and transfer contract and will be transferred to the Vietnamese government after the completion of a 25 year PPA. The performance obligation to construct the facility was substantially completed in

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2015. Approximately $1.4 billion of contract consideration related to the construction, but not yet collected through the 25 year PPA, was reflected as a loan receivable as of December 31, 2019.

Remaining Performance Obligations — The transaction price allocated to remaining performance obligations represents future consideration for unsatisfied (or partially unsatisfied) performance obligations at the end of the reporting period. As of December 31, 2019, the aggregate amount of transaction price allocated to remaining performance obligations was $12 million, primarily consisting of fixed consideration for the sale of renewable energy credits (RECs) in long-term contracts in the U.S. We expect to recognize revenue on approximately one-fifth of the remaining performance obligations in 2020 and 2021, with the remainder recognized thereafter.

Other income generally includes gains on insurance recoveries in excess of property damage, gains on asset sales and liability extinguishments, favorable judgments on contingencies, gains on contract terminations, allowance for funds used during construction and other income from miscellaneous transactions. Other expense generally includes losses on asset sales and dispositions, losses on legal contingencies, defined benefit plan non-service costs, and losses from other miscellaneous transactions. The components are summarized as follows (in millions):

	Year Ended December 31,	2019				2018				2017
Other Income	Gain on insurance proceeds (1)	$	118			$	—			$	—
	Gain on remeasurement of contingent consideration (2)	—				32				—
	AFUDC (US Utilities)	3				8				26
	Legal settlements (3)	—				—				60
	Other	24				32				34
	Total other income	$	145			$	72			$	120
Other Expenses	Loss on commencement of sales-type leases (4)	36				—				—
	Loss on sale and disposal of assets (5)	22				30				28
	Non-service pension and other postretirement costs	17				10				1
	Allowance for other receivables	—				7				—
	Water rights write-off	—				—				19
	Other	5				11				10
	Total other expense	$	80			$	58			$	58

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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.

Year ended December 31, (in millions)		2019				2018				2017
Kilroot and Ballylumford		$	115			$	—			$	37
Hawaii		60				—				—
Shady Point		—				157				—
Nejapa		—				37				—
DPL		—				—				175
Laurel Mountain		—				—				121
Kazakhstan Hydroelectric		—				—				92
Kazakhstan CHPs		—				—				94
Other		10				14				18
Total		$	185			$	208			$	537

Hawaii — During the fourth quarter of 2019, the Company tested the recoverability of its long-lived coal-fired asset in Hawaii. Uncertainty around the ability to contract the asset upon expiration of its existing PPA resulted in management's decision to reassess the economic useful life of the generation facility. A decrease in the economic useful life was identified as an impairment indicator. The Company determined that the carrying amount was not recoverable. The asset group, consisting of property, plant and equipment and intangible assets, was determined to

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have a fair value of $103 million using the income approach. As a result, the Company recognized asset impairment expense of $60 million as of December 31, 2019. Hawaii is reported in the US and Utilities SBU reportable segment.

Kilroot and Ballylumford — During the fourth quarter of 2017, the Company tested the recoverability of its long-lived assets at Kilroot, a coal and oil-fired plant in Northern Ireland, as Kilroot was not successful in bidding its coal units into the December 2017 capacity auction for the newly implemented I-SEM market. The Company determined that the carrying amount of the asset group was not recoverable. The Kilroot asset group was determined to have a fair value of $20 million using the income approach. As a result, the Company recognized asset impairment expense of $37 million during the year ended December 31, 2017, which was limited to the carrying value of the coal units.

In April 2019, the Company entered into an agreement to sell its entire 100% interest in the Kilroot coal and oil-fired plant and energy storage facility and the Ballylumford gas-fired plant in the United Kingdom. Upon meeting the held-for-sale criteria, the Company performed an impairment analysis and determined that the carrying value of the asset group of $232 million was greater than its fair value less costs to sell of $114 million. As a result, the Company recognized asset impairment expense of $115 million. The Company completed the sale of Kilroot and Ballylumford in June 2019. Prior to their sale, Kilroot and Ballylumford were reported in the Eurasia SBU reportable segment. See Note 25—Held-for-Sale and Dispositions for further information.

Shady Point — In December 2018, the Company entered into an agreement to sell Shady Point, a coal-fired generation facility in the U.S. Due first to the uncertainty around future cash flows, and then upon meeting the held-for-sale criteria, the Company performed an impairment analysis of the Shady Point asset group in the second, third and fourth quarters of 2018, resulting in the recognition of total asset impairment expense of $157 million for the year ended December 31, 2018. Using the market approach, the asset group was determined to have a fair value of $30 million as of December 31, 2018. The sale was completed in May 2019. Prior to the sale, Shady Point was reported in the US and Utilities SBU reportable segment. See Note 25—Held-for-Sale and Dispositions for further information.

Nejapa — During the fourth quarter of 2018, the Company tested the recoverability of its long-lived assets at Nejapa, a landfill gas plant in El Salvador. Decreased production as a result of the landfill owner's failure to perform improvements necessary to continue extracting gas from the landfill was identified as an impairment indicator. The Company determined that the carrying amount was not recoverable. The asset group, consisting of property, plant, and equipment and intangible assets, was determined to have a fair value of $5 million using the income approach. As a result, the Company recognized asset impairment expense of $37 million as of December 31, 2018. Nejapa is reported in the US and Utilities SBU reportable segment.

DPL — In March 2017, the Board of Directors of DPL approved the retirement of the DPL operated and co-owned Stuart coal-fired and diesel-fired generating units, and the Killen coal-fired generating unit and combustion turbine on or before June 1, 2018. The Company performed an impairment analysis and determined that the carrying amounts of the facilities were not recoverable. The Stuart and Killen asset groups were determined to have fair values of $3 million and $8 million, respectively, using the income approach. As a result, the Company recognized total asset impairment expense of $66 million. The Stuart and Killen units were retired in May 2018. Prior to their retirement, Stuart and Killen were reported in the US and Utilities SBU reportable segment.

In December 2017, DPL entered into an agreement for the sale of six of its combustion turbine and diesel-fired generation facilities and related assets ("DPL peaker assets"). Upon meeting the held-for-sale criteria, the Company performed an impairment analysis and determined that the carrying value of the asset group of $346 million was greater than its fair value less costs to sell of $237 million. As a result, the Company recognized asset impairment expense of $109 million. DPL completed the sale of the peaker assets in March 2018. Prior to their sale, the DPL peaker assets were reported in the US and Utilities SBU reportable segment. See Note 25—Held-for-Sale and Dispositions for further information.

Laurel Mountain — During the fourth quarter of 2017, the Company tested the recoverability of its long-lived assets at Laurel Mountain, a wind farm in the U.S. Impairment indicators were identified based on a decline in forward pricing. The Company determined that the carrying amount was not recoverable. The Laurel Mountain asset group was determined to have a fair value of $33 million using the income approach. As a result, the Company recognized asset impairment expense of $121 million. Laurel Mountain is reported in the US and Utilities SBU reportable segment.

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Kazakhstan Hydroelectric — In April 2017, the Republic of Kazakhstan stated the concession agreements would not be extended for Shulbinsk HPP and Ust-Kamenogorsk HPP, two hydroelectric plants in Kazakhstan, and initiated the process to transfer these plants back to the government. Upon meeting the held-for-sale criteria in the second quarter of 2017, the Company performed an impairment analysis and determined the carrying value of the asset group of $190 million, which included cumulative translation losses of $100 million, was greater than its fair value less costs to sell of $92 million. As a result, the Company recognized asset impairment expense of $92 million limited to the carrying value of the long-lived assets. The Company completed the transfer of the plants in October 2017. Prior to their transfer, the Kazakhstan hydroelectric plants were reported in the Eurasia SBU reportable segment. See Note 25—Held-for-Sale and Dispositions for further information.

Kazakhstan CHPs — In January 2017, the Company entered into an agreement for the sale of Ust-Kamenogorsk CHP and Sogrinsk CHP, its combined heating and power coal plants in Kazakhstan. Upon meeting the held-for-sale criteria in the first quarter of 2017, the Company performed an impairment analysis and determined that the carrying value of the asset group of $171 million, which included cumulative translation losses of $92 million, was greater than its fair value less costs to sell of $29 million. As a result, the Company recognized asset impairment expense of $94 million limited to the carrying value of the long-lived assets. The Company completed the sale of its interest in the Kazakhstan CHP plants in April 2017. Prior to their sale, the plants were reported in the Eurasia SBU reportable segment. See Note 25—Held-for-Sale and Dispositions for further information.

U.S. Tax Reform — In 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “TCJA”). The TCJA significantly changed U.S. corporate income tax law. Among other changes effective in 2017, the TCJA required companies to pay a one-time tax on certain unrepatriated earnings of foreign subsidiaries. Many other changes took effect in 2018, including a limit on the deductibility of interest expense and a new regime for taxing certain earnings of foreign subsidiaries.

The Company recognized the income tax effects of the TCJA in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) which provides SEC guidance on the application of ASC 740, Income Taxes, in the reporting period in which the TCJA was signed into law. Accordingly, the Company’s 2017 financial statements reflected provisional amounts for those impacts for which the accounting under ASC 740 was incomplete, but a reasonable estimate could be determined. As of December 31, 2018, the Company's accounting for the initial impacts of the TCJA was complete under SAB 118.

For the year ended December 31, 2018 the Company increased its estimate of the one-time transition tax by $194 million to $869 million. The estimated tax expense recognized for the year ended December 31, 2017 relating to the remeasurement of deferred tax assets and liabilities from an income tax rate of 35% to 21%, decreased $77 million, resulting in a total remeasurement benefit of $38 million.

In 2019, the U.S. Treasury issued final regulations related to the one-time transition tax which further amended the guidance of previously proposed regulations. As a result, $17 million of tax benefit was recorded in 2019, decreasing the total one-time transition tax to $852 million. This impact was partially offset by $7 million of deferred tax remeasurement expense, decreasing the total remeasurement benefit to $31 million.

Argentine Tax Reform — In December 2017, the Argentine government enacted reforms to its income tax laws that resulted in a decrease to statutory income tax rates for our Argentine businesses from 35% to 30% in 2018-2019 and to 25% for 2020 and future years. The impact of remeasuring deferred taxes to account for the enacted change in future applicable income tax rates was recognized as income tax benefit in the fourth quarter of 2017, resulting in a decrease of $21 million to consolidated income tax expense. In December 2019, the Argentine government delayed certain impacts of the 2017 reform. The corporate income tax rate for 2020 and 2021 will remain at 30%, reducing to 25% only from 2022. The impact of remeasuring deferred taxes for this latest change to enacted income tax rates was recognized as income tax expense of $4 million in the fourth quarter of 2019.

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Income Tax Provision — The following table summarizes the expense for income taxes on continuing operations for the periods indicated (in millions):

December 31,		2019				2018				2017
Federal:	Current	$	(7	)		$	7			$	—
	Deferred	(4		)		186				545
State:	Current	(1		)		2				—
	Deferred	—				5				1
Foreign:	Current	368				378				335
	Deferred	(4		)		130				109
Total		$	352			$	708			$	990

Effective and Statutory Rate Reconciliation — The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to the Company's effective tax rate as a percentage of income from continuing operations before taxes for the periods indicated:

December 31,		2019			2018			2017
Statutory Federal tax rate		21	%		21	%		35	%
State taxes, net of Federal tax benefit		6	%		2	%		(7	)%
Taxes on foreign earnings		12	%		9	%		—	%
Valuation allowance		(2	)%		(2	)%		10	%
Change in tax law		(1	)%		6	%		90	%
Other—net		(1	)%		(1	)%		—	%
Effective tax rate		35	%		35	%		128	%

For 2019, the 12% taxes on foreign earnings item includes $19 million of tax benefit associated with the Company's equity investment in Guacolda. Included in the 2019 change in tax law amount of (1)% are the downward adjustments to the U.S. one-time transition tax expense and deferred tax remeasurement benefit resulting from the issuance of the final regulations in 2019, offset by the impact of deferred tax remeasurement expense related to the December 2019 Argentina tax law change. 

For 2018, the 6% change in tax law item relates primarily to changes in estimate under SAB 118 of the impacts of adoption of the TCJA. The Company recognized tax expense of $194 million related to revised estimates of the one-time transition tax in accordance with proposed regulations issued by the U.S. Treasury in 2018. The adjustment was due in large part to the approach the proposed regulations adopted to determine the fair value of our interests in publicly traded subsidiaries. The Company also recognized tax benefit of $77 million related to revised estimates of deferred tax remeasurement. Included in the 9% taxes on foreign earnings item is $124 million of U.S. GILTI tax expense related to foreign subsidiaries, including the sale of our interest in Masinloc.

For 2017, the 90% change in tax law item relates primarily to the impact of U.S. and Argentine tax reform. The impact of the U.S one-time transition tax and remeasurement of deferred taxes represents 88% and 5%, respectively, which is partially offset by the tax benefit resulting from Argentine tax reform representing 3%.

Income Tax Receivables and Payables — The current income taxes receivable and payable are included in Other Current Assets and Accrued and Other Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The noncurrent income taxes receivable and payable are included in Other Noncurrent Assets and Other Noncurrent Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The following table summarizes the income taxes receivable and payable as of the periods indicated (in millions):

December 31,		2019				2018
Income taxes receivable—current		$	131			$	163
Income taxes receivable—noncurrent		10				8
Total income taxes receivable		$	141			$	171
Income taxes payable—current		$	172			$	210
Income taxes payable—noncurrent		—				7
Total income taxes payable		$	172			$	217

Deferred Income Taxes — Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss and tax credit carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.

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As of December 31, 2019, the Company had federal net operating loss carryforwards for tax return purposes of approximately $0.8 billion expiring in years 2033 to 2036. The Company also had federal general business tax credit carryforwards of approximately $23 million expiring primarily from 2021 to 2039, and federal alternative minimum tax credits of approximately $8 million that may be fully recovered by 2021 under the TCJA. Additionally, the Company had state net operating loss carryforwards as of December 31, 2019 of approximately $6.9 billion expiring primarily in years 2020 to 2039. As of December 31, 2019, the Company had foreign net operating loss carryforwards of approximately $2.7 billion that expire at various times beginning in 2020 and some of which carry forward without expiration, and tax credits available in foreign jurisdictions of approximately $14 million, $12 million of which expire in 2021.

Valuation allowances decreased $44 million during 2019 to $824 million at December 31, 2019. This net decrease was primarily the result of valuation allowance activity at certain U.S. states.

Valuation allowances decreased $120 million during 2018 to $868 million at December 31, 2018. This net decrease was primarily the result of valuation allowance activity at certain of our Brazil subsidiaries and U.S. states.

The Company believes that it is more likely than not that the net deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income.

The following table summarizes deferred tax assets and liabilities, as of the periods indicated (in millions):

December 31,		2019				2018
Differences between book and tax basis of property		$	(1,426	)		$	(1,418	)
Other taxable temporary differences		(287		)		(243		)
Total deferred tax liability		(1,713		)		(1,661		)
Operating loss carryforwards		1,060				1,066
Capital loss carryforwards		57				52
Bad debt and other book provisions		74				62
Tax credit carryforwards		33				55
Other deductible temporary differences		256				111
Total gross deferred tax asset		1,480				1,346
Less: valuation allowance		(824		)		(868		)
Total net deferred tax asset		656				478
Net deferred tax liability		$	(1,057	)		$	(1,183	)

The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested outside of the U.S. Except for the one-time transition tax in the U.S., no taxes have been recorded with respect to our indefinitely reinvested earnings in accordance with the relevant accounting guidance for income taxes. Should the earnings be remitted as dividends, the Company may be subject to additional foreign withholding and state income taxes. Under the TCJA, future distributions from foreign subsidiaries will generally be subject to a federal dividends received deduction in the U.S. As of December 31, 2019, the cumulative amount of U.S. GAAP foreign un-remitted earnings upon which additional income taxes have not been provided is approximately $4 billion. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings.

Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The Company's income tax benefits related to the tax status of these operations are estimated to be $26 million, $35 million and $26 million for the years ended December 31, 2019, 2018 and 2017, respectively. The per share effect of these benefits after noncontrolling interests was $0.02, $0.04 and $0.03 for the years ended December 31, 2019, 2018 and 2017, respectively. Included in the Company's income tax benefits is the benefit related to our operations in Vietnam, which is estimated to be $13 million, $19 million and $13 million for the years ended December 31, 2019, 2018 and 2017, respectively. The per share effect of these benefits related to our operations in Vietnam after noncontrolling interest was $0.01, $0.01 and $0.01 for the years ended December 31, 2019, 2018 and 2017, respectively.

The following table shows the income (loss) from continuing operations, before income taxes, net equity in earnings of affiliates and noncontrolling interests, for the periods indicated (in millions):

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December 31,		2019				2018				2017
U.S.		$	(57	)		$	(218	)		$	(511	)
Non-U.S.		1,058				2,236				1,282
Total		$	1,001			$	2,018			$	771

Uncertain Tax Positions — Uncertain tax positions have been classified as noncurrent income tax liabilities unless they are expected to be paid within one year. The Company's policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations. The following table shows the total amount of gross accrued income taxes related to interest and penalties included in the Consolidated Balance Sheets for the periods indicated (in millions):

December 31,		2019				2018
Interest related		$	2			$	4
Penalties related		—				—

The following table shows the expense/(benefit) related to interest and penalties on unrecognized tax benefits for the periods indicated (in millions):

December 31,		2019				2018				2017
Total expense (benefit) for interest related to unrecognized tax benefits		$	(2	)		$	(3	)		$	1
Total expense for penalties related to unrecognized tax benefits		—				—				—

We are potentially subject to income tax audits in numerous jurisdictions in the U.S. and internationally until the applicable statute of limitations expires. Tax audits by their nature are often complex and can require several years to complete. The following is a summary of tax years potentially subject to examination in the significant tax and business jurisdictions in which we operate:

Jurisdiction		Tax Years Subject to Examination
Argentina		2014-2019
Brazil		2014-2019
Chile		2016-2019
Colombia		2016-2019
Dominican Republic		2015-2019
El Salvador		2017-2019
Netherlands		2013-2019
Panama		2016-2019
United Kingdom		2016-2019
United States (Federal)		2016-2019

As of December 31, 2019, 2018 and 2017, the total amount of unrecognized tax benefits was $465 million, $463 million and $348 million, respectively. The total amount of unrecognized tax benefits that would benefit the effective tax rate as of December 31, 2019, 2018 and 2017 is $448 million, $446 million and $332 million, respectively, of which $33 million, $33 million and $29 million, respectively, would be in the form of tax attributes that would warrant a full valuation allowance. Further, the total amount of unrecognized tax benefit that would benefit the effective tax rate as of 2019 would be reduced by approximately $161 million of tax expense related to remeasurement from 35% to 21%.

The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax benefits within 12 months of December 31, 2019 is estimated to be between $0 million and $10 million, primarily relating to statute of limitation lapses and tax exam settlements.

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the periods indicated (in millions):

		2019				2018				2017
Balance at January 1		$	463			$	348			$	352
Additions for current year tax positions		6				2				—
Additions for tax positions of prior years		4				146				2
Reductions for tax positions of prior years		(5		)		(26		)		(5		)
Lapse of statute of limitations		(3		)		(7		)		(1		)
Balance at December 31		$	465			$	463			$	348

The Company and certain of its subsidiaries are currently under examination by the relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the

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taxing jurisdictions when determining the adequacy of the amount of unrecognized tax benefit recorded. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe we have appropriately accrued for our uncertain tax benefits. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits and the range of anticipated increases or decreases in unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of current or future examinations may exceed our provision for current unrecognized tax benefits in amounts that could be material, but cannot be estimated as of December 31, 2019. Our effective tax rate and net income in any given future period could therefore be materially impacted.

Due to a portfolio evaluation in the first half of 2016, management decided to pursue a strategic shift to reduce the Company's exposure to the Brazilian distribution market.

Eletropaulo — In November 2017, Eletropaulo converted its preferred shares into ordinary shares and transitioned the listing of those shares to the Novo Mercado, which is a listing segment of the Brazilian stock exchange with the highest standards of corporate governance. Upon conversion of the preferred shares into ordinary shares, AES no longer controlled Eletropaulo, but maintained significant influence over the business. As a result, the Company deconsolidated Eletropaulo. After deconsolidation, the Company's 17% ownership interest was reflected as an equity method investment. The Company recorded an after-tax loss on deconsolidation of $611 million, which primarily consisted of $455 million related to cumulative translation losses and $243 million related to pension losses reclassified from AOCL.

In December 2017, all remaining criteria were met for Eletropaulo to qualify as a discontinued operation. Therefore, its results of operations and financial position were reported as such in the consolidated financial statements for all periods presented.

In June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo through a bidding process hosted by the Brazilian securities regulator, CVM. Gross proceeds of $340 million were received at our subsidiary in Brazil, subject to the payment of taxes. Upon disposal of Eletropaulo, the Company recorded a pre-tax gain on sale of $243 million (after-tax $199 million).

Excluding the gain on sale, Eletropaulo's pre-tax loss attributable to AES was immaterial for the year ended December 31, 2018. Eletropaulo's pre-tax loss attributable to AES, including the loss on deconsolidation, for the year ended December 31, 2017 was $633 million. Prior to its classification as discontinued operations, Eletropaulo was reported in the South America SBU reportable segment.

Borsod — In 2011, Borsod, which held two coal and biomass-fired generation plants in Hungary, filed for liquidation and was deconsolidated with its historical operating results reflected in discontinued operations under prior accounting guidance. In October 2018, the liquidation was completed and the Company recognized a deferred gain of $26 million, primarily comprised of a $20 million write-off of cumulative translation balances. Prior to its liquidation, Borsod was reported in the Eurasia SBU reportable segment.

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Excluding the gain on sale of Eletropaulo and the deferred gain on liquidation of Borsod, income from discontinued operations and cash flows from operating and investing activities of discontinued operations were immaterial for the year ended December 31, 2018.

The following table summarizes the major line items constituting loss from discontinued operations for the period indicated (in millions):

December 31,	2017
Income (loss) from discontinued operations, net of tax:
Revenue — regulated	$	3,320
Cost of sales	(3,151		)
Other income and expense items that are not major (1)	(166		)
Income from operations of discontinued businesses	3
Loss from disposal and impairments of discontinued businesses	(611		)
Loss from discontinued operations	(608		)
Less: Net income attributable to noncontrolling interests	(25		)
Loss from discontinued operations attributable to The AES Corporation	(633		)
Income tax expense	(21		)
Loss from discontinued operations, net of tax	$	(654	)

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

The following table summarizes the operating and investing cash flows from discontinued operations for the period indicated (in millions):

December 31,	2017
Cash flows provided by operating activities of discontinued operations	$	164
Cash flows used in investing activities of discontinued operations	(288		)

Held-for-Sale

Jordan — In February 2019, the Company entered into an agreement to sell its 36% ownership interest in two generation plants, IPP1 and IPP4, and a solar plant in Jordan for $86 million, subject to customary post-closing adjustments, plus capital contributions to the solar project of approximately $5 million. The sale of IPP1 and IPP4 is expected to close in the first half of 2020 and the sale of the solar plant is expected to close in the second half of 2020. As of December 31, 2019, the generation plants and solar plant were classified as held-for-sale, but did not meet the criteria to be reported as discontinued operations. On a consolidated basis, the carrying value of the plants held-for-sale as of December 31, 2019 was $153 million. Pre-tax income attributable to AES was $19 million, $10 million and $11 million for the years ended December 31, 2019, 2018 and 2017, respectively. Jordan is reported in the Eurasia SBU reportable segment.

Redondo Beach — In October 2018, the Company entered into an agreement to sell land held by AES Redondo Beach, a gas-fired generating facility in California. The sale is expected to close by the end of the first quarter of 2020. As of December 31, 2019, the $24 million carrying value of the land held by Redondo Beach was classified as held-for-sale. Redondo Beach is reported in the US and Utilities SBU reportable segment.

Dispositions

Stuart and Killen — In December 2019, DPL completed the transfer of the co-owned Stuart coal-fired and diesel-fired generating units and the Killen coal-fired generating unit and combustion turbine retired in May 2018, including the associated environmental liabilities. The transfer resulted in cash expenditures of $51 million and a gain on disposal of $20 million. Prior to their transfer, Stuart and Killen were reported in the US and Utilities SBU reportable segment. See Note 22—Asset Impairment Expense for further information.

Kilroot and Ballylumford — In June 2019, the Company completed the sale of its entire interest in the Kilroot coal and oil-fired plant and energy storage facility and the Ballylumford gas-fired plant in the United Kingdom for $118 million, subject to customary post-closing adjustments, resulting in a pre-tax loss on sale of $33 million primarily due to the write-off of cumulative translation adjustments and accumulated other comprehensive income balances. The sale did not meet the criteria to be reported as discontinued operations. Prior to the sale, Kilroot and Ballylumford were reported in the Eurasia SBU reportable segment. See Note 22—Asset Impairment Expense for further information.

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Shady Point — In May 2019, the Company completed the sale of Shady Point, a U.S. coal-fired generating facility, for $29 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, Shady Point was reported in the US and Utilities SBU reportable segment. See Note 22—Asset Impairment Expense for further information.

CTNG — In December 2018, AES Gener completed the sale of CTNG, an entity that holds transmission lines in Chile, for $225 million, resulting in a pre-tax gain on sale of $126 million after post-closing adjustments. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, CTNG was reported in the South America SBU reportable segment.

Electrica Santiago — In May 2018, AES Gener completed the sale of Electrica Santiago for total consideration of $287 million, resulting in a final pre-tax gain on sale of $70 million after post-closing adjustments. Electrica Santiago consisted of four gas and diesel-fired generation plants in Chile. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, Electrica Santiago was reported in the South America SBU reportable segment.

Masinloc — In March 2018, the Company completed the sale of its entire 51% equity interest in Masinloc for cash proceeds of $1.05 billion, resulting in a pre-tax gain on sale of $772 million after post-closing adjustments, subject to U.S. income tax. Masinloc consisted of a coal-fired generation plant in operation, a coal-fired generation plant under construction and an energy storage facility all located in the Philippines. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, Masinloc was reported in the Eurasia SBU reportable segment.

In 2014, the Company completed the sale of 45% of its ownership interest in Masinloc for $436 million, including $23 million of consideration that was contingent upon the achievement of certain tax restructuring efficiencies. In December 2017, the related contingency expired and the $23 million of contingent consideration was recognized as a gain in Gain (loss) on disposal and sale of business interests in the Consolidated Statement of Operations.

DPL peaker assets — In March 2018, DPL completed the sale of six of its combustion turbine and diesel-fired generation facilities and related assets ("DPL peaker assets") for total proceeds of $239 million, resulting in a loss on sale of $2 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, the DPL peaker assets were reported in the US and Utilities SBU reportable segment.

Beckjord facility — In February 2018, DPL transferred its interest in Beckjord, a coal-fired generation facility retired in 2014, including its obligations to remediate the facility and its site. The transfer resulted in cash expenditures of $15 million, inclusive of disposal charges, and a loss on disposal of $12 million. Prior to the transfer, Beckjord was reported in the US and Utilities SBU reportable segment.

Advancion Energy Storage — In January 2018, the Company deconsolidated the AES Advancion energy storage development business and contributed it to the Fluence joint venture, resulting in a gain on sale of $23 million. See Note 8—Investments in and Advances to Affiliates for further discussion. Prior to the transfer, the AES Advancion energy storage development business was reported as part of Corporate and Other.

Zimmer and Miami Fort — In December 2017, DPL and AES Ohio Generation completed the sale of Zimmer and Miami Fort, two coal-fired generating plants, for net proceeds of $70 million, resulting in a gain on sale of $13 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, Zimmer and Miami Fort were reported in the US and Utilities SBU reportable segment.

Kazakhstan Hydroelectric — Affiliates of the Company (the “Affiliates”) previously operated Shulbinsk HPP and Ust-Kamenogorsk HPP (the “HPPs”), two hydroelectric plants in Kazakhstan, under a concession agreement with the Republic of Kazakhstan (“RoK”). In April 2017, the RoK initiated the process to transfer these plants back to the RoK. The RoK indicated that arbitration would be necessary to determine the correct Return Share Transfer Payment ("RST") and, rather than paying the Affiliates, deposited the RST into an escrow account. In exchange, the Affiliates transferred 100% of the shares in the HPPs to the RoK, under protest and with a full reservation of rights. The Company recorded a loss on disposal of $33 million in the fourth quarter of 2017. In February 2018, the Affiliates initiated the arbitration process in international court to recover at least $75 million of the RST placed in escrow, based on the September 30, 2017 RST calculation. As of December 31, 2019, the arbitration proceedings are ongoing, and additional losses are not considered probable at this time. However, additional losses may be incurred if some or all of the disputed consideration is not paid by the RoK via a mutually acceptable settlement, or

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upon any unfavorable decision rendered by the arbiter. The transfer did not meet the criteria to be reported as discontinued operations. Prior to their transfer, the Kazakhstan HPPs were reported in the Eurasia SBU reportable segment. See Note 22—Asset Impairment Expense for further information.

Kazakhstan CHPs — In April 2017, the Company completed the sale of Ust-Kamenogorsk CHP and Sogrinsk CHP, its combined heating and power coal plants in Kazakhstan, for net proceeds of $24 million. The Company recognized a pre-tax loss on sale of $49 million, primarily related to cumulative translation losses. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, the Kazakhstan CHP plants were reported in the Eurasia SBU reportable segment. See Note 22—Asset Impairment Expense for further information.

Excluding any impairment charge or gain/loss on sale, pre-tax income (loss) attributable to AES of disposed businesses was as follows (in millions):

Year Ended December 31,	2019				2018				2017
Kilroot and Ballylumford	$	(1	)		$	35			$	38
Stuart and Killen (1)(2)	52				77				17
Shady Point	(5		)		19				19
Masinloc	—				9				103
Zimmer and Miami Fort	—				—				26
Kazakhstan Hydroelectric	—				—				33
Other	—				21				39
Total	$	46			$	161			$	275

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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.

Los Cururos — In November 2019, AES Gener completed the acquisition of the Los Cururos wind farm and transmission lines in Chile from EPM Chile S.A. for total consideration of $143 million, including $5 million in working capital adjustments paid in the first quarter of 2020. The transaction was accounted for as an asset acquisition, therefore the consideration transferred, plus transaction costs, was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. Any differences arising from post-closing adjustments will be allocated accordingly. Los Cururos is reported in the South America SBU reportable segment.

Distributed Energy — In December 2018, Distributed Energy acquired the outstanding noncontrolling interest in a partnership holding various solar projects from its tax equity partner for $23 million of consideration in a non-cash transaction through the assumption of debt, increasing the Company's ownership to 100%. The partnership was previously classified as an equity method investment. The transaction was accounted for as an asset acquisition, therefore the Company remeasured the equity investment at fair value and recognized a loss of $5 million in Other expense in the Consolidated Statement of Operations. The fair value of the investment, along with the consideration transferred, plus transaction costs, was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. Distributed Energy is reported in the US and Utilities SBU reportable segment.

Oahu — In November 2018, AES Oahu amended a 2017 agreement to acquire 100% of Na Pua Makani Power Partners, a partnership designed to develop and hold a wind project in Hawaii. The fair value of the initial consideration was $53 million, of which $48 million was contingent on meeting predefined development milestones. The transaction was accounted for as an acquisition of a variable interest entity that did not meet the definition of a business, therefore the assets acquired and liabilities assumed were recorded at their fair values, which equaled the fair value of the consideration. As a result of the amendment, the Company paid $11 million in 2018 and the contingent consideration was reduced to $5 million, resulting in a $32 million gain on remeasurement of contingent consideration recorded in Other income in the Consolidated Statement of Operations. AES Oahu is reported in the US and Utilities SBU reportable segment.

Guaimbê Solar Complex — In September 2018, AES Tietê completed the acquisition of the Guaimbê Solar Complex (“Guaimbê”) from Cobra do Brasil for $152 million, comprised of the exchange of $119 million of non-convertible debentures in project financing and additional cash consideration of $33 million. The transaction was

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accounted for as an asset acquisition, therefore the consideration transferred, plus transaction costs, was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. Guaimbê is reported in the South America SBU reportable segment.

Alto Sertão II — In August 2017, the Company completed the acquisition of the Alto Sertão II Wind Complex (“Alto Sertão II”) from Renova Energia S.A. for $179 million, plus the assumption of $346 million of non-recourse debt. At closing, the Company made a cash payment of $143 million, which excluded holdbacks related to indemnifications. In September 2018, an additional $12 million was paid to settle a portion of the remaining indemnification liability. In the first quarter of 2018, the Company finalized the purchase price allocation related to the acquisition of Alto Sertão II. There were no significant adjustments made to the preliminary purchase price allocation recorded in the third quarter of 2017 when the acquisition was completed. The assets acquired and liabilities assumed at the acquisition date were recorded at fair value, including a contingent liability for earn-out payments of $18 million, based on the final purchase price allocation at March 31, 2018. Subsequent changes to the fair value of the earn-out payments will be reflected in earnings. Alto Sertão II is reported in the South America SBU reportable segment.

Basic and diluted earnings per share are based on the weighted-average number of shares of common stock and potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive RSUs and stock options. The effect of such potential common stock is computed using the treasury stock method.

The following table is a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation for income from continuing operations for the years ended December 31, 2019, 2018 and 2017, where income represents the numerator and weighted-average shares represent the denominator.

Year Ended December 31,	2019											2018											2017
(in millions, except per share data)	Income				Shares			$ per Share				Income				Shares			$ per Share				Loss				Shares			$ per Share
BASIC EARNINGS (LOSS) PER SHARE
Income (loss) from continuing operations attributable to The AES Corporation common stockholders	$	302			664			$	0.46			$	985			662			$	1.49			$	(507	)		660			$	(0.77	)
EFFECT OF DILUTIVE SECURITIES
Restricted stock units	—				3			(0.01		)		—				3			(0.01		)		—				—			—
DILUTED EARNINGS (LOSS) PER SHARE	$	302			667			$	0.45			$	985			665			$	1.48			$	(507	)		660			$	(0.77	)

The calculation of diluted earnings per share excluded stock awards which would be anti-dilutive. The calculation of diluted earnings per share excluded 2 million and 7 million stock awards outstanding for the years ended December 31, 2018 and 2017, respectively, that could potentially dilute basic earnings per share in the future.

For the year ended December 31, 2017, the calculation of diluted earnings per share also excluded 4 million outstanding restricted stock units that could potentially dilute earnings per share in the future, because their impact would be anti-dilutive given the loss from continuing operations. Had the Company generated income, 2 million potential shares of common stock related to the restricted stock units would have been included in diluted weighted-average shares outstanding.

AES is a diversified power generation and utility company organized into four market-oriented SBUs. See additional discussion of the Company's principal markets in Note 18—Segments and Geographic Information. Within our four SBUs, we have two primary lines of business: generation and utilities. The generation line of business uses a wide range of fuels and technologies to generate electricity such as coal, gas, hydro, wind, solar, and biomass. Our utilities business comprises businesses that transmit, distribute, and in certain circumstances, generate power. In addition, the Company has operations in the renewables area. These efforts include projects primarily in wind, solar, and energy storage.

Operating and Economic Risks — The Company operates in several developing economies where macroeconomic conditions are typically more volatile than developed economies. Deteriorating market conditions and evolving industry expectations to transition away from fossil fuel sources for generation expose the Company to

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the risk of decreased earnings and cash flows due to, among other factors, adverse fluctuations in the commodities and foreign currency spot markets, and potential changes in the estimated useful lives of our coal-fired generation assets. Additionally, credit markets around the globe continue to tighten their standards, which could impact our ability to finance growth projects through access to capital markets. Currently, the Company has an investment grade rating from Fitch of BBB-, and a below-investment grade rating from Standard & Poor's of BB+ and Moody's of Ba1. This could affect the Company's ability to finance new and/or existing development projects at competitive interest rates. As of December 31, 2019, the Company had $1 billion of unrestricted cash and cash equivalents.

During 2019, 68% of our revenue was generated outside the U.S. and a significant portion of our international operations is conducted in developing countries. We continue to invest in several developing countries to expand our existing platform and operations. International operations, particularly the operation, financing, and development of projects in developing countries, entail significant risks and uncertainties, including, without limitation:

•	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.

Any of these factors, individually or in combination with others, could materially and adversely affect our business, results of operations, and financial condition. In addition, our Latin American operations experience volatility in revenue and earnings which have caused and are expected to cause significant volatility in our results of operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability, indexation of certain PPAs to fuel prices, and currency fluctuations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses.

Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any inability to obtain reasonable increases in tariffs or tariff adjustments for increased expenses, could adversely impact our results of operations or our ability to meet publicly announced projections or analysts' expectations. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions where we operate, particularly our utility businesses where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:

•	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.

Any of the above events may result in lower margins for the affected businesses, which can adversely affect our results of operations.

Goodwill — The Company considers a reporting unit at risk of impairment when its fair value does not exceed its carrying amount by more than 10%. During the annual goodwill impairment test performed as of October 1, 2019, the Company determined that the fair value of its Gener reporting unit exceeded its carrying value by 3%. Therefore, Gener's $868 million goodwill balance was considered to be "at risk" as of December 31, 2019, largely due to the Chilean Government's announcement to phase out coal generation by 2040, and a decline in long-term energy prices.

The Company monitors its reporting units at risk of impairment for interim impairment indicators, and believes that the estimates and assumptions used in the calculations are reasonable as of December 31, 2019. Should the fair value of any of the Company’s reporting units fall below its carrying amount because of reduced operating performance, market declines, changes in the discount rate, regulatory changes, or other adverse conditions, goodwill impairment charges may be necessary in future periods.

Foreign Currency Risks — AES operates businesses in many foreign countries and such operations could be impacted by significant fluctuations in foreign currency exchange rates. Fluctuations in currency exchange rate between the USD and the following currencies could create significant fluctuations in earnings and cash flows: the Argentine peso, the Brazilian real, the Chilean peso, the Colombian peso, the Dominican Republic peso, the Euro, the Indian rupee, and the Mexican peso.

Argentina — In September 2019, currency controls were established by the Argentine government in order to control the devaluation of the Argentine peso and keep Argentine central bank reserves at acceptable levels. Restrictions on the flow of capital have limited the availability of international credit, and economic conditions in Argentina have further deteriorated, triggering additional devaluation of the Argentine peso and a deterioration of the country’s risk profile.

Concentrations — Due to the geographical diversity of its operations, the Company does not have any significant concentration of customers or sources of fuel supply. Several of the Company's generation businesses rely on PPAs with one or a limited number of customers for the majority of, and in some cases all of, the relevant businesses' output over the term of the PPAs. However, no single customer accounted for 10% or more of total revenue in 2019, 2018 or 2017.

The cash flows and results of operations of our businesses depend on the credit quality of our customers and the continued ability of our customers and suppliers to meet their obligations under PPAs and fuel supply agreements. If a substantial portion of the Company's long-term PPAs and/or fuel supply were modified or terminated, the Company would be adversely affected to the extent that it would be unable to replace such contracts at equally favorable terms.

Certain of our businesses in Panama and the Dominican Republic are partially owned by governments either directly or through state-owned institutions. In the ordinary course of business, these businesses enter into energy purchase and sale transactions, and transmission agreements with other state-owned institutions which are controlled by such governments. At two of our generation businesses in Mexico, the offtakers exercise significant influence, but not control, through representation on these businesses' Boards of Directors. These offtakers are also required to hold a nominal ownership interest in such businesses. In Chile, we provide capacity and energy under contractual arrangements to our investment which is accounted for under the equity method of accounting. Additionally, the Company provides certain support and management services to several of its affiliates under various agreements.

The Company's Consolidated Statements of Operations included the following transactions with related parties for the periods indicated (in millions):

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Years Ended December 31,	2019				2018				2017
Revenue—Non-Regulated	$	1,544			$	1,533			$	1,297
Cost of Sales—Non-Regulated	531				342				220
Interest income	21				14				8
Interest expense	74				54				36

The following table summarizes the balances receivable from and payable to related parties included in the Company's Consolidated Balance Sheets as of the periods indicated (in millions):

December 31,	2019				2018
Receivables from related parties	$	370			$	371
Accounts and notes payable to related parties (1)	1,976				754

_____________________________

(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.

Quarterly Financial Data — The following tables summarize the unaudited quarterly Condensed Consolidated Statements of Operations for the Company for 2019 and 2018 (amounts in millions, except per share data). Amounts have been restated to reflect discontinued operations in all periods presented and reflect all adjustments necessary in the opinion of management for a fair statement of the results for interim periods.

Quarter Ended 2019	Mar 31				Jun 30				Sep 30				Dec 31
Revenue	$	2,650			$	2,483			$	2,625			$	2,431
Operating margin	586				502				701				560
Income (loss) from continuing operations, net of tax (1)	233				66				298				(120		)
Income from discontinued operations, net of tax	—				1				—				—
Net income (loss)	$	233			$	67			$	298			$	(120	)
Net income (loss) attributable to The AES Corporation	$	154			$	17			$	210			$	(78	)
Basic earnings (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.23			$	0.02			$	0.32			$	(0.12	)
Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax	—				—				—				—
Net income (loss) attributable to The AES Corporation common stockholders	$	0.23			$	0.02			$	0.32			$	(0.12	)
Diluted earnings (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.23			$	0.02			$	0.32			$	(0.12	)
Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax	—				—				—				—
Net income (loss) attributable to The AES Corporation common stockholders	$	0.23			$	0.02			$	0.32			$	(0.12	)
Dividends declared per common share	$	0.14			$	—			$	0.14			$	0.28

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Quarter Ended 2018	Mar 31				Jun 30				Sep 30				Dec 31
Revenue	$	2,740			$	2,537			$	2,837			$	2,622
Operating margin	656				600				671				646
Income from continuing operations, net of tax (2)	778				224				192				155
Income (loss) from discontinued operations, net of tax (3)	(1		)		192				(1		)		26
Net income	$	777			$	416			$	191			$	181
Net income attributable to The AES Corporation	$	684			$	290			$	101			$	128
Basic earnings per share:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	1.04			$	0.15			$	0.15			$	0.15
Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax	—				0.29				—				0.04
Net income attributable to The AES Corporation common stockholders	$	1.04			$	0.44			$	0.15			$	0.19
Diluted earnings per share:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	1.03			$	0.15			$	0.15			$	0.15
Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax	—				0.29				—				0.04
Net income attributable to The AES Corporation common stockholders	$	1.03			$	0.44			$	0.15			$	0.19
Dividends declared per common share	$	0.13			$	—			$	0.13			$	0.27

_____________________________

(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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THE AES CORPORATION

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

BALANCE SHEETS

		December 31,
		2019				2018
		(in millions)
ASSETS
Current Assets:
Cash and cash equivalents		$	11			$	19
Accounts and notes receivable from subsidiaries		238				285
Prepaid expenses and other current assets		35				31
Total current assets		284				335
Investment in and advances to subsidiaries and affiliates		6,782				6,834
Office Equipment:
Cost		27				27
Accumulated depreciation		(20		)		(19		)
Office equipment, net		7				8
Other Assets:
Other intangible assets, net of accumulated amortization		1				3
Deferred financing costs, net of accumulated amortization of $5 and $4, respectively		5				4
Deferred income taxes		14				24
Other assets		16				2
Total other assets		36				33
Total assets		$	7,109			$	7,210
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable		$	20			$	15
Accounts and notes payable to subsidiaries		339				74
Accrued and other liabilities		221				206
Senior notes payable—current portion		5				5
Total current liabilities		585				300
Long-term Liabilities:
Senior notes payable		3,391				3,650
Accounts and notes payable to subsidiaries		28				28
Other long-term liabilities		109				24
Total long-term liabilities		3,528				3,702
Stockholders' equity:
Common stock		8				8
Additional paid-in capital		7,776				8,154
Accumulated deficit		(692		)		(1,005		)
Accumulated other comprehensive loss		(2,229		)		(2,071		)
Treasury stock		(1,867		)		(1,878		)
Total stockholders' equity		2,996				3,208
Total liabilities and equity		$	7,109			$	7,210

See Notes to Schedule I.

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THE AES CORPORATION

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF OPERATIONS

For the Years Ended December 31,		2019				2018				2017
		(in millions)
Revenue from subsidiaries and affiliates		$	30			$	36			$	28
Equity in earnings of subsidiaries and affiliates		674				1,909				630
Interest income		53				39				49
General and administrative expenses		(148		)		(142		)		(158		)
Other income		1				25				5
Other expense		(103		)		—				(554		)
Loss on extinguishment of debt		(5		)		(171		)		(92		)
Interest expense		(197		)		(220		)		(317		)
Income (loss) before income taxes		305				1,476				(409		)
Income tax (expense)		(2		)		(273		)		(752		)
Net income (loss)		$	303			$	1,203			$	(1,161	)

See Notes to Schedule I.

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THE AES CORPORATION

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017

	2019				2018				2017
	(in millions)
NET INCOME (LOSS)	$	303			$	1,203			$	(1,161	)
Foreign currency translation activity:
Foreign currency translation adjustments, net of income tax benefit of $1, $2 and $11, respectively	(23		)		(214		)		18
Reclassification to earnings, net of $0 income tax for all periods	23				(21		)		643
Total foreign currency translation adjustments, net of tax	—				(235		)		661
Derivative activity:
Change in derivative fair value, net of income tax benefit of $53, $16 and $13, respectively	(202		)		(64		)		(14		)
Reclassification to earnings, net of income tax benefit (expense) of $(4), $(13) and $1, respectively	36				78				37
Total change in fair value of derivatives, net of tax	(166		)		14				23
Pension activity:
Prior service cost for the period, net of income tax expense of $0, $1 and $1, respectively	1				(2		)		1
Change in pension adjustments due to net actuarial gain (loss) for the period, net of income tax benefit (expense) of $6, $(1) and $6, respectively	(16		)		2				(20		)
Reclassification of earnings, net of income tax expense of $13, $2 and $126, respectively	27				7				248
Total change in unfunded pension obligation	12				7				229
OTHER COMPREHENSIVE INCOME (LOSS)	(154		)		(214		)		913
COMPREHENSIVE INCOME (LOSS)	$	149			$	989			$	(248	)

See Notes to Schedule I.

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THE AES CORPORATION

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF CASH FLOWS

For the Years Ended December 31,		2019				2018				2017
		(in millions)
Net cash provided by operating activities		$	583			$	409			$	148
Investing Activities:
Proceeds from the sale of business interests, net of expenses		196				1,222				—
Investment in and net advances to subsidiaries		(596		)		(216		)		(339		)
Return of capital		411				242				243
Additions to property, plant and equipment		(8		)		(13		)		(13		)
Net cash provided by (used in) investing activities		3				1,235				(109		)
Financing Activities:
(Repayments) Borrowings under the revolver, net		180				(207		)		207
Borrowings of notes payable and other coupon bearing securities		—				1,000				1,025
Repayments of notes payable and other coupon bearing securities		(450		)		(1,933		)		(1,353		)
Loans from (Repayments to) subsidiaries		40				(143		)		309
Proceeds from issuance of common stock		6				7				1
Common stock dividends paid		(362		)		(344		)		(317		)
Payments for deferred financing costs		(3		)		(11		)		(12		)
Other financing		(4		)		(5		)		(7		)
Net cash used in financing activities		(593		)		(1,636		)		(147		)
Effect of exchange rate changes on cash		(1		)		1				6
Increase (Decrease) in cash and cash equivalents		(8		)		9				(102		)
Cash and cash equivalents, beginning		19				10				112
Cash and cash equivalents, ending		$	11			$	19			$	10
Supplemental Disclosures:
Cash payments for interest, net of amounts capitalized		$	192			$	232			$	282
Cash payments (refunds) for income taxes		$	(5	)		$	10			$	2

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SCHEDULE I

NOTES TO SCHEDULE I

1. Application of Significant Accounting Principles

The Schedule I Condensed Financial Information of the Parent includes the accounts of The AES Corporation (the “Parent Company”) and certain holding companies.

ACCOUNTING FOR SUBSIDIARIES AND AFFILIATES — The Parent Company has accounted for the earnings of its subsidiaries on the equity method in the financial information.

INCOME TAXES — Positions taken on the Parent Company's income tax return which satisfy a more-likely-than-not threshold will be recognized in the financial statements. The income tax expense or benefit computed for the Parent Company reflects the tax assets and liabilities on a stand-alone basis and the effect of filing a consolidated U.S. income tax return with certain other affiliated companies as well as effects of U.S. tax law reform enacted in 2017.

ACCOUNTS AND NOTES RECEIVABLE FROM SUBSIDIARIES — Amounts have been shown in current or long-term assets based on terms in agreements with subsidiaries, but payment is dependent upon meeting conditions precedent in the subsidiary loan agreements.

2. Debt

Senior and Secured Notes and Loans Payable ($ in millions)

						December 31,
		Interest Rate		Maturity		2019				2018
Senior Unsecured Note		4.00%		2021		500				500
Senior Secured Term Loan		LIBOR + 1.75%		2022		18				366
Senior Unsecured Note		4.875%		2023		613				713
Senior Unsecured Note		4.50%		2023		500				500
Drawings on secured credit facility		LIBOR + 1.75%		2024		180				—
Senior Unsecured Note		5.50%		2024		63				63
Senior Unsecured Note		5.50%		2025		544				544
Senior Unsecured Note		6.00%		2026		500				500
Senior Unsecured Note		5.125%		2027		500				500
Unamortized (discounts)/premiums & debt issuance (costs)						(22		)		(31		)
Subtotal						$	3,396			$	3,655
Less: Current maturities						(5		)		(5		)
Total						$	3,391			$	3,650

FUTURE MATURITIES OF RECOURSE DEBT — As of December 31, 2019 scheduled maturities are presented in the following table (in millions):

December 31,	Annual Maturities
2020	$	5
2021	505
2022	8
2023	1,113
2024	243
Thereafter	1,544
Unamortized (discount)/premium & debt issuance (costs)	(22		)
Total debt	$	3,396

3. Dividends from Subsidiaries and Affiliates

Cash dividends received from consolidated subsidiaries were $1.0 billion, $1.9 billion and $1.2 billion for the years ended December 31, 2019, 2018, and 2017, respectively. For the years ended December 31, 2019 and 2018, $200 million and $1.2 billion, respectively, of the dividends paid to the Parent Company are derived from the sale of business interests and are classified as an investing activity for cash flow purposes. All other dividends are classified as operating activities. There were no cash dividends received from affiliates accounted for by the equity method for the years ended December 31, 2019, 2018, and 2017.

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4. Guarantees and Letters of Credit

GUARANTEES — In connection with certain project financing, acquisitions and dispositions, power purchases and other agreements, the Parent Company has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments, excluding those collateralized by letter of credit and other obligations discussed below, were limited as of December 31, 2019 by the terms of the agreements, to an aggregate of approximately $865 million, representing 38 agreements with individual exposures ranging up to $157 million. These amounts exclude 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.

LETTERS OF CREDIT — At December 31, 2019, the Parent Company had $19 million in letters of credit outstanding under the senior secured credit facility, representing 28 agreements with individual exposures up to $4 million, and $342 million in letters of credit outstanding under the senior unsecured credit facility, representing 11 agreements with individual exposures ranging from $1 million to $296 million. During the year ended December 31, 2019, the Parent Company paid letter of credit fees ranging from 1% to 3% per annum on the outstanding amounts.