In this Annual Report the terms “AES,” “the Company,” “us,” or “we” refer to The AES Corporation and all of its subsidiaries and affiliates, collectively. The terms “The AES Corporation” and “Parent Company” refer only to the parent, publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates.
In this filing we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot assure you that they will prove to be correct.
Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:
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;
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 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;
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;
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 attract and retain talented directors, management and other personnel, including, but not limited to, financial personnel in our foreign businesses that have extensive knowledge of accounting principles generally accepted in the United States; and
We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.
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| ◦ | Reduced Parent debt by 22%, to $3.7 billion, compared to December 31, 2017 |
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| ◦ | In December 2018, the Company achieved a key investment grade financial metric of 3.95x Parent leverage one year earlier than previously planned |
As of December 31, 2018, the Company's backlog of 5,787 MW includes:
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| ◦ | 3,841 MW under construction and coming on-line through 2021; and |
| Leveraging Our Platforms | | |
| ◦ | 1,946 MW of renewables signed under long-term PPAs |
In 2018, the Company agreed to sell approximately 48% of its interest in sPower's operating portfolio
| Focusing our growth in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns | | |
| ◦ | | | |
| | ● | In 2016, brought on-line nine projects for a total of 2,976 MW | | |
| | ● | 3,389 MW currently under construction | | |
| | | ○ | Represents $6.4 billionOnce these sales close, AES' ownership in total capital expenditures | | |
| | | ○ | Majority of AES’ $1.1 billion in equity already funded | | |
| | | ○ | ExpectedsPower's operating portfolio will decrease from 50% to come on-line through 2019 | | |
| | ● | Will continue to advance select projects from our development pipeline | | |
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| | Reducing Complexity | | |
| | Exiting businesses and markets where we do not have a competitive advantage, simplifying our portfolio and reducing risk | | |
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| | ● | Since 2011 | | |
| | | ○ | Sold assets to generate $3.6 billion in equity proceeds | | |
| | | ○ | Decreased total number of countries where we have operations from 28 to 17 | | |
| | ● | In 2016, announced or closed $510 million in equity proceeds from sales or sell-downs of six businesses | | |
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| | Performance Excellence | | |
| | Striving to be the low-cost manager of a portfolio of assets and deriving synergies and scale from our businesses | | |
| | ● | In 2015, launched a $150 million cost reduction and revenue enhancement initiative | | |
| | | ○ | Includes overhead reductions, procurement efficiencies and operational improvements | | |
| | | ○ | Achieved $50 million in savings in 2016 and expect to ramp up to a total of $150 million in 2018 | | |
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| | Expanding Access to Capital | | |
| | Optimizing risk-adjusted returns in existing businesses and growth projects | | |
| | ● | Adjust our global exposure to commodity, fuel, country and other macroeconomic risks | | |
| | ● | Building strategic partnerships at the project and business level with an aim to optimize our risk-adjusted returns in our business and growth projects. | | |
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| | Allocating Capital in a Disciplined Manner | | |
| | Maximizing risk-adjusted returns to our shareholders by investing our free cash flow to strengthen our credit and deliver attractive growth in cash flow and earnings | | |
| | ● | In 2016, we generated substantial cash by executing on our strategy, which we allocated in line with our capital allocation framework | | |
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| | | ○ | Used $312 million to prepay and refinance Parent Company debt | | |
| | | ○ | Returned $369 million to shareholders through share repurchases and quarterly dividends | | |
| | | | ■ | Increased our quarterly dividend by 9.1% to $0.12 per share beginning in the first quarter of 2017 | | |
| | | ○ | Invested $394 million in our subsidiaries | | |
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| | | | | | | approximately 26% |
In 2018, the Company signed long-term agreements to sell 25 TBTU of LNG annually in the Dominican Republic, which will contribute to growth beyond 2020
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(1) | Investments in subsidiaries excludes $2.2 billion investment in DPL.DPL |
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(2) | Excludes working capital adjustments and growth activity prior to the close of the acquisition. |
Segments
We are organized into sixfour market-oriented strategic business units ("SBUs"): SBUs: US and Utilities (United States), AndesStates, Puerto Rico and El Salvador); South America (Chile, Colombia, Argentina and Argentina), Brazil, Brazil); MCAC (Mexico, Central America and the Caribbean), Europe,; and Asia Eurasia (Europe and Asia)— which are led by our SBU Presidents. During the first quarter of 2018, the Andes and Brazil SBUs were merged in order to leverage scale and are now reported together as part of the South America SBU. Further, the Puerto Rico and El Salvador businesses, formerly part of the MCAC SBU, were combined with the US SBU, which is now reported as the US and Utilities SBU. Within our sixfour SBUs, we have two lines of business. The first business line is generation, where we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. The second business line is utilities, where we own and/or operate utilities to generate or purchase, distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market.
The Company measuresWe measure the operating performance of itsour SBUs using Adjusted PTC, and Proportional Free Cash Flow, both of which area non-GAAP measures.measure. The Adjusted PTC and Proportional Free Cash Flow by SBU for the year ended December 31, 2016 are2018 is shown below. The percentages for Adjusted PTC and Proportional Free Cash Flow are the contribution by each SBU to the gross metric, i.e., the total Adjusted PTC by SBU, before deductions for Corporate. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis of this Form 10-K for reconciliation and definitions of Adjusted PTC and Proportional Free Cash Flow.PTC.
The following summarizes our businesses within our sixfour SBUs.
Overview
Generation
We currently own and/or operate a generation portfolio of 30,37931,792 MW, excluding the generation capabilities of ourincluding one integrated utilities.utility. Our generation fleet is diversified by fuel type. See discussion below under Fuel Costs.
Performance drivers of our generation businesses include types of electricity sales agreements, plant reliability and flexibility, availability of generation capacity to meet contracted sales, fuel costs, seasonality, weather variations and economic activity, fixed-cost management, and competition.
Electricity
Contract Sales Contracts — OurMost of our generation businesses sell electricity under medium- or long-term contracts ("contract sales") or under short-term agreements in competitive markets ("short-term sales").
Contract Sales — Most of our generation fleet sells electricity under contracts. Our medium-term contract sales have a termterms of 2two to 5five years, while our long-term contracts have a termterms of more than 5five years. Across our portfolio, the average remaining contract term is 6 years.
In contract sales, our generation businesses recover variable costs, including fuel and variable O&M costs, either through direct or indexation-based contractual pass-throughs or tolling arrangements. When the contract does not include a fuel pass-through, we typically hedge fuel costs or enter into fuel supply agreements for a similar contract period (see discussion below underthe Fuel Costs section below)). These contracts are intended to reduce exposure to the volatility of fuel prices and electricity prices by linking the business's revenues and costs. These contracts also help us to fund a significant portion of the total capital cost of the project through long-term non-recourse project-level financing.
Capacity Payments andin Contract Sales — Most of our contract sales include a capacity payment that covers projected fixed costs of the plant, including fixed O&M expenses, and a return on capital invested. In addition, most of our contracts require that the majority of the capacity payment be denominated in the currency matching our fixed costs. We generally structure our business to eliminate or reduce foreign exchange risk by matching the currency of revenue and expenses, including fixed costs and debt. Our project debt may consist of both fixed and floating rate debt for which we typically hedge a significant portion of our exposure. Some of our contracted businesses also receive a regulated market-based capacity payment, which is discussed in more detail in the Short-Term Sales and Capacity Payments and Short-Term Sales sectionsections below.
Thus, these contracts, or other related commercial arrangements, significantly mitigate our exposure to changes in power and fuel prices, currency fluctuations and changes in interest rates. In addition, these contracts generally provide for a recovery of our fixed operating expenses and a return on our investment, as long as we operate the plant to the reliability and efficiency standards required in the contract.
Short-Term Sales — Our other generation businesses sell power and ancillary services under short-term contracts with an average termterms of less than 2two years, including spot sales, directly in the short-term market or in some cases, at regulated prices. The short-term markets are typically administered by a system operator to coordinate dispatch. Short-term markets generally operate on merit order dispatch, where the least expensive generation facilities, based upon variable cost or bid price, are dispatched first and the most expensive facilities are dispatched last. The short-term price is typically set at the marginal cost of energy or bid price (the cost of the last plant required to meet system demand). As a result, the cash flows and earnings associated with these businesses are more sensitive to fluctuations in the market price for electricity. In addition, many of these wholesale markets include markets for ancillary services to support the reliable operation of the transmission system. Across our portfolio, we provide a wide array of ancillary services, including voltage support, frequency regulation and spinning reserves.
In certain markets, such as Argentina and Kazakhstan, a regulator establishes the prices for electricity and fuel and adjusts them periodically for inflation, changes in fuel prices and other factors. In these cases, our businesses are particularly sensitive to changes in regulation.
Capacity Payments — Many of the markets in which we operate include regulated capacity markets. These capacity markets are intended to provide additional revenue based upon availability without reliance on the energy margin from the merit order dispatch. Capacity markets are typically priced based on the cost of a new entrant and the system capacity relative to the desired level of reserve margin (generation available in excess of peak demand). Our generating facilities selling in the short-term markets typically receive capacity payments based on their availability in the market. Our most significant capacity revenues are earned by our generation capacity in Ohio and Northern Ireland.
Plant Reliability and Flexibility — Our contract and short-term sales provide incentives to our generation plants to optimally manage availability, operating efficiency and flexibility. Capacity payments under contract sales are frequently tied to meeting minimum standards. In short-term sales, our plants must be reliable and flexible to capture peak market prices and to maximize market-based revenues. In addition, our flexibility allows us to capture ancillary service revenue while meeting local market needs.
Fuel Costs — For our thermal generation plants, fuel is a significant component of our total cost of generation. For contract sales, we often enter into fuel supply agreements to match the contract period, or we may hedge our fuel costs. Some of our contracts have periodic adjustments for changes in fuel cost indices. In those cases, we have fuel supply agreements with shorter terms to match those adjustments. For certain projects, we have tolling arrangements where the power offtaker is responsible for the supply and cost of fuel to our plants.
In short-term sales, we sell power at market prices that are generally reflective of the market cost of fuel at the time, and thus procure fuel supply on a short-term basis, generally designed to match up with our market sales profile. Since fuel price is often the primary determinant for power prices, the economics of projects with short-term sales are often subject to volatility of relative fuel prices. For further information regarding commodity price risk please see Item 7A.—Quantitative and Qualitative Disclosures about Market Riskin this Form 10-K. 34% of the capacity of our generation fleet is coal-fired. In the U.S., most of our plants are supplied from domestic coal. At our non-U.S. generation plants, and at our plant in Hawaii, we source coal internationally. Across our fleet, we utilize our global sourcing program to maximize the purchasing power of our fuel procurement.
33%
37% of the capacity of our generation plants are fueled by natural gas. Generally, we use gas from local suppliers in each market. A few exceptions to this are AES Gener in Chile, where we purchase imported gas from third parties, and our plants in the Dominican Republic, where we import LNG to utilize in the local market.
27%31% of the capacity of our generation fleet is coal-fired. In the U.S., most of our plants are supplied from domestic coal. At our non-U.S. generation plants, and at our plant in Hawaii, we source coal internationally. Across our fleet, we utilize our global sourcing program to maximize the purchasing power of our fuel procurement.
29% of the capacity of our generation plants are fueled by renewables, including hydro, solar, wind, and energy storage, biomass and landfill gas, which do not have significant fuel costs.
6%3% of the capacity of our generation fleet utilizes oil,pet coke, diesel and petroleum coke ("pet coke")or oil for fuel. Oil and diesel are sourced locally at prices linked to international markets, while pet coke is largely sourced from Mexico and the U.S.
Renewable Generation Facilities — We currently own and operate 8,228 MW (4,293 proportional MW) of renewable generation, including hydro, wind, energy storage, solar, biomass and landfill gas.
Seasonality, Weather Variations and Economic Activity — Our generation businesses are affected by seasonal weather patterns throughout the year and, therefore, operating margin is not generated evenly by month duringthroughout the year. Additionally, weather variations, including temperature, solar and wind resources, and hydrological conditions, may also have an impact on generation output at our renewable generation facilities. In competitive markets for power, local economic activity can also have an impact on power demand and short-term prices for power.
Fixed-Cost Management —In our businesses with long-term contracts, the majority of the fixed O&M costs are recovered through the capacity payment. However, for all generation businesses, managing fixed costs and reducing them over time is a driver of business performance.
Competition — For our businesses with medium- or long-term contracts, there is limited competition during the term of the contract. For short-term sales, plant dispatch and the price of electricity are determined by market competition and local dispatch and reliability rules.
Utilities
AES' sevensix utility businesses distribute power to 9.42.4 million people in threetwo countries. AES' two utilities in the U.S. also include generation capacity totaling 6,3144,102 MW. TheOur utility businesses have a varietyconsist of structures, ranging fromIPL (an integrated utility to pure transmissionutility) and distribution businesses.DP&L (transmission and distribution) in the U.S., and four utilities in El Salvador (distribution).
In general, our utilities sell electricity directly to end-users, such as homes and businesses, and bill customers directly. Key performance drivers for utilities include the regulated rate of return and tariff, seasonality, weather variations, economic activity, reliability of service and competition. Revenue from utilities is classified as regulated inon the Consolidated Statements of Operations.
Regulated Rate of Return and Tariff — In exchange for the exclusive right to sell or distribute electricity in a franchise area,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 retail customers for electricity and establishes service standards that we are required to meet.
Our utilities are generally permitted to earn a regulated rate of return on assets, determined by the regulator based on the utility's allowed regulatory asset base, capital structure and cost of capital. The asset base on which the utility is permitted a return is determined by the regulator and is based on the amount of assets that are considered used and useful in serving customers. Both the allowed return and the asset base are important components of the utility's earning power. The allowed rate of return and operating expenses deemed reasonable by the regulator are recovered through the regulated tariff that the utility charges to its customers.
The tariff may be reviewed and reset by the regulator from time to time depending on local regulations, or the utility may seek a change in its tariffs. The tariff is generally based upon a certain usage level and may include a pass-through to the customer of costs that are not controlled by the utility, such as the costs of fuel (in the case of integrated utilities) and/or the costs of purchased energy. In additionenergy, to fuel and purchased energy, other types of costs may be passed through to customers via an existing mechanism, such as certain environmental expenditures that are covered under an environmental tracker at our utility in Indiana, IPL.the customer. Components of the tariff that are directly passed through to the customer are usually adjusted through a summary regulatory process or an existing formula-based mechanism. In some regulatory regimes, customers with demand above an established level are unregulated and can choose to contract with other retail energy suppliers directly and pay wheeling and other non-bypassable fees, which are fees to the distribution company for use of its distribution system.
The regulated tariff generally recognizes that our utility businesses should recover certain operating and fixed costs, as well as manage uncollectible amounts, quality of service and non-technical losses. Utilities, therefore, need to manage costs to the levels reflected in the tariff, or risk non-recovery of costs or diminished returns.
Seasonality, Weather Variations, and Economic Activity — Our utility businesses are affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses aremargin is not generated evenly by month duringthroughout the year. Additionally, weather
variations may also have an impact based on the number of customers, temperature variances from normal conditions, and customers' historic usage levels and patterns. The retail kWhRetail sales, after adjustments for weather variations, are affected by changes in local economic activity, energy efficiency and distributed generation initiatives, as well as the number of retail customers.
Reliability of Service — Our utility businesses must meet certain reliability standards, such as duration and frequency of outages. Those standards may be specificexplicit, with defined performance incentives or penalties, for performance against these standards. In other cases, the standards areor implicit, andwhere the utility must operate to meet customer expectations.
Competition — Our fully integrated utilities,utility, IPL, and our transmission and distribution regulated utility, DP&L, operate as the sole distributordistributors of electricity within their respective jurisdictions. Our businesses ownIPL owns and operateoperates all of the businesses and facilities necessary to generate, transmit and distribute electricity. DP&L owns and operates all of the businesses and facilities necessary to transmit and distribute electricity. Competition in the regulated electricelectricity business is primarily from the on-site generation for industrial customers; however, in Ohio, customers in our service territory have the ability to switch to alternative suppliers for their generation service. Our integrated utilities, particularly DP&L, arecustomers. IPL is exposed to the volatility in wholesale prices to the extent our generating capacity exceeds the native load served under the regulated tariff and short-term contracts. However, effective with the approval of the 2018 IPL rate order in December, annual wholesale margins earned above or below a certain benchmark are shared with customers, thus mitigating this volatility. See the full discussion under the US and Utilities SBU.
At our pure transmission and distribution businesses, such as thosebusiness in Brazil and El Salvador, we face relatively limited competition due to significant barriers to entry. At many of these businesses,enter the market. According to El Salvador's regulation, large regulated customers as defined by the relevant regulator, have the option to both leaveof becoming unregulated users and return to regulated service.requesting service directly by the generation or commercialization agents.
Development and Construction
We develop and construct new generation facilities. For our utility businesses,business, new plants may be built or existing plants retrofitted in response to customer needs or to comply with regulatory developments anddevelopments. The projects are developed subject to regulatory approval that permits recovery of our capital cost and a return on our investment. For our generation businesses, our priority for development is platform expansion opportunities, where we can add on to our existing facilities in our key platform markets where we have a competitive advantage. We make the decision to invest in new projects by evaluating the project returns and financial profile against a fair risk-adjusted return for the investment and against alternative uses of capital, including corporate debt repayment and share buybacks.
In some cases, we enter into long-term contracts for output from new facilities prior to commencing construction. To limit required equity contributions from The AES Corporation, we also seek non-recourse project debt financing and other sources of capital, including partners where it is commercially attractive. For construction, weWe typically contract with a third party to manage construction, although our construction management team supervises the construction work and tracks progress against the project's budget and the required safety, efficiency and productivity standards.
Segments
US AND UTILITIES SBU
Our US and Utilities SBU has 1829 generation facilities, and two integrated utilities in the United States.States, and four utilities in El Salvador.
Generation — Operating installed capacity of our US and Utilities SBU totals 11,92911,574 MW. IPL's parent, IPALCO Enterprises, Inc.(IPL's parent), DP&L, and DPL Inc. (DP&L's parent) are voluntaryall SEC registrants, and as such, follow the public filing requirements of the Securities Exchange Act of 1934. The following table lists our US and Utilities SBU generation facilities:
| | | Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| Bosforo | | | El Salvador | | Solar | | 43 |
| | 50 | % | | 2018 | | 2043 | | EEO |
| AES Nejapa | | | El Salvador | | Landfill Gas | | 6 |
| | 100 | % | | 2011 | | 2035 | | CAESS |
| Moncagua | | | El Salvador | | Solar | | 3 |
| | 100 | % | | 2015 | | 2035 | | EEO |
| El Salvador Subtotal | | | 52 |
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| Southland—Alamitos | | U.S.-CA | | Gas | | 2,075 |
| | 100 | % | | 1998 | | 2018 | | Southern California Edison | | US-CA | | Gas | | 2,075 |
| | 100 | % | | 1998 | | 2019-2020 | | Southern California Edison |
| Southland—Redondo Beach | | U.S.-CA | | Gas | | 1,392 |
| | 100 | % | | 1998 | | 2018 | | Southern California Edison | | US-CA | | Gas | | 1,392 |
| | 100 | % | | 1998 | | 2020 | | EDF Energy, LLC, Clean Power Alliance of Southern California |
sPower (1) | | | US-Various | | Solar | | 1,081 |
| | 50 | % | | 2017-2018 | | 2028-2046 | | Various |
| AES Puerto Rico | | | US-PR | | Coal | | 524 |
| | 100 | % | | 2002 | | 2027 | | Puerto Rico Electric Power Authority |
| Southland—Huntington Beach | | U.S.-CA | | Gas | | 474 |
| | 100 | % | | 1998 | | 2018 | | Southern California Edison | | US-CA | | Gas | | 474 |
| | 100 | % | | 1998 | | 2019-2020 | | Southern California Edison |
| Shady Point | | U.S.-OK | | Coal | | 360 |
| | 100 | % | | 1991 | | 2018 | | Oklahoma Gas & Electric | |
Buffalo Gap II (1),(2) | | U.S.-TX | | Wind | | 233 |
| | 100 | % | | 2007 | | 2017 | | Direct Energy | |
Shady Point (2) | | | US-OK | | Coal | | 360 |
| | 100 | % | | 1991 | |
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Buffalo Gap II (3) | | | US-TX | | Wind | | 233 |
| | 100 | % | | 2007 | |
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| Hawaii | | U.S.-HI | | Coal | | 206 |
| | 100 | % | | 1992 | | 2022 | | Hawaiian Electric Co. | | US-HI | | Coal | | 206 |
| | 100 | % | | 1992 | | 2022 | | Hawaiian Electric Co. |
| Warrior Run | | U.S.-MD | | Coal | | 205 |
| | 100 | % | | 2000 | | 2030 | | First Energy | | US-MD | | Coal | | 205 |
| | 100 | % | | 2000 | | 2030 | | First Energy |
Buffalo Gap III (1) | | U.S.-TX | | Wind | | 170 |
| | 100 | % | | 2008 | |
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Buffalo Gap I (1) | | U.S.-TX | | Wind | | 119 |
| | 100 | % | | 2006 | | 2021 | | Direct Energy | |
Buffalo Gap III (3) | | | US-TX | | Wind | | 170 |
| | 100 | % | | 2008 | |
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sPower (1) | | | US-Various | | Wind | | 140 |
| | 50 | % | | 2017 | | 2036 | | Various |
AES Distributed Energy (AES DE) (3) | | | US-Various | | Solar | | 136 |
| | 100 | % | | 2015-2018 | | 2029-2042 | | Utility, Municipality, Education, Non-Profit |
Buffalo Gap I (3) | | | US-TX | | Wind | | 117 |
| | 100 | % | | 2006 | | 2021 | | Direct Energy |
| Laurel Mountain | | U.S.-WV | | Wind | | 98 |
| | 100 | % | | 2011 | |
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| | US-WV | | Wind | | 98 |
| | 100 | % | | 2011 | |
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Distributed PV - Commercial & Utility (1) (3) | | U.S.-Various | | Solar | | 89 |
| | 100 | % | | 2015-2016 | | 2029-2042 | | Utility, Municipality, Education, Non-Profit | |
| Mountain View I & II | | U.S.-CA | | Wind | | 67 |
| | 100 | % | | 2008 | | 2021 | | Southern California Edison | | US-CA | | Wind | | 65 |
| | 100 | % | | 2008 | | 2021 | | Southern California Edison |
| Mountain View IV | | U.S.-CA | | Wind | | 49 |
| | 100 | % | | 2012 | | 2032 | | Southern California Edison | | US-CA | | Wind | | 49 |
| | 100 | % | | 2012 | | 2032 | | Southern California Edison |
Lawa'i (AES DE) (3) | | | US-HI | | Solar | | 20 |
| | 100 | % | | 2018 | | 2043 | | Kaua'i Island Utility Cooperative |
| | | Energy Storage | | 20 |
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| Ilumina | | | US-PR | | Solar | | 24 |
| | 100 | % | | 2012 | | 2032 | | Puerto Rico Electric Power Authority |
| Laurel Mountain ES | | U.S.-WV | | Energy Storage | | 32 |
| | 100 | % | | 2011 | |
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| | US-WV | | Energy Storage | | 16 |
| | 100 | % | | 2011 | |
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| Tait ES | | U.S.-OH | | Energy Storage | | 20 |
| | 100 | % | | 2013 | |
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Distributed PV - Residential (1) (3) | | U.S.-Various | | Solar | | 14 |
| | 100 | % | | 2015 | | 2037-2040 | | Residential | |
| AES Gilbert (Salt River) | | | US-AZ | | Energy Storage | | 10 |
| | 100 | % | | 2019 | | 2039 | | Salt River Project Agricultural Improvement and Power District |
| Warrior Run ES | | U.S.-MD | | Energy Storage | | 10 |
| | 100 | % | | 2016 | |
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| | US-MD | | Energy Storage | | 5 |
| | 100 | % | | 2016 | |
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| Advancion Applications Center | | U.S.-PA | | Energy Storage | | 2 |
| | 100 | % | | 2013 | |
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| United States Subtotal | | | 7,420 |
| | | |
| | | 5,615 |
| | | | | 7,472 |
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(1) | Unconsolidated entity, accounted for as an equity affiliate. |
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(2) | Announced the sale of this business in December 2018. |
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(3) | 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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(2)
| Power Purchase Agreement with Direct Energy is for 80% of annual expected energy output. |
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(3)
| AES operates these facilities located throughout the U.S. through management or O&M agreements as of December 31, 2016. |
Under construction — The following table lists our plants under construction in the US and Utilities SBU:
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| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| Eagle Valley CCGT | | U.S.-IN | | Gas | | 671 |
| | 70 | % | | 1H 2018 |
| Distributed PV - Commercial | | U.S.-Various | | Solar | | 10 |
| | 100 | % | | 1H 2017 |
| | | | | | | 681 |
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| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| AES Distributed Energy (AES DE) | | US-Various | | Solar | | 47 |
| | 100 | % | | 1H-2H 2019 |
| | | Energy Storage | | 3 |
| | 100 | % | | 2H 2019 |
| Riverhead (sPower) | | US-NY | | Solar | | 20 |
| | 50 | % | | 1H 2019 |
| Bosforo | | El Salvador | | Solar | | 57 |
| | 50 | % | | 1H 2019 |
| Basin Electric (sPower) | | US-SD | | Wind | | 220 |
| | 50 | % | | 2H 2019 |
| San Pablo (sPower) | | US-CA | | Solar | | 100 |
| | 50 | % | | 2H 2019 |
| Antelope DSR3 (sPower) | | US-CA | | Solar | | 20 |
| | 50 | % | | 2H 2019 |
| Kekaha (AES DE) | | US-HI | | Solar | | 14 |
| | 100 | % | | 2H 2019 |
| | | Energy Storage | | 14 |
| | 100 | % | |
| Southland Repowering | | US-CA | | Gas | | 1,284 |
| | 100 | % | | 1H 2020 |
| Na Pua Makani | | US-HI | | Wind | | 28 |
| | 100 | % | | 1H 2020 |
| Alamitos Energy Center | | US-CA | | Energy Storage | | 100 |
| | 100 | % | | 1H 2021 |
| | | | | | | 1,907 |
| | | | |
Utilities — The following table lists our U.S. utilities and their generation facilities:facilities.
| | | Business | | Location | | Approximate Number of Customers Served as of 12/31/2016 | | GWh Sold in 2016 | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Location | | Approximate Number of Customers Served as of 12/31/2018 | | GWh Sold in 2018 | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation |
| CAESS | | | El Salvador | | 602,000 |
| | 2,122 |
| | | | 75 | % | | 2000 |
| CLESA | | | El Salvador | | 404,000 |
| | 931 |
| | | | 80 | % | | 1998 |
| DEUSEM | | | El Salvador | | 81,000 |
| | 138 |
| | | | 74 | % | | 2000 |
| EEO | | | El Salvador | | 310,000 |
| | 598 |
| | | | 89 | % | | 2000 |
| El Salvador Subtotal | | El Salvador Subtotal | | 1,397,000 |
| | 3,789 |
| | | | | |
DPL (1) | | U.S.-OH | | 519,000 |
| | 16,757 |
| | Coal/Gas/Oil | | 3,066 |
| | 100 | % | | 2011 | | US-OH | | 525,000 |
| | 7,139 |
| | Coal | | 129 |
| | 100 | % | | 2011 |
IPL (2) | | U.S.-IN | | 490,000 |
| | 14,186 |
| | Coal/Gas/Oil | | 3,248 |
| | 70 | % | | 2001 | | US-IN | | 498,000 |
| | 15,092 |
| | Coal/Gas/Oil | | 3,973 |
| | 70 | % | | 2001 |
| United States Subtotal | | United States Subtotal | | 1,023,000 |
| | 22,231 |
| | 4,102 |
| | | |
| | | 1,009,000 |
| | 30,943 |
| | 6,314 |
| | | | | 2,420,000 |
| | 26,020 |
| | | | | |
_____________________________
| |
(1) | DPLDPL's subsidiary, DP&L hasAES Ohio Generation, LLC, owned an undivided interest in Conesville Unit 4. In October 2018, the following plants: Tait Units 1-3 and diesels, Yankee Street, Yankee Solar, Monument and Sidney. DP&L jointly owned plants:co-owner of Conesville Unit 4 Killen, Miami Fort Units 7 & 8, Stuart and Zimmer. In addition toannounced that the above,plant will be retired by May 2020. DPL's subsidiary, DP&L, also owns a 4.9% equity ownership in OVEC, ("Ohio Valley Electric Corporation"), an electric generating company. OVEC has two plants in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of approximately 2,109 MW. DP&L’s share of this generation is approximately 103 MW. DPL's GWh sold in 2018 represent 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 the competitive bid process. Total transmission sales were 14,439 GWh. |
approximately 2,109 MW. DP&L's share of this generation capacity is approximately 103 MW. AES Ohio Generation, LLC plants: Tait Units 4-7 and Montpelier Units 1-4.
| |
(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 (new CCGT currently under construction). 3.2Valley. 20 MW of IPL total is considered a transmission asset. |
The following map illustrates the locationlocations of our U.S.US and Utilities facilities:
U.S. Businesses
IPL
Regulatory Framework and Market Structure — IPL is subject to comprehensive regulation by the IURC with respect to its services and facilities, retail rates and charges, the issuance of long-term securities, and certain other matters. The regulatory authority of the IURC over IPL's business is typical of regulation generally imposed by state public utility commissions. The IURC sets tariff rates for electric service provided by IPL. The IURC considers all allowable costs for ratemaking purposes, including a fair return on assets used and useful to providing service to customers.
IPL's tariff rates consist of basic rates and approved charges. In addition, IPL's rates include various adjustment mechanisms, including, but not limited to: (i) a rider to reflect changes in fuel and purchased power costs to meet IPL's retail load requirements and (ii) a rider for the timely recovery of costs incurred to comply with environmental laws and regulations. These components function somewhat independently of one another, and are subject to review at the same time as any review of IPL's basic rates and charges.
IPL is one of many transmission system owner members in MISO, an RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. UtilitiesMISO operates on a merit order dispatch, considering transmission constraints and other reliability issues to meet the total demand in the MISO region. IPL offers electricity in the MISO day-ahead and real-time markets.
IPALCO
Business Description — IPALCO owns all of the outstanding common stock of IPL. IPL is engaged primarily in generating, transmitting, distributing and selling electric energy to approximately 490,000 retail customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL has an exclusive right to provide electric service to those customers. IPL's service area covers about 528 square miles with an estimated population of approximately 939,000.950,000. IPL owns and operates four generating stations.stations, all within the state of Indiana. IPL’s largest generating station, Petersburg, is coal-fired. The second largest station, Harding Street, has converted its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines. In addition, IPL operates a 20 MW battery-based energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, retired its coal-fired unitsis a newly constructed 671 MW CCGT natural gas plant. IPL took operational control and commenced commercial operations of this CCGT plant in April 2016 and their CCGT is expected to be completed in the first half of 2018. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of December
On October 31, 2016, IPL's net electric generation capacity for winter is 2,993 MW and net summer capacity is 2,878 MW.
Market Structure — IPL is one of many transmission system owner members in the MISO. MISO is a RTO, which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. IPL offers the available electricity production of each of its generation assets into the MISO day-ahead and real-time markets. MISO operates on a merit order dispatch, considering transmission constraints and other reliability issues to meet the total demand in the MISO region.
Regulatory Framework -Retail Ratemaking — In addition to the regulations referred to below in Other Regulatory Matters, IPL is subject to regulation by the IURC with respect to IPL's services and facilities; retail rates and charges; the issuance of long-term securities; and certain other matters. The regulatory power of the IURC over IPL's business is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions. IPL's tariff rates for electric service to retail customers consist of basic rates and charges,
which are set and approved by the IURC after public hearings. The IURC gives consideration to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. In addition, IPL's rates include various adjustment mechanisms including, but not limited to: (i) a rider to reflect changes in fuel and purchased power costs to meet IPL's retail load requirements, referred to as the FAC, and (ii) a rider for the timely recovery of costs incurred to comply with environmental laws and regulations referred to as the Environmental Compliance Cost Recovery Adjustment. These components function somewhat independently of one another, but the overall structure of IPL's rates and charges would be subject to review at the time of any review of IPL's basic rates and charges.
In March 2016,2018, the IURC issued an order authorizing IPLapproving an uncontested settlement agreement to increase its basicIPL's annual revenues by $44 million, or 3% (the "2018 Rate Order"). The 2018 Rate Order primarily includes recovery through rates and charges by approximately $31 million annually. On December 22, 2016, IPL filed a petitionof costs associated with the IURC for authority to increase its basic rates and charges, primarily to recover the cost of the newCCGT at Eagle Valley, CCGT. The Eagle Valley CCGT was previously expected to be completed in the first half of 2017, but is now expected to be completed2018, and other construction projects. New base rates and charges became effective on December 5, 2018. The order also provides customers with approximately $50 million in benefits, including tax reform benefits associated with the first half of 2018. To address this change, on February 24, 2017, IPL filedTCJA, over a motion to withdraw the case without prejudice or alternatively amend the petition attwo-year period through a later date. No assurances can be given as to the timing or outcome of this proceeding.rate adjustment mechanism beginning in March 2019.
Replacement Generation — IPL has several generating units that have been recently retired or refueled. These units were primarily coal-fired and represented 472 MW of net capacity in total. To replace this generation, IPL has approval to build a 644 to 685 MW CCGT at its Eagle Valley Station site in Indiana and refuel its Harding Street Station Units 5 and 6 from coal to natural gas (approximately 100 MW net capacity each) with a total budget of $649 million. The current estimated cost of these projects is $632 million. IPL was granted authority to accrue post in-service allowance for debt and equity funds used during construction, and to defer the recognition of depreciation expense of the CCGT and refueling project. These costs to build and operate the CCGT and the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after the assets have been placed in service. The CCGT is expected to be completed in the first half of 2018, and the refueling project was completed in December 2015.
In July 2015 IPL received approval from the IURC for a CPN to refuel the Harding Street Station Unit 7 from coal to natural gas (about 410 MW net capacity). The Harding Street Station Unit 7 conversion was completed in the second quarter of 2016.
Key Financial Drivers —IPL's financial results are driven primarily by retail demand, weather, energy efficiency and wholesale prices.outage costs. In addition, IPL's financial results are likely to be driven by many factors, including, but not limited to:
rate case outcomes
the timely recovery of capital expenditures through base rate growthregulatory outcomes;
the passage of new legislation, or implementation of regulations or other changes in regulation;
timely recovery of capital expenditures; and
to a lesser extent, wholesale and capacity prices.
Construction and Development —IPL's construction program is composed of capital expenditures necessary for prudent utility operations and compliance with environmental laws and regulations, along with discretionary investments designed to replace aging equipment or improve overall performance. Refer toAdditionally, IPL is currently evaluating future investments under the section aboveTransmission, Distribution, and Storage System Improvement Charge, for which electric utilities in Indiana can recover costs (including a description of our major construction projects.return) for IURC approved infrastructure improvement plans.
DPL
Business Description Regulatory Framework and Market Structure — DPL is an energy holding company whose principal subsidiaries include DP&L and AES Ohio Generation, LLC.
DP&L generates, transmits, distributes and sells electricity to approximately 519,000 customersLLC, both of which operate in a 6,000 square mile area of West Central Ohio. DP&L, solely or through jointly owned facilities, owns 2,510 MW of generation capacity and numerous transmission facilities.
AES Ohio Generation, LLC owns peaking generation units representing 556 MW located in Ohio and Indiana.
On January 1, 2016, DPL closed on the sale of DPLER to Interstate Gas Supply, Inc. DPLER, a competitive retail marketer, sold retail electricity to more than 124,000 retail customers in Ohio and Illinois while owned by DPL. Approximately 110,000 of those customers were also distribution customers of DP&L in Ohio.
Market Structure — Since January 2001, electricElectric customers within Ohio have beenare permitted to choose to purchase power under a contract withfrom a CRES Providerprovider or to continue to purchase power from their local utility
under SSO rates established by the tariff. DP&L and other Ohio utilities continue to have the exclusive right to provide delivery service in their state certified territories, and DP&L has the obligation to provide retail generation service to customers that did not choose an alternative supplier. Beginning in 2014, a portion of therates. The SSO generation supply was no longer supplied by DP&L, but wasis provided by third parties through a competitive bid process. A total of 10%, 60%Ohio utilities have the exclusive right to provide transmission and 100% of the SSO load was sourced through competitive biddistribution services in 2014, 2015 and 2016, respectively. The PUCO maintains jurisdiction over DP&L's delivery of electricity, SSO and other retail electric services. The PUCO has issued extensive rules on how and when a customer can switch generation suppliers, how the local utility will interact with CRES Providers and customers, including for billing and collection purposes, and which elements of a utility's rates are "bypassable" (i.e., avoided by a customer that elects a CRES Provider) and which elements are "non-bypassable" (i.e., charged to all customers receiving a distribution service irrespective of what entity provides the retail generation service).their state-certified territories.
DP&L is a member of PJM. The PJM RTO operates the transmission systems owned by utilities operating in all or parts of Pennsylvania, New Jersey, Maryland, Delaware, D.C., Virginia, Ohio, West Virginia, Kentucky, North Carolina, Tennessee, Indiana and Illinois. PJM has an integrated planning process to identify potential needs for additional transmission to be built to avoid future reliability problems. PJM also runs the day-ahead and real-time energy markets, ancillary services market and forward capacity market for its members.
As a member of PJM, DP&L is also subject to charges and costs associated with PJM operations as approved by the FERC. Prior to 2015, the RPM was PJM's capacity construct. In 2015, PJM implemented a new CP program, replacing the RPM model. The CP program offers the potential for higher capacity revenues, combined with substantially increased penalties for non-performance or under-performance during certain periods identified as "capacity performance hours." This linkage between non- or under-performance during specific hours means that a generation unit that is generally performing well on an annual basis, may incur substantial penalties if it happens to be unavailable for service during some capacity performance hours. Similarly, a generation unit that is generally performing poorly on an annual basis may avoid such penalties if its outages happen to occur only during hours that are not capacity performance hours. An annual “stop-loss” provision exists that limits the size of penalties to 150% of the net cost of new entry, which is a value computed by PJM. This level is likely to be larger than the capacity price established under the CP program, so that there is potential that participation in the CP program could result in capacity penalties that exceed capacity revenues. The purpose of the RPM and CP Program is to enable PJM to obtain sufficient resources to reliably meet the needs of electric customers within the PJM footprint. PJM conducts an auction to establish the price by zone.
The PJM CP auctions are held three years in advance for a period covering 12 months starting from June 1. Auctions for the period covering June 1, 2020 through May 30, 2021 are expected to take place in May 2017. Future auction results are dependent upon various factors including the demand and supply situation, capacity additions and retirements and any changes in the current auction rules related to bidding for demand response and energy efficiency resources in the capacity auctions. For DPL-owned generation, applicable capacity prices through the auction year 2019/20 are as follows:
|
| | | | | | | | | | | | |
| Auction Year (June 01-May 31) | | 2019/20 | | 2018/19 | | 2017/18 | | 2016/17 | | 2015/16 | | 2014/15 |
| Capacity Clearing Price ($/MW-Day) | | $100 | | $165 | | $152 | | $134 | | $136 | | $126 |
The computed average capacity prices by calendar year are as follows:
|
| | | | | | | | | | |
| Year | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Computed Average Capacity Price ($/MW-Day) | | $127 | | $159 | | $145 | | $135 | | $132 |
The above tables reflect the capacity prices after the transitional auctions discussed earlier. Substantially all of DP&L's capacity cleared in the CP auction. The results of these auctions could have a significant effect on DP&L's revenues in the future.
Regulatory Framework -Retail Regulation and Rate Structure — DP&L is subject to regulationregulated by the PUCO for its distribution services and facilities, retail rates and charges, reliability of service, compliance with renewable energy portfolio requirements, energy efficiency program requirements, and certain other matters. DP&L's rates forThe PUCO maintains jurisdiction over the delivery of electricity, SSO, and other retail electric service to retail customers consist of basic rates and charges that are set and approved by the PUCO after public hearings. In addition, DP&L's rates include various adjustment mechanisms including, but not limited to, the timely recovery of costs incurred to comply with alternative energy, renewables, energy efficiency, and economic development costs. These components function independently of one another, but the overall structure of DP&L's retail rates and charges are subject to the rules and regulations established by the PUCO.services.
SinceWhile Ohio is deregulated, and allows customers to choose retail generation providers, DP&L is required to provide retail generation service at SSO rates to any customer that has not signed a contract with a CRES provider.
SSO rates are subject to rules and regulations of the PUCO and are established based on DP&L's most recently approved ESP.through a competitive bid process for the supply of power to SSO customers. DP&L's distribution rates are regulated by the PUCO and are established through a traditional cost-based rate-setting process. DP&L is permitted to recover its costs of providing distribution service as well as earn a regulated rate of return on assets, determined by the regulator, based on the utility's allowed regulated asset base, capital structure and cost of capital. DP&L's rates include various adjustment mechanisms including, but not limited to, the timely recovery of costs incurred to comply with alternative energy, renewables, energy efficiency, and economic development costs. DP&L's wholesale transmission rates are regulated by the FERC.
Although it had been in effect since January 2014, on June 20, 2016, the Supreme Court of Ohio ("Court") issued an opinion in the appeal of DP&L’s ESP (ESP 2) that had been approved by the PUCO for the years 2014-2016 and which, among other matters, permitted DP&L to collect a non-bypassable Service Stability Rider equal to $110 million per year from 2014-2016 and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. DP&L's own generation was phased-out of supplying SSO service over the three year period and beginning January 1, 2016 DP&L's SSO was 100% sourced through the competitive bid. In the opinion, the Court stated that the PUCO’s approval of ESP 2 was reversed. In view of that reversal, DP&L filed a motion to withdraw ESP 2 and implement rates consistent with those in effect prior to 2014 (ESP 1). Those rates will be in effect until rates consistent with DP&L’s pending February 22, 2016 ESP (ESP 3) filing are approved and effective.
DP&L originally filedis a member of PJM, an RTO that operates the transmission systems owned by utilities operating in all or parts of Pennsylvania, New Jersey, Maryland, Delaware, D.C., Virginia, Ohio, West Virginia, Kentucky, North
Carolina, Tennessee, Indiana and Illinois. PJM also runs the day-ahead and real-time energy markets, ancillary services market and forward capacity market for its ESP 3 seeking an effective datemembers.
Business Description — DP&L transmits, distributes and sells electricity to retail customers in a 6,000 square mile area of January 1, 2017. On October 11, 2016, DP&L amendedWest Central Ohio. Ohio consumers have the application requestingright to recover $145 million per year for seven years supportingchoose the alternative described in the original filing, named the Distribution Modernization Rider. This plan establishes the terms and conditions for DP&L's SSO beginning June 1, 2017 to customers that do not choose a competitiveelectric generation supplier from whom they purchase retail electric supplier. In its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $11 million of regulatory assets. The plan also proposes a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions from DP&L's energy efficiency programs, and certain environmental liabilities the Company may incur.
On January 30, 2017 DP&L, in conjunction with nine intervening parties, filed a settlement in the ESP 3 case, which is subject to PUCO approval. DP&L and the intervening parties agreed to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:
The establishment of a five-year Distribution Modernization Rider designed to collect $90 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain itsgeneration service; however, retail transmission and distribution infrastructure;
The establishment of a Distribution Investment Rider for distribution investments, with one component designedservices are still regulated. DP&L has the exclusive right to collect $35 million in revenue per year to enable the implementation of smart grid and advanced metering, ending after the fifth year of the term of the ESP,
A commitment by the Company to separate DP&L’s generation assets from itsprovide such transmission and distribution assets (if approved by FERC);services to those customers. Additionally, DP&L procures retail SSO electric service on behalf of residential, commercial, industrial and governmental customers.
A commitments to commence the sale process of our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants and;
A commitment to develop or procure wind and/or solar energy projects in Ohio,
Restrictions on DPL making dividend or tax sharing payments, various other riders, and competitive retail market enhancements.
A hearing on the stipulation has been scheduled for March 2017. A final decision byIn September 2018, DP&L received an order from the PUCO is expected at establishing new base distribution rates for DP&L (“the end of Q2 or early Q3 2017. Iforder”), which became effective October 1, 2018. The order approved, without modification, a stipulation and recommendation previously filed by DP&L, along with various intervening parties, with the PUCO agrees to the proposed settlement, the average residential customer in the DP&L service territory, using 1,000 kWh onstaff. The order established a revenue requirement of $248 million for DP&L's Standard Service Offer, can expect a monthly bill increase of $2.39. There can be no assurance that the ESP 3 stipulation will be approved as filed or on a timely basis, and if the final ESP provides for terms that are more adverse than those submitted in DP&L's stipulation, our results of operations, financial condition and cash flows could be materially impacted.
On November 30, 2015 DP&L filed an application to increase itselectric service base distribution rate case using a 12-month test year of June 1, 2015 to May 31, 2016 to measure revenue and expenses and a date certain of September 30, 2015 to measure its asset base. The Company is seekingrates, which reflects an increase to distribution revenues of $66$30 million per year. In addition, the order authorizes DP&L to collect from customers costs related to qualified investments through a Distribution Investment Rider, changes the Decoupling Rider to reduce variability from the impact of weather and demand, partially resolves regulatory issues related to the TCJA, and authorizes DP&L to defer certain vegetation management costs for future collection.
In January 2019, DP&L filed a request with the PUCO for a two-year extension of its Distribution Modernization Rider ("DMR") through October 2022, in the proposed amount of $199 million for each of the two additional years. The Company has askedrequest was made pursuant to the PUCO’s October 2017 ESP order, which approved the DMR and the option for recovery of certain regulatory assets as well as two new riders that would allow the CompanyDP&L to recover certain costs on an ongoing basis. It has proposedfile for a modified straight-fixed variable rate design in an effort to decouple distribution revenues from electric sales. If approved as filed the rates aretwo-year extension. The extension request is set at a level expected to have a total bill impact of approximately 4% on a typical residential customer.
Environmental Regulation — In relationreduce debt obligations at both DP&L and DPL and to MATS, DPL does not expectposition DP&L to incur materialmake capital expenditures to ensure compliance.maintain and modernize its electric grid.
and Regulations.
Key Financial Drivers — DPLDPL's financial results are primarily driven by customer growth. Following the issuance of the distribution rate order in September 2018 and the resulting changes to the decoupling rider, DPL's financial results are no longer driven by retail demand and weather, energy efficiency and wholesale prices on financial results. but will be impacted by customer growth within our service territory.
In addition, DPLDPL's financial results are likely to be driven by many factors, including, but not limited to:
PJM capacity pricesthe passage of new legislation, new regulations or other changes in regulation;
Outcometimely recovery of DP&L's pending ESP 3 case, including the amount of non-bypassable revenuetransmission and distribution expenditures; and
Outcome of DP&L's pending distribution rate case
Operational performance of generation facilities
Recovery in the power market, particularly as it relates to an expansion in dark spreads
Sale or transfer to a DPL affiliate of DP&Lexiting generation assets currently owned by AES Ohio Generation.
DPL's ability to reduce its cost structure
Construction and Development — Planned construction additions primarily relate to new investments in and upgrades to DP&L's power plant equipment andDPL's transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments, and changing environmental standards, among other factors.
DPLDP&L is projecting to spend an estimated $414$628 million inon capital projects for the period 20172019 through 2019 with 65% attributable to Transmission and Distribution. DPL's ability to complete capital projects and the reliability of future service will be affected by its financial condition, the availability of internal funds and the reasonable cost of external funds.2021. We expect to finance thesethis construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.
In December 2018, DP&L filed a Distribution Modernization Plan with the PUCO proposing to invest $576 million in capital projects over the next 20 years. The principal components of the Distribution Modernization Plan includes leveraging technologies to modernize and improve the sustainability of the grid, and enhancing customer experience and security. These initiatives will allow DP&L to leverage and integrate distributed energy resources into its grid, including community solar, energy storage, microgrids and electric vehicle charging infrastructure.
U.S. Generation
Business Description — In the U.S., we own a diversified generation portfolio in terms of geography, technology and fuel source. The principal markets and locations where we are engaged in the generation and supply of electricity (energy and capacity) are the Western Electric Coordinating Council, PJM, Southwest Power Pool Electric Energy Network and Hawaii. AES Southland, in the Western Electric Coordinating Council, is our most significant generating business.
Many of our U.S. generation plants provide baseload operations and are required to maintain a guaranteed level of availability. Any change in availability has a direct impact on financial performance. The plants are generally eligible for availability bonuses on an annual basis if they meet certain requirements. In addition to plant availability, fuel cost is a key business driver for some of our facilities.
AES Southland
Business Description — In terms of aggregate installed capacity, AES Southland is one of the largest generation operators in California, with an installed gross capacity of 3,941 MW, accounting for approximately 5% of the state's installed capacity and 17% of the peak demand ofin Southern California Edison.Edison's territory. The three coastal power plants comprising AES Southland are in areas that are critical for local reliability and play an important role in integrating the increasing amounts of renewable generation resources in California.
Market Structure — All of AES Southland's capacity iswas previously contracted through a long-term20 year agreement (the “Tolling Agreement”), which expires inthat expired on May 31, 2018. ACurrently, AES Huntington Beach, LLC and AES Alamitos, LLC are contracted though Resource Adequacy agreementPurchase Agreements (the “RAPAs”), approved by the California Public Utilities Commission in 2017. AES Redondo Beach, LLC has been executed that coversalso entered into various RAPAs for the period fromof June 1, 2018 through 2020, but it is still subject to approval from the California Public Utilities Commission. Under the current Tolling Agreement, AES Southland's largest revenue driver is unit availability, as approximately 98% of its revenue comes from availability-related payments. Historically, AES Southland has generally met or exceeded its contractual availability requirements under the Tolling Agreement and may capture bonuses for exceeding availability requirements in peak periods.December 31, 2020.
Under the Tolling Agreement,RAPAs, the offtaker provides gasgenerating stations provide resource adequacy capacity, and have no obligation to produce or sell any energy to the three facilities thus AES Southland is not exposedRAPA counterparty. However, the generating stations are required to significant fuel price risk. If the units operate better than the guaranteed efficiency, AES Southland gets credit for the gas that is not consumed. Conversely, AES Southland is responsible for the cost of fuel in excess of what would have been consumed had the guaranteed efficiency been achieved. The business is also exposed to replacement power costs for a limited period if dispatched by the offtaker and not able to meet the required generation.
AES Southland delivers electricitybid energy into the California ISO's market through its Tolling Agreement counterparty.ISO markets. Compensation under these RAPAs is dependent on the availability of the AES Southland units in the California ISO market. Failure to achieve the minimum availability target will result in an assessed penalty.
Environmental Regulation — For a discussion of environmental regulatory matters affecting U.S. Generation, see Item 1.—United States Environmental and Land-Use Legislation and Regulations.
Re-powering — In OctoberNovember 2014, AES Southland was awarded 20-year contracts by SCE to provide 1,284 MW of combined cycle gas-fired generation and 100 MW of interconnected battery-based energy storage. In addition to replacing older gas-fired plantsThe contracts are resource adequacy agreements with more efficient gas-fired capacity, SCE chose advancedannual energy storage as a cost effective way to ensure critical power system reliability. This new storage resource will provide operational flexibility, enablingput options. If the efficient dispatch of other generating plants, lowering cost and emissions and supporting the on-going addition of renewable power sources.
This newput option is exercised, all capacity will be built atsold to SCE in exchange for a fixed monthly capacity fee that covers fixed operating cost, debt service, and return on capital. In addition, SCE will reimburse variable costs and provide the Company's existing power plant sites in Huntington Beachnatural gas and Alamitos Beach. Forcharging electricity. If the gas-firedannual put option is not exercised, SCE only has rights to the resource adequacy capacity financing agreements are expected to be completed in mid-2017 with construction expected to begin shortly thereafter,for that contract year and commercial operation scheduled for 2020. ForAES Southland can sell the energy storage capacity, commercial operation is scheduledand ancillary services to other counterparties.
In April 2017, the California Energy Commission unanimously approved the licenses for 2021.
the new combined cycle projects at AES is pursuing permits to build bothAlamitos and AES Huntington Beach. In June 2017, AES closed the gas-fired and energy storage capacity and will complete the licensing process before financial close. The total cost for these projects is expected to be approximately $1.9financing of $2.0 billion, which will be funded with a combination of non-recourse debt and AES equity. The construction of this new capacity started in 2017 and commercial operation of the gas-fired capacity is expected to commence in 2020 and the energy storage capacity is expected to commence in 2021.
Key Financial Drivers — AES Southland's contractual availability is one of the single most important driverdrivers of operations. Its units are generally required to achieve at least 86% availability in each contract year. AES Southland has historically met or exceeded its contractual availability.operations along with market prices for gas and electricity.
Additional U.S. Generation BusinessesFacilities
Business Description — Additional businesses include thermal, wind,Regulatory Framework and solar generating facilities, of which AES Hawaii, our U.S. wind generation businesses and distributed solar are the most significant.
AES Hawaii — AES Hawaii receives a fuel payment from its offtaker under a PPA expiring in 2022, which is based on a fixed rate indexed to the Gross National Product - Implicit Price Deflator. Since the fuel payment is not directly linked to market prices for fuel, the risk arising from fluctuations in market prices for coal is borne by AES Hawaii.
To mitigate the risk from such fluctuations, AES Hawaii has entered into fixed-price coal purchase commitments that end in December 2018; the business could be subject to variability in coal pricing beginning in January 2019. To mitigate fuel risk beyond December 2018, AES Hawaii plans to seek additional fuel purchase commitments on favorable terms. However, if market prices rise and AES Hawaii is unable to procure coal supply on favorable terms, the financial performance of AES Hawaii could be materially and adversely affected.
U.S. Wind — AES has 736 MW of wind capacity in the U.S., located in California, Texas and West Virginia. Typically, these facilities sell under long-term PPAs. AES financed most of these projects with tax equity structures. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in a net loss to AES consolidated results in periods in which the facilities report net income. These non cash net losses will be expected to reverse during the life of the facilities. Some of the wind projects are exposed to the volatility of energy prices and their revenue may change materially as energy prices fluctuate in their respective markets of operations.
Buffalo Gap is located in Texas and is comprised of three wind projects with an aggregate generation capacity of 522 MW. Each wind project operates its own PPA with the exception of Buffalo Gap III. The energy price of the entire production of Buffalo Gap I is guaranteed by a PPA expiring in 2021. The PPA of Buffalo Gap II guarantees the energy price of 80% of the installed capacity while the energy price for the remaining 20% is dictated by the prices in the ERCOT market. The PPA of Buffalo Gap II expires in December 2017. Once the PPAs expire, the entire installed capacity of Buffalo Gap will be exposed to the volatility of energy prices in the ERCOT market which could adversely affect revenues.
Laurel Mountain is a wind project located in West Virginia with an installed capacity of 98 MW. Laurel Mountain does not operate under a long-term contract and sells its entire capacity and power generated into the PJM market. The volatility and fluctuations of energy prices in PJM have a direct impact in the results of Laurel Mountain.
AES manages the wind portfolio as part of its broader investments in the U.S., leveraging operational and commercial resources to supplement the experienced subject matter experts in the wind industry to achieve optimal results.
AES Distributed Energy — AES has 103 MW of solar capacity in the U.S., located across multiple states. Distributed Energy's Commercial and Utility division, which comprised 89 MW of solar capacity as of December 31, 2016, sells electricity generated by photovoltaic solar energy systems to public sector, utility, and non-profit entities through power purchase agreements. AES has added 33 MW of commercial and utility capacity in 2016. A majority of this new capacity has been financed with tax equity structures. Under these tax equity structures, the tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in a net loss to AES consolidated results in periods in which the facilities report net income. These non cash net losses will be expected to reverse during the life of the facilities.
AES manages the Distributed Energy portfolio as part of its broader investments in the U.S., leveraging operational and commercial resources to supplement the experienced subject matter experts in the solar industry to achieve optimal results.
Market Structure — For the non-renewable businesses, included in our additional U.S. generation facilities, coal and natural gas are used as the primary fuels. Coal has prices that are set by market factors internationally, while natural gas isprices are generally set domestically. Price variations for these fuels can change the composition of generation costs and energy prices in our generation businesses, and the prices of these fuels have been subject to volatility in recent years.businesses.
Many of these generation businesses have entered into long-term PPAs with utilities or other offtakers. Some coal-fired power plant businesses in the U.S. with PPAs have mechanisms to recover fuel costs from the offtaker, including an energy payment that is partially based on the market price of coal. In addition, thesefuel. When market price fluctuations in fuel are borne by the offtaker, revenue may change as fuel prices fluctuate, but the variable margin or profitability should remain consistent. These businesses often have an opportunity to increase or decrease profitability from payments under their PPAs depending on such items as plant efficiency and availability, heat rate, ability to buy coal at lower costs through AES' global sourcing program and fuel flexibility. Revenue may change materially as prices in fuel markets fluctuate, but the variable margin or profitability should not be materially changed when market price fluctuations in fuel are borne by the offtaker.
Regulatory Framework — Several of our generation businesses in the U.S. currently operate as QFs, including Hawaii, Shady Point and Warrior Run, as defined under the PURPA. These businesses entered into long-term contracts with electric utilities that had a mandatory obligation under PURPA requirements to purchase power from QFs at the utility's avoided cost (i.e., the likely costs for both energy and capital investment that would have been incurred by the purchasing utility if that utility had to provide its own generating capacity or purchase it from another source). To be a QF, a cogeneration facility must
produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility's total energy output and meet certain efficiency standards. To be a QF, a small power production facility must generally use a renewable resource as its energy input and meet certain size criteria.
Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators as defined under the EPAct 1992. These businesses, subject to approval of FERC, have the right to sell power at market-based rates, either directly to the wholesale market or to a third-party offtaker such as a power marketer or utility/industrial customer. Under the FPAFederal Power Act and FERC's regulations, approval from FERC to sell wholesale power at market-based rates is generally dependent upon a showing to FERC that the seller lacks market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no opportunity for abusive transactions involving regulated affiliates of the seller. To prevent market manipulation, FERC requires sellers with market-based rate authority to file certain reports, including a triennial updated market power analysis for markets in which they control certain threshold amounts of generation.
Other Regulatory Matters — The U.S. wholesale electricity market consists of multiple distinct regional markets that are subject to both federal regulation, as implemented by the U.S. FERC, and regional regulation as defined by rules designed and implemented by the RTOs, non-profit corporations that operate the regional transmission grid and maintain organized markets for electricity. These rules, for the most part, govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity. See Item 1A.—Risk Factors for additional discussion on U.S. regulatory matters.Environmental Regulation Business Description — ForAdditional businesses include thermal, wind, and solar generating facilities, of which our U.S. Renewables businesses and AES Hawaii are the most significant.
U.S. Renewables
sPower owns and/or operates 153 utility and distributed electrical generation systems with a discussioncapacity of environmental laws and regulations affecting1,221 MWh currently in operation across the U.S. business, see Item 1.—United StatesEnvironmentalsPower is also actively buying, developing and Land-Use Legislationconstructing renewable assets in the U.S.
AES Distributed Energy develops, constructs and Regulations.sells electricity generated by photovoltaic solar energy systems and energy storage systems to public sector, utility, and non-profit entities through PPAs.
Excluding sPower wind plants, AES has 732 MW of wind capacity in the U.S., located in California, Texas and West Virginia. Mountain View I & II, Mountain View IV and Buffalo Gap I sell under long-term PPAs through which the energy price on the entire production of these facilities is guaranteed. Laurel Mountain, Buffalo Gap II and Buffalo Gap III are exposed to the volatility of energy prices and their revenue may change materially as energy prices fluctuate in their respective markets of operations.
AES manages the U.S. Renewables portfolio as part of its broader investments in the U.S.. A portion of U.S. Solar projects and the majority of wind projects have been financed with tax equity structures. Under these tax equity structures, the tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in variability to earnings attributable to AES compared to the earnings reported at the facilities.
AES Hawaii
AES Hawaii receives a fuel payment from its offtaker under a PPA expiring in 2022, which is based on a fixed rate indexed to the Gross National Product — Implicit Price Deflator. Since the fuel payment is not directly linked to market prices for fuel, the risk arising from fluctuations in market prices for coal is borne by AES Hawaii. AES Hawaii has entered into fixed-price coal purchase commitments through December 2019 and plans to seek additional fuel purchase commitments to manage fuel price risk after December 2019.
Key Financial Drivers — U.S. Generation'sthermal generation's financial results are driven by fuel costs and outages. The Company has entered into long-term fuel contracts to mitigate the risks associated with fluctuating prices. In addition, major maintenance requiring units to be off-line is performed during periods when power demand is typically lower. The financial results of U.S. Wind are primarily driven by increased production due to faster and less
Construction and Development — Planned capital projects include the AES Southland re-powering described above. In addition to the new construction projects,project, U.S. Generation performs capital projects related to major plant
maintenance, repairs and upgrades to be compliant with new environmental laws and regulations. sPower has 360 MW of projects under construction and a development pipeline that includes 938 MW of projects for which long-term PPAs have been signed. The budget for construction of the projects currently under construction and the contracted projects is over $1.8 billion. AES Distributed Energy has 78 MW of projects under construction and a development pipeline that includes 332 MW of projects for which long-term PPAs have been signed or, as applicable, tariffs have been assigned through a regulatory process. The budget for construction of the projects currently under construction and the contracted projects is over $1 billion.
Puerto Rico
Regulatory Framework and Market Structure — Puerto Rico has a single electric grid managed by PREPA, a state-owned entity that supplies virtually all of the electric power consumed in Puerto Rico and generates, transmits and distributes electricity to 1.5 million customers. The Puerto Rico Energy Bureau is the main regulatory body. The bureau approves wholesale and retail rates, sets efficiency and interconnection standards, and oversees PREPA's compliance with Puerto Rico's renewable portfolio standard.
Puerto Rico's electricity is 98% produced by thermal plants (47% from petroleum, 34% from natural gas, 17% from coal).
El Salvador
Regulatory Framework and Market Structure — El Salvador's national electric market is composed of generation, distribution, transmission and marketing businesses, as well as a market and system operator and regulatory agencies. The operation of the transmission system and the wholesale market is based on production costs with a marginal economic model that rewards efficiency and allows investors to have guaranteed profits, while end users receive affordable rates. The energy sector is governed by the General Electricity Law, which establishes two regulatory entities responsible for monitoring its compliance:
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.
El Salvador has a national electric grid that interconnects with Guatemala and Honduras. The sector has approximately 1,659 MW of installed capacity, composed primarily of thermal (43%), hydroelectric (34%), geothermal (10%), biomass (9%) and solar (4%) generation plants.
Business Description — AES El Salvador is the majority owner of four of the five distribution companies operating in El Salvador (CAESS, CLESA, EEO and DEUSEM). AES El Salvador's territory covers 79% of the country and accounted for 4,040 GWh of the wholesale market energy purchases during 2018, or about 63% market share.
Construction and Development — As part of the initiative to pursue opportunities in renewable generation, AES El Salvador has entered into a joint venture with Corporacion Multi-Inversiones, a Guatemalan investment group, to develop, construct and operate Bosforo, a 142 MW solar farm. 43 MW of the project were completed in 2018 and are fully operational. 57 MW are under construction and expected to become operational during the first half of 2019 and the remaining 42 MW will start construction in 2019 and are expected to be completed in the second half of 2019. The energy produced by this project will be contracted directly by AES' utilities in El Salvador.
South America SBU
Generation — Our AndesSouth America SBU has generation facilities in threefour countries — Chile, Colombia, Argentina and Argentina.Brazil. AES Gener, which owns all of our assets in Chile, Chivor in Colombia and TermoAndes in Argentina, as detailed below, is a publicly listedtraded company in Chile. AES has a 66.7% ownership interest in AES Gener and this business is consolidated in our financial statements. Tietê is a publicly traded company in Brazil. AES controls and consolidates Tietê through its 24% economic interest.
Operating installed capacity of our AndesSouth America SBU totals 9,30812,435 MW, of which 44%33%, 45%28%, 8%, and 11% is31% are located in Argentina, Chile, Colombia and Colombia,Brazil, respectively. The following table lists our AndesSouth America SBU generation facilities:
| | | Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| Chivor | | Colombia | | Hydro | | 1,000 |
| | 67 | % | | 2000 | | Short-term | | Various | | Colombia | | Hydro | | 1,000 |
| | 67 | % | | 2000 | | 2019-2026 | | Various |
| Tunjita | | Colombia | | Hydro | | 20 |
| | 67 | % | | 2016 | | | Colombia | | Hydro | | 20 |
| | 67 | % | | 2016 | |
| Colombia Subtotal | | 1,020 |
| | | | | 1,020 |
| | | |
Guacolda (1) | | Chile | | Coal/Pet Coke | | 760 |
| | 33 | % | | 2000 | | 2017-2032 | | Various | |
Electrica Santiago (2) | | Chile | | Gas/Diesel | | 750 |
| | 67 | % | | 2000 | |
| |
| |
Gener - SIC (3) | | Chile | | Hydro/Coal/Diesel/Biomass | | 689 |
| | 67 | % | | 2000 | | 2020-2037 | | Various | |
Gener - Chile (1) | | | Chile | | Coal/Hydro/Diesel/Solar/Biomass | | 1,532 |
| | 67 | % | | 2000 | | 2019-2040 | | Various |
Guacolda (2) | | | Chile | | Coal | | 760 |
| | 33 | % | | 2000 | | 2019-2032 | | Various |
| Electrica Angamos | | Chile | | Coal | | 558 |
| | 67 | % | | 2011 | | 2026-2037 | | Minera Escondida, Minera Spence, Quebrada Blanca | | Chile | | Coal | | 558 |
| | 67 | % | | 2011 | | 2026-2037 | | Minera Escondida, Minera Spence, Quebrada Blanca |
| Cochrane | | Chile | | Coal | | 532 |
| | 40 | % | | 2016 | | 2030-2034 | | SQM, Sierra Gorda, Quebrada Blanca | | Chile | | Coal | | 550 |
| | 40 | % | | 2016 | | 2030-2037 | | SQM, Sierra Gorda, Quebrada Blanca |
Gener - SING (4) | | Chile | | Coal/Pet Coke | | 277 |
| | 67 | % | | 2000 | | 2017-2037 | | Minera Escondida, Codelco, SQM, Quebrada Blanca | |
Electrica Ventanas (5) | | Chile | | Coal | | 272 |
| | 67 | % | | 2010 | | 2025 | | Gener | |
Electrica Campiche (6) | | Chile | | Coal | | 272 |
| | 67 | % | | 2013 | | 2020 | | Gener | |
| Andes Solar | | Chile | | Solar | | 21 |
| | 67 | % | | 2016 | | 2037 | | Quebrada Blanca | |
| Cochrane ES | | Chile | | Energy Storage | | 20 |
| | 40 | % | | 2016 | | | Chile | | Energy Storage | | 20 |
| | 40 | % | | 2016 | |
| Electrica Angamos ES | | Chile | | Energy Storage | | 20 |
| | 67 | % | | 2011 | |
| |
| | Chile | | Energy Storage | | 20 |
| | 67 | % | | 2011 | |
| |
|
| Gener - Norgener ES (Los Andes) | | Chile | | Energy Storage | | 12 |
| | 67 | % | | 2009 | |
| |
| |
| Norgener ES (Los Andes) | | | Chile | | Energy Storage | | 12 |
| | 67 | % | | 2009 | |
| |
|
| Chile Subtotal | | 4,183 |
| | | | | 3,452 |
| | | |
TermoAndes (7) | | Argentina | | Gas/Diesel | | 643 |
| | 67 | % | | 2000 | | Short-term | | Various | |
TermoAndes (3) | | | Argentina | | Gas/Diesel | | 643 |
| | 67 | % | | 2000 | | 2019-2020 | | Various |
| AES Gener Subtotal | | 5,846 |
| | | | | 5,115 |
| | | |
| Alicura | | Argentina | | Hydro | | 1,050 |
| | 100 | % | | 2000 | | 2017 | | Various | | Argentina | | Hydro | | 1,050 |
| | 100 | % | | 2000 | |
| | Various |
| Paraná-GT | | Argentina | | Gas/Diesel | | 845 |
| | 100 | % | | 2001 | |
| |
| | Argentina | | Gas/Diesel | | 870 |
| | 100 | % | | 2001 | |
| |
|
| San Nicolás | | Argentina | | Coal/Gas/Oil | | 675 |
| | 100 | % | | 1993 | |
| |
| | Argentina | | Coal/Gas/Oil | | 675 |
| | 100 | % | | 1993 | |
| |
|
Guillermo Brown (8) | | Argentina | | Gas/Diesel | | 576 |
| | — | % | | 2016 | | |
Los Caracoles (8) | | Argentina | | Hydro | | 125 |
| | — | % | | 2009 | | 2019 | | Energia Provincial Sociedad del Estado (EPSE) | |
Guillermo Brown (4) | | | Argentina | | Gas/Diesel | | 576 |
| | — | % | | 2016 | |
Los Caracoles (4) | | | Argentina | | Hydro | | 125 |
| | — | % | | 2009 | | 2019 | | Energia Provincial Sociedad del Estado (EPSE) |
| Cabra Corral | | Argentina | | Hydro | | 102 |
| | 100 | % | | 1995 | |
| | Various | | Argentina | | Hydro | | 102 |
| | 100 | % | | 1995 | |
| | Various |
| Ullum | | Argentina | | Hydro | | 45 |
| | 100 | % | | 1996 | |
| | Various | | Argentina | | Hydro | | 45 |
| | 100 | % | | 1996 | |
| | Various |
| Sarmiento | | Argentina | | Gas/Diesel | | 33 |
| | 100 | % | | 1996 | |
| |
| | Argentina | | Gas/Diesel | | 33 |
| | 100 | % | | 1996 | |
| |
|
| El Tunal | | Argentina | | Hydro | | 11 |
| | 100 | % | | 1995 | |
| | Various | | Argentina | | Hydro | | 10 |
| | 100 | % | | 1995 | |
| | Various |
| Argentina Subtotal | | 3,462 |
| | | | | 3,486 |
| | | |
Tietê (5) | | | Brazil | | Hydro | | 2,658 |
| | 24 | % | | 1999 | | 2029 | | Various |
| Alto Sertão II | | | Brazil | | Wind | | 386 |
| | 24 | % | | 2017 | | 2033-2035 | | Various |
| Guaimbe | | | Brazil | | Solar | | 150 |
| | 24 | % | | 2018 | | 2037 | | CCEE |
| Tietê Subtotal | | | 3,194 |
| | | |
| Uruguaiana | | | Brazil | | Gas | | 640 |
| | 46 | % | | 2000 | |
| Brazil Subtotal | | | 3,834 |
| | | |
| | | 9,308 |
| | | | | 12,435 |
| | | |
_____________________________
| |
(1) | GuacoldaGener - Chile plants: GuacoldaAlfalfal, Andes Solar, Laguna Verde, Laguna Verde Turbogas, Laja, Maitenes, Norgener 1, Norgener 2, Queltehues, Ventanas 1, Ventanas 2, Ventanas 3, Ventanas 4 and 5. Unconsolidated entitiesVolcán. |
| |
(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 EquityNet equity in Earningsearnings of Affiliates.affiliates. The Company's ownership in Guacolda is held through AES Gener, a 67%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 33%. |
| |
(2)
| Electrica Santiago plants: Nueva Renca, Renca, Los Vientos and Santa Lidia. |
| |
(3) | Gener — SIC plants: Alfalfal, Laguna Verde, Laguna Verde Turbogas, Laja, Maitenes, Queltehues, Ventanas 1, Ventanas 2 and Volcán. |
| |
(4)
| Gener — SING plants: Norgener 1 and Norgener 2. |
| |
(5)
| Electrica Ventanas plant: Ventanas 3. |
| |
(6)
| Electrica Campiche plant: Ventanas 4. |
| |
(7)
| TermoAndes is located in Argentina, but is connected to both the SINGSEN in Chile and the SADI in Argentina. |
| |
(8)(4)
| AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses. |
| |
(5) | Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mog-Guaçu, Nova Avanhandava, Promissão, Sao Joaquim and Sao Jose. |
Under construction — The following table lists our plants under construction in the AndesSouth America SBU:
| | | Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| Boa Hora | | | Brazil | | Solar | | 69 |
| | 24 | % | | 1H 2019 |
| AGV Solar | | | Brazil | | Solar | | 75 |
| | 24 | % | | 1H 2019 |
| Energetica | | | Argentina | | Wind | | 100 |
| | 100 | % | | 1H 2020 |
| Vientos Nequinos | | | Argentina | | Wind | | 80 |
| | 100 | % | | 1H 2020 |
| Alto Maipo | | Chile | | Hydro | | 531 |
| | 40 | % | | 1H 2019 | | Chile | | Hydro | | 531 |
| | 62 | % | | 2H 2020 |
| Chile Subtotal | | 531 |
| | | | |
| | | 531 |
| | | | | 855 |
| | | |
In June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo, a distribution business in Brazil. Prior to its sale, Eletropaulo was accounted for as an equity method investment and its results of operations and financial position were reported as discontinued operations in the consolidated financial statements for all periods presented.
The following map illustrates the location of our AndesSouth America facilities:
Andes Businesses
Chile
Market Structure and Regulatory Framework — The Chilean electricity industry is divided into three business segments: generation, transmission and distribution. Private companies operate in all three segments, and generators can enter into PPAs to sell energy to regulated and unregulated customers, as well as to other generators in the spot market.
Chile has operated a single power market, referred to as the SEN, which has been managed by the grid operator CEN since November 2017. Previously, Chile had two main power systems, the SIC and SING, largely as a result of its geographic shape and size, which were merged to form the SEN. The SEN has an installed capacity
of approximately 24,586 MW. SEN represents 99% of the installed generation capacity of the country.
CEN coordinates all generation and transmission companies in the SEN. CEN minimizes the operating costs of the electricity system, while maximizing service quality and reliability requirements. CEN dispatches plants in merit order based on their variable cost of production, allowing for electricity to be supplied at the lowest available cost. In the south-central region of the SEN (former SIC), thermoelectric generation is required to fulfill demand not satisfied by hydroelectric, solar and wind output and is critical to provide reliable and dependable electricity supply under dry hydrological conditions. In the northern region of the SEN (former SING), which includes the Atacama Desert, thermoelectric capacity represents the majority of installed capacity as hydroelectric generation is not feasible. The fuels used for thermoelectric generation, mainly coal, diesel and LNG, are indexed to international prices. In 2018, the generation installed capacity in the Chilean market was composed of the following:
|
| | | |
| Installed Capacity | | | SEN |
| Thermoelectric | | | 54% |
| Hydroelectric | | | 27% |
| Solar | | | 10% |
| Wind | | | 7% |
| Other | | | 2% |
Hydroelectric plants represent a significant portion of the system's installed capacity. Hydrological conditions influence reservoir water levels, which in turn affects dispatch of the system's hydroelectric and thermoelectric generation plants, thereby influencing spot market prices. Precipitation and snow melt impact hydrological conditions in Chile. Rains occurs principally between June and August and are scarce during the remainder of the year. Snow melt occurs between September and November.
The Ministry of Energy has primary responsibility for the Chilean electricity system directly or through the National Energy Commission and the Superintendency of Electricity and Fuels.
In July 2016, modifications to the Transmission Law were enacted. This law establishes that the transmission system will be completely paid for by the end-users, gradually allocating the costs on the demand side from 2019 through 2034.
All generators can sell energy through contracts with regulated distribution companies or directly to unregulated customers. Unregulated customers are customers whose connected capacity is higher than 5 MW. Customers with connected capacity between 0.5 MW and 5.0 MW can opt for regulated or unregulated contracts for a minimum period of four years. By law, both regulated and unregulated customers are required to purchase all electricity under contracts. Generators may also sell energy to other power generation companies on a short-term basis at negotiated prices outside the spot market. Electricity prices in Chile are denominated in U.S. dollars, although payments are made in Chilean pesos.
Business Description — In Chile, through AES Gener, we are engaged in the generation and supply of electricity (energy and capacity) in the two principal markets: the SIC and SING. In terms of aggregate installed capacity,SEN. AES Gener is the second largest generation operator in Chile with a calculatedin terms of installed capacity of 4,131with 3,400 MW, excluding energy storage , and TermoAndes, andhas a market share of approximately 18%14% as of December 31, 2016.2018.
AES Gener owns a diversified generation portfolio in Chile in terms of geography, technology, customers and fuel source. AES Gener's installed capacity isplants are located near the principal electricity consumption centers, including Santiago, Valparaiso and Antofagasta. AES Gener's diverse generation portfolio is composedprovides flexibility for the management of hydroelectric, coal, gas, diesel, solar photovoltaiccontractual obligations with regulated and biomass facilities, that allowsunregulated customers, provides backup energy to the businesses to operatespot market and facilitates operations under a variety of market and hydrological conditions, manage AES Gener's contractual obligations with regulated and unregulated customers and, as required, provide backup energy to the spot market.
AES Gener has experienced significant growth in recent years by responding to market opportunities. The company successfully completed a first expansion phase between 2007 and 2014 that added 6 new power plants totaling 1,677 MW. It continued to grow in Chile through its second expansion phase that will add 1,236 MW. As of the end of 2016, AES Gener has completed the construction of Guacolda Unit 5 (152 MW), Cochrane (532 MW) and Andes Solar (21 MW). Additionally, we continue to advance in the construction of the 531 MW Alto Maipo run-of-the-river hydroelectric plant in the SIC.conditions.
Our commercial policystrategy in Chile aims to maximize margin while reducing cash flow volatility. In order toTo achieve this, we contract a significant portion of our baseload capacity, currently coal and hydroelectric baseload capacity under long-term agreements with a diversified customer base, that includes both regulated and unregulated customers.base. Power plants that are not considered within our baseload capacity (higher variable cost units, mainly diesel and gas fired
units) operatediesel) sell energy on the spot market when operating during scarce system supply conditions, such as dry hydrological conditions andlow hydrology and/or plant outages, selling their energy in the spot market.outages. In Chile, sales on the spot market are made only to other generation companies (entities thatwho are members of the Economic Load Dispatch Center - "CISEN")SEN at the system marginal cost. In anticipation of the SIC and SING interconnection, the new Transmission Law created the CISEN, an entity that will merge both system operators into one.
AES Gener currently has long-term contracts, with an average remaining term of approximately 11 years, with regulated distribution companies and unregulated customers, such as mining and industrial companies. In general, these long-term contracts include both fixed and variable paymentspass-through mechanisms for fuel costs along with indexation mechanisms that periodically adjust prices based on the generation cost structure relatedprice indexations to the United States Consumer Price Index, the international price of coal, and in some cases, with pass-through of fuel and regulatory costs, including changes in law.US CPI.
In addition to energy payments, AES Gener also receives firm capacity payments to compensate for contributing to the system's ability to meetavailability during periods of peak demand. These payments are added to the final electricity price paid by both unregulated and regulated customers. In each system, the CISENCEN annually determines the firm capacity amount allocated torequirements for each power plant. A plant's firm capacity is defined as the capacity that it can guarantee at peak hours during critical conditions, such as droughts, taking into account statistical information regarding maintenance periods and water inflows in the case of hydroelectric plants. The
capacity price is fixed semiannually by the National Energy Commission in the semiannual node price report and indexed to the United States Consumer Price IndexCPI and other relevant indices.
Market Structure Environmental Regulation — Chile has two main power systems, largely as a result of its geographic shapeDuring 2017 and size. The SIC is the largest of these systems, with an installed capacity of 17,543 MW as of December 31, 2016. The SIC serves approximately 92% of the Chilean population, including the densely populated Santiago Metropolitan Region, and represents 75% of the country's electricity demand. The SING serves about 6% of the Chilean population, representing 25% of Chile's electricity consumption, and mainly supplies mining companies.
In 2016, thermoelectric generation represented 67% of the total generation in Chile. In the SIC, thermoelectric generation represents 48% of installed capacity, required to fulfill demand not satisfied by hydroelectric output and is critical to guaranteeing reliable and dependable electricity supply under dry hydrological conditions. In the SING, which includes the Atacama Desert, the driest desert in the world, thermoelectric capacity represents 92% of installed capacity. The fuels used for generation, mainly coal, diesel and LNG, are indexed to international prices.
In the SIC, where hydroelectric plants represent a large part of the system's installed capacity, hydrological conditions largely influence plant dispatch and, therefore, spot market prices, given that river inflows, snow melting and initial water levels in reservoirs largely determine the dispatch of the system's hydroelectric and thermoelectric generation plants. Rainfall and snowfall occur in Chile principally in the southern cone winter season (June to August) and during the remainder of the year precipitation is scarce. When rain is abundant, energy produced by hydroelectric plants can amount to more than 70% of total generation. In 2016 hydroelectric generation represented 36% of total energy production within the SIC, and 27% of the country’s total energy production.
Solar and wind installed capacity represents a small but growing part of the total capacity installed. In the SIC, solar accounts for 3% of the power generation and 7% of the system’s installed capacity while in the SING solar accounts for 4% of the power generation and 6% of the system’s capacity. As for wind, in the SIC, wind contributes with 4% of the power generation and 7% of the system’s capacity, while in the SING wind generation represents 1% of the power generation and with 2% of the system’s capacity.
Regulatory Framework — The government entity that has primary responsibility for the Chilean electricity system is the Ministry of Energy, acting directly or throughEnvironment under the National Energy Commissionprevious administration updated the Atmospheric Decontamination Plan for the Ventanas and the Superintendency of Electricity and Fuels. The electricity sector is divided into three segments: generation, transmission and distribution. In general terms, generation and transmission expansion are subject to market competition, while transmission operation and distribution, are subject to price regulation. The transmission segment consists of companiesHuasco regions. Under that transmit the electricity produced by generation companies at high voltage. The individual and joint participation of companies operating in any other segment of the electricity sector cannot exceed 8% and 40%, respectively, of the total investment value of the national transmission system.
Companies in the SIC and the SING that own generation, transmission, sub-transmission or additional transmission facilities, as well as unregulated customers directly connected to transmission facilities, are coordinated through the CISEN, which minimizes the operating costs of the electricity system, while meeting all service quality and reliability requirements. The principal purpose of the CISEN is to ensure that the most efficient electricity generation available to meet demand is dispatched to customers. The CISEN dispatches plants in merit order based on their variable cost of production, allowing for electricity to be supplied at the lowest available cost.
All generators can commercialize energy through contracts with distribution companies for their regulated and unregulated customers or directly with unregulated customers. Unregulated customers are customers whose connected capacity is higher than 2MW. Customers with connected capacity between 0.5 MW and 2.0 MW can opt for a Regulated or Unregulated regime for a minimum period of four years. By law, both regulated and unregulated customers are required to purchase all of their electricity requirements under contract. Generators may also sell energy to other power generation companies on a short-term basis. Power generation companies may engage in contracted sales among themselves at negotiated prices outside the spot market. Electricity prices in Chile, under contract and on the spot market, are denominated in U.S. Dollars, although payments are made in Chilean Pesos.
In July 2016, modifications to the Transmission Lawproposed plan, no significant investments were enacted. This Law establishes that the transmission system will be completely paid for by the end-users, gradually allocating the costs on the demand side from year 2019 through 2034.
Environmental Regulation — In 2011, a regulation on air emission standards for thermoelectric power plants became effective. This regulation provides for stringent limits on emission of PM and gases produced by the combustion of solid and liquid fuels, particularly coal. For existing plants, including those currently under construction, the new limits for PM emissions went into effect at the end of 2013, and the new limits for SO2, NOx and mercury emission were in effect since mid-2016, except for those plants operating in zones declared saturated or latent zones (areas at risk of or affected by excessive air pollution), where these emission limits became effective in June 2015. In orderneeded to comply with new requirements at our plants Ventanas and Guacolda. However, the new emission standards, AES Gener initiated investments in Chile at its older coal facilities (Ventanas I and II and Norgener I and II, constructed between 1964 and 1997) in 2012. As of December 31, 2016, AES Gener has concluded investments of approximately $229 million in order to comply within the required time frame. Additionally, its equity method investee Guacolda started the installation of new emission control equipment during 2013, and concluded investments of approximately $209 million in order to comply within the required time frame.
On March 29, 2016, the Health Ministry enacted Supreme Decree N°43 (“DS 43”) ruling “Storage of Hazardous Materials”, modifyingauthority under the current applicable rules. This regulation will become fully effective in Marchadministration rejected that proposed plan on December 30, 2017. In December 2018, a new decontamination plan for structural improvements of currently authorized storage facilities. The estimated investment required to comply with DS 43 would be approximately $15 million.
During 2016,the Ventanas and Huasco regions was proposed by the authority under the current administration. Currently, the Environmental Ministry worked on upgradingexpects approval of the Atmospheric Decontamination Plans for Santiago, Ventanasnew decontamination plan in early March 2019 and Huasco areas, each of which, as of December 31, 2016,we are currently under different stages of progress. Nueva Renca, Ventanas and Guacolda power plants may require an improvement of their operational practices and additional investments to meetassessing the expected new requirements during the year following the enactmentimpact of the Decontamination Plan, which is expected for mid 2017.new proposed decontamination plan.
Chilean law requires everyall electricity generatorgenerators to supply a certain portion of itstheir total contractual obligations with Non-conventional Renewable Energy ("NCREs"). In October 2013, the NCRE law was amended, increasing the NCRE requirements. The law distinguishes between energy contracts executed before and after July 1, 2013. For contracts executed between August 31, 2007 and July 1, 2013, the NCRE requirement is equal to 5% in 2014 with annual contract increases of 0.5% until reaching 10% in 2024. The NCRE requirement for contracts executed after July 1, 2013 is equal to 5% in 2013, with annual increases of 1% thereafter until reaching 12% in 2020, and subsequently annual increases of 1.5% until it is equal to 20% in 2025.NCREs. Generation companies are able to meet this requirement by developing their ownbuilding NCRE generation capacity (wind, solar, biomass, geothermal and small hydroelectric technology), or purchasing NCREs from qualified generators or by payinggenerators. Non-compliance with the applicable fines for non-compliance.NCRE requirements will result in fines. AES Gener currently fulfills the NCRE requirements by utilizing AES Gener's own solar and biomass power plants and by purchasing NCREs from other generation companies. It has sold certain water rights to companies that are developing small hydro projects, entering into power purchase agreements with these companies in order to promote development of these projects, while at the same time meeting the NCRE requirements. At present, AES Gener is in the process of negotiating additional NCRE supply contracts to meet the future requirements.
In September 2014, a new tax law was enacted. The new law introduces an emission tax, or "green tax", that assesses the emissionsgreen tax, was enacted effective January 2017. Emissions of PM, SO2, NOx and CO2 produced are monitored for installationsplants with an installed capacity over 50 MW. The first annual payment shall be made in April 2018 forMW; these emissions produced in 2017.are taxed. In the case of CO2, the tax will be equivalent to $5 per ton emitted. InPPAs originating from the SING allhave clauses allowing the Company to pass the green tax costs to unregulated customers. Distribution PPAs have "change of law" clauses, which would allow the company to transfer this cost to customers. Inoriginating from the SIC costs can only be passed through to unregulated customers, as existing PPAs with distribution companies do not have change of law clauses. According to its PPAs,allow for the company is currently discussing the pass-through mechanism with each client. Additionally, the new tax systems introduced by the new tax laws enacted in February 2016 will be effective from January 1, 2017 onwards. The statutory income tax rate for most of our Chilean businesses will increase from 25% to 25.5% in 2017 and to 27%
for 2018 and future years. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Income Taxes for further details of the impactspass through of these new laws.costs.
In June 2015, the Chilean government published Decree N°7/2015, which allows the export of energy generated by plants not dispatched in the SING to Argentina using the transmission line connecting the SING with the SADI. This transmission line is owned by AES Gener and has a capacity of approximately 600 MW, but will be operated at 200 MW according to the government permit and related technical studies. AES Gener signed an agreement with CAMMESA and Chilean generators to export electricity to Argentina. In December 2016, Decree N° 7/2015 was amended to allow the export of energy generated by plants dispatched into the SING to Argentina. During 2016, energy exported to Argentina reached 102 GWh.
Key Financial Drivers —Hedge levels at AES Gener provide some certainty and clarity onlimit volatility to the underlying financial drivers. In addition, financial results are likely to be driven by many factors, including, but not limited to:
Drydry hydrology scenarios reduce hydro generationscenarios;
Forced outages may impact earningsforced outages;
Changeschanges in current regulatory rulings could alteraltering the ability to pass through or recover certain costscosts;
AES is exposed to the fluctuationfluctuations of the Chilean peso which may pose a risk to earnings; our(our hedging strategy reduces this risk, but some residual risk to earnings remainsremains);
Taxtax policy changeschanges;
Current legislation is trending towards promoting renewable energy and strengtheningand/or more restrictive regulations on thermal generation assets, posing a risk to future coal marginsassets; and
Marketmarket price risk when re-contractingre-contracting.
Construction and Development — Since 2007, AES Gener has constructed and commissioned approximately 2,400 MW of new capacity, representing a significant portion of the capacity increase in the SIC and SING during the period. During 2016, AES Gener achieved important milestones relatedcontinues to advance the construction of their projects:
Cochrane project began operations (Unit 2 on October 12 and Unit 1 on July 9) adding 532the 531 MW to the SING.
Cochrane Energy Storage began operations in October 2016 adding 20 MW of batteries contributing to system stability in the SING.
Andes Solar with 21 MW began operations in May 2016
Additionally, in the SIC, we continue advancing in the construction of our Alto Maipo
project, a 531 MW two unit run-of-riverrun-of-the-river hydroelectric
power plant, adjacent to our existing Alfalfal plant, located 50 km from Santiago.plant. Alto Maipo is the largest project in construction in the
SIC market andSEN market. When completed, it
includes 67will include 75 km of
tunnel works,tunnels, two
caverns,power houses and 17 km of transmission
lines as partlines. See Item 7.—Management's Discussion and Analysis of the construction,Financial Condition and is 90% underground. Results of Operations—Key Trends and Uncertainties—Alto Maipo has three main contractors and covers three adjacent valleys in the Chilean Andes. As of today, the project employs approximately 4,300 people and expects to reach a peak close to 4,500. The project units are scheduled to reach commercial operation in the first half of 2019.We are expanding our business by evaluating opportunities in the desalination business line through two initiatives: i) brownfield projects, which take advantage of existing infrastructure in thermoelectric power plants (marine works, easy access to power, strategic location, permits, etc.), providing shorter development time lines and more competitive water tariffs to offtakers; and ii) greenfield projects, mainly for mining companies which either purchase industrial water through water purchase agreements, or either invite external companies to compete in a bidding process to develop a project under a build-own-operate-and-transfer scheme where the water facility along its pipeline is transferred to the mining operation at the end of a defined period. In Chile, most of the water demand comes from mining operations, either directly or indirectly (their service providers), hence negative outlooks in the mineral markets have translated in the postponement of most of the mining projects and their corresponding water demands..
Colombia
Business Description — We operate in Colombia through AES Chivor, a subsidiary of AES Gener, who owns a hydroelectric plant with an installed capacity of 1,000 MW,Regulatory Framework and Tunjita, a 20 MW run-of-river hydroelectric, both located approximately 160 km east of Bogota. As of December 31, 2016, AES Chivor's net power production in reached 4,373 GWh. AES Chivor’s installed capacity accounted for approximately 6.1% of system capacity by the end of the year. Chivor remains dependent on prevailing hydrological conditions in the region in which it operates. Hydrological conditions largely influence generation and the spot prices at which AES Chivor sells its non-
contracted generation in Colombia.
AES Chivor's commercial strategy aims to reduce margin volatility by selling a significant portion of the expected generation under short term contracts, mainly with distribution companies. These contracts are awarded in public auctions and normally last from one to three years. The remaining generation is sold on the spot market to other generation and trading companies at the system marginal cost, allowing us to maximize the operating margin. Additionally, AES Chivor receives reliability payments to compensate for the plant availability during periods of power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.
Market Structure — Electricity supply in Colombia is concentrated in one main system, the SIN, which encompasses one-third of Colombia's territory, providing coverageelectricity to 97% of the country's population. The SIN's installed capacity, primarily hydroelectric (68%) and thermal (31%), totaled 16,69017,392 MW as of December 31, 2016, comprised of 70% hydroelectric generation, 29% thermoelectric generation and 1% other.2018. The dominance of hydroelectric generation and the marked seasonal variations in Colombia's hydrology result in price volatility in the short-term market. In 2016, 72%2018, 84% of total energy demand was supplied by hydroelectric plants with the remaining supply from thermoelectric generation of 27% and cogeneration and self-generation power of 1%. From 2003 to 2016, electricity demand in the SIN has grown at a compound annual growth rate of 2.9% and the Mining and Energetic Planning Unit projects an average compound annual growth rate in electricity demand of 3.0% per year for the next 10 years.plants.
Regulatory Framework — Since 1994, theThe electricity sector in Colombia has operatedoperates under a competitive market framework for the generation and sale of electricity, and a regulated framework for transmission and distribution.distribution of electricity. The distinct activities of the electricity sector are governed by variousColombian laws as well asand the regulationsCREG, regulating entity for energy and technical standards issued by the CREG.gas. Other government entities that play an importanthave a role in the electricity industry, includeincluding the Ministry of Mines and Energy, which defines the government's policy for the energy sector; the Public Utility Superintendency of Colombia, which is in charge of overseeing and inspecting the utility companies; and the Mining and Energetic Planning Unit, which is in charge of planning the expansion of the generation and transmission network.
The generation sector is organized on a competitive basis with companies selling their generation in the wholesale market at the short-term price or under bilateral contracts with other participants, including distribution
companies, generators and traders, and unregulated customers at freely negotiated prices. Generation companies must submit price bids and report the quantity of energy available on a daily basis. The National Dispatch Center dispatches generators in merit order based on bid offers in order to ensure that demand will be satisfied by the lowest cost combination of available generating units.
Regulatory Framework - Tax Regulation — OnIn 2018, the Ministry of Mines and Energy published the final resolution for renewable energy auctions in Colombia. The auction allocates 12-year energy contracts for 1.1 TW/h of energy demand under which renewable generators commit to be in commercial operation by December 29, 2016, Law 1819 was enacted in Colombia, which introduced a tax reform with several changes in the Colombian tax system, and became effective on January 1, 2017. This tax reform reduced the statutory corporate tax rate of companies to 40% in 2017, 37% in 2018, and 33% in2021. The auction is scheduled for February 2019 onwards. The law also created a new withholding tax on dividend distributions based on a tax rate of 5%, applicable on distribution of Colombian profits generated from the taxable year 2017 onwards.
Other Regulatory Considerations — After the phenomenon of El Niño put the energy supply at risk, regulatory agencies and the government have carried out various studiesregulator expects to make adjustments to the market. The subjects susceptible to revision include the following:
Adjustments to the scarcity price so that it reflects a true value of thermal plants that operate in periods of crisis.
A plan to implement an option to assign firm energy obligations without the need for reliability auctions but with obligation of signing energy contracts with non-regulated demand.
Possible participation of renewable plants in the market and its effect in the formation of prices and operation of the market.
The implementation of the standardized contract market, and
The possibility of entering into the intraday markets and markets of the previous day are still being considered.
Other topics that the regulator could analyze in 2017, but with a secondary priority are: An international interconnection scheme, review of the AGC market and analysis of other ancillary services, and possible modification ofadopt the current regulation for emergency situations.the entry of renewable generation to the market during 2019.
Business Description — We operate in Colombia through AES Chivor, a subsidiary of AES Gener, which owns a hydroelectric plant with an installed capacity of 1,000 MW, and Tunjita, a 20 MW run-of-river hydroelectric plant, both located approximately 160 km east of Bogota. AES Chivor’s installed capacity accounted for approximately 6% of system capacity at the end of 2018. AES Chivor is dependent on hydrological conditions, which influence generation and spot prices of non-contracted generation in Colombia.
AES Chivor's commercial strategy aims to execute contracts with commercial and industrial customers, and bid in public tenders for one to four year contracts, mainly with distribution companies to reduce margin volatility with proper portfolio risk management. The remaining energy generated by our portfolio is sold to the spot market, including ancillary services. Additionally, AES Chivor receives reliability payments for maintaining the plant available during periods of power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.
Key Financial Drivers — Hydrological conditions largely influence Chivor's generation level.power generation. Maintaining the appropriate contract level, while working to maximizemaximizing revenue through the sale of excess generation, is key to Chivor's results of operationsoperations. Hedge levels at Chivor provide certainty and clarity onlimit volatility in the underlying financial drivers, hedging the net cash flows of Chivor, up to 90%.drivers. In addition to hydrology, financial results are likely to be driven by many factors, including, but not limited to:
forced outages;
Forced outages may impact earnings
AES is exposed to fluctuationfluctuations of the Colombian peso,peso; and
spot market prices.
Argentina
Regulatory Framework and Market Structure — Argentina has one main power system, the SADI, which pose a riskserves 96% of the country. As of December 31, 2018, the installed capacity of the SADI totaled 38,538 MW. The SADI's installed capacity is composed primarily of thermoelectric generation (64%) and hydroelectric generation (28%).
Thermoelectric generation in the SADI is primarily natural gas. However, scarcity of natural gas during winter periods (June to earnings; our hedging strategy reduces this risk, but some residual riskAugust), result in the use of alternative fuels, such as oil and coal. The SADI is also highly reliant on hydroelectric plants. Hydrological conditions impact reservoir water levels and largely influence the dispatch of the system's hydroelectric and thermoelectric generation plants and, therefore, influence market costs. Precipitation in Argentina occurs principally between June and August.
Regulatory Framework — The Argentine regulatory framework divides the electricity sector into generation, transmission and distribution. The wholesale electric market is comprised of generation companies, transmission companies, distribution companies and large customers who are permitted to earnings remains
Chivor has exposure totrade electricity. Generation companies can sell their output in the spot market as hedge levelsor under PPAs. CAMMESA manages the electricity market and is responsible for dispatch coordination. The Electricity National Regulatory Agency is in charge of regulating public service activities and the Secretariat of Energy regulates system framework and grants concessions or authorizations for sector activities. In Argentina, the regulator establishes the prices for electricity and fuel and adjusts them periodically for inflation, changes in fuel prices and other factors. As a result, our businesses are lowerparticularly sensitive to changes in regulation.
The Argentine electric market is an "average cost" system, with generators being compensated for fixed costs and non-fuel variable costs plus a rate of return. All fuel, except coal, can be provided by CAMMESA. In December 2018, Resolution 70/2018 was enacted. This allows generation companies to buy fuel directly from producers or from CAMMESA.
Argentina’s administration continues introducing regulatory improvements aiming to normalize the futureenergy sector. Among others, Resolution 19/2017 was enacted in 2017 to set higher tariffs, denominated in USD, for energy and capacity prices. The enactment of resolution 19/2017 ceased the remuneration intended to fund increased capacity projects . Likewise, long term USD-denominated PPAs have been awarded to develop 9.4 GW
Construction
of new capacity (thermal and Development —In Colombia, renewable) through the execution of competitive auctions. During 2018, the government has continued to increase end user prices to reduce subsidies and decrease system deficit.
Argentina
Business Description — As of December 31, 2016,2018, AES Argentina operates 4,105plants totaling 4,129 MW, which represents 12%representing 11% of the country's total installed capacity. The installed capacity in the SADI includes the TermoAndes plant, a subsidiary of AES Gener, which is connected both to the SADI and the Chilean SING.SEN markets. AES Argentina has a diversified generation portfolio of ten generation facilities, comprised of 68% thermoelectric and 32% hydroelectric capacity. All of the thermoelectric capacity has the capability to burn alternative fuels. Approximately 76% of the thermoelectric capacity can operate with natural gas or diesel oil, and the remaining 24% can operate with natural gas, fuel oil, or coal.portfolio.
AES Argentina primarily sells its production toenergy in the wholesale electricelectricity market where prices are largely regulated. In 2016,2018, approximately 94%93% of the energy was sold in the wholesale electricelectricity market and 6%7% was sold under contract, as a result of the Energy Pluscontract sales made by TermoAndes.
All of the thermoelectric facilities not affected by the Resolution 95/2013, a regulation passedForeign currency controls were lifted in March 2013 discussed below, including the portion of TermoAndes plant committed to Energy Plus Contracts, are able to use natural gas and receive gas supplied through contracts with Argentine producers. In recent years, gas supply restrictions in Argentina, particularly during the winter season, have affected some of the plants, such as the TermoAndes plant. The TermoAndes plant commenced operations in 2000, selling exclusively into the Chilean SING. In 2008, following requirements from the Argentine authorities, TermoAndes connected its two gas turbines to the SADI, while maintaining its steam turbine connected to the SING. However, since December 2011, TermoAndes has been selling the plant's full capacity in the SADI.
Market Structure — The SADI electricity market is managed by CAMMESA. As of December 31, 2016, the installed capacity of the SADI totaled 33,901 MW. In 2016, 66% of total energy demand was supplied by thermoelectric plants, 26% by hydroelectric plants and 8% from nuclear, wind and solar plants.
Thermoelectric generation in the SADI is principally fueled by natural gas. However, since 2004 due to natural gas shortages, in addition to increasing electricity demand, the use of alternative fuels in thermoelectric generation, such as oil and coal, has increased. Given the importance of hydroelectric facilities in the SADI, hydrological conditions determining river flow volumes and initial water levels in reservoirs largely influence hydroelectric and thermoelectric plant dispatch. Rainfall occurs principally in the southern cone winter season (June to August).
Regulatory Framework — The Argentine regulatory framework divides the electricity sector into generation, transmission and distribution. The wholesale electric market is made up of generation companies, transmission companies, distribution companies and large customers who are allowed to buy and sell electricity. Generation companies can sell their output in the short-term market or to customers in the contract market. CAMMESA is responsible for dispatch coordination and determination of short-term prices. The Electricity National Regulatory Agency is in charge of regulating public service activities and the Ministry of Federal Planning, Public Investment and Services, through the Energy Secretariat, regulates system dispatch and grants concessions or authorizations for sector activities.
Since 2001, significant modifications have been made to the electricity regulatory framework. These modifications include the freezing of tariffs, the cancellation of inflation adjustment mechanisms and the introduction of a complex pricing system in the wholesale electric market, which have materially affected electricity generators, transporters and distributors, and generated substantial price differences within the market. Since 2004, as a result of energy market reforms and overdue accounts receivables owed by the government to generators operating in Argentina, AES Argentina contributed certain accounts receivables to fund the construction of new power plants under FONINVEMEM agreements. These receivables accrue interest and are collected in monthly installments over 10 years once the related plants begin operations. At this point, three funds have been created to construct three facilities. The three plants are operating and payments are being received. AES Argentina will receive a pro rata ownership interest in these newly built plants once the accounts receivables have been paid. See Item 7.—Capital Resources and Liquidity—Long-Term Receivables and Note 7—Financing Receivables for further discussion of receivables in Argentina.
In March 2013, the Secretariat of Energy released Resolution 95/2013, which affects the remuneration of generators whose sales prices had been frozen since 2003. This regulation is applicable to generation companies with certain exceptions. It defined a compensation system based on compensating for fixed costs, non-fuel variable costs and an additional margin. Resolution 95/2013 converted the Argentine electric market to an "average cost" compensation scheme.
Thermal units must achieve an availability target, which varies by technology, in order to receive full fixed cost revenues. The Resolution also established that all fuels, except coal, are to be provided by CAMMESA. Thermoelectric natural gas plants not affected by the Resolution, such as TermoAndes, are able to purchase gas directly from the producers for Energy Plus sales.
In May 2014, the Argentine government passed Resolution No. 529/214 ("Resolution 529") which retroactively updated the prices of Resolution 95/2013 to February 1, 2014, changed target availability and added a remuneration for non-periodic maintenance. This remuneration is aimed to cover the expenses that the generator incurs when performing major maintenances in its units. Since 2014, this resolution has been updated annually, the most recent of which was issued in March 2016.
On February 2, 2017, the Ministry of Energy issued Resolution 19/2017 establishing changes to the Energia Base price framework. Effective in February 2017, the framework will maintain the current tolling agreement structure, as fuels will continue to be sourced by CAMMESA. A key change will be introduced to the tariff structure which will now have prices set in USD and also eliminates all future non-cash retention of margins.
In December 2015, the finance minister lifted foreign currency controls, allowing the Argentine peso to float under the administration of Argentineanthe Argentinian Central Bank. The newly freed currency fell by more than 30%. OverIn 2018, the course of 2016, the Argentinean PesoArgentine peso devalued by approximately 22%. At December 31, 2016, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank.102% and Argentina’s economy was determined to be highly inflationary. See Note 7—Financing Receivables in Item 8.7.—Financial StatementsManagement's Discussion and Supplementary DataAnalysis Key Trends and Uncertainties of this Form 10-K for further informationdiscussion.
Tax Regulation — On December 29, 2017, Law 27430 was enacted in Argentina, which introduced a tax reform with several changes in the Argentine tax system, effective on January 1, 2018. This tax reform reduced the statutory corporate tax rate of companies from 35% to 30% in 2018 and 2019, and will reduce the rate to 25% from 2020 onward. The law also eliminated the Equalization Tax on the long-term receivables. Further weakeningdistribution of earnings generated after January 1, 2018. The Equalization Tax was replaced with a withholding tax on dividends at the Argentine Pesorate of 7% for 2018 and local economic activity could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to the Parent Company,2019, and the value of our assets.13% from 2020 onward.
Key Financial Drivers — Financial results are likely to be driven by many factors, including, but not limited to:
•Forced outages may impact earningsforced outages;
•FX exposure to fluctuations of the Argentine Pesopeso;
•Hydrology
Timely collection of FONINVEMEM installment and outstanding receivables (See Note 7—Financing Receivableschanges in Item 8.—Financial Statements and Supplementary Data for further discussion)hydrology;
| |
| • | timely collection of FONINVEMEM installment and outstanding receivables (See Note 6.—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion); and |
•Level ofnatural gas prices and availability for contracted generation.
Brazil
Regulatory Framework and Market Structure — In Brazil, the Ministry of Mines and Energy determines the maximum amount of energy a generation (Energy Plus)
plant can sell, called physical guarantee, representing the long-term average expected energy production of the plant. Under current rules, physical guarantee energy can be sold to distribution companies through long-term regulated auctions or under unregulated bilateral contracts with large consumers or energy trading companies. Brazil SBU
Our Brazil SBU has generation and distribution businesses. Tietê and Eletropaulo are publicly listed companies in Brazil. AES has a 24% economic interest in Tietê and a 17% economic interest in Eletropaulo. These businesses are consolidated in our financial statements as we maintain control over their operations.
Generation — Operating installed capacity of our Brazil SBU totals 2,658162,932 MW, which is primarily hydroelectric (64%) and renewables (19%). Operation is centralized and controlled by the national operator, ONS, and regulated by ANEEL. The ONS dispatches generators based on their marginal cost of production and on the risk of system rationing. Key variables for the dispatch decision are forecasted hydrological conditions, reservoir levels, electricity demand, fuel prices and thermal generation availability.
In case of unfavorable hydrology, the ONS will reduce hydroelectric dispatch to preserve reservoir levels and increase dispatch of thermal plants to meet demand. The consequences of unfavorable hydrology are (i) higher energy spot prices due to higher energy production costs by thermal plants and (ii) the need for hydro plants to purchase energy in AESthe spot market to fulfill their contractual obligations.
A mechanism known as the MRE was created under ONS to share hydrological risk across MRE hydro generators. If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may
need to purchase energy in the short-term market. When total hydro generation is higher than the total MRE physical guarantee, the surplus is proportionally shared among its participants and they may sell the excess energy on the spot market.
Business Description — Tietê has a portfolio of 12 hydroelectric power plants located in the state of São Paulo. AsPaulo with total installed capacity of December 31, 2016,2,658 MW. Tietê represents approximately 10% of the total generation capacity in the state of São Paulo and is one of the largest generation companiesPaulo. Tietê hydroelectric plants operate under a 30-year concession expiring in Brazil. We also have another generation plant, AES Uruguaiana, located in southern Brazil with an installed capacity of 640 MW. The following table lists our Brazil SBU generation facilities:
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| | | | | | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
Tietê (1) | | Brazil | | Hydro | | 2,658 |
| | 24 | % | | 1999 | | 2029 | | Various |
| Uruguaiana | | Brazil | | Gas | | 640 |
| | 46 | % | | 2000 | |
| |
|
| | | | | | | 3,298 |
| | | | | | | | |
_____________________________
| |
(1)
| Tietê plants with installed capacity: Água Vermelha (1,396 MW), Bariri (143 MW), Barra Bonita (141 MW), Caconde (80 MW), Euclides da Cunha (109 MW), Ibitinga (132 MW), Limoeiro (32 MW), Mogi-Guaçu (7 MW), Nova Avanhandava (347 MW), Promissão (264 MW), Sao Joaquim (3 MW) and Sao Jose (4 MW). |
Utilities — Eletropaulo operates in the metropolitan area of São Paulo and adjacent regions, distributing electricity to 24 municipalities in a total area of 4,526 km2, covering a region of high demographic density and the largest concentration of GDP in the country. Serving approximately 18 million people and 7 million consumer units,
Eletropaulo is the largest power distributor in Brazil, according to the 2015 ranking of the Brazilian Association of the Distributors of Electric Energy (Abradee). On October 31, 2016, the Company completed the sale of its wholly-owned subsidiary AES Sul, a distribution business in Brazil. The following table describes our Brazil utility:
|
| | | | | | | | | | | | | |
| Business | | Location | | Approximate Number of Customers Served as of 12/31/2016 | | GWh Sold in 2016 | | AES Equity Interest (% Rounded) | | Year Acquired |
| Eletropaulo | | Brazil | | 7,015,909 |
| | 34,464 |
| | 17 | % | | 1998 |
The following map illustrates the location of our Brazil facilities:
Brazil Businesses
Brazil Utility
Business Description — Eletropaulo distributes electricity to the greater São Paulo area, Brazil's main economic and financial center.2029. AES owns 17%24% of the economic interest in Eletropaulo, our partner, BNDES, owns 19%Tietê and the remaining shares are publicly held or held by government-related entities. On December 30, 2016 AES purchased par shares from BNDES and increased its participation in Eletropaulo from 16% to 17%.AES is the controlling shareholder and manages and consolidates this business. Eletropaulo holds a 30-year concession that expires in 2028. In December 2016, Eletropaulo underwent a corporate restructuring which is expected to, among other things, prepare for the listing of its shares on the Novo Mercado, a segment of the Brazilian stock exchange.
Regulatory Framework — In Brazil, ANEEL, a government agency, sets the tariff for each distribution company based on a return on asset base methodology, which also benchmarks operational costs against other distribution companies. The tariff charged to regulated customers consists of two elements: (i) pass-through of non-manageable costs under a determined methodology ("Parcel A"), including energy purchase costs, sector charges and transmission and distribution system expenses; and (ii) a manageable cost component ("Parcel B"), including operation and maintenance costs (defined by ANEEL), recovery of investments and a component for a return to the distributor. The return to distributors is calculated as the net asset base multiplied by the regulatory weighted-average cost of capital, which is set for all industry participants during each tariff reset cycle. The current regulatory weighted-average cost of capital for Eletropaulo, after tax, is 8.1%.
Each year ANEEL reviews each distributor's tariff for an annual tariff adjustment. The annual tariff adjustments allow for pass-through of Parcel A costs and inflation impacts on Parcel B costs, adjusted for expected efficiency gains and quality performances. Distribution companies are required to contract between 100% and 105% of anticipated energy needs through the regulated auction market. If contracted levels fall below required levels distribution companies may be subject to limitations on the pass-through treatment of energy purchase costs as well as penalties. As the costs incurred on energy purchases made by our distribution company are passed through
to customers with adjustments on a yearly basis, working capital can be sensitive to significant increases in energy prices. In order to reduce potential working capital needs, in 2015 ANEEL established the tariff flag mechanism, which allows temporary tariff changes to customers on a monthly basis depending on energy purchase prices. The resources collected by the tariff flag mechanism are centralized in an account and shared among distribution companies in proportion to their respective exposure to the spot market.
Every four years, ANEEL resets each distributor's tariff to incorporate the revised regulatory weighted-average cost of capital and determination of the distributor's net asset base as well as operational costs. Eletropaulo's tariff reset occurs every four years and the next tariff reset will be in July 2019. The 4th Tariff Reset for AES Eletropaulo occurred on July 4, 2015, representing an average tariff increase of 15.23%.
Between the tariff reset periods, the regulator applies the annual adjustments. On July 4, 2016 ANEEL approved a negative tariff adjustment for Eletropaulo, mainly due to a decrease in energy purchase and sector charges costs. The average tariff decrease was 8.1%.
In 2013, ANEEL challenged the parameters of a tariff reset for Eletropaulo implemented in July 2012 and retroactive to 2011. ANEEL asserted that during the period between 2007 and 2011, certain assets that were included in the regulatory asset base should not have been included and that Eletropaulo should refund customers for the return on the disputed assets earned during this period. On December 17, 2013, ANEEL determined, at the administrative level, that Eletropaulo should adjust the prior 2007-2011 regulatory asset base and refund customers in the amount of $269 million over a period of up to four tariff processes beginning in July 2014. The Company recognized a regulatory liability of approximately $269 million in 2013, since ANEEL had compelled the Company to refund customers, and started reimbursing customers in July 2014. Eletropaulo filed for an administrative appeal requesting ANEEL to reconsider its decision and requested that the decision be suspended until the appeal process is completed. The injunction was granted and, although for a period was suspended, it has been restored and in effect since December 2014.
Given ANEEL's failure to suspend the injunction through the appeals process in the Brazilian courts thus far, the tariff reset resulted in management's reassessment of the probability of refunding customers these disputed amounts. Therefore, at this point, the Company considers it only reasonably possible that Eletropaulo will be required to refund these amounts to customers prior to the ultimate resolution of the pending court case. As a result, during 2015, the Company reversed the remaining regulatory liability for this contingency of $161 million. Eletropaulo believes it has meritorious arguments on this matter and will continue to pursue its objections to ANEEL's rulings vigorously, however there can be no assurance that Eletropaulo will prevail.
Key Financial Drivers — Eletropaulo's financial results is likely to be driven by many factors including, but not limited to:
Hydrology, impacting quantity of energy sold and energy purchased
Brazilian economic scenario and tariff increases, impacting energy consumption growth, losses and delinquency
Quality indicators recovery plan
Ability of Eletropaulo to pass through costs via productivity gains
Ability of Eletropaulo to solve involuntary exposure
Capital structure optimization to reduce leverage and interest costs
The CTEEP Eletrobrás case (see Item 3.—Legal Proceedings for further information)
Eletropaulo is affected by the demand for electricity, which is driven by economic activity, weather patterns and customers' consumption behavior. Operating performance is also driven by the quality of service, efficient management of operating and maintenance costs as well as the ability to control non-technical losses. Finally, annual tariff adjustments and periodic tariff resets by ANEEL impact results from operations.
Brazil Generation
Business Description — Tietê has a portfolio of 12 hydroelectric power plants with total installed capacity of 2,658 MW in the state of São Paulo. Tietê was privatized in 1999 under a 30-year concession expiring in 2029. AES owns a 24% economic interest in Tietê, our partner, the BNDES, owns 28% and the remaining shares are publicly held or held by government-related entities. AES is the controlling shareholder and manages and consolidates this business.
Tietê sold nearly 100% of its physical guarantee, approximately 11,194 GWh, to Eletropaulo under a long-term PPA, which expired in December 2015. The contract was price-adjusted annually for inflation, and as of December
31, 2015, the price was R$218/MWh. After the expiration of contract with Eletropaulo, Tietê's strategy isaims to contract most of its physical guarantee as described in Regulatory Framework section below,requirements and sell the remaining portion in the spot market. Tietê'sThe commercial strategy is reassessed from time to timeperiodically according to changes in market conditions, hydrology and other factors. Tietê has been continuously selling itsgenerally sells available energy from 2016 forward through medium-term bilateral contractscontracts.
Tietê's strategy is to grow by adding renewable capacity to its generation platform. In 2017, Tietê acquired Alto Sertão II Wind Complex (“Alto Sertão II”) located in the state of threeBahia, with an installed capacity of 386 MW and subject to five years.
As20-year PPAs expiring between 2033 and 2035. Furthermore, in 2017 Tiete acquired Boa Hora Solar, a solar development project and won a bid to develop a second solar project, AGV Solar, in the state of December 31, 2016,São Paulo. In 2018, Tietê's acquired Guaimbê, a solar power complex. All the solar assets are fully contracted portfolio position is 95% and 88% with average prices20 year PPAs. Through its ownership of R$157/MWh and R$159/MWh (inflation adjusted until December 2016) for 2016 and 2017, respectively. As Brazil is mostlyTietê, AES owns a hydro-based country with energy prices highly tied24% economic interest in those entities. These assets are not subject to return at the hydrological situation, the deteriorationend of the hydrology since the beginning of 2014 caused an increase in energy prices going forward. Tietê is closely monitoring and analyzing system supply conditions to support energy commercialization decisions.concession.
Under the concession agreement, Tietê has an obligationis required to increase its capacity by 15%. Tietê, as well as other concession generators, have not yet met this requirement due to regulatory, environmental, hydrological and fuel constraints. The state of São Paulo does not have a sufficient potential for wind power and only has a small remaining potential for hydro projects. As such, the capacity increases in the state will mostly be derived from thermal gas capacity projects. Due to the highly complex process to obtain an environmental license for coal projects, Tietê decided to fulfill its obligation with gas-fired projects in line with the federal government plans. Petrobras refuses to supply natural gas and to offer capacity in its pipelines and regasification terminals. Therefore, there are no regulations for natural gas swaps in place, and it is unfeasible to bring natural gas to AES Tietê. A legal case has been initiated by the state of São Paulo requiringby 15% (or 398 MW). The above mentioned investments in new solar generation capacity in the investmentstate of São Paulo allowed Tietê to be performed. Tietêsign a legal agreement in October 2018 with the state government in which it was agreed that: (i) 80% of the expansion obligation (317 MW) was delivered or is in performance stage; and (ii) the process of analyzing optionsCompany will have up to six years from the agreement's approval date to meet the obligation.remaining balance (81 MW).
Uruguaiana is a 640 MW gas-fired combined cycle power plant located in the town of Uruguaiana in the state of Rio Grande do Sul, commissioned in December 2000.Sul. AES manages and has a 46% economic interest in the plant with the remaining interest held by BNDES.plant. The plant's operations werehave been largely suspended in April 2009 due to the unavailability of gas. The plant operated for short periods of time in 2013, 2014 and 2015 when short-term supply of LNG was sourced for the facility. The plant did not operate in 2016, 2017 or 2018. AES has evaluated several alternatives to bring gas supply on a competitive basis to Uruguaiana. One of the challenges is the capacityCapacity restrictions on the Argentinean pipeline are a challenge, especially during the winter season when gas demand in Argentina is very high. The plant operated on a short-term basis during February and March 2013, March through May 2014, and February through May 2015 due to the short-term supply of LNG for the facility. The plant did not operate in 2016. Uruguaiana continues to work toward securing gas on a long-term basis.
Market Structure — Brazil has installed capacity of 150,136 MW, which is 65% hydroelectric, 19% thermal and 16% renewable (biomass and wind). Brazil's national grid is divided into four subsystems. Tietê is in the Southeast and Uruguaiana is in the South subsystems of the national grid.
Regulatory Framework — In Brazil, the Ministry of Mines and Energy determines the maximum amount of energy that a plant can sell, called physical guarantee, which represents the long-term average expected energy production of the plant. Under current rules, physical guarantee can be sold to distribution companies through long-term regulated auctions or under unregulated bilateral contracts with large consumers or energy trading companies.
The National System Operator ("ONS") is responsible for coordinating and controlling the operation of the national grid. The ONS dispatches generators based on hydrological conditions, reservoir levels, electricity demand and the prices of fuel and thermal generation. Given the importance of hydro generation in the country, the ONS sometimes reduces dispatch of hydro facilities and increases dispatch of thermal facilities to protect reservoir levels in the system.
In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels. A mechanism known as the Energy Reallocation Mechanism ("MRE") was created to share hydrological risk across MRE hydro generators. If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may need to purchase energy in the short-term market to fulfill their contract obligations. When total hydro generation is higher than the total MRE physical guarantee, the surplus is proportionally shared among its participants and they are able to make extra revenue selling the excess energy on the spot market. The consequences of unfavorable hydrology are (i) thermal plants more expensive to the system being dispatched, (ii) lower hydropower generation with deficits in the MRE and (iii) high spot prices. ANEEL defines the spot price cap for electricity in the Brazilian market. The spot price caps as defined by ANEEL and average spot prices by calendar year are as follows (R$/MWh):
|
| | | | | | | | |
| Year | | 2017 | | 2016 | | 2015 | | 2014 |
| Spot price cap as defined by ANEEL | | 534 | | 423 | | 388 | | 822 |
| Average spot rate | | | | 94 | | 287 | | 689 |
Key Financial Drivers — As the system is highly dependent on hydroelectric generation, Tietê and Uruguaiana are are affectedelectricity pricing is driven by the hydrology in Brazil. Plant availability is also a significant financial driver as in times of high hydrology AES is more exposed to the overall sector. They are also affected by the availability of Tietê's plants and reliability of the Uruguaiana facility.spot market. The availability of gas is also a driver for continued operations at Uruguaiana. Tietê's financial results are likely to be driven by many factors, including, but not limited to:
Hydrology,hydrology, impacting quantity of energy generated in MREMRE;
Demand growthdemand growth;
Re-contracting pricere-contracting price;
Assetasset management and plant availabilityavailability;
Cost managementcost management; and
Abilityability to execute on its growth strategystrategy.
Construction and Development — As part of the initiative to pursue opportunities in renewable generation discussed above, Tietê is currently constructing photovoltaic power plants with a total projected capacity of 144 MW, subject to 20 year PPAs. Commercial operation of first phase, Boa Hora Solar, and of the second phase, AGV Solar, is expected in the first half of 2019.
MCAC SBU
Our MCAC SBU has a portfolio of distribution businesses and generation facilities, including renewable energy, in fivethree countries, with a total capacity of 3,2393,205 MW and distribution networks serving 1.4 million customers as of December 31, 2016.2018.
Generation — The following table lists our MCAC SBU generation facilities:
| | | Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| DPP (Los Mina) | | | Dominican Republic | | Gas | | 358 |
| | 85 | % | | 1996 | | 2022 | | CDEEE |
| Andres | | Dominican Republic | | Gas | | 319 |
| | 90 | % | | 2003 | | 2018 | | Ede Este/Non-Regulated Users/Linea Clave | | Dominican Republic | | Gas | | 319 |
| | 85 | % | | 2003 | | 2022 | | Ede Norte/Ede Este/Ede Sur/Non-Regulated Users |
Itabo (1) | | Dominican Republic | | Coal/Gas | | 295 |
| | 45 | % | | 2000 | | 2017 | | Ede Este/Ede Sur/Ede Norte | | Dominican Republic | | Coal | | 295 |
| | 43 | % | | 2000 | | 2022 | | Ede Norte/Ede Este/Ede Sur |
| DPP (Los Mina) | | Dominican Republic | | Gas | | 236 |
| | 90 | % | | 1996 | | 2022 | | CDEEE | |
| Andres ES | | | Dominican Republic | | Energy Storage | | 10 |
| | 85 | % | | 2017 | |
| Los Mina DPP ES | | | Dominican Republic | | Energy Storage | | 10 |
| | 85 | % | | 2017 | |
| Dominican Republic Subtotal | | 850 |
| | | | | 992 |
| | | |
| AES Nejapa | | El Salvador | | Landfill Gas | | 6 |
| | 100 | % | | 2011 | | 2035 | | CAESS | |
| Moncagua | | El Salvador | | Solar | | 3 |
| | 100 | % | | 2015 | | 2035 | | EEO | |
| El Salvador Subtotal | | 9 |
| | | | |
| Merida III | | Mexico | | Gas | | 505 |
| | 55 | % | | 2000 | | 2025 | | Comision Federal de Electricidad | | Mexico | | Gas | | 505 |
| | 75 | % | | 2000 | | 2025 | | Comision Federal de Electricidad |
| Termoelectrica del Golfo (TEG) | | Mexico | | Pet Coke | | 275 |
| | 99 | % | | 2007 | | 2027 | | CEMEX | | Mexico | | Pet Coke | | 275 |
| | 99 | % | | 2007 | | 2027 | | CEMEX |
| Termoelectrica del Penoles (TEP) | | Mexico | | Pet Coke | | 275 |
| | 99 | % | | 2007 | | 2027 | | Penoles | | Mexico | | Pet Coke | | 275 |
| | 99 | % | | 2007 | | 2027 | | Penoles |
| Mexico Subtotal | | 1,055 |
| | | | | 1,055 |
| | | |
Colon (2) | | | Panama | | Gas | | 381 |
| | 50 | % | | 2018 | | 2028 | | Electra Noreste/Edemet/Edechi |
| Bayano | | Panama | | Hydro | | 260 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other | | Panama | | Hydro | | 260 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Changuinola | | Panama | | Hydro | | 223 |
| | 90 | % | | 2011 | | 2030 | | AES Panama | | Panama | | Hydro | | 223 |
| | 90 | % | | 2011 | | 2030 | | AES Panama |
| Chiriqui-Esti | | Panama | | Hydro | | 120 |
| | 49 | % | | 2003 | | 2030 | | Electra Noreste/Edemet/Edechi/Other | | Panama | | Hydro | | 120 |
| | 49 | % | | 2003 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Estrella de Mar I | | Panama | | Heavy Fuel Oil | | 72 |
| | 49 | % | | 2015 | | 2020 | | Electra Noreste/Edemet/Edechi/Other | |
| Estrella del Mar I | | | Panama | | Heavy Fuel Oil | | 72 |
| | 49 | % | | 2015 | | 2020 | | Electra Noreste/Edemet/Edechi/Other |
| Chiriqui-Los Valles | | Panama | | Hydro | | 54 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other | | Panama | | Hydro | | 54 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Chiriqui-La Estrella | | Panama | | Hydro | | 48 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other | | Panama | | Hydro | | 48 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Panama Subtotal | | 777 |
| | | | | 1,158 |
| | | |
| Puerto Rico | | US-PR | | Coal | | 524 |
| | 100 | % | | 2002 | | 2027 | | Puerto Rico Electric Power Authority | |
| Illumina | | US-PR | | Solar | | 24 |
| | 100 | % | | 2012 | | 2032 | | Puerto Rico Electric Power Authority | |
| Puerto Rico Subtotal | | 548 |
| | | | |
| | | 3,239 |
| | | | | 3,205 |
| | | |
_____________________________
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(1) | Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine). |
| |
(2) | Plant also includes an adjacent regasification facility, as well as a 180,000 m3 LNG storage tank, which is expected to come on-line in 2019. |
Under construction — The following table lists our plants under construction in the MCAC SBU:
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| DPP (Los Mina) Conversion | | Dominican Republic | | Gas | | 122 |
| | 90 | % | | 1H 2017 |
| Dominican ES | | Dominican Republic | | Energy Storage | | 20 |
| | 90 | % | | 1H 2017 |
| Dominican Republic Subtotal | | | | | | 142 |
| | | | |
| Colón | | Panama | | Gas | | 380 |
| | 50 | % | | 1H 2018 |
| Panama Subtotal | | | | | | 380 |
| | | | |
| | | | | | | 522 |
| | | | |
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| Mesa La Paz | | Mexico | | Wind | | 306 |
| | 50 | % | | 1H 2020 |
Utilities — Our distribution businesses are located in El Salvador and distribute power to 1.4 million people in the country. These businesses consist of four companies, each of which operates in defined service areas. The following table lists our MCAC utilities:
|
| | | | | | | | | | | | | |
| Business | | Location | | Approximate Number of Customers Served as of 12/31/2016 | | GWh Sold in 2016 | | AES Equity Interest | | Year Acquired or Began Operation |
| CAESS | | El Salvador | | 590,971 |
| | 2,232 |
| | 75 | % | | 2000 |
| CLESA | | El Salvador | | 388,341 |
| | 894 |
| | 80 | % | | 1998 |
| DEUSEM | | El Salvador | | 78,063 |
| | 133 |
| | 74 | % | | 2000 |
| EEO | | El Salvador | | 298,026 |
| | 576 |
| | 89 | % | | 2000 |
| | | | | 1,355,401 |
| | 3,835 |
| | | | |
The following map illustrates the location of our MCAC facilities:
MCAC Businesses
MCAC Utilities
El Salvador
Business Description — AES is the majority owner of four of the five distribution companies operating in El Salvador. The distribution companies are operated by AES on an integrated basis under a single management team. AES El Salvador's territory covers 77% of the country. AES El Salvador accounted for 4,151 GWh of market energy purchases during 2016, or about 63% market share of the country's total energy purchases.
MCAC Generation
Dominican RepublicPuerto Rico
Regulatory Framework and Market Structure — Puerto Rico has a single electric grid managed by PREPA, a state-owned entity that supplies virtually all of the electric power consumed in Puerto Rico and generates, transmits and distributes electricity to 1.5 million customers. The Puerto Rico Energy Bureau is the main regulatory body. The bureau approves wholesale and retail rates, sets efficiency and interconnection standards, and oversees PREPA's compliance with Puerto Rico's renewable portfolio standard.
Puerto Rico's electricity is 98% produced by thermal plants (47% from petroleum, 34% from natural gas, 17% from coal).
Business Description — AES Dominicana consists of three operating subsidiaries, Itabo, Andres and DPP. AES has 24% of the system capacity of 850 MW and supplies approximately 37% of energy demand through these generation facilities. AES has a strategic partnership with the Estrella and Linda Groups ("Estrella-Linda"), an investor group based in the Dominican Republic. Estrella-Linda is a consortium of two leading Dominican industrial groups: Estrella and Grupo Linda. The two partners manage a diversified business portfolio, including construction services, cement, agribusiness, metalwork, plastics, textiles, paints, transportation, insurance and media.
Itabo is 45% owned by AES, 5% by Estrella-Linda, 49.97% owned by FONPER, a government-owned utility and the remaining 0.03% is owned by employees. ItaboPuerto Rico owns and operates two thermal power generation units with a totalcoal-fired cogeneration plant and a solar plant of 295524 MW of installed capacity. Itabo's PPAs with government-owned distribution companies expired in July 2016 and thus two new short term contracts with Ede Sur and Ede Este were signed until new long term contracts take place. The Dominican Corporation of State Electrical Companies is sponsoring a bidding process, released in
AndresEl Salvador
Regulatory Framework and DPP are owned 90% by AESMarket Structure — El Salvador's national electric market is composed of generation, distribution, transmission and 10% by Estrella-Linda. Andres has a combined cycle gas turbine and generation capacity of 319 MWmarketing businesses, as well as a market and system operator and regulatory agencies. The operation of the only LNG import facilitytransmission system and the wholesale market is based on production costs with a marginal economic model that rewards efficiency and allows investors to have guaranteed profits, while end users receive affordable rates. The energy sector is governed by the General Electricity Law, which establishes two regulatory entities responsible for monitoring its compliance:
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 country,energy matrix.
The General Superintendence of Electricity and Telecommunications regulates the market and sets consumer prices, and, jointly with 160,000 cubic meters of storage capacity. DPP (Los Mina) has two open cycle natural gas turbines and generation capacity of 236 MW. Both Andres and DPP have in aggregate 555 MW of installed capacity, of which 450 MW is mostly contracted until 2018 with government-ownedthe distribution companies and large customers.in El Salvador, developed the tariff calculation applicable from 2018 until 2022.
AES DominicanaEl Salvador has a long-term LNG purchase contract through 2023 for 33.6 trillion btu/yearnational electric grid that interconnects with a price linked to NYMEX Henry Hub.Guatemala and Honduras. The LNG contract terms allow the diversion of the cargoes to various markets in Latin America. These plants capitalize on the competitively-priced LNG contract by selling power where the market is dominated by fuel oil-based generation. Andressector has a long-term contract to sell re-gasified LNG to industrial users within the Dominican Republic using compression technology to transport it within the country thereby capturing demand from industrial and commercial customers.
Market Structure - Electricity and Natural Gas — The Dominican Republic has one main interconnected system with approximately 3,5531,659 MW of installed capacity, composed primarily of thermal generation (80%(43%), hydroelectric power plants (17%(34%), geothermal (10%), biomass (9%) and windsolar (4%) generation plants.
Business Description — AES El Salvador is the majority owner of four of the five distribution companies operating in El Salvador (CAESS, CLESA, EEO and DEUSEM). AES El Salvador's territory covers 79% of the country and accounted for 4,040 GWh of the wholesale market energy purchases during 2018, or about 63% market share.
Construction and Development — As part of the initiative to pursue opportunities in renewable generation, AES El Salvador has entered into a joint venture with Corporacion Multi-Inversiones, a Guatemalan investment group, to develop, construct and operate Bosforo, a 142 MW solar farm. 43 MW of the project were completed in 2018 and are fully operational. 57 MW are under construction and expected to become operational during the first half of 2019 and the remaining 42 MW will start construction in 2019 and are expected to be completed in the second half of 2019. The energy produced by this project will be contracted directly by AES' utilities in El Salvador.
South America SBU
Our South America SBU has generation facilities in four countries — Chile, Colombia, Argentina and Brazil. AES Gener, which owns all of our assets in Chile, Chivor in Colombia and TermoAndes in Argentina, as detailed below, is a publicly traded company in Chile. AES has a 66.7% ownership interest in AES Gener and this business is consolidated in our financial statements. Tietê is a publicly traded company in Brazil. AES controls and consolidates Tietê through its 24% economic interest.
Operating installed capacity of our South America SBU totals 12,435 MW, of which 33%, 28%, 8%, and 31% are located in Argentina, Chile, Colombia and Brazil, respectively. The following table lists our South America SBU generation facilities:
|
| | | | | | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| Chivor | | Colombia | | Hydro | | 1,000 |
| | 67 | % | | 2000 | | 2019-2026 | | Various |
| Tunjita | | Colombia | | Hydro | | 20 |
| | 67 | % | | 2016 | | | | |
| Colombia Subtotal | | | | | | 1,020 |
| | | | | | | | |
Gener - Chile (1) | | Chile | | Coal/Hydro/Diesel/Solar/Biomass | | 1,532 |
| | 67 | % | | 2000 | | 2019-2040 | | Various |
Guacolda (2) | | Chile | | Coal | | 760 |
| | 33 | % | | 2000 | | 2019-2032 | | Various |
| Electrica Angamos | | Chile | | Coal | | 558 |
| | 67 | % | | 2011 | | 2026-2037 | | Minera Escondida, Minera Spence, Quebrada Blanca |
| Cochrane | | Chile | | Coal | | 550 |
| | 40 | % | | 2016 | | 2030-2037 | | SQM, Sierra Gorda, Quebrada Blanca |
| Cochrane ES | | Chile | | Energy Storage | | 20 |
| | 40 | % | | 2016 | | | | |
| Electrica Angamos ES | | Chile | | Energy Storage | | 20 |
| | 67 | % | | 2011 | |
| |
|
| Norgener ES (Los Andes) | | Chile | | Energy Storage | | 12 |
| | 67 | % | | 2009 | |
| |
|
| Chile Subtotal | | | | | | 3,452 |
| | | | | | | | |
TermoAndes (3) | | Argentina | | Gas/Diesel | | 643 |
| | 67 | % | | 2000 | | 2019-2020 | | Various |
| AES Gener Subtotal | | | | | | 5,115 |
| | | | | | | | |
| Alicura | | Argentina | | Hydro | | 1,050 |
| | 100 | % | | 2000 | |
| | Various |
| Paraná-GT | | Argentina | | Gas/Diesel | | 870 |
| | 100 | % | | 2001 | |
| |
|
| San Nicolás | | Argentina | | Coal/Gas/Oil | | 675 |
| | 100 | % | | 1993 | |
| |
|
Guillermo Brown (4) | | Argentina | | Gas/Diesel | | 576 |
| | — | % | | 2016 | | | | |
Los Caracoles (4) | | Argentina | | Hydro | | 125 |
| | — | % | | 2009 | | 2019 | | Energia Provincial Sociedad del Estado (EPSE) |
| Cabra Corral | | Argentina | | Hydro | | 102 |
| | 100 | % | | 1995 | |
| | Various |
| Ullum | | Argentina | | Hydro | | 45 |
| | 100 | % | | 1996 | |
| | Various |
| Sarmiento | | Argentina | | Gas/Diesel | | 33 |
| | 100 | % | | 1996 | |
| |
|
| El Tunal | | Argentina | | Hydro | | 10 |
| | 100 | % | | 1995 | |
| | Various |
| Argentina Subtotal | | | | | | 3,486 |
| | | | | | | | |
Tietê (5) | | Brazil | | Hydro | | 2,658 |
| | 24 | % | | 1999 | | 2029 | | Various |
| Alto Sertão II | | Brazil | | Wind | | 386 |
| | 24 | % | | 2017 | | 2033-2035 | | Various |
| Guaimbe | | Brazil | | Solar | | 150 |
| | 24 | % | | 2018 | | 2037 | | CCEE |
| Tietê Subtotal | | | | | | 3,194 |
| | | | | | | | |
| Uruguaiana | | Brazil | | Gas | | 640 |
| | 46 | % | | 2000 | | | | |
| Brazil Subtotal | | | | | | 3,834 |
| | | | | | | | |
| | | | | | | 12,435 |
| | | | | | | | |
_____________________________
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(1) | Gener - Chile plants: Alfalfal, Andes Solar, Laguna Verde, Laguna Verde Turbogas, Laja, Maitenes, Norgener 1, Norgener 2, Queltehues, Ventanas 1, Ventanas 2, Ventanas 3, Ventanas 4 and Volcán. |
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(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%. |
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(3) | TermoAndes is located in Argentina, but is connected to both the SEN in Chile and the SADI in Argentina. |
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(4) | AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses. |
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(5) | Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mog-Guaçu, Nova Avanhandava, Promissão, Sao Joaquim and Sao Jose. |
Under construction — The following table lists our plants (3%).under construction in the South America SBU:
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| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| Boa Hora | | Brazil | | Solar | | 69 |
| | 24 | % | | 1H 2019 |
| AGV Solar | | Brazil | | Solar | | 75 |
| | 24 | % | | 1H 2019 |
| Energetica | | Argentina | | Wind | | 100 |
| | 100 | % | | 1H 2020 |
| Vientos Nequinos | | Argentina | | Wind | | 80 |
| | 100 | % | | 1H 2020 |
| Alto Maipo | | Chile | | Hydro | | 531 |
| | 62 | % | | 2H 2020 |
| | | | | | | 855 |
| | | | |
In June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo, a distribution business in Brazil. Prior to its sale, Eletropaulo was accounted for as an equity method investment and its results of operations and financial position were reported as discontinued operations in the consolidated financial statements for all periods presented.
The following map illustrates the location of our South America facilities:
South America Businesses
Chile
Market Structure and Regulatory Framework — The regulatory framework in the Dominican Republic consists of a decentralizedChilean electricity industry includingis divided into three business segments: generation, transmission and distribution, where generationdistribution. Private companies operate in all three segments, and generators can earn revenue through short-enter into PPAs to sell energy to regulated and long-term PPAs, ancillary services andunregulated customers, as well as to other generators in the spot market.
Chile has operated a competitive wholesale generation market. All electric companies (generators, transmission and distributors), are subjectsingle power market, referred to and regulatedas the SEN, which has been managed by the General Electricity Law.grid operator CEN since November 2017. Previously, Chile had two main power systems, the SIC and SING, largely as a result of its geographic shape and size, which were merged to form the SEN. The SEN has an installed capacity
Two main agencies
of approximately 24,586 MW. SEN represents 99% of the installed generation capacity of the country.
CEN coordinates all generation and transmission companies in the SEN. CEN minimizes the operating costs of the electricity system, while maximizing service quality and reliability requirements. CEN dispatches plants in merit order based on their variable cost of production, allowing for electricity to be supplied at the lowest available cost. In the south-central region of the SEN (former SIC), thermoelectric generation is required to fulfill demand not satisfied by hydroelectric, solar and wind output and is critical to provide reliable and dependable electricity supply under dry hydrological conditions. In the northern region of the SEN (former SING), which includes the Atacama Desert, thermoelectric capacity represents the majority of installed capacity as hydroelectric generation is not feasible. The fuels used for thermoelectric generation, mainly coal, diesel and LNG, are responsibleindexed to international prices. In 2018, the generation installed capacity in the Chilean market was composed of the following:
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| | | |
| Installed Capacity | | | SEN |
| Thermoelectric | | | 54% |
| Hydroelectric | | | 27% |
| Solar | | | 10% |
| Wind | | | 7% |
| Other | | | 2% |
Hydroelectric plants represent a significant portion of the system's installed capacity. Hydrological conditions influence reservoir water levels, which in turn affects dispatch of the system's hydroelectric and thermoelectric generation plants, thereby influencing spot market prices. Precipitation and snow melt impact hydrological conditions in Chile. Rains occurs principally between June and August and are scarce during the remainder of the year. Snow melt occurs between September and November.
The Ministry of Energy has primary responsibility for monitoring and ensuring compliance with the General Electricity Law,Chilean electricity system directly or through the National Energy Commission and the SuperintendenceSuperintendency of Electricity.Electricity and Fuels.
In July 2016, modifications to the Transmission Law were enacted. This law establishes that the transmission system will be completely paid for by the end-users, gradually allocating the costs on the demand side from 2019 through 2034.
All generators can sell energy through contracts with regulated distribution companies or directly to unregulated customers. Unregulated customers are customers whose connected capacity is higher than 5 MW. Customers with connected capacity between 0.5 MW and 5.0 MW can opt for regulated or unregulated contracts for a minimum period of four years. By law, both regulated and unregulated customers are required to purchase all electricity under contracts. Generators may also sell energy to other power generation companies on a short-term basis at negotiated prices outside the spot market. Electricity prices in Chile are denominated in U.S. dollars, although payments are made in Chilean pesos.
Business Description — In Chile, through AES Gener, we are engaged in the generation and supply of electricity (energy and capacity) in the SEN. AES Gener is the second largest generation operator in Chile in terms of installed capacity with 3,400 MW, excluding energy storage , and has a market share of approximately 14% as of December 31, 2018.
AES Gener owns a diversified generation portfolio in Chile in terms of geography, technology, customers and fuel source. AES Gener's plants are located near the principal electricity consumption centers, including Santiago, Valparaiso and Antofagasta. AES Gener's diverse generation portfolio provides flexibility for the management of contractual obligations with regulated and unregulated customers, provides backup energy to the spot market and facilitates operations under a variety of market and hydrological conditions.
Our commercial strategy in Chile aims to maximize margin while reducing cash flow volatility. To achieve this, we contract a significant portion of our coal and hydroelectric baseload capacity under long-term agreements with a diversified customer base. Power plants not considered within our baseload capacity (higher variable cost units, mainly diesel) sell energy on the spot market when operating during scarce system supply conditions, such as low hydrology and/or plant outages. In Chile, sales on the spot market are made only to other generation companies who are members of the SEN at the system marginal cost.
AES Gener currently has long-term contracts, with an average remaining term of approximately 11 years, with regulated distribution companies and unregulated customers, such as mining and industrial companies. In general, these long-term contracts include pass-through mechanisms for fuel costs along with price indexations to US CPI.
In addition to energy payments, AES Gener also receives capacity payments to compensate for availability during periods of peak demand. CEN annually determines the capacity requirements for each power plant. The
capacity price is fixed semiannually by the National Energy Commission and indexed to the CPI and other relevant indices.
Environmental Regulation — During 2017 and 2016, the Ministry of Environment under the previous administration updated the Atmospheric Decontamination Plan for the Ventanas and Huasco regions. Under that proposed plan, no significant investments were needed to comply with new requirements at our plants Ventanas and Guacolda. However, the authority under the current administration rejected that proposed plan on December 30, 2017. In December 2018, a new decontamination plan for the Ventanas and Huasco regions was proposed by the authority under the current administration. Currently, the Environmental Ministry expects approval of the new decontamination plan in early March 2019 and we are currently assessing the impact of the new proposed decontamination plan.
Chilean law requires all electricity generators to supply a certain portion of their total contractual obligations with NCREs. Generation companies are able to meet this requirement by building NCRE generation capacity (wind, solar, biomass, geothermal and small hydroelectric technology) or purchasing NCREs from qualified generators. Non-compliance with the NCRE requirements will result in fines. AES Gener currently fulfills the NCRE requirements by utilizing AES Gener's solar and biomass power plants and by purchasing NCREs from other generation companies. At present, AES Gener is in chargethe process of draftingnegotiating additional NCRE supply contracts to meet the future requirements.
In September 2014, a new emission tax, or green tax, was enacted effective January 2017. Emissions of PM, SO2, NOx and coordinatingCO2 are monitored for plants with an installed capacity over 50 MW; these emissions are taxed. In the legal framework and regulatory legislation, proposing and adopting policies and procedurescase of CO2, the tax will be equivalent to assure best practices, drafting plans$5 per ton emitted. PPAs originating from the SING have clauses allowing the Company to ensurepass the proper functioning and developmentgreen tax costs to unregulated customers. Distribution PPAs originating from the SIC do not allow for the pass through of the energy sector and promoting investment. The Superintendence of Electricity's main responsibilities include monitoring and supervising compliance with legal provisions and rules, monitoring compliance with the technical procedures governing generation, transmission, distribution and commercialization of electricity and supervising electric market behavior in order to avoid monopolistic practices.these costs.
The electricity tariff applicable to regulated customers is subject to regulation within the concessions of the distribution companies. Clients with demand above 1 MW are classified as unregulated customers and their tariffs are unregulated.
Fuels and hydrocarbons are regulated by a specific law which establishes prices to end customers and a tax on consumption of fossil fuels. For natural gas there are regulations related to the procedures to be followed to grant licenses and concessions: i) distribution, including loading, transportation and compression plants; ii) the installation and operation of natural gas stations, including consumers and potential modifications of existing facilities; and iii) conversion equipment suppliers for vehicles. The regulation is administered by the Industrial and Commerce Ministry who supervises commercial and industrial activities in the Dominican Republic as well as the fuels and natural gas commercialization to the end users.
Key Financial Drivers — FinancialHedge levels at AES Gener limit volatility to the underlying financial drivers. In addition, financial results are likely to be driven by many factors, including, but not limited to:
Changesdry hydrology scenarios;
forced outages;
changes in spot prices duecurrent regulatory rulings altering the ability to fluctuations in commodity prices, (since fuel is a pass-through cost under the PPAs, any variation in oil prices will impact the spot sales for both Andres and Itabo)pass through or recover certain costs;
Contracting levels and the extent of capacity awarded
Supply shortages in the near term (next two to three years) may provide opportunities for short term upside, but new generation is expected to come online beginning 2018
Additional sales derived from domestic natural gas demand are expected to continue providing income and growth based on the entry of future projects and the fees from the infrastructure service.
In addition, the financial weaknessfluctuations of the three state-owned distribution companies due to low collection ratesChilean peso (our hedging strategy reduces this risk, but some residual risk remains);
tax policy changes;
legislation promoting renewable energy and/or more restrictive regulations on thermal generation assets; and high levels of non-technical losses has led to delays in payments for the electricity supplied by generators. At times
market price risk when outstanding receivable balances have accumulated, AES Dominicana has accepted payment through other means, such as government bonds, in order to reduce the balance. There can be no guarantee that alternative collection methodologies will always be an avenue available for payment options.re-contracting.
Construction and Development — DPPAES Gener continues to advance the construction of the 531 MW Alto Maipo run-of-the-river hydroelectric plant. Alto Maipo is converting its existing plant from open cycle to combined cycle. Thethe largest project will recycle DPP's heat emissions and increase total power output by approximately 114 MW of gross capacity at an estimated cost of $260 million, fully financed with non-recourse debt. The EPC contract was signed on July 2, 2014, and the additional capacity is expected to become operationalin construction in the first halfSEN market. When completed, it will include 75 km of 2017. Based ontunnels, two power houses and 17 km of transmission lines. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Alto Maipo. Colombia
Regulatory Framework and Market Structure — Electricity supply in Colombia is concentrated in one main system, the increasedSIN, which encompasses one-third of Colombia's territory, providing electricity to 97% of the country's population. The SIN's installed capacity, AES Dominicana executed a PPA for 270 MW for a 6.5 year term beginning in 2017.
Panama
Business Description — AES owns and operates fiveprimarily hydroelectric plants and one thermoelectric power plant, Estrella del Mar I, which commenced operations in March 2015, representing 705 MW and 72 MW of hydro(68%) and thermal capacity respectively, for a total(31%), totaled 17,392 MW as of 777 MW equivalent to 23% of the installed capacityDecember 31, 2018. The marked seasonal variations in Panama. The majority of hydro sourcesColombia's hydrology result in Panama are based on run-of-river technology, with the exception of the 260 MW Bayano plant.
A portion of the PPAs with distribution companies will expire in December 2018 reducing the total contracted capacity of the company from 496 MW to 430 MW. Another portion contracted through Estrella del Mar I will expire in June 2020, reducing the total contracted capacity to 350 MW until December 2030.
Market Structure — Panama's current total installed capacity is 3,350 MW, of which 52% is hydroelectric, 8% wind, 2% solar and the remaining 38% thermal generation from diesel, bunker fuel and coal.
The Panamanian power sector is composed of three distinct operating business units: generation, distribution and transmission, all of which are governed by Electric Law 6 enacted in 1997.
Generators can enter into long-term PPAs with distributors or unregulated consumers. In addition, generators can enter into alternative supply contracts with each other. Outside of the PPA market, generators may buy and sell energyprice volatility in the short-term market. In 2018, 84% of total energy demand was supplied by hydroelectric plants.
The electricity sector in Colombia operates under a competitive market framework for the generation and sale of electricity, and a regulated framework for transmission and distribution of electricity. The distinct activities of the electricity sector are governed by Colombian laws and the CREG, regulating entity for energy and gas. Other government entities have a role in the electricity industry, including the Ministry of Mines and Energy, which defines the government's policy for the energy sector; the Public Utility Superintendency of Colombia, which is in charge of overseeing utility companies; and the Mining and Energetic Planning Unit, which is in charge of expansion of the generation and transmission network.
The generation sector is organized on a competitive basis with companies selling their generation in the wholesale market at the short-term price or under bilateral contracts with other participants, including distribution
companies, generators and traders, and unregulated customers at freely negotiated prices. The National Dispatch Center implementsdispatches generators in merit order based on bid offers in order to ensure that demand will be satisfied by the economic dispatchlowest cost combination of electricityavailable generating units.
In 2018, the Ministry of Mines and Energy published the final resolution for renewable energy auctions in Colombia. The auction allocates 12-year energy contracts for 1.1 TW/h of energy demand under which renewable generators commit to be in commercial operation by December 2021. The auction is scheduled for February 2019 and the wholesale market. The National Dispatch Center's objectives areregulator expects to minimizeadopt the total costcurrent regulation for the entry of renewable generation to the market during 2019.
Business Description — We operate in Colombia through AES Chivor, a subsidiary of AES Gener, which owns a hydroelectric plant with an installed capacity of 1,000 MW, and Tunjita, a 20 MW run-of-river hydroelectric plant, both located approximately 160 km east of Bogota. AES Chivor’s installed capacity accounted for approximately 6% of system capacity at the end of 2018. AES Chivor is dependent on hydrological conditions, which influence generation and maintain the reliabilityspot prices of non-contracted generation in Colombia.
AES Chivor's commercial strategy aims to execute contracts with commercial and security of the electric power system, taking into account the price of water, which determines the dispatch of hydro plantsindustrial customers, and bid in public tenders for one to four year contracts, mainly with reservoirs. Short-term power prices are determined on an hourly basisdistribution companies to reduce margin volatility with proper portfolio risk management. The remaining energy generated by the last dispatched generating unit.
In Panama, dry hydrological conditions remained until June 2016, dueour portfolio is sold to the presence of the El Niño phenomenon, affecting the generation output from hydroelectric facilities compared to the prior year. AES Panama had to purchase energy on the spot market, including ancillary services. Additionally, AES Chivor receives reliability payments for maintaining the plant available during periods of power scarcity, such as adverse hydrological conditions, in order to fulfill its contract obligations as its generation output was below contract levels. The drop in the commodities prices helped to reduce the replacement cost and the financial impact of spot purchases compared to the prior year. Despite the hydrology conditions, spot prices were down to $60/MWh from $91/MWh in 2015, limiting the amount recognized through the 2014-2016 Government Compensation Agreement to $1 million out of the possible $30 million for 2016. On March 31, 2014, the government of Panama agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70 MW reduction in contracted capacity for the period 2014-2016 by compensating AES Panama for spot purchases above the contracted price of $82.45/MWh, up to $40 million in 2014, $30 million in 2015 and $30 million in 2016.prevent power shortages.
Regulatory Framework — 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 promote the procurement of electrical energy, hydrocarbons and alternative energy 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 and the transmission and distribution of natural gas utilities and the companies that provide such services.
Generators can only contract up to their firm capacity. Physical generation of energy is determined by the National Dispatch Center regardless of contractual arrangements.
Key Financial Drivers — FinancialHydrological conditions largely influence Chivor's power generation. Maintaining the appropriate contract level, while maximizing revenue through the sale of excess generation, is key to Chivor's results of operations. Hedge levels at Chivor limit volatility in the underlying financial drivers. In addition to hydrology, financial results are likely to be driven by many factors, including, but not limited to:
In the event of low hydrology, high commodity prices will increase the business exposure and the cost of replacement power to fulfill our contractual commitments, partially mitigated by additional generation from Estrella del Mar I.forced outages;
Fluctuations in commodity prices, mainly oil prices, affect the thermal generation cost impacting the spot prices and the opportunity cost of water.
Constraints imposed by the capacityfluctuations of the transmission line connectingColombian peso; and
spot market prices.
Argentina
Regulatory Framework and Market Structure — Argentina has one main power system, the west sideSADI, which serves 96% of the country with the load center are expected to continue until the end of 2017 keeping surplus power trapped, particularly during the wet season.
Country demand as GDP growth is expected to remain strong over the short and medium term.
Given that most of AES' portfolio is run-of-river, hydrological conditions have an important influence on its profitability. Variations in actual hydrology can result in excess or a short energy balance relative to our contract obligations. During the low inflow period of January through May, generation tends to be lower and AES Panama may purchase energy in the short-term market to cover contractual obligations. During the remainder of the year (June to December), generation tends to be higher and energy generated in excess of contract volumes is sold to the short-term market. In addition to hydrological conditions, commodity prices affect short-term electricity prices.
Construction and Development — Continuing with the strategy to reduce reliance on hydrology started with the acquisition of the power barge, Estrella del Mar I, in August 2015 AES executed a partnership agreement with Deeplight Corporation, a minority partner, with the purpose to construct, operate and maintain a natural gas power generation plant and a liquefied natural gas terminal, in order to purchase and sell energy and capacity as well as commercialize natural gas and other ancillary activities related to natural gas.country. As of December 31, 2016, amounts capitalized include $254 million recorded2018, the installed capacity of the SADI totaled 38,538 MW. The SADI's installed capacity is composed primarily of thermoelectric generation (64%) and hydroelectric generation (28%).
Thermoelectric generation in Constructionthe SADI is primarily natural gas. However, scarcity of natural gas during winter periods (June to August), result in Progressthe use of alternative fuels, such as oil and coal. The SADI is also highly reliant on hydroelectric plants. Hydrological conditions impact reservoir water levels and largely influence the dispatch of the system's hydroelectric and thermoelectric generation plants and, therefore, influence market costs. Precipitation in Argentina occurs principally between June and August.
Regulatory Framework — The Argentine regulatory framework divides the electricity sector into generation, transmission and distribution. The wholesale electric market is comprised of generation companies, transmission companies, distribution companies and large customers who are permitted to trade electricity. Generation companies can sell their output in the spot market or under PPAs. CAMMESA manages the electricity market and is responsible for dispatch coordination. The Electricity National Regulatory Agency is in charge of regulating public service activities and the projectSecretariat of Energy regulates system framework and grants concessions or authorizations for sector activities. In Argentina, the regulator establishes the prices for electricity and fuel and adjusts them periodically for inflation, changes in fuel prices and other factors. As a result, our businesses are particularly sensitive to changes in regulation.
The Argentine electric market is scheduledan "average cost" system, with generators being compensated for fixed costs and non-fuel variable costs plus a rate of return. All fuel, except coal, can be provided by CAMMESA. In December 2018, Resolution 70/2018 was enacted. This allows generation companies to initiate operationsbuy fuel directly from producers or from CAMMESA.
Argentina’s administration continues introducing regulatory improvements aiming to normalize the energy sector. Among others, Resolution 19/2017 was enacted in 2017 to set higher tariffs, denominated in USD, for energy and capacity prices. The enactment of resolution 19/2017 ceased the first half remuneration intended to fund increased capacity projects . Likewise, long term USD-denominated PPAs have been awarded to develop 9.4 GW
of 2018.new capacity (thermal and renewable) through the execution of competitive auctions. During 2018, the government has continued to increase end user prices to reduce subsidies and decrease system deficit.
MexicoAES Argentina has contributed certain accounts receivable to fund the construction of new power plants under FONINVEMEM agreements. These receivables accrue interest and are collected in monthly installments over 10 years once the related plants begin to operate. AES Argentina has three FONINVEMEM funds related to operational plants under which payments are being received. AES Argentina will receive a pro rata ownership interest in these plants once the accounts receivables have been fully repaid. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Long-Term Receivables and Note 6.—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-Kfor further discussion of receivables in Argentina.Business Description — As of December 31, 2018, AES has 1,055operates plants totaling 4,129 MW, representing 11% of the country's total installed capacity. The installed capacity in Mexico, including the 550 MW Termoeléctrica del Golfo ("TEG") and Termoeléctrica Peñoles ("TEP") facilities and Merida III ("Merida"),SADI includes the TermoAndes plant, a 505 MW generation facility.
The TEG and TEP pet coke-fired plants, located in San Luis Potosi, supply power to their offtakers under long-term PPAs expiring in 2027 with a 90% availability guarantee. TEG and TEP secure their fuel under a long-term contract.
Meridasubsidiary of AES Gener, which is a CCGT, located in Merida, on Mexico's Yucatan Peninsula. Merida sells powerconnected both to the Federal Commission of Electricity ("CFE") under a capacitySADI and energy based long-term PPA through 2025. Additionally, the plant purchases natural gas and diesel fuel under a long-term contract, the cost of which is then passed through to CFE under the terms of the PPA.
In line with AES' strategy of building strategic partnerships, on January 18, 2016 the 50/50 joint venture partnership agreement with Grupo BAL was fully executed. The joint venture will co-invest in power and related infrastructure projects in Mexico.
Market Structure — MexicoChilean SEN markets. AES Argentina has a single national electricity grid, the National Power System, covering nearly all of Mexico's territory. Mexico has an installed capacity totaling 68 GW with adiversified generation mix of 72% thermal, 18% hydroelectric and 10% other. Electricity consumption is split between the following end users: industrial of 58%, residential of 26% and commercial and service of 16%.portfolio.
Regulatory Framework —Following the constitutional changes approvedAES primarily sells its energy in December 2013, during 2014 and 2015 the Mexican government issued a package of secondary regulations, including the Electricity Law, and operational dispositions, with the objective to start the implementation of a new regulatory framework with the following characteristics:
The energy market liberalization in January 2016 through the implementation of: wholesale electricity market (day ahead and real time market), ancillary services, capacity, Clean Energy Certificates, and Financial Transmission Rights market.
CFE's, former state-owned electric monopoly, vertical and horizontal disintegration into different segments of the value chain: generation, transmission, distribution and commercialization.
CENACE as new ISO is responsible for managing the wholesale electricity market transmissionwhere prices are largely regulated. In 2018, approximately 93% of the energy was sold in the wholesale electricity market and distribution infrastructure, planning7% was sold under contract, as a result of contract sales made by TermoAndes.
Foreign currency controls were lifted in December 2015, allowing the network developments, guaranteeing open accessArgentine peso to network infrastructure, executing competitive mechanisms to cover regulated demand, and setting transmission charges.
Implementation of annual mid and long term auctions to secure supply for the regulated demand, establishing a PPA with CFE as the Basic Supplier.
According to the new regulatory framework, new assets developedfloat under the new framework or assets transferred to the new regime and in operation after the approvaladministration of the ElectricityArgentinian Central Bank. In 2018, the Argentine peso devalued by approximately 102% and Argentina’s economy was determined to be highly inflationary. See Item 7.—Management's Discussion and Analysis Key Trends and Uncertainties of this Form 10-K for further discussion.
Tax Regulation — On December 29, 2017, Law (August 2014) are eligible to participate27430 was enacted in Argentina, which introduced a tax reform with several changes in the new markets. Additionally, projects developedArgentine tax system, effective on January 1, 2018. This tax reform reduced the statutory corporate tax rate of companies from 35% to 30% in 2018 and operated under2019, and will reduce the Electric Public Service Lawrate to 25% from 2020 onward. The law also eliminated the Equalization Tax on the distribution of earnings generated after January 1, 2018. The Equalization Tax was replaced with a withholding tax on dividends at the rate of 7% for 2018 and 2019, and 13% from 2020 onward.
(self-supply framework) like TEG/TEP, could choose to participate. Until the new framework is further analyzed, AES will continue operating under the same conditions. Merida III and TEG/TEP will continue providing power under long-term contracts and selling any excess or surplus energy produced to CFE.
Key Financial Drivers — Financial results are likely to be driven by many factors, including, but not limited to:
Operational performance (asforced outages;
exposure to fluctuations of the Argentine peso;
changes in hydrology;
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| • | timely collection of FONINVEMEM installment and outstanding receivables (See Note 6.—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion); and |
natural gas prices and availability for contracted generation.
Brazil
Regulatory Framework and Market Structure — In Brazil, the Ministry of Mines and Energy determines the maximum amount of energy a generation plant can sell, called physical guarantee, representing the long-term average expected energy production of the plant. Under current rules, physical guarantee energy can be sold to distribution companies through long-term regulated auctions or under unregulated bilateral contracts with large consumers or energy trading companies.
Brazil has installed capacity of 162,932 MW, which is primarily hydroelectric (64%) and renewables (19%). Operation is centralized and controlled by the national operator, ONS, and regulated by ANEEL. The ONS dispatches generators based on their marginal cost of production and on the risk of system rationing. Key variables for the dispatch decision are forecasted hydrological conditions, reservoir levels, electricity demand, fuel prices and thermal generation availability.
In case of unfavorable hydrology, the ONS will reduce hydroelectric dispatch to preserve reservoir levels and increase dispatch of thermal plants to meet demand. The consequences of unfavorable hydrology are (i) higher energy spot prices due to higher energy production costs by thermal plants and (ii) the need for hydro plants to purchase energy in the spot market to fulfill their contractual obligations.
A mechanism known as the MRE was created under ONS to share hydrological risk across MRE hydro generators. If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may
need to purchase energy in the short-term market. When total hydro generation is higher than the total MRE physical guarantee, the surplus is proportionally shared among its participants and they may sell the excess energy on the spot market.
Business Description — Tietê has a portfolio of 12 hydroelectric power plants in the state of São Paulo with total installed capacity of 2,658 MW. Tietê represents approximately 10% of the total generation capacity in the state of São Paulo. Tietê hydroelectric plants operate under a 30-year concession expiring in 2029. AES owns 24% of Tietê and is the controlling shareholder and manages and consolidates this business. Tietê aims to contract most of its physical guarantee requirements and sell the remaining portion in the spot market. The commercial strategy is reassessed periodically according to changes in market conditions, hydrology and other factors. Tietê generally sells available energy through medium-term bilateral contracts.
Tietê's strategy is to grow by adding renewable capacity to its generation platform. In 2017, Tietê acquired Alto Sertão II Wind Complex (“Alto Sertão II”) located in the state of Bahia, with an installed capacity of 386 MW and subject to 20-year PPAs expiring between 2033 and 2035. Furthermore, in 2017 Tiete acquired Boa Hora Solar, a solar development project and won a bid to develop a second solar project, AGV Solar, in the state of São Paulo. In 2018, Tietê acquired Guaimbê, a solar power complex. All the solar assets are fully contracted with 20 year PPAs. Through its ownership of Tietê, AES owns a 24% economic interest in those entities. These assets are not subject to return at the end of the concession.
Under the concession agreement, Tietê is required to increase its capacity in the state of São Paulo by 15% (or 398 MW). The above mentioned investments in new solar generation capacity in the state of São Paulo allowed Tietê to sign a legal agreement in October 2018 with the state government in which it was agreed that: (i) 80% of the expansion obligation (317 MW) was delivered or is in performance stage; and better performance provides additional financial benefits including performance incentives and/or excess energy sales (in(ii) the case of TEG/TEP)Company will have up to six years from the agreement's approval date to meet the remaining balance (81 MW).
Uruguaiana is a 640 MW gas-fired combined cycle power plant located in the town of Uruguaiana in the state of Rio Grande do Sul. AES manages and has a 46% economic interest in the plant. The energy pricesplant's operations have been largely suspended due to the unavailability of TEG/TEPgas. The plant operated for short periods of time in 2013, 2014 and 2015 when short-term supply of LNG was sourced for the salesfacility. The plant did not operate in excess over its2016, 2017 or 2018. AES has evaluated several alternatives to bring gas supply on a competitive basis to Uruguaiana. Capacity restrictions on the Argentinean pipeline are a challenge, especially during the winter season when gas demand in Argentina is very high. Uruguaiana continues to work toward securing gas on a long-term contracts are driven bybasis.
Key Financial Drivers — As the average production cost of CFE whichsystem is highly dependent on naturalhydroelectric generation, electricity pricing is driven by hydrology in Brazil. Plant availability is also a significant financial driver as in times of high hydrology AES is more exposed to the spot market. The availability of gas is also a driver for continued operations at Uruguaiana. Tietê's financial results are driven by many factors, including, but not limited to:
hydrology, impacting quantity of energy generated in MRE;
demand growth;
re-contracting price;
asset management and oil.plant availability;
Ifcost management; and
ability to execute on its growth strategy.
Construction and Development — As part of the average production costinitiative to pursue opportunities in renewable generation discussed above, Tietê is currently constructing photovoltaic power plants with a total projected capacity of CFE144 MW, subject to 20 year PPAs. Commercial operation of first phase, Boa Hora Solar, and of the second phase, AGV Solar, is higher thanexpected in the costfirst half of generating with pet coke, our businesses in Mexico will benefit provided that they are able to sell2019.
MCAC SBU
Our MCAC SBU has a portfolio of generation facilities, including renewable energy, in excessthree countries, with a total capacity of their PPAs.3,205 MW as of December 31, 2018.
Generation — The following table lists our MCAC SBU generation facilities:
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| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| DPP (Los Mina) | | Dominican Republic | | Gas | | 358 |
| | 85 | % | | 1996 | | 2022 | | CDEEE |
| Andres | | Dominican Republic | | Gas | | 319 |
| | 85 | % | | 2003 | | 2022 | | Ede Norte/Ede Este/Ede Sur/Non-Regulated Users |
Itabo (1) | | Dominican Republic | | Coal | | 295 |
| | 43 | % | | 2000 | | 2022 | | Ede Norte/Ede Este/Ede Sur |
| Andres ES | | Dominican Republic | | Energy Storage | | 10 |
| | 85 | % | | 2017 | | | | |
| Los Mina DPP ES | | Dominican Republic | | Energy Storage | | 10 |
| | 85 | % | | 2017 | | | | |
| Dominican Republic Subtotal | | | | | | 992 |
| | | | | | | | |
| Merida III | | Mexico | | Gas | | 505 |
| | 75 | % | | 2000 | | 2025 | | Comision Federal de Electricidad |
| Termoelectrica del Golfo (TEG) | | Mexico | | Pet Coke | | 275 |
| | 99 | % | | 2007 | | 2027 | | CEMEX |
| Termoelectrica del Penoles (TEP) | | Mexico | | Pet Coke | | 275 |
| | 99 | % | | 2007 | | 2027 | | Penoles |
| Mexico Subtotal | | | | | | 1,055 |
| | | | | | | | |
Colon (2) | | Panama | | Gas | | 381 |
| | 50 | % | | 2018 | | 2028 | | Electra Noreste/Edemet/Edechi |
| Bayano | | Panama | | Hydro | | 260 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Changuinola | | Panama | | Hydro | | 223 |
| | 90 | % | | 2011 | | 2030 | | AES Panama |
| Chiriqui-Esti | | Panama | | Hydro | | 120 |
| | 49 | % | | 2003 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Estrella del Mar I | | Panama | | Heavy Fuel Oil | | 72 |
| | 49 | % | | 2015 | | 2020 | | Electra Noreste/Edemet/Edechi/Other |
| Chiriqui-Los Valles | | Panama | | Hydro | | 54 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Chiriqui-La Estrella | | Panama | | Hydro | | 48 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Panama Subtotal | | | | | | 1,158 |
| | | | | | | | |
| | | | | | | 3,205 |
| | | | | | | | |
_____________________________
| |
(1) | Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine). |
| |
(2) | Plant also includes an adjacent regasification facility, as well as a 180,000 m3 LNG storage tank, which is expected to come on-line in 2019. |
Under construction — The following table lists our plants under construction in the MCAC SBU:
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| Mesa La Paz | | Mexico | | Wind | | 306 |
| | 50 | % | | 1H 2020 |
The following map illustrates the location of our MCAC facilities:
MCAC Businesses
Puerto Rico
Regulatory Framework and Market Structure — Puerto Rico has a single electric grid managed by PREPA, a state-owned entity that supplies virtually all of the electric power consumed in Puerto Rico and generates, transmits and distributes electricity to 1.5 million customers. The Puerto Rico Energy Bureau is the main regulatory body. The bureau approves wholesale and retail rates, sets efficiency and interconnection standards, and oversees PREPA's compliance with Puerto Rico's renewable portfolio standard.
Puerto Rico's electricity is 98% produced by thermal plants (47% from petroleum, 34% from natural gas, 17% from coal).
El Salvador
Business Description Regulatory Framework and Market Structure — AES El Salvador also owns AES Nejapa,Salvador's national electric market is composed of generation, distribution, transmission and marketing businesses, as well as a 6 MW power plant generating electricity with methane gas from a landfill, fully contracted with CAESS. During 2015, AES El Salvador began operations of a AES Moncagua, a 2.5 MW solar facility located in the Eastmarket and system operator and regulatory agencies. The operation of the country, whichtransmission system and the wholesale market is fully contractedbased on production costs with EEO.
a marginal economic model that rewards efficiency and allows investors to have guaranteed profits, while end users receive affordable rates. The energy sector is governed by the General Electricity Law, which establishes two regulatory entities responsible for monitoring its compliance:
The National Energy Council is the highest authority on energy policy and strategy, and the generalcoordinating 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 specific orders are issued by Superintendencia General de Electricidad y Telecomunicacions ("SIGET"). SIGET,Telecommunications regulates the market and sets consumer prices, and, jointly with the distribution companies in El Salvador, completed the tariff reset process in December 2012 and defineddeveloped the tariff calculation applicable from 2018 until 2022.
El Salvador has a national electric grid that interconnects with Guatemala and Honduras. The sector has approximately 1,659 MW of installed capacity, composed primarily of thermal (43%), hydroelectric (34%), geothermal (10%), biomass (9%) and solar (4%) generation plants.
Business Description — AES El Salvador is the majority owner of four of the five distribution companies operating in El Salvador (CAESS, CLESA, EEO and DEUSEM). AES El Salvador's territory covers 79% of the country and accounted for 4,040 GWh of the wholesale market energy purchases during 2018, or about 63% market share.
Construction and Development — As part of the initiative to pursue opportunities in renewable generation, AES El Salvador has entered into a joint venture with Corporacion Multi-Inversiones, a Guatemalan investment group, to develop, construct and operate Bosforo, a 142 MW solar farm. 43 MW of the project were completed in 2018 and are fully operational. 57 MW are under construction and expected to become operational during the first half of 2019 and the remaining 42 MW will start construction in 2019 and are expected to be applicable forcompleted in the five year period 2013-2017.second half of 2019. The energy produced by this project will be contracted directly by AES' utilities in El Salvador.
South America SBU
Generation — Our EuropeSouth America SBU has generation facilities in five countries. four countries — Chile, Colombia, Argentina and Brazil. AES Gener, which owns all of our assets in Chile, Chivor in Colombia and TermoAndes in Argentina, as detailed below, is a publicly traded company in Chile. AES has a 66.7% ownership interest in AES Gener and this business is consolidated in our financial statements. Tietê is a publicly traded company in Brazil. AES controls and consolidates Tietê through its 24% economic interest.
Operating installed capacity of our EuropeSouth America SBU totaled 6,619 MW.totals 12,435 MW, of which 33%, 28%, 8%, and 31% are located in Argentina, Chile, Colombia and Brazil, respectively. The following table lists our EuropeSouth America SBU generation facilities:
|
| | | | | | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| Maritza | | Bulgaria | | Coal | | 690 |
| | 100 | % | | 2011 | | 2026 | | Natsionalna Elektricheska |
| St. Nikola | | Bulgaria | | Wind | | 156 |
| | 89 | % | | 2010 | | 2025 | | Natsionalna Elektricheska |
| Bulgaria Subtotal | | | | | | 846 |
| | | | | | | | |
| Amman East | | Jordan | | Gas | | 381 |
| | 37 | % | | 2009 | | 2033-2034 | | National Electric Power Company |
| IPP4 | | Jordan | | Heavy Fuel Oil/Gas | | 250 |
| | 36 | % | | 2014 | | 2039 | | National Electric Power Company |
| Jordan Subtotal | | | | | | 631 |
| | | | | | | | |
| Ust-Kamenogorsk CHP | | Kazakhstan | | Coal | | 1,398 |
| | 100 | % | | 1997 | | Short-term | | Various |
Shulbinsk HPP (1) | | Kazakhstan | | Hydro | | 702 |
| | — | % | | 1997 | | 2020 | | Titanium Magnesium Kombiant |
| Sogrinsk CHP | | Kazakhstan | | Coal | | 345 |
| | 100 | % | | 1997 | | Short-term | | Various |
Ust-Kamenogorsk HPP (1) | | Kazakhstan | | Hydro | | 331 |
| | — | % | | 1997 | | 2020 | | Titanium Magnesium Kombiant |
| Kazakhstan Subtotal | | | | | | 2,776 |
| | | | | | | | |
Elsta (2) | | Netherlands | | Gas | | 630 |
| | 50 | % | | 1998 | | 2018 | | Dow Benelux/Delta/Nutsbedrijven/Essent Energy |
| Netherlands ES | | Netherlands | | Energy Storage | | 10 |
| | 100 | % | | 2015 | |
| |
|
| Netherlands Subtotal | | | | | | 640 |
| | | | | | | | |
| Ballylumford | | United Kingdom | | Gas | | 1,015 |
| | 100 | % | | 2010 | | 2023 | | Power NI/Single Electricity Market (SEM) |
Kilroot (3) | | United Kingdom | | Coal/Oil | | 701 |
| | 99 | % | | 1992 | |
| | SEM |
| Kilroot ES | | United Kingdom | | Energy Storage | | 10 |
| | 100 | % | | 2015 | |
| |
|
| United Kingdom Subtotal | | | | | | 1,726 |
| | | | | | | | |
| | | | | | | 6,619 |
| | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| Chivor | | Colombia | | Hydro | | 1,000 |
| | 67 | % | | 2000 | | 2019-2026 | | Various |
| Tunjita | | Colombia | | Hydro | | 20 |
| | 67 | % | | 2016 | | | | |
| Colombia Subtotal | | | | | | 1,020 |
| | | | | | | | |
Gener - Chile (1) | | Chile | | Coal/Hydro/Diesel/Solar/Biomass | | 1,532 |
| | 67 | % | | 2000 | | 2019-2040 | | Various |
Guacolda (2) | | Chile | | Coal | | 760 |
| | 33 | % | | 2000 | | 2019-2032 | | Various |
| Electrica Angamos | | Chile | | Coal | | 558 |
| | 67 | % | | 2011 | | 2026-2037 | | Minera Escondida, Minera Spence, Quebrada Blanca |
| Cochrane | | Chile | | Coal | | 550 |
| | 40 | % | | 2016 | | 2030-2037 | | SQM, Sierra Gorda, Quebrada Blanca |
| Cochrane ES | | Chile | | Energy Storage | | 20 |
| | 40 | % | | 2016 | | | | |
| Electrica Angamos ES | | Chile | | Energy Storage | | 20 |
| | 67 | % | | 2011 | |
| |
|
| Norgener ES (Los Andes) | | Chile | | Energy Storage | | 12 |
| | 67 | % | | 2009 | |
| |
|
| Chile Subtotal | | | | | | 3,452 |
| | | | | | | | |
TermoAndes (3) | | Argentina | | Gas/Diesel | | 643 |
| | 67 | % | | 2000 | | 2019-2020 | | Various |
| AES Gener Subtotal | | | | | | 5,115 |
| | | | | | | | |
| Alicura | | Argentina | | Hydro | | 1,050 |
| | 100 | % | | 2000 | |
| | Various |
| Paraná-GT | | Argentina | | Gas/Diesel | | 870 |
| | 100 | % | | 2001 | |
| |
|
| San Nicolás | | Argentina | | Coal/Gas/Oil | | 675 |
| | 100 | % | | 1993 | |
| |
|
Guillermo Brown (4) | | Argentina | | Gas/Diesel | | 576 |
| | — | % | | 2016 | | | | |
Los Caracoles (4) | | Argentina | | Hydro | | 125 |
| | — | % | | 2009 | | 2019 | | Energia Provincial Sociedad del Estado (EPSE) |
| Cabra Corral | | Argentina | | Hydro | | 102 |
| | 100 | % | | 1995 | |
| | Various |
| Ullum | | Argentina | | Hydro | | 45 |
| | 100 | % | | 1996 | |
| | Various |
| Sarmiento | | Argentina | | Gas/Diesel | | 33 |
| | 100 | % | | 1996 | |
| |
|
| El Tunal | | Argentina | | Hydro | | 10 |
| | 100 | % | | 1995 | |
| | Various |
| Argentina Subtotal | | | | | | 3,486 |
| | | | | | | | |
Tietê (5) | | Brazil | | Hydro | | 2,658 |
| | 24 | % | | 1999 | | 2029 | | Various |
| Alto Sertão II | | Brazil | | Wind | | 386 |
| | 24 | % | | 2017 | | 2033-2035 | | Various |
| Guaimbe | | Brazil | | Solar | | 150 |
| | 24 | % | | 2018 | | 2037 | | CCEE |
| Tietê Subtotal | | | | | | 3,194 |
| | | | | | | | |
| Uruguaiana | | Brazil | | Gas | | 640 |
| | 46 | % | | 2000 | | | | |
| Brazil Subtotal | | | | | | 3,834 |
| | | | | | | | |
| | | | | | | 12,435 |
| | | | | | | | |
_____________________________
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(1) | AES operates these facilities under concession agreements until 2017.Gener - Chile plants: Alfalfal, Andes Solar, Laguna Verde, Laguna Verde Turbogas, Laja, Maitenes, Norgener 1, Norgener 2, Queltehues, Ventanas 1, Ventanas 2, Ventanas 3, Ventanas 4 and Volcán. |
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(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%. |
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(3) | TermoAndes is located in Argentina, but is connected to both the SEN in Chile and the SADI in Argentina. |
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(4) | AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses. |
| |
(5) | Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mog-Guaçu, Nova Avanhandava, Promissão, Sao Joaquim and Sao Jose. |
Under construction — The following table lists our plants under construction in the South America SBU:
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| Boa Hora | | Brazil | | Solar | | 69 |
| | 24 | % | | 1H 2019 |
| AGV Solar | | Brazil | | Solar | | 75 |
| | 24 | % | | 1H 2019 |
| Energetica | | Argentina | | Wind | | 100 |
| | 100 | % | | 1H 2020 |
| Vientos Nequinos | | Argentina | | Wind | | 80 |
| | 100 | % | | 1H 2020 |
| Alto Maipo | | Chile | | Hydro | | 531 |
| | 62 | % | | 2H 2020 |
| | | | | | | 855 |
| | | | |
In June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo, a distribution business in Brazil. Prior to its sale, Eletropaulo was accounted for as an equity method investment and its results of operations and financial position were reported as discontinued operations in the consolidated financial statements for all periods presented.
The following map illustrates the location of our South America facilities:
South America Businesses
Chile
Market Structure and Regulatory Framework — The Chilean electricity industry is divided into three business segments: generation, transmission and distribution. Private companies operate in all three segments, and generators can enter into PPAs to sell energy to regulated and unregulated customers, as well as to other generators in the spot market.
Chile has operated a single power market, referred to as the SEN, which has been managed by the grid operator CEN since November 2017. Previously, Chile had two main power systems, the SIC and SING, largely as a result of its geographic shape and size, which were merged to form the SEN. The SEN has an installed capacity
of approximately 24,586 MW. SEN represents 99% of the installed generation capacity of the country.
CEN coordinates all generation and transmission companies in the SEN. CEN minimizes the operating costs of the electricity system, while maximizing service quality and reliability requirements. CEN dispatches plants in merit order based on their variable cost of production, allowing for electricity to be supplied at the lowest available cost. In the south-central region of the SEN (former SIC), thermoelectric generation is required to fulfill demand not satisfied by hydroelectric, solar and wind output and is critical to provide reliable and dependable electricity supply under dry hydrological conditions. In the northern region of the SEN (former SING), which includes the Atacama Desert, thermoelectric capacity represents the majority of installed capacity as hydroelectric generation is not feasible. The fuels used for thermoelectric generation, mainly coal, diesel and LNG, are indexed to international prices. In 2018, the generation installed capacity in the Chilean market was composed of the following:
|
| | | |
| Installed Capacity | | | SEN |
| Thermoelectric | | | 54% |
| Hydroelectric | | | 27% |
| Solar | | | 10% |
| Wind | | | 7% |
| Other | | | 2% |
Hydroelectric plants represent a significant portion of the system's installed capacity. Hydrological conditions influence reservoir water levels, which in turn affects dispatch of the system's hydroelectric and thermoelectric generation plants, thereby influencing spot market prices. Precipitation and snow melt impact hydrological conditions in Chile. Rains occurs principally between June and August and are scarce during the remainder of the year. Snow melt occurs between September and November.
The Ministry of Energy has primary responsibility for the Chilean electricity system directly or through the National Energy Commission and the Superintendency of Electricity and Fuels.
In July 2016, modifications to the Transmission Law were enacted. This law establishes that the transmission system will be completely paid for by the end-users, gradually allocating the costs on the demand side from 2019 through 2034.
All generators can sell energy through contracts with regulated distribution companies or directly to unregulated customers. Unregulated customers are customers whose connected capacity is higher than 5 MW. Customers with connected capacity between 0.5 MW and 5.0 MW can opt for regulated or unregulated contracts for a minimum period of four years. By law, both regulated and unregulated customers are required to purchase all electricity under contracts. Generators may also sell energy to other power generation companies on a short-term basis at negotiated prices outside the spot market. Electricity prices in Chile are denominated in U.S. dollars, although payments are made in Chilean pesos.
Business Description — In Chile, through AES Gener, we are engaged in the generation and supply of electricity (energy and capacity) in the SEN. AES Gener is the second largest generation operator in Chile in terms of installed capacity with 3,400 MW, excluding energy storage , and has a market share of approximately 14% as of December 31, 2018.
AES Gener owns a diversified generation portfolio in Chile in terms of geography, technology, customers and fuel source. AES Gener's plants are located near the principal electricity consumption centers, including Santiago, Valparaiso and Antofagasta. AES Gener's diverse generation portfolio provides flexibility for the management of contractual obligations with regulated and unregulated customers, provides backup energy to the spot market and facilitates operations under a variety of market and hydrological conditions.
Our commercial strategy in Chile aims to maximize margin while reducing cash flow volatility. To achieve this, we contract a significant portion of our coal and hydroelectric baseload capacity under long-term agreements with a diversified customer base. Power plants not considered within our baseload capacity (higher variable cost units, mainly diesel) sell energy on the spot market when operating during scarce system supply conditions, such as low hydrology and/or plant outages. In Chile, sales on the spot market are made only to other generation companies who are members of the SEN at the system marginal cost.
AES Gener currently has long-term contracts, with an average remaining term of approximately 11 years, with regulated distribution companies and unregulated customers, such as mining and industrial companies. In general, these long-term contracts include pass-through mechanisms for fuel costs along with price indexations to US CPI.
In addition to energy payments, AES Gener also receives capacity payments to compensate for availability during periods of peak demand. CEN annually determines the capacity requirements for each power plant. The
capacity price is fixed semiannually by the National Energy Commission and indexed to the CPI and other relevant indices.
Environmental Regulation — During 2017 and 2016, the Ministry of Environment under the previous administration updated the Atmospheric Decontamination Plan for the Ventanas and Huasco regions. Under that proposed plan, no significant investments were needed to comply with new requirements at our plants Ventanas and Guacolda. However, the authority under the current administration rejected that proposed plan on December 30, 2017. In December 2018, a new decontamination plan for the Ventanas and Huasco regions was proposed by the authority under the current administration. Currently, the Environmental Ministry expects approval of the new decontamination plan in early March 2019 and we are currently assessing the impact of the new proposed decontamination plan.
Chilean law requires all electricity generators to supply a certain portion of their total contractual obligations with NCREs. Generation companies are able to meet this requirement by building NCRE generation capacity (wind, solar, biomass, geothermal and small hydroelectric technology) or purchasing NCREs from qualified generators. Non-compliance with the NCRE requirements will result in fines. AES Gener currently fulfills the NCRE requirements by utilizing AES Gener's solar and biomass power plants and by purchasing NCREs from other generation companies. At present, AES Gener is in the process of negotiating additional NCRE supply contracts to meet the future requirements.
In September 2014, a new emission tax, or green tax, was enacted effective January 2017. Emissions of PM, SO2, NOx and CO2 are monitored for plants with an installed capacity over 50 MW; these emissions are taxed. In the case of CO2, the tax will be equivalent to $5 per ton emitted. PPAs originating from the SING have clauses allowing the Company to pass the green tax costs to unregulated customers. Distribution PPAs originating from the SIC do not allow for the pass through of these costs.
Key Financial Drivers —Hedge levels at AES Gener limit volatility to the underlying financial drivers. In addition, financial results are likely to be driven by many factors, including, but not limited to:
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 (our hedging strategy reduces this risk, but some residual risk remains);
tax policy changes;
legislation promoting renewable energy and/or more restrictive regulations on thermal generation assets; and
market price risk when re-contracting.
Colombia
Regulatory Framework and Market Structure — Electricity supply in Colombia is concentrated in one main system, the SIN, which encompasses one-third of Colombia's territory, providing electricity to 97% of the country's population. The SIN's installed capacity, primarily hydroelectric (68%) and thermal (31%), totaled 17,392 MW as of December 31, 2018. The marked seasonal variations in Colombia's hydrology result in price volatility in the short-term market. In 2018, 84% of total energy demand was supplied by hydroelectric plants.
The electricity sector in Colombia operates under a competitive market framework for the generation and sale of electricity, and a regulated framework for transmission and distribution of electricity. The distinct activities of the electricity sector are governed by Colombian laws and the CREG, regulating entity for energy and gas. Other government entities have a role in the electricity industry, including the Ministry of Mines and Energy, which defines the government's policy for the energy sector; the Public Utility Superintendency of Colombia, which is in charge of overseeing utility companies; and the Mining and Energetic Planning Unit, which is in charge of expansion of the generation and transmission network.
The generation sector is organized on a competitive basis with companies selling their generation in the wholesale market at the short-term price or under bilateral contracts with other participants, including distribution
companies, generators and traders, and unregulated customers at freely negotiated prices. The National Dispatch Center dispatches generators in merit order based on bid offers in order to ensure that demand will be satisfied by the lowest cost combination of available generating units.
In 2018, the Ministry of Mines and Energy published the final resolution for renewable energy auctions in Colombia. The auction allocates 12-year energy contracts for 1.1 TW/h of energy demand under which renewable generators commit to be in commercial operation by December 2021. The auction is scheduled for February 2019 and the regulator expects to adopt the current regulation for the entry of renewable generation to the market during 2019.
Business Description — We operate in Colombia through AES Chivor, a subsidiary of AES Gener, which owns a hydroelectric plant with an installed capacity of 1,000 MW, and Tunjita, a 20 MW run-of-river hydroelectric plant, both located approximately 160 km east of Bogota. AES Chivor’s installed capacity accounted for approximately 6% of system capacity at the end of 2018. AES Chivor is dependent on hydrological conditions, which influence generation and spot prices of non-contracted generation in Colombia.
AES Chivor's commercial strategy aims to execute contracts with commercial and industrial customers, and bid in public tenders for one to four year contracts, mainly with distribution companies to reduce margin volatility with proper portfolio risk management. The remaining energy generated by our portfolio is sold to the spot market, including ancillary services. Additionally, AES Chivor receives reliability payments for maintaining the plant available during periods of power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.
Key Financial Drivers — Hydrological conditions largely influence Chivor's power generation. Maintaining the appropriate contract level, while maximizing revenue through the sale of excess generation, is key to Chivor's results of operations. Hedge levels at Chivor limit volatility in the underlying financial drivers. In addition to hydrology, financial results are driven by many factors, including, but not limited to:
forced outages;
fluctuations of the Colombian peso; and
spot market prices.
Argentina
Regulatory Framework and Market Structure — Argentina has one main power system, the SADI, which serves 96% of the country. As of December 31, 2018, the installed capacity of the SADI totaled 38,538 MW. The SADI's installed capacity is composed primarily of thermoelectric generation (64%) and hydroelectric generation (28%).
Thermoelectric generation in the SADI is primarily natural gas. However, scarcity of natural gas during winter periods (June to August), result in the use of alternative fuels, such as oil and coal. The SADI is also highly reliant on hydroelectric plants. Hydrological conditions impact reservoir water levels and largely influence the dispatch of the system's hydroelectric and thermoelectric generation plants and, therefore, influence market costs. Precipitation in Argentina occurs principally between June and August.
Regulatory Framework — The Argentine regulatory framework divides the electricity sector into generation, transmission and distribution. The wholesale electric market is comprised of generation companies, transmission companies, distribution companies and large customers who are permitted to trade electricity. Generation companies can sell their output in the spot market or under PPAs. CAMMESA manages the electricity market and is responsible for dispatch coordination. The Electricity National Regulatory Agency is in charge of regulating public service activities and the Secretariat of Energy regulates system framework and grants concessions or authorizations for sector activities. In Argentina, the regulator establishes the prices for electricity and fuel and adjusts them periodically for inflation, changes in fuel prices and other factors. As a result, our businesses are particularly sensitive to changes in regulation.
The Argentine electric market is an "average cost" system, with generators being compensated for fixed costs and non-fuel variable costs plus a rate of return. All fuel, except coal, can be provided by CAMMESA. In December 2018, Resolution 70/2018 was enacted. This allows generation companies to buy fuel directly from producers or from CAMMESA.
Argentina’s administration continues introducing regulatory improvements aiming to normalize the energy sector. Among others, Resolution 19/2017 was enacted in 2017 to set higher tariffs, denominated in USD, for energy and capacity prices. The enactment of resolution 19/2017 ceased the remuneration intended to fund increased capacity projects . Likewise, long term USD-denominated PPAs have been awarded to develop 9.4 GW
of new capacity (thermal and renewable) through the execution of competitive auctions. During 2018, the government has continued to increase end user prices to reduce subsidies and decrease system deficit.
AES Argentina has contributed certain accounts receivable to fund the construction of new power plants under FONINVEMEM agreements. These receivables accrue interest and are collected in monthly installments over 10 years once the related plants begin to operate. AES Argentina has three FONINVEMEM funds related to operational plants under which payments are being received. AES Argentina will receive a pro rata ownership interest in these plants once the accounts receivables have been fully repaid. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Long-Term Receivables and Note 6.—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-Kfor further discussion of receivables in Argentina. Business Description — As of December 31, 2018, AES operates plants totaling 4,129 MW, representing 11% of the country's total installed capacity. The installed capacity in the SADI includes the TermoAndes plant, a subsidiary of AES Gener, which is connected both to the SADI and the Chilean SEN markets. AES Argentina has a diversified generation portfolio.
AES primarily sells its energy in the wholesale electricity market where prices are largely regulated. In 2018, approximately 93% of the energy was sold in the wholesale electricity market and 7% was sold under contract, as a result of contract sales made by TermoAndes.
Foreign currency controls were lifted in December 2015, allowing the Argentine peso to float under the administration of the Argentinian Central Bank. In 2018, the Argentine peso devalued by approximately 102% and Argentina’s economy was determined to be highly inflationary. See Item 7.—Management's Discussion and Analysis Key Trends and Uncertainties of this Form 10-K for further discussion.
Tax Regulation — On December 29, 2017, Law 27430 was enacted in Argentina, which introduced a tax reform with several changes in the Argentine tax system, effective on January 1, 2018. This tax reform reduced the statutory corporate tax rate of companies from 35% to 30% in 2018 and 2019, and will reduce the rate to 25% from 2020 onward. The law also eliminated the Equalization Tax on the distribution of earnings generated after January 1, 2018. The Equalization Tax was replaced with a withholding tax on dividends at the rate of 7% for 2018 and 2019, and 13% from 2020 onward.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
forced outages;
exposure to fluctuations of the Argentine peso;
changes in hydrology;
| |
| • | timely collection of FONINVEMEM installment and outstanding receivables (See Note 6.—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion); and |
natural gas prices and availability for contracted generation.
Brazil
Regulatory Framework and Market Structure — In Brazil, the Ministry of Mines and Energy determines the maximum amount of energy a generation plant can sell, called physical guarantee, representing the long-term average expected energy production of the plant. Under current rules, physical guarantee energy can be sold to distribution companies through long-term regulated auctions or under unregulated bilateral contracts with large consumers or energy trading companies.
Brazil has installed capacity of 162,932 MW, which is primarily hydroelectric (64%) and renewables (19%). Operation is centralized and controlled by the national operator, ONS, and regulated by ANEEL. The ONS dispatches generators based on their marginal cost of production and on the risk of system rationing. Key variables for the dispatch decision are forecasted hydrological conditions, reservoir levels, electricity demand, fuel prices and thermal generation availability.
In case of unfavorable hydrology, the ONS will reduce hydroelectric dispatch to preserve reservoir levels and increase dispatch of thermal plants to meet demand. The consequences of unfavorable hydrology are (i) higher energy spot prices due to higher energy production costs by thermal plants and (ii) the need for hydro plants to purchase energy in the spot market to fulfill their contractual obligations.
A mechanism known as the MRE was created under ONS to share hydrological risk across MRE hydro generators. If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may
need to purchase energy in the short-term market. When total hydro generation is higher than the total MRE physical guarantee, the surplus is proportionally shared among its participants and they may sell the excess energy on the spot market.
Business Description — Tietê has a portfolio of 12 hydroelectric power plants in the state of São Paulo with total installed capacity of 2,658 MW. Tietê represents approximately 10% of the total generation capacity in the state of São Paulo. Tietê hydroelectric plants operate under a 30-year concession expiring in 2029. AES owns 24% of Tietê and is the controlling shareholder and manages and consolidates this business. Tietê aims to contract most of its physical guarantee requirements and sell the remaining portion in the spot market. The commercial strategy is reassessed periodically according to changes in market conditions, hydrology and other factors. Tietê generally sells available energy through medium-term bilateral contracts.
Tietê's strategy is to grow by adding renewable capacity to its generation platform. In 2017, Tietê acquired Alto Sertão II Wind Complex (“Alto Sertão II”) located in the state of Bahia, with an installed capacity of 386 MW and subject to 20-year PPAs expiring between 2033 and 2035. Furthermore, in 2017 Tiete acquired Boa Hora Solar, a solar development project and won a bid to develop a second solar project, AGV Solar, in the state of São Paulo. In 2018, Tietê acquired Guaimbê, a solar power complex. All the solar assets are fully contracted with 20 year PPAs. Through its ownership of Tietê, AES owns a 24% economic interest in those entities. These assets are not subject to return at the end of the concession.
Under the concession agreement, Tietê is required to increase its capacity in the state of São Paulo by 15% (or 398 MW). The above mentioned investments in new solar generation capacity in the state of São Paulo allowed Tietê to sign a legal agreement in October 2018 with the state government in which it was agreed that: (i) 80% of the expansion obligation (317 MW) was delivered or is in performance stage; and (ii) the Company will have up to six years from the agreement's approval date to meet the remaining balance (81 MW).
Uruguaiana is a 640 MW gas-fired combined cycle power plant located in the town of Uruguaiana in the state of Rio Grande do Sul. AES manages and has a 46% economic interest in the plant. The plant's operations have been largely suspended due to the unavailability of gas. The plant operated for short periods of time in 2013, 2014 and 2015 when short-term supply of LNG was sourced for the facility. The plant did not operate in 2016, 2017 or 2018. AES has evaluated several alternatives to bring gas supply on a competitive basis to Uruguaiana. Capacity restrictions on the Argentinean pipeline are a challenge, especially during the winter season when gas demand in Argentina is very high. Uruguaiana continues to work toward securing gas on a long-term basis.
Key Financial Drivers — As the system is highly dependent on hydroelectric generation, electricity pricing is driven by hydrology in Brazil. Plant availability is also a significant financial driver as in times of high hydrology AES is more exposed to the spot market. The availability of gas is also a driver for continued operations at Uruguaiana. Tietê's financial results are driven by many factors, including, but not limited to:
hydrology, impacting quantity of energy generated in MRE;
demand growth;
re-contracting price;
asset management and plant availability;
cost management; and
ability to execute on its growth strategy.
Construction and Development — As part of the initiative to pursue opportunities in renewable generation discussed above, Tietê is currently constructing photovoltaic power plants with a total projected capacity of 144 MW, subject to 20 year PPAs. Commercial operation of first phase, Boa Hora Solar, and of the second phase, AGV Solar, is expected in the first half of 2019.
MCAC SBU
Our MCAC SBU has a portfolio of generation facilities, including renewable energy, in three countries, with a total capacity of 3,205 MW as of December 31, 2018.
Generation — The following table lists our MCAC SBU generation facilities:
|
| | | | | | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| DPP (Los Mina) | | Dominican Republic | | Gas | | 358 |
| | 85 | % | | 1996 | | 2022 | | CDEEE |
| Andres | | Dominican Republic | | Gas | | 319 |
| | 85 | % | | 2003 | | 2022 | | Ede Norte/Ede Este/Ede Sur/Non-Regulated Users |
Itabo (1) | | Dominican Republic | | Coal | | 295 |
| | 43 | % | | 2000 | | 2022 | | Ede Norte/Ede Este/Ede Sur |
| Andres ES | | Dominican Republic | | Energy Storage | | 10 |
| | 85 | % | | 2017 | | | | |
| Los Mina DPP ES | | Dominican Republic | | Energy Storage | | 10 |
| | 85 | % | | 2017 | | | | |
| Dominican Republic Subtotal | | | | | | 992 |
| | | | | | | | |
| Merida III | | Mexico | | Gas | | 505 |
| | 75 | % | | 2000 | | 2025 | | Comision Federal de Electricidad |
| Termoelectrica del Golfo (TEG) | | Mexico | | Pet Coke | | 275 |
| | 99 | % | | 2007 | | 2027 | | CEMEX |
| Termoelectrica del Penoles (TEP) | | Mexico | | Pet Coke | | 275 |
| | 99 | % | | 2007 | | 2027 | | Penoles |
| Mexico Subtotal | | | | | | 1,055 |
| | | | | | | | |
Colon (2) | | Panama | | Gas | | 381 |
| | 50 | % | | 2018 | | 2028 | | Electra Noreste/Edemet/Edechi |
| Bayano | | Panama | | Hydro | | 260 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Changuinola | | Panama | | Hydro | | 223 |
| | 90 | % | | 2011 | | 2030 | | AES Panama |
| Chiriqui-Esti | | Panama | | Hydro | | 120 |
| | 49 | % | | 2003 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Estrella del Mar I | | Panama | | Heavy Fuel Oil | | 72 |
| | 49 | % | | 2015 | | 2020 | | Electra Noreste/Edemet/Edechi/Other |
| Chiriqui-Los Valles | | Panama | | Hydro | | 54 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Chiriqui-La Estrella | | Panama | | Hydro | | 48 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other |
| Panama Subtotal | | | | | | 1,158 |
| | | | | | | | |
| | | | | | | 3,205 |
| | | | | | | | |
_____________________________
| |
(1) | Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine). |
| |
(2) | Plant also includes an adjacent regasification facility, as well as a 180,000 m3 LNG storage tank, which is expected to come on-line in 2019. |
Under construction — The following table lists our plants under construction in the MCAC SBU:
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| Mesa La Paz | | Mexico | | Wind | | 306 |
| | 50 | % | | 1H 2020 |
The following map illustrates the location of our MCAC facilities:
MCAC Businesses
Dominican Republic
Regulatory Framework and Market Structure — The Dominican Republic energy market is a decentralized industry consisting of generation, transmission and distribution businesses. Generation companies can earn revenue through short- and long-term PPAs, ancillary services, and a competitive wholesale generation market. All generation, transmission and distribution companies are subject to and regulated by the General Electricity Law.
Two main agencies are responsible for monitoring compliance with the General Electricity Law:
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.
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 Industrial and Commerce Ministry supervises commercial and industrial activities in the Dominican Republic as well as the fuels and natural gas commercialization to the end users.
The Dominican Republic has one main interconnected system with approximately 3,800 MW of installed capacity, composed primarily of thermal (78%), hydroelectric (16%), wind (4%) and solar (2%) generation plants/farms.
Business Description — AES Dominicana consists of three operating subsidiaries, Itabo, Andres and Los Mina. With a total of 992 MW of installed capacity, AES has 26% of the system capacity and supplies approximately 40% of energy demand via these generation facilities. 821 MW is mostly contracted until 2022 with government-owned distribution companies and large customers.
AES has a strategic partnership with the Estrella and Linda Groups ("Estrella-Linda"), a consortium of two leading Dominican industrial groups that manage a diversified business portfolio.
Itabo is 42.5% owned by AES. Itabo owns and operates two thermal power generation units with a total of 295 MW of installed capacity.
Andres and Los Mina are owned 85% by AES. Andres has a combined cycle natural gas turbine, an energy storage solution and generation capacity of 329 MW as well as the only LNG import facility in the country, with 160,000 cubic meters of storage capacity. Los Mina has a combined cycle with two natural gas turbines, an energy storage solution and generation capacity of 368 MW.
AES Dominicana has a long-term LNG purchase contract through 2023 for 33.6 trillion btu/year with a price linked to NYMEX Henry Hub. The LNG contract terms allow delivery to various markets in Latin America. These plants capitalize on the competitively-priced LNG contract by selling power where the market is dominated by fuel oil-based generation. Andres has a long-term contract to sell re-gasified LNG to industrial users within the Dominican Republic using compression technology to transport it within the country, thereby capturing demand from industrial and commercial customers.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
changes in spot prices due to fluctuations in commodity prices (since fuel is a pass-through cost under the PPAs, any variation in oil prices will impact the spot sales for both Andres and Itabo);
contracting levels and the extent of capacity awarded;
supply shortages in the near term (next two to three years) may provide opportunities for short term upside, but new generation is expected to come online beginning 2019; and
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.
Panama
Regulatory Framework and Market Structure — The Panamanian power sector is composed of three distinct operating business units: generation, distribution and transmission. Generators can enter into long-term PPAs with distributors or unregulated consumers. In addition, generators can enter into alternative supply contracts with each other. Outside of the PPA market, generators may buy and sell energy in the short-term market. Generators can only contract up to their firm capacity.
Three main agencies are responsible for monitoring compliance with the General Electricity Law:
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.
Panama's current total installed capacity is 3,501 MW, composed primarily of hydroelectric (49%) and thermal (40%) generation.
Business Description — AES owns and operates five hydroelectric plants and two thermoelectric power plants, Estrella del Mar I and Colon, representing 705 MW and 453 MW of hydro and thermal capacity, respectively and 33% of the total installed capacity in Panama.
The majority of hydroelectric plants in Panama are based on run-of-river technology, with the exception of the 260 MW Bayano plant. Hydrological conditions have an important influence on profitability. Variations in hydrology
can result in excess or a shortfall in energy production relative to our contract obligations. Hydro generation is generally in a shortfall position during the dry season from January through May, while thermal assets are expected to be in a long position as their behavior is opposite and complimentary to hydro generation.
Both hydro and thermal assets are mainly contracted through medium- to long-term PPAs with distribution companies. A small volume of contracts are with unregulated users.
Hydro assets in Panama have PPAs with distribution companies up to December 2030 for a total contracted capacity of 350 MW. Thermal assets in Panama have PPAs with distribution companies for a total contracted capacity of 430 MW, of which 80 MW will expire in June 2020 and 350 MW will expire in December 2028.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
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 the 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.
Construction and Development — In August 2015, AES executed a partnership agreement with Deeplight Corporation, a minority partner, to construct, operate, and maintain a natural gas power generation plant and a liquefied natural gas terminal, in order to purchase and sell energy and capacity as well as commercialize natural gas and other ancillary activities related to natural gas. The combined cycle natural gas power generation plant initiated operations in September 2018 and the liquefied natural gas storage and regasification facility is scheduled for completion in the second half of 2019.
Mexico
Regulatory Framework and Market Structure — Mexico has a single electric grid, the National Electricity System, covering all of Mexico's territory through the Interconnected National Electricity, Baja California and Southern Baja California Systems. The market comprises generation, transmission, distribution and commercialization segments.
Three main agencies, in addition to the Ministry of Energy, are responsible for monitoring compliance with the Electric Industry Law:
The Energy Regulatory Commission is responsible for the establishment of directives, orders, methodologies and standards oriented to regulate the electric and fuel markets.
The National Center for Energy Control, as new ISO, is responsible for managing the wholesale electricity market, transmission and distribution infrastructure, planning the network developments, guaranteeing open access to network infrastructure, executing competitive mechanisms to cover regulated demand, and setting transmission charges.
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.
Mexico has an installed capacity totaling 74 GW with a generation mix primarily comprising of thermal (71%) and hydroelectric (17%) plants.
Business Description — AES has 1,055 MW of installed capacity in Mexico. The TEG and TEP pet coke-fired plants, located in Tamuin, San Luis Potosi, supply power to their offtakers under long-term PPAs expiring in 2027 with a 90% availability guarantee. TEG and TEP secure their fuel under a long-term contract.
Merida is a CCGT, located in Merida, on Mexico's Yucatan Peninsula. Merida sells power to the CFE under a capacity and energy based long-term PPA through 2025. Additionally, the plant purchases natural gas and diesel under a long-term contract with one of the CFE’s subsidiaries, the cost of which is then passed through to CFE under the terms of the PPA.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
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, which impacts the excess energy sales to CFE.
Construction and Development — AES has partnered in a joint venture with Grupo BAL to co-invest in power and related infrastructure projects in Mexico, focusing on renewable and natural gas generation. The first development, a 306 MW wind project, began construction in 2018 and is expected to be completed in 2020.
Eurasia SBU
Generation — Our Eurasia SBU has generation facilities in six countries. Operating installed capacity totaled 4,578 MW. The following table lists our Eurasia SBU generation facilities:
|
| | | | | | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| Maritza | | Bulgaria | | Coal | | 690 |
| | 100 | % | | 2011 | | 2026 | | Natsionalna Elektricheska |
| St. Nikola | | Bulgaria | | Wind | | 156 |
| | 89 | % | | 2010 | | 2025 | | Natsionalna Elektricheska |
| Bulgaria Subtotal | | | | | | 846 |
| | | | | | | | |
OPGC (1) | | India | | Coal | | 420 |
| | 49 | % | | 1998 | | 2026 | | GRID Corporation Ltd. |
| Delhi ES | | India | | Energy Storage | | 10 |
| | 60 | % | | 2019 | | | | |
| India Subtotal | | | | | | 430 |
| | | | | | | | |
| Amman East | | Jordan | | Gas | | 381 |
| | 37 | % | | 2009 | | 2033 | | National Electric Power Company |
| IPP4 | | Jordan | | Heavy Fuel Oil | | 250 |
| | 36 | % | | 2014 | | 2039 | | National Electric Power Company |
| Jordan Subtotal | | | | | | 631 |
| | | | | | | | |
| Netherlands ES | | Netherlands | | Energy Storage | | 10 |
| | 100 | % | | 2015 | | | | |
| Netherlands Subtotal | | | | | | 10 |
| | | | | | | | |
Ballylumford (2) | | United Kingdom | | Gas | | 708 |
| | 100 | % | | 2010 | | 2023 | | Power NI/I-SEM |
Kilroot (3) | | United Kingdom | | Coal/Oil | | 701 |
| | 99 | % | | 1992 | | | | I-SEM |
| Kilroot ES | | United Kingdom | | Energy Storage | | 10 |
| | 100 | % | | 2015 | | | | |
| United Kingdom Subtotal | | | | | | 1,419 |
| | | | | | | | |
| Mong Duong 2 | | Vietnam | | Coal | | 1,242 |
| | 51 | % | | 2015 | | 2040 | | EVN |
| Vietnam Subtotal | | | | | | 1,242 |
| | | | | | | | |
| | | | | | | 4,578 |
| | | | | | | | |
_____________________________
| |
(1) | Unconsolidated entity, the results of operations of which are reflected in Equity in Earnings of Affiliates. |
| |
(2) | The Ballylumford B Station began the process for a safe shutdown in December 2018. |
| |
(3) | Includes Kilroot Open Cycle Gas Turbine ("OCGT").Turbine. |
Under construction — The following table lists our plants under construction in the Eurasia SBU:
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
OPGC 2 (1) | | India | | Coal | | 1,320 |
| | 49 | % | | 1H 2019 |
| AM Solar | | Jordan | | Solar | | 52 |
| | 36 | % | | 2H 2019 |
| | | | | | | 1,372 |
| | | |
_____________________________
| |
(1) | Unconsolidated entity, accounted for as an equity affiliate. |
In March 2018, the Company completed the sale of its entire 51% ownership interest in Masinloc, a 630 MW coal-fired plant located in the Philippines. Prior to its sale, Masinloc was accounted for as a consolidated entity and its results were included in our operations as we had a controlling interest in the business.
The following map illustrates the location of our EuropeEurasia facilities:
Europe Businesses
Bulgaria
Regulatory Framework and Market Structure — The electricity sector in Bulgaria allows both regulated and competitive segments. NEK, the state-owned electricity public supplier and energy trading company, acts as a single buyer and seller for all regulated transactions on the market. Electricity outside the regulated market trades on one of the platforms of the Independent Bulgarian Electricity Exchange day-ahead market, intra-day market or bilateral contracts market. Bulgaria is working with the European Commission on a model that will allow the gradual phase-out of regulated energy prices.
Bulgaria’s power sector is supported by a diverse generation mix, universal access to the grid, and numerous cross-border connections in neighboring countries. In addition, it plays an important role in the energy balance in the Balkan region.
Bulgaria has 12 GW of installed capacity enabling the country to meet and exceed domestic demand and export energy. Installed capacity is 37% coal-fired and 17% nuclear.
Business Description — Our Maritza plant is a 690 MW lignite fuel plant that was commissioned in June 2011. Maritza is fully compliant with the European Union Industrial Emission Directive, which became effective in January 2016.thermal power plant. Maritza's entire power output is contracted with NEK under a 15-year PPA, capacity and energy based, with a fuel pass-though, expiring in May 2026. Since the renegotiation of the PPA in April 2016, Maritza has been collecting receivables from NEK in a timely manner. However, NEK's liquidity position remains subject to political conditions and regulatory changes in Bulgaria.
The ligniteDG Comp is reviewing NEK’s PPA with Maritza pursuant to the European Commission’s state aid rules. Maritza believes that its PPA is legal and limestone are supplied under 15-year fuel supply contracts.in compliance with all applicable laws. See Item 7. —Management's
Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Regulatory.
AES also owns an 89% economic interest in the St. Nikola wind farm with 156 MW of installed capacity. St. Nikola was commissioned in March 2010. ItsThrough December 31, 2018, the entire power output isof the St. Nikola wind farm was contracted with NEK under a 15-year PPA expiringwith NEK. Starting January 1, 2019, the power output of St. Nikola is sold on the Independent Bulgarian Electricity Exchange and the plant receives additional revenue per the terms of an October 2018 Contract for Premium with the state-owned Electricity Security Fund.
Environmental Regulation — Best Available Techniques Reference Document for Large Combustion Plants (BREF LCP), the new EU environmental standards regulating emissions from the combustion of solid fuels for large combustion plants, was enacted in March 2025.
Market Structure — The maximum market capacity in 2016was approximately 13 GW. Thermal generation, which is mostly coal-fired,August 2017 and nuclearapplies to Maritza. Impacted power plants account for 61% ofare required to either meet the installed capacity.
Regulatory Framework — The electricity sector in Bulgaria operates under the Energy Act of 2004 which allows the sale of electricity to take place freely at negotiated prices, at regulated prices between partiesnew standards or on the organized market. In 2016 the government of Bulgaria made advances toward market liberalization and has engaged with the World Bank to developbe granted a model for a fully liberalized electricity market in Bulgaria. The final report with recommendationsderogation by August 2021. Maritza requested such derogation from the World Bank was finalizedBulgarian environmental authorities in December 2016. The Independent Bulgarian Energy Exchange (IBEX) started commercial operation of the power exchange2018, and expects to receive a response in January 2016 with the introduction of Day Ahead market platform.In September 2016, IBEX expanded its trading platform for bilateral forward contracts. The next step of the development of IBEX2019. If derogation is the introduction of intra-day trading, which is expected in mid-2017.
Our investments in Bulgaria rely on long-term PPAs with NEK, the state-owned electricity public supplier and energy trading company. NEK had been facing some liquidity issues and had been delayed in making payments under the PPAs withnot received Maritza and St. Nikola. In August 2015, the ninth amendment of Maritza's PPA was executed, under which Maritza and NEK agreedwould seek to reduce the capacity payment to Maritza by 14%pass through the PPA term without impactingcompliance costs to the energy price component. In exchange, NEK paid Maritza its overdue receivables. The amendment became effective in April 2016 upon full payment of the overdue receivables by NEK. Maritza has experienced timely collection of outstanding receivables from NEK since May 2016.
The Directorate-General for Competition of the European Commission (“DG Comp”) continues to review NEK’s respective PPAs with Maritza and an unrelated generatoroff-taker pursuant to the European Commission’s state aid rules. Although no formal investigation has been launchedPPA.
Key Financial Drivers —Financial results are driven by DG Comp, Maritza has met withmany factors, including, but not limited to:
regulatory changes to the Bulgaria power market;
results of the DG Comp case team and representatives of Bulgaria to discuss the agency’s review. Maritza expects that the parties will engage in
further discussions on the issues surrounding the review. At this time, we cannot predict the outcome of such discussions, nor can we predict how DG Comp might resolve its review if the anticipated discussions fail to result in an agreement concerning the review. Maritza believes that its PPA is legal and in compliance with all applicable laws, and it will take all actions necessary to protect its interests, whether through negotiated agreement or otherwise. However, there can be no assurances that this matter will be resolved favorably; if it is not, there could be a material adverse impact on Maritza’s and the Company’s respective financial statements.
In 2015, a number of measures were introduced to the regulation of the energy sector that significantly improved the liquidity of NEK. As a result, NEK is forecast to end the year 2016 with a $7 million net profit, more than a $102 million improvement over year 2015 and more than a $316 million improvement over year 2014. However, the financial situation of NEK remains subject to political conditions and regulatory changes in Bulgaria.
Key Financial Drivers —Both businesses, Maritza and St. Nikola, operate under PPA contracts. For the duration of the PPA, the financial results are primarily driven by, but not limited to:review;
the availability of the operating unitsunits;
the level of wind resourceresources for St. NikolaNikola;
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 contractcontract.
United Kingdom
Business Description Regulatory Framework and Market Structure — AES' generation businessesAES UK operates in the United Kingdom are locatedIntegrated Single Electricity Market ("I-SEM") in Northern Ireland and operateIreland. The I-SEM is the wholesale electricity market arrangement operating in the Irish SEM (1,726 MW). The Northern Ireland generation facilities consist of two plants within the Greater Belfast region. Our Kilroot plant is a 701 MW coal-fired plant with an additional 10 MW of energy storage facility and our Ballylumford plant is a 1,015 MW gas-fired plant. These plants provide approximately 62% of the Northern Ireland installed capacity and 16% of the combined installed capacity for the island of Ireland.
Kilroot is a merchant plant that bids into the SEM. the plant earns margin when scheduled in merit, out of merit, for capacity payments, and for ancillary services. Out of merit dispatch, through which costs are recovered, occurs when there are system constraints related to wind generation, voltage and transmission.
Ballylumford is partially contracted for 600 MW under a PPA with PPB that expires in 2023 with the remaining capacity bid into the SEM market. 310 MW of this merchant capacity has a supplemental Local Reserve Services Agreement ("LRSA") with the system operator. Ballylumford earns margin from availability payments received under the PPA, capacity payments offered through the SEM and revenues from the LRSA. Additionally, Ballylumford receives margin from out of merit dispatch through which the costs of operation are recovered as well as ancillary services.
Market Structure — The majority of the generation capacity in the SEM is represented by gas-fired power plants, which results in market sensitivity to gas prices. Wind generation capacity represents approximately 25% of the total generation capacity. The governments of Northern Ireland and the Republic of Ireland plan further increases in renewableand Northern Ireland starting October 1, 2018, replacing the previously existing SEM. The I-SEM market arrangements are designed to integrate the Irish All Island electricity market with European electricity markets enabling the free flow of energy sources.across borders, creating increased levels of competition and increased security of supply.
The Single Electricity Market availabilityOperator facilitates the continuous operation and liquidity of hedging products are weak, reflecting the limited size and immaturityadministration of the market,I-SEM. The organization is managed as a contractual joint venture between EirGrid, the predominancetransmission system operator for the Republic of vertical integrationIreland, and lack of forward pricing. There are essentially three products (baseload, mid-meritthe System Operator for Northern Ireland. The Single Electricity Market Operator is licensed and peaking) which are traded between the generators and suppliers.
Regulatory Framework — The SEM is an energy market established in 2007 and is based on a gross mandatory pool within which all generators with a capacity higher than 10 MW must trade the physical delivery of power. Generators are centrally dispatched based on merit order and physical constraints of the system. The SEM structure is under reviewregulated cooperatively by the regulatory authorities with a new structure due to be introducedCommission for Energy Regulation in the second quarterRepublic of 2018.Ireland and the Northern Ireland Authority for Utility Regulation.
In addition, there isthe I-SEM has a competitive capacity payment mechanism to ensure that sufficient generating capacity is offered to the market. The first competitive capacity payment is derived from a regulated Euro-basedauction for the capacity payment pool, established a year ahead byMay 2018 to September 2019 was completed in January 2018. The second capacity auction for the regulatory authority. Capacity payments are basedcapacity year October 2019 to September 2020 was completed on February 1, 2019.
Since the declared availabilityintroduction of a unitI-SEM in October 2018, new instruments such as day-ahead, intra-day and have a degree of volatilitybalancing markets were introduced to reflect seasonal influences, demand andintegration with EU energy markets. The system support services market was also reformed in May 2018 through the actual out-turnintroduction of generation declared available over each trading period.
Environmental Regulation — In 2011, the European Commission adopted the Industrial Emission Directive ("IED") that establishes the Emission Limit Values ("ELV") for SO2, NOx and dust emissions effective January 1, 2016. Both Ballylumford and KilrootDS3, a competitive services market where participants are required to complycomplete a separate qualification process.
Northern Ireland's power sector is supported by a diverse generation mix, a stable regulatory environment, universal access to the grid, and connections between the Republic of Ireland, Northern Ireland and the remainder of the UK. Installed capacity in the I-SEM is 41% gas fired and 38% from renewable sources, resulting in sensitivity to gas prices relative to order of merit. I-SEM has also set a target of 40% renewable generation by 2020.
Business Description — AES has two generation plants in the UK, Kilroot and Ballylumford, both of which are located in Northern Ireland within the Greater Belfast region.
Kilroot is a 701 MW coal-fired merchant plant, with an additional 10 MW of energy storage, that bids into the IED.I-SEM. Kilroot's coal fired units failed to clear in the first I-SEM capacity auction process finalized in January 2018. Consequently, AES announced its intent to shut down the coal units, pending the results of an assessment by the
regulator to determine the long term needs of the Northern Ireland power grid. In November 2018, Kilroot's Unit 1 was awarded the 12 month System Support Service Agreement for the period October 2018 to September 2019. In addition, the Company also decided to transfer the capacity contract awarded to Ballylumford Unit 4 to Kilroot Unit 2. As a result, the decision to shut down both Kilroot coal units was reversed.
Ballylumford is a 708 MW gas-fired plant, of which 592 MW is contracted under a PPA with Power NI Power Procurement Business expiring in 2023. The Ballylumford C Station116 MW remaining capacity is compliant withoutbid into the need for investment. Both BallylumfordI-SEM market. Ballylumford's B Stationstation Unit 5 failed to clear the aforementioned I-SEM capacity auction while Unit 4’s capacity contract was transferred to Kilroot. As a result, AES stopped generation at Ballylumford's B station in late 2018, and Kilroot required investmentongoing work to safely shut down the station is expected to be completed in compliance.early 2019.
The IED provides for two options that may be implemented by the European Union member states other than compliance with the new ELV's the Transitional National Plan or Limited Life Time Derogation.
Kilroot has opted into the Transitional National Plan which allows the plant to operate between 2016-2020, being exempt from compliance with ELVs, but observing a ceiling set for maximum annual emissions that is based on the last 10 years average emissions and operating hours. Kilroot has invested approximately $10 million in Umbrella Selective Non Catalytic Reduction technology, which reduces the plant's NOx emissions enabling the plant to increase its capacity factor within the ceiling of NOx emissions and earn energy margin. The Transitional National Plan also established a UK wide NOx trading scheme which Kilroot avails of as required. Further technical modifications are being evaluated which could make the plant fully compliant with the IED from 2020.
Without investment, the Ballylumford B station of 540 MW did not meet the standards of the IED. In 2014, AES secured a LRSA with the Transmission System Operator ("TSO") to refurbish two of the three units to be compliant with ELVs under IED, providing at least 250 MW of capacity from 2016 to 2018 with an option to extend to 2020 by the TSO. The project was executed in 2015 with an achieved combined gross output of 310 MW.
Key Financial Drivers — For our businesses in the SEM market, the financialFinancial results will be driven by, but not limited to, the following:
Regulatory changes to the market structure and payment mechanism
Availability of the operating units
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• | Commodity prices (gas, coal and CO2) and sufficient market liquidity to hedge prices in the short-term
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Electricity demand in the SEM (including impact of wind generation)
Kazakhstan
Business Description — Our businesses account for approximately 6% of the total annual generation in Kazakhstan. Of the total capacity of 2,776 MW, 1,033 MW is hydroelectric and operates under a concession agreement until the beginning of October 2017 and 1,743 MW is coal-fired capacity which is owned outright. The thermal plants are designed to produce heat with electricity as a co- or by-product.
The Kazakhstan businesses act as merchant plants for electricity sales by entering into bilateral contracts directly with consumers for periods of generally no more than one year. There are limited opportunities for the plants to be in contracted status, as there is no central offtaker, and the few businesses that could take a whole plant's generation tend to have in-house generation capacity.
The hydroelectric plants are run-of-river and rely on river flow and precipitation, particularly snow. Due to the presence of a large multi-year storage dam upstream and a season minimum river flow rate agreement with Russia downstream, the plants are protected against significant downside risk to their volume in years with low precipitation. AES does not control water flow which impacts our generation.
Ust Kamenogorsk CHP provides heat to the city of Ust Kamenogorsk through the city heat network company (Ust Kamenogorsk Heat Nets). Ust Kamenogorsk CHP is their only source of supply.
Market Structure — The Kazakhstan electricity market totals approximately 21,307 MW, of which 17,504 MW is available. The bulk of the generating capacity in Kazakhstan is thermal with coal as the main fuel. As coal is abundantly available in Kazakhstan, most plants are designed to burn local coal. The geographical remoteness of Kazakhstan, in combination with its abundant resources, results in coal prices that are not reflective of world coal prices, current delivered cost is less than $12 per metric ton. In addition, the government closely monitors coal prices, due to their impact on the price of socially necessary heating and on electricity tariffs.
Regulatory Framework — All Kazakhstan generating companies sell electricity at or below their respective tariff-cap level. These tariff-cap levels have been fixed by the Kazakhstan government for the period 2009-2018 for each of the fifteen groups of generators. These groups were determined by the Ministry of Energy, based on a number of factors including plant type and fuel used.
In July 2012, Kazakhstan enacted an amendment to its Electricity Law requiring electricity producers to reinvest all profits generated during the years 2013-2015 as part of annual investment obligation agreements, thereby limiting the businesses ability to distribute dividends. These investment obligation agreements had to be equal to the sum of the planned annual depreciation and profit. Selection of investment projects was at the discretion of electricity producers, but the Ministry of Energy had the right to reject submitted proposals. An electricity producer without an investment obligation agreement executed by the Ministry of Energy was not allowed to charge tariffs exceeding its incremental cost of production, excluding depreciation.
In November 2015, Kazakhstan enacted amendments to its Electricity Law to eliminate the obligation for power plants to sign annual investment obligation agreements for 2016-2018, thereby allowing the businesses to distribute dividends. In addition, the amendment stated that a centrally organized capacity market will be established by 2019 and that the Kazakhstan government plans to prolong price cap regulation by fixing new caps on energy and capacity tariffs for each group of power plants.
Kazakhstan government has approved a renewable energy law which set feed-in tariffs for renewable energy and set a renewable energy target of 3% by 2020 and 10% by 2030. This renewable energy law imposes an obligation on all non-renewable power plants to purchase renewable energy at the renewable energy tariff and resell it to customers at their own, lower price cap level.
Heat production in Kazakhstan is also regulated as a natural monopoly. The heat tariffs are set on a cost-plus basis by making an application to the Committee of Natural Monopoly Regulation and Competition Protection, the regulator. Currently, tariffs are only for multi-year periods, but with some annual adjustments for fuel cost.
Key Financial Drivers — The financial results for assets in Kazakhstan are driven by many factors, including, but not limited to:
Availability of the operating units;
Regulated electricity tariff-cap levels and heat tariff levels
Weather conditions,
Regulatoryregulatory changes to the market structure and payment mechanismmechanisms;
Costinvestments to maintain compliance with EU environmental legislation;
weather conditions impacting availability of growing renewables generation;
availability of the operating units and trading strategy;
commodity and FX prices (gas, coal, CO2) and Kazakhstan currency exchange rate fluctuation.sufficient market liquidity to hedge prices in the short-term; and
electricity demand in the I-SEM (including impact of wind generation).
Jordan
Regulatory Framework and Market Structure — The Jordan electricity transmission market is a single-buyer model with the state owned NEPCO responsible for transmission. NEPCO generally enters into long-term power purchase agreements with IPP's to fulfill energy procurement requests from distribution utilities. The sector is prioritizing renewable energy development, with 2,200 MW of renewable energy installed capacity expected by 2020, 940 MW of which is already connected to the grid.
Business Description — In Jordan, AES has a 37% controlling interest in Amman East, a 381 MW oil/gas-fired plant fully contracted with the national utility under a 25-year PPA expiring in 2033, and a 36% controlling interest in the IPP4 plant, in Jordan, a 250 MW oil/gas-fired peaker plant, which commenced operations in July 2014, fully contracted with the national utility under a 25-year PPA. Asuntil 2039. We consolidate the results in our operations as we have controlling interest in these businesses, we consolidatebusinesses.
Construction and Development —AES, in conjunction with Mitsui & Co of Japan and NEBRAS Power of Qatar, have signed an agreement to construct a 52 MW solar project in Jordan. The plant is currently under construction, and is expected to be completed by mid 2019 to coincide with the resultsstart of a PPA to provide energy to NEPCO through 2038.
India
Regulatory Framework and Market Structure — The power sector is comprised of state and central government-owned and privately-owned generation and distribution utilities. Electricity is sold to state utilities mostly under long-term PPAs and about 10% of electricity is sold in our operations.the short-term market, for example, traded on an energy exchange or through competitively bid bilateral contracts. The tariffs are fixed on yearly basis by the Electricity Regulatory Commissions Central / State(s) for the long-term PPAs or determined through a competitive bidding process. OERC regulates the electricity purchase process for the distribution licensees, including the price at which the electricity from generating companies shall be procured for supply within the state of Orissa. OERC also facilitates intrastate transmission and wheeling of electricity. The electricity regulatory commissions are guided by the Electricity Act, National Electricity Policy, National Electricity Plan and Tariff Policy issued by the Government of India.
Asia SBU
Generation — Our Asia SBU has generation facilitiesThe power sector in three countries. OperatingIndia is composed of coal, gas, hydroelectric, renewable and nuclear energy. Total installed capacity totals 2,300 MW.as of December 31, 2018 was 349 GW, of which 64% is thermal generation. Renewable energy is adding capacity at a rapid pace and currently represents 21% of the total installed capacity. The following table lists our Asia SBU generation facilities:remaining capacity is nuclear (2%) and hydro (13%).
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| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
OPGC (1) | | India | | Coal | | 420 |
| | 49 | % | | 1998 | | 2026 | | GRID Corporation Ltd. |
| India Subtotal | | | | | | 420 |
| | | | | | | | |
| Masinloc | | Philippines | | Coal | | 630 |
| | 51 | % | | 2008 | | Mid and long-term | | Various |
| Masinloc ES | | Philippines | | Energy Storage | | 10 |
| | 51 | % | | 2016 | | | | |
| Philippines Subtotal | | | | | | 640 |
| | | | | | | | |
| Mong Duong 2 | | Vietnam | | Coal | | 1,240 |
| | 51 | % | | 2015 | | 2040 | | EVN |
| Vietnam Subtotal | | | | | | 1,240 |
| | | | | | | | |
| | | | | | | 2,300 |
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_____________________________
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(1)
| Unconsolidated entity for which the results of operations are reflected in Equity in Earnings of Affiliates. |
Under construction — The following table lists our plants under construction in the Asia SBU:
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| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| OPGC II | | India | | Coal | | 1,320 |
| | 49 | % | | 2H 2018 |
| India Subtotal | | | | | | 1,320 |
| | | | |
| Masinloc 2 | | Philippines | | Coal | | 335 |
| | 51 | % | | 1H 2019 |
| Philippines Subtotal | | | | | | 335 |
| | | | |
| | | | | | | 1,655 |
| | | | |
The following map illustrates the location of our Asia facilities:
Asia Businesses
India
Business Description — OPGC is a 420 MW coal-fired generation facility located in the state of Odisha. OPGC has a 30-year PPA with GRIDCO Limited, a state utility, expiring in 2026. The PPA is composed of a capacity payment based on fixed parameters and a variable component, including a pass-through of actual fuel costs. OPGC is an unconsolidated entity and results are reported as Net Equityequity in Earningsearnings of Affiliates inaffiliates on our Consolidated Statements of Operations.
Construction and Development — AES has one 1,320 MW coal-fired project under construction, which is expected to begin operations in the first half of 2019. As of December 31, 2018, total capitalized costs at the project level were $1.3 billion. Once becoming operational, 75% of the expansion installed capacity is contracted with GRIDCO for a period of four years through 2023 and 100% for the next 25 years through 2048. A separate trading agreement is being negotiated for the remaining 25% of capacity to be sold in the trading market by GRIDCO on behalf of OPGC during the first four years following commencement of operations.
Environmental Regulation — The Ministry of Environment, Forest and Climate Change in India has recently amended the Environment (Protection) Rules with stricter emission limits for new and existing thermal power plants viathrough their notification issued in December 2015. All existing plants installed before December 31, 2003 are required to meet revised emission limits within two years and any new thermal power plants that will be operational from January 1, 2017 onwards are required to operate withwithin the revised emission limits. An FGD system needsAs a result of this amendment, Selective Catalytic Rectifier and Flue Gas Desulphurisation systems are to be installed in the existing OPGC units of OPGC for complyingto comply with the new NOX and SO2 emissions requirements.limits. The business has evaluated the options and the cost implications for the operating plant including design modification and schedule implications for the expansion project. The larger impact of these amendments and requirements of substantial investmentshardware to be installed to meet the revised environmental guidelines across the power sector in India, bornetightened emission requirements will require substantial investment by the public and private power generation companies, is still under review.OPGC. We believe the cost of complying with the new environmental regulations for particulate matters, water consumption, SOx and NOx limits will be a pass-through in the GRIDCOOERC prescribed tariff regulations for both the existing and expansion units. Ministry of Power has issued a revised Tariff Policy in January 2016 to bring more regulatory certainty, attract private investment, ensure distribution efficiency and promote renewable energy.
Construction and Development — As noted above, AES has one coal-fired project under development with a total capacity of 1,320 MW which is an expansion of our existing OPGC business. The project started construction in April 2014 and is currently expected to begin operations in the second half of 2018. As of December 31, 2016, total capitalized costs at the project level were $598 million (the Company's share is $293 million as part of our investment in subsidiary). In addition, AES has capitalized $18 million in construction management costs which are not attributable to the partner. Currently, 50% of the expansion capacity is contracted with the state offtaker, GRIDCO, for a period of 25 years, with a normative after-tax rate of return of 15.5% with an opportunity to capture additional 0.5% tied to timely completion of the project. The rest of the 50% of the generation capacity is proposed to be offered to GRIDCO under a fresh regulated PPA due to restrictions on power sale under new guidelines.
In August 2014, the Supreme Court of India invalidated the allocation of captive coal blocks. The government of India has subsequently enacted new laws allowing coal block allocation to companies with limited levels of private ownership, based on which the coal blocks have been allocated to a subsidiary of OPGC, Odisha Coal and Power Ltd., which is an OPGC joint venture with another company wholly-owned by the government of Odisha. This new company meets the lower private ownership stipulations for allocation of mines.
Key Financial Drivers — Financial results are likely to be driven by many factors, including, but not limited to:
Operatingoperating performance of the facilityfacility;
Regulatoryregulatory and environmental policy changeschanges;
Philippinestariff determination by the OERC; and
Business Description PPA provisions and energy trading.
Vietnam
Regulatory Framework and Market Structure — The MasinlocMinistry of Industry and Trade in Vietnam is primarily responsible for formulating a program to restructure the power project inindustry, developing the Philippines is a 630 MW gross coal-fired plant located in Zambales, Philippineselectricity market, and is interconnected to the Luzon Grid, andpromulgating electricity market regulations. The fuel supply is owned 51% by AES. More than 95% of Masinloc's current peak capacity is contractedthe government through medium to long-term bilateral contracts primarily with Meralco, the largest distribution company in the Philippines, several electric cooperativesVinacomin, a state-owned entity, and industrial customers.Petro Vietnam.
In January 2013, Masinloc entered into a new PSA with its main customer, Meralco, as the previous PSA expired in December 2012. The PSA is for seven years and included an additional three-year extension option, which the parties agreed to exercise in March 2016. Payments are primarily capacity-based. The PSA is primarily priced in U.S. dollars, aligning the revenues with the majority of variable and fixed costs (fuel, debt, insurance) and minimizing currency exchange risks. Masinloc's remaining contracts on the existing units expire between 2017 and 2026.
Market Structure — The PhilippineVietnam power market is divided into three grids representing the country's three major island groups — Luzon, Visayasregions (North, Central and Mindanao. Luzon, which includes Manila and is the country's largest island, has limited interconnectionSouth), with Visayas and represents 85% of the total demand of both regions. Luzon and Visayas together have an installed capacity of 17,294 MW.approximately 47 GW. The fuel mix in Vietnam is composed primarily of hydropower at 42% and coal at 37%. EVN, the national utility, owns 60% of installed generation capacity.
ThereThe government is diversity in the mixprocess of realigning EVN-owned companies into three different independent operations in order to create a competitive power market. A competitive electricity market has already been established. A pilot competitive wholesale electricity market has been developed, and will be implemented over the Luzon — Visayas generation. For Luzon, coal accounts for 49% of generation, followed by natural gas at 32%, and the remaining 19% is comprised by oil, geothermal, and renewable resources (i.e. hydro, solar, and wind, with the latter two having priority dispatch with feed-in tariff). For Visayas, geothermal is the top energy source and accounts for 47% of generation followed by coal at 39%, and the remaining 14% comprised by oil, geothermal, and renewable resources.
next five years. The primary customers for electricity are private distribution utilities, electric cooperatives, and large contestable (industrial and commercial) customers. Over 90% of the system's total energy requirement is currently being sold/purchased through medium (three to five years) to long (six to ten years) term bilateral contracts. The remaining energy is sold through the Wholesale Electricity Spot Market ("WESM"), which is the real-time, bid-based and hourlyretail market for energy where the sellers and the buyers adjust their differences between their production/demand and their contractual commitments.
Regulatory Framework — The Philippines has divided itswill undergo similar reforms after 2022. BOT power sector into generation, transmission, distribution and supply under the Electric Power Industry Reform Act of 2001. This Act primarily aims to increase private sector participationplants will not directly participate in the power sector and to privatize the Philippine government's generation and transmission assets. Generation and supply are open and competitive sectors, while transmission and distribution are regulated sectors. Sale of power is conducted primarily through medium or long-term bilateral contracts between generation companies and distribution utilities specifying the volume, price and conditions for the sale of energy and capacity, which are approvedmarket; however, their dispatch will be impacted by the ERC. Power is traded in the WESM which operates under a gross pool, central dispatch and net settlement protocols. Parties to bilateral contracts settle their transactions outside of the WESM and distribution companies or electricity cooperatives buy their imbalance (i.e., power requirements not covered by bilateral contracts) from the WESM. Distribution utilities and electric cooperatives are allowed to pass on to their end-users the bilateral contract rates, including WESM purchases, approved by the ERC.merit order
Other Regulatory Considerations — Pursuant to Electric Power Industry Reform Act of 2001, Retail Competition & Open Access ("RCOA") commenced on June 26, 2013, under which retail electricity suppliers, who are duly licensed by the ERC, may supply directly to contestable customers (end-users with an average demand of at least 1 MW), with distribution companies or electricity cooperatives providing non-discriminatory wire services. In order to ensure implementation of RCOA and stimulate transition of contestable customers, ERC issued rules implementing mandatory contestability. Under the said rules, all contestable customers are mandated to enter into power supply contracts with retail electricity suppliers by February 2017 instead of purchasing power from their local distribution utility.
Masinloc has obtained a retail electricity supplier license from the ERC and currently markets power to contestable customers. Unlike Masinloc’s contracts with distribution utilities, its contract with contestable customers do not require ERC approval to be implemented.
Environmental Regulation — To promote renewable energy, the Philippine government enacted the Renewable Energy Act of 2008 which provides incentives for the development, utilization and commercialization of
renewable energy resources such as solar, wind, small hydroelectric and biomass energies. In addition, the government also adopted a feed-in tariff scheme which was detailed under ERC Res No.16 s. 2010, where an eligible producer of renewable energy is entitled to a guaranteed payment of a fixed rate feed-in tariff for each kilowatt-hour of energy it supplies to the grid. The feed-in tariff to be approved shall be specific for each emerging renewable energy technology and shall be extended on a first-to-build basis as there is an established cap per technology on eligibility under the feed-in tariff scheme.
Other Environmental Regulation —Over the past year, the government of the Philippines has sought to reduce its environmental impact, including the country’s carbon footprint. As such, the Department of Environment and Natural Resources is promoting stricter environmental compliance, particularly on the effluent discharge standards. The new effluent standards issued in May 2016 have restricted discharge temperature limit compared to previous standards. It is yet uncertain if the new standards will be applicable to the projects under construction which received environmental clearance before the new standards were issued.
Construction and Development — AES started construction on a 335 MW gross Masinloc expansion project in March 2016. The total capitalized cost at December 31, 2016 is $133 million. An engineering, procurement and construction contract was entered into with POSCO Engineering and Construction of Korea and their wholly owned Philippine affiliate company, Ventanas Philippine Construction Incorporated, in December 2015, with full notice to proceed issued on March 2016. The project is expected to be commercially operating in 2019. Progress is advancing as planned and the project is expected to be completed on schedule and within budget. The additional capacity is targeted for sale to distribution utilities, electric cooperatives, and industrial and commercial customers in the Luzon and Visayas grids. Approximately 50% of this additional capacity has already been contracted with an expectation to have additional capacity contracted by the date of commercial operations.
Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to:
Operating performance of the facility
Demand from contracted customers
Whole sale electricity price in the market
Vietnam
Business Description — The Mong Duong II power project is a 1,242 MW gross coal-fired plant located in Quang Ninh Province of Vietnam and was constructed under a BOT contract (the project will be transferred to Vietnamese government after 25 years). AES-VCM Mong Duong Power Company Limited ("the BOT Company") is a limited liability joint venture owned by affiliates of AES (51%), Posco Energy Corporation (30%) and China Investment Corporation (19%).service concession agreement expiring in 2040. This is the first and largest coal-fired BOT projectplant using pulverized coal firedcoal-fired boiler technology in Vietnam. The BOT Companycompany has entered a PPA with EVN the national utility, and a Coal Supply Agreement with Vinacomin a state owned entity, both with a 25 year term starting from Commercial Operation Date.expiring in 2040.
Since April 22, 2015, both units of the power facility have been in commercial operations, six months earlier than the committed schedule with the Vietnamese government. The BOT Company makes available the dependable capacity and delivers electrical energy to EVN and, in return, EVN makes payments to the BOT Company.
Market Structure — The Vietnam power market is divided into three regions (North, Central and South), with total installed capacity of approximately 41GW, an 8% increase from 2015 (38GW). The total demand in 2016 was 159.5 billion kWh with the highest demand of 76.7 billion kWh in the South and 66.5 billion kWh in the North.
The fuel mix in Vietnam is comprised of hydropower 35% (priority dispatch with low tariff), coal 36%, gas 19%, diesel and small hydro generation 4%, oil 2% (dispatched during emergencies or during peak demand), thermo-gas 1% and the remaining 3% imported from China and Lao. The government has a plan to increase thermal power capacity, primarily with coal, to reduce the dependence on hydroelectricity. According to the Master Plan VII revised in March 2016, the total targeted installed capacity for 2020 is approximately 60,000 MW, in which coal-fired power will account for 43%, hydropower and pumped storage hydropower 30%, gas-fired thermo-power 15%, renewable energy 10%, and imported power 2%.
EVN owns 57% of installed generation capacity followed by Petro Vietnam 11%, Vinacomin 4%, BOT projects 11% and others 17%. EVN is a state-owned company that is solely in charge of buying and selling electricity all over Vietnam. The government is planning to decrease EVN's ownership and increase private sector participation in the power market.
Regulatory Framework — The electricity sector is overseen by several key government entities, including the National Assembly, the Prime Minister, the Ministry of Industry and Trade and the Electricity Regulatory Agency of Vietnam, which is under the supervision of the Ministry of Industry and Trade. These entities are responsible for the issuance of laws, guidance, and implementing regulations for the sector. The Ministry of Industry and Trade, in particular, is responsible for formulating a program to restructure the power industry, develop the electricity market and promulgating electricity market regulations. The fuel supply is owned by the government through Vinacomin and Petro Vietnam. The government plans to equitize EVN-owned generation companies and separate generation, System and Market Provider and distribution into three different independent operations in order to establish the competitive power market.
Other Regulatory Considerations — According to Decision 63/2013/QD-TTG dated August 2013, the roadmap of the power market of Vietnam consists of three phases. The first phase established a competitive electricity market and was finished at the end of 2014. The second phase: (i) period of 2015-2016 for establishment of a pilot competitive wholesale electricity market; and (ii) period of 2017-2021 for implementation of a competitive wholesale electricity market. The third phase: (i) period of 2022-2023 for establishment of a pilot competitive retail electricity market; and (ii) from 2024 onward for implementation of competitive retail electricity market. EVN, a long standing monopoly in the whole chain of generation, transmission and distribution, is being restructured to allow spin-off of several subsidiaries into either independent state-owned enterprises or joint stock companies. The BOT power plants will not participate in the power market; alternatively the single buyer will bid the tariff on the power pool on their behalf.
Environmental Regulation — Mong Duong II BOT Power Plant complies strictly with environmental requirements involving local regulations and IFC Environmental, Health and Safety Guidelines for thermal power plants.
Key Financial Drivers — Financial results are likely to be driven by many factors, including, but not limited to, the operating performance and availability of the facility.
Financial Data by Country
See the table with our consolidated operations for each of the three years ended December 31, 2016, 2015 and 2014, and property, plant and equipment as of December 31, 2016 and 2015, by country, in Note 16 — Segment and Geographic Information included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
Environmental and Land-Use Regulations
The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion residuals), and certain air emissions, such as SO2, NOX, PM, mercury and other hazardous air pollutants. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries, and our consolidated results of operations. For further information about these risks, see Item 1A.—Risk Factors—Our operations are subject to significant government regulation and our business and results of operations could be adversely affected by changes in the law or regulatory schemes; Several of our businesses are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR; Our businesses are subject to stringent environmental laws, rules and regulations; Our businesses are subject to enforcement initiatives from environmental regulatory agencies; andRegulators, politicians, non-governmental organizations and other private parties have expressed concern Concerns about greenhouse gas, or GHG emissions and the
potential risks associated with climate change have led to increased regulation and are takingother actions whichthat could have a material adverse impact on our consolidated results of operations, financial condition and cash flowsbusinesses in this Form 10-K. For a discussion of the laws and regulations of individual countries within each SBU where our subsidiaries operate, see discussion within Item 1.—Business of this Form 10-K under the applicable SBUs. Many of the countries in which the Company does business also have laws and regulations relating to the siting, construction, permitting, ownership, operation, modification, repair and decommissioning of, and power sales from electric power generation or distribution assets. In addition, international projects funded by the International Finance Corporation, the private sector lending arm of the World Bank, or many other international lenders are subject to World Bank environmental standards or similar standards, which tend to be more stringent than local country standards. The Company often has used advanced generation technologies in order to minimize environmental impacts, such as CFBcombined fluidized bed boilers and advanced gas turbines, and environmental control devices such as flue gas desulphurization for SO2 emissions and selective catalytic reduction for NOx emissions.
Environmental laws and regulations affecting electric power generation and distribution facilities are complex, change frequently and have become more stringent over time. The Company has incurred and will continue to incur capital costs and other expenditures to comply with these environmental laws and regulations. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Environmental Capital Expenditures in this Form 10-K for more detail. The Company and its subsidiaries may be required to make significant capital or other expenditures to comply with these regulations. There can be no assurance that the businesses operated by the subsidiaries of the Company will be able to recover any of these compliance costs from their counterparties or customers such that the Company's consolidated results of operations, financial condition and cash flows would not be materially affected.
Various licenses, permits and approvals are required for our operations. Failure to comply with permits or approvals, or with environmental laws, can result in fines, penalties, capital expenditures, interruptions or changes to our operations. Certain subsidiaries of the Company are subject to litigation or regulatory action relating to environmental permits or approvals. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation and regulatory action. United States Environmental and Land-Use Legislation and Regulations
In the U.S.United States, the CAA and various state laws and regulations regulate emissions of air pollutants, including SO2, NOX, PM, GHGs, mercury and other hazardous air pollutants. Certain applicable rules are discussed in further detail below.
CSAPR — CSAPR addresses the "good neighbor" provision of the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment, or interference with maintenance of, any NAAQS. The CSAPR requiresrequired significant reductions in SO2 and NOX emissions from power plants in many states in which subsidiaries of the Company operate. Once fully implemented,The Company is required to comply with the rule requires SO2 emission reductions of 73%,CSAPR in several states, including Ohio, Indiana, Oklahoma and NOX reductions of 54%, from 2005 levels.Maryland. The CSAPR is implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA. The CSAPR contemplates limited interstate and unlimited intra-state trading of emissions allowances by covered sources. Initially, the EPA issued
emissions allowances to affected power plants based on state emissions budgets established by the EPA under the CSAPR. The Company is required to comply with the CSAPR in several states, including Ohio, Indiana, Oklahoma and Maryland. The Company complies with CSAPR through operation of existing controls and purchases of allowances on the open market, as needed. While the Company's 2015 CSAPR compliance costs were immaterial, the future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time.
The EPA issued an interim final rule establishing the following deadlines for implementation of the CSAPR:
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• | January 1, 2015: Phase 1 (2015 and 2016) began for annual trading programs. Existing units must have begun monitoring and reporting SO2 and NOx emissions.
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• | May 1, 2015: Phase 1 began for ozone-season NOx trading program. Existing units must have begun monitoring and reporting NOx emissions.
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• | December 1, 2015 (and each Dec. 1 thereafter): Date by which sources must demonstrate compliance with ozone-season NOx trading program (i.e., allowance transfer deadline).
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March 1, 2016 (and each March 1 thereafter): Date by which sources must demonstrate compliance with annual trading programs (i.e., allowance transfer deadline).
January 1, 2017: Phase 2 (2017 and beyond) begins for annual trading programs. Assurance provisions in effect.
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• | May 1, 2017: Phase 2 (2017 and beyond) begins for ozone-season NOx trading program. Assurance provisions in effect.
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On October 26, 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS ("CSAPR Update Rule"). The CSAPR Update Rule finds that NOx ozone season emissions in 22 states (including Indiana, Maryland, Ohio and Oklahoma) affect the ability of downwind states to attain and maintain the 2008 ozone NAAQS, and, accordingly, the EPA issued federal implementation plans that both updated existing CSAPR NOx ozone season emission budgets for electric generating units within these states and implemented these budgets through modifications to the CSAPR NOx ozone season allowance trading program. Implementation will startstarted in the 2017 ozone season (May-September 2017). Affected facilities willbegan to receive fewer ozone season NOx allowances in 2017, and later, resulting in the need to purchase additional allowances. AtWhile the Company's 2017 and 2018 CSAPR compliance costs were immaterial, the future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time, we cannot predict what the impact will be with respect to these new standards and requirements, but it could be material if certain facilities will need to purchase additional allowances based on reduced allocations.
MATS — Pursuant to Section 112 of the CAA, the EPA published a final rule in 2012 called the MATS establishing National Emissions Standards for Hazardous Air Pollutants from coal and oil-fired electric utility steam generating units. The rule required all affected power plants to comply with the applicable MATS standards by April 2015, with the possibility of obtaining a one year extension, if needed, to complete the installation of necessary controls. All of the Company's U.S. coal-fired plants operated by the Company's subsidiaries are currently in compliance with MATS.
There currently are challenges to the EPA’s determination that it was appropriate and necessary to regulate hazardous air pollutant emissions from electric generating units - the basis for the MATS rule - proceeding in the United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) but, in the meantime, the MATS rule remains in effect. We currently cannot predict the outcome of this litigation, or its impact, if any, on our MATS compliance or ultimate costs.
New Source Review ("NSR") — The NSR requirements under the CAA impose certain requirements on major emission sources, such as electric generating stations, if changes are made to the sources that result in a significant increase in air emissions. Certain projects, including power plant modifications, are excluded from these NSR requirements, if they meet the RMRR exclusion of the CAA. There is ongoing uncertainty, and significant litigation, regarding which projects fall within the RMRR exclusion. TheOver the past several years, the EPA has pursued a coordinated compliance and enforcement strategy to address NSR compliance issues at the nation's coal-fired power plants. The strategy has included both the filing offiled suits against coal-fired power plant owners and the issuance ofissued NOVs to a number of power plant owners alleging NSR violations. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation
and regulatory action, including a NOV issued by the EPA against IPL concerning NSR and prevention of significant deterioration issues under the CAA.
In 2000, DP&L's Stuart Station received a NOV from the EPA alleging that certain activities undertaken in the past are outside the scope of the RMRR exclusion. Hutchings Station also received such a NOV in 2009. Additionally, generation units partially owned by DP&L but operated by other utilities have received such NOVs
relating to equipment repairs or replacements alleged to be outside the RMRR exclusion. The NOVs issued to DP&L-operated plants have not been pursued through litigation by the EPA.
If NSR requirements were imposed on any of the power plants owned by the Company's subsidiaries, the results could have a material adverse impact on the Company's business, financial condition and results of operations. In connection with the imposition of any such NSR requirements on IPL, the utility would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions, but not fines or penalties; however, there can be no assurances that they would be successful in that regard.
Regional Haze Rule — The EPA's "Regional Haze Rule" is intended to reduce haze and protect visibility in designated federal areas, and sets guidelines for determining BART at affected plants and how to demonstrate "reasonable progress" towardstoward eliminating man-made haze by 2064. The Regional Haze Rule required states to consider five factors when establishing BART for sources, including the availability of emission controls, the cost of the controls and the effect of reducing emission on visibility in Class I areas (including wilderness areas, national parks and similar areas). The statute requireswould require compliance within five years after the EPA approves the relevant SIP or issues a federal implementation plan, although individual states may impose more stringent compliance schedules.
In September 2017, the EPA previously determined thatpublished a final rule affirming the continued validity of the EPA's previous determination allowing states included into rely on the CSAPR would not be required to make source-specificsatisfy BART determinations for BART-affected electric generating units, reasoningrequirements. All of the Company’s facilities that are subject to BART comply by meeting the emissions reductions required by the CSAPR were "better than BART." Concurrently, EPA also finalized a limited disapprovalrequirements of certain states' plans — including Ohio's — that previously relied on the EPA's Clean Air Interstate Rule to improve visibility and substituted a Federal Implementation Plan that relies on the CSAPR. Environmental groups have challenged EPA's determination than the CSAPR is "better than BART." The challenge currently is proceeding in the D.C. Circuit.
The second phase of the Regional Haze Rule begins in 2019 and states2019. States must submit regional haze plans for this second implementation period in 2021 to continue to demonstrate reasonable progress towards reducing visibility impairment in Class I areas. States may need to require additional emissions controls for visibility impairing pollutants, including on BART sources, during the second implementation period. We currently cannot predict the impact of this second implementation period, if any, on any of our Company’s U.S. subsidiaries.
National Ambient Air Quality Standards ("NAAQS") — Under the CAA, the EPA sets NAAQS for six principal pollutants considered harmful to public health and the environment, including ozone, particulate matter, NOx and SO2, which result from coal combustion. Areas meeting the NAAQS are designated "attainment areas" while those that do not meet the NAAQS are considered "nonattainment areas." Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS, which may include imposing operating limits on individual plants. The EPA is required to review NAAQS at five-year intervals.
Based on the current and potential future ambient air standards, certain of the states in which the Company's subsidiaries operate have determined or will be required to determine whether certain areas within such states meet the NAAQS. Some of these states may be required to modify their State Implementation Plans to detail how the states will regainattain or maintain their attainment status. As part of this process, it is possible that the applicable state environmental regulatory agency or the EPA may require reductions of emissions from our generating stations to reach attainment status for ozone, fine particulate matter, NOx or SO2. The compliance costs of the Company's U.S. subsidiaries could be material.
On September 30, 2015, IDEM published itsBeginning January 1, 2017, IPL Petersburg has been required to meet reduced SO2 limits established in a final rule establishing reduced SO2 limits for IPL facilitiespublished by IDEM in 2015 in accordance with a new one-hour standardSO2 NAAQS of 75 parts per billion, for the areas in which IPL's Harding Street, Petersburg, and Eagle Valley Generating Stations operate. The compliance date for these requirements was January 1, 2017. No impact is expected for Eagle Valley or Harding Street Generating Stations because these facilities ceased coal combustion prior to the compliance date. It is expected that improvementsbillion. Improvements to the existing FGDsFGD systems at IPL’s Petersburg will bestation were required in order to comply. IPL estimates costsmeet the emission limits imposed by the rule. The IURC approved IPL’s request for compliance at Petersburg at approximately $29 million for measures that enhance the performance and integrity of the FGDs systems. On May 31, 2016, IPL filed itsNAAQS SO2 NAAQS compliance plans with the IURC. IPL is seeking approval for a CPCN for these measures at its Petersburg Generating Station. IPL expects to recover through its environmental rate adjustment mechanism any operating or capital expenditures related to compliancegeneration station with these requirements. Recovery of these costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs recovered through a rate adjustment mechanism withand the remainder recorded as a regulatory asset to be considered for recovery in the next basea subsequent rate case proceeding. However, there can be no assurances that IPL will be successful in that regard. In lightcase. The approved capital cost of the uncertainties at this time, we cannot predictNAAQS SO2 compliance plan is approximately $29 million. On August 15, 2018, EPA proposed to approve Indiana’s State Implementation Plan addressing attainment of the impact2010 SO2 standard for certain locations including those of these permit requirements on our consolidated results of operations, cash flows, or financial condition, but it may be material.IPL's Petersburg Generating Stations.
Greenhouse Gas Emissions — In January 2011, the EPA began regulating GHG emissions from certain
stationary sources, under the so-called "Tailoring Rule." The regulations are being implemented pursuant to two CAA programs: the Title V Operating Permitincluding pre-construction permitting program and the program requiring a permit if undergoingfor certain new construction or major modifications, known as the PSD. Obligations relating to Title V permits include record-keeping and monitoring requirements. Sources subject to PSD can be required to implement BACT. In June 2014, the U.S. Supreme Court ruled that the EPA had exceeded its statutory authority in issuing the Tailoring Rule by regulating under the PSD program sources based solely on their GHG emissions. However, the U.S. Supreme Court also held that the EPA could impose GHG BACT requirements for sources already required to implement PSD for certain other pollutants. Therefore, ifIf future modifications to our U.S.-based businesses' sources requirebecome subject to PSD review for other pollutants, it may trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHGrequirements and has now proposed NSPS for modified and reconstructed units (see below) that will serve as a floor (maximum emission rate) for future BACT requirements. Individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of the BACT requirements applicable to us on our operations cannot be determined at this time as our U.S.-based businesses will not be required to implement BACT until one of them constructs a new major source or makes a major modification of an existing major source. However, the cost of compliance couldwith such requirements may be material.
On October 23, 2015, the EPA's rule establishing NSPS for new electric generating units became effective. The NSPS establisheffective establishing CO2 emissions standards of 1400 lbs/MWh for newly constructed coal-fueled electric generating plants, which reflects the partial capture and storage of CO2 emissions from the plants. The NSPS for large, newly constructed NGCC facilities is 1,000 lbs/MWh. These standards apply to any electric generating unit with construction commencing after January 8, 2014. The EPA also promulgated NSPS applicable to modified and reconstructed electric generating units, which will serve as a floor for future BACT determinations for such units. The NSPS applicable to modified and reconstructed coal-fired units will be 1,800 lbs CO2/MWh for sources with heat input greater than 2,000 MMBtu per hour. For smaller sources, below 2,000 MMBtu per hour, the standard is 2,000 lbs CO2/MWh. The NSPS could have an impact on the Company's plans to construct and/or modify or reconstruct electric generating units in some locations. On December 20, 2018, EPA published proposed revisions to the final NSPS for new, modified and reconstructed coal-fired electric utility steam generating units proposing that the Best System of Emissions Reduction for these units is highly efficient generation that would be equivalent to supercritical
steam conditions for larger units and sub-critical steam conditions for smaller units, and not partial carbon capture and sequestration, as was finalized in the 2015 final NSPS. EPA did not include revisions for natural-gas combined cycle or simple cycle units in the December 20, 2018 proposal.
On December 22, 2015, the EPA's finalEPA finalized CO2 emission rules for existing power plants under Clean Air Act Section 111(d) (called the CPP) also became effective.. The CPP provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates that must be achieved starting in 2030. Under the CPP, states are required to meet state-wide emission rate standards or equivalent mass-based standards, with the goal being a 32% reduction in total U.S. power sector emissions from 2005 levels by 2030. The CPP requires states to submit, by 2016, implementation plans to meet the standards or a request for an extension to 2018. If a state fails to develop and submit an approvable implementation plan, the EPA will finalize a federal plan for that state. The full impact of the CPP willwould depend on the following:
whether and how the states in which the Company's U.S. businesses operate respond to the CPP;
whether the states adopt an emissions trading regime and, if so, which trading regime;
how other states respond to the CPP, which will affect the size and robustness of any emissions trading market; and
how other companies may respond in the face of increased carbon costs.
Several states and industry groups challenged the NSPS for CO2 in the D.C. Circuit. Oral argument onPursuant to a court order issued in August 2017, the challengeslitigation is scheduled for April 2017. We cannot predict at this time the likely outcome of these challenges but, if the NSPS is vacated, it also likely would resultbeing held in the invalidation of the CPP, as EPA’s authority to issue the CPP under Section 111(d) of the Clean Air Act is triggered only be EPA’s promulgation of NSPS under Section 111(b) of the Clean Air Act.indefinite abeyance pending further court order.
In addition, several states and industry groups filed petitions in the D.C. Circuit challenging the CPP and requested a stay of the rule while the challenge was considered. The D.C. Circuit denied the stay and granted requests to consider the challenges on an expedited basis. As a result, the D.C. Circuit may issue an opinion on these challenges prior to the end of 2016. On February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the CPP pending resolution of challenges to the rule. Challenges to both the CPP and the GHG NSPS are being held in abeyance at this time. On October 16, 2017, the EPA published in the Federal Register a proposed rule that would rescind the CPP. On December 28, 2017, the EPA published an Advance Notice of Proposed Rulemaking to solicit comments as EPA considers a potential rule to establish emission guidelines to replace the CPP and limit GHG emissions from existing electric generating units under Section 111(d) of the CAA.
On August 31, 2018, the EPA published in the Federal Register proposed Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units, known as the Affordable Clean Energy (ACE) Rule. In addition, the EPA proposed associated revisions to implementing regulations and the New Source Review program. The challenges have been fully briefedproposed ACE Rule would replace the EPA’s 2015 Clean Power Plan and argued beforeproposes to determine that heat rate improvement measures are the D.C. Circuitbest system of emission reduction for existing coal-fired electric generating units.
Due to the future uncertainty of the CPP or potential replacement rule, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, could be decided bymaterial. The GHG NSPS remains in effect at this time, and, absent further action from the court atEPA that rescinds or substantively revises the NSPS, it could impact any time. ChallengesCompany plans to the D.C. Circuit’s decision could then be filed with the Supreme Court.
The Company will likely not know the answers to the above questions regarding the CPP until 2018 construct and/or later. As the first compliance period will not end until 2025, and because we cannot predict whether the CPP will survive the legal challenges, it is too soon to determine the CPP's potentialmodify or reconstruct electric generating units in some locations, which may have a material impact on our business, operations or financial condition but any such impact could be material.or results of operations.
Cooling Water Intake — The Company's facilities are subject to a variety of rules governing water use and discharge. In particular, the Company's U.S. facilities are subject to the CWA Section 316(b) rule issued by the EPA that seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the BTA for cooling water intake structures. On August 15, 2014, the EPA published its final standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other industrial facilities.plants. These standards require certain subject facilities that utilize at least 25% of the withdrawn water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day to choose among seven BTA options to reduce fish impingement. In addition, facilities that withdraw at least 125 million gallons per day for cooling purposes must conduct studies to assist permitting authorities to determine whether and whatwhich site-specific controls, if any, would beare required to reduce entrainment of aquatic organisms. This decision-making process would include public input as part of permit renewal or permit modification.entrainment. It is possible that this decision-making process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility to increase generation capacity are required to reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards for entrainment. It is not yet possible to predict the total impacts of this recent final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.
AES Southland's current plan is to comply with the California State Water Resources Board's ("SWRCB") regulations will seeSWRCB OTC Policy by shutting down and permanently retiring all once-through-cooled ("OTC")existing generating units retired from serviceat AES Alamitos, AES Huntington Beach and AES Redondo Beach that utilize OTC by December 31, 2020.2020, the compliance date included in the OTC Policy. New air-cooled combined cycle gas turbine generators and battery energy storage systems will be constructed at the AES Alamitos and AES Huntington Beach generating stations, and there is currently no plan to replace the OTC generating units at the AES Redondo Beach generating station will be retired.station. The execution of the Implementation Planimplementation plan for compliance with the SWRCB's OTC policyPolicy is entirely dependent on the Company's ability to execute on long-term power purchase agreements to support project financing of the replacement generating units at AES Alamitos and AES Huntington Beach. The SWRCB is currently reviewing the Implementation Planimplementation plan and latest update information on OTC generating unit retirement dates and
new generation availability to evaluate the impact on electrical system reliability, which could result in the extension of OTC compliance dates for specific units.
The Company’s California subsidiaries have signed 20-year term power purchase agreements with Southern California Edison for the new generating capacity which have been approved by the California Public Utilities Commission. Approvals and permits to construct theConstruction of new generating units are pending approval by the California Energy Commission and South Coast Air Quality Management District. Construction is scheduled to begincapacity began in June 2017 at AES Huntington Beach and July 2017 at AES Alamitos. Construction at both sites is on schedule and will require the following existing OTC units to retire earlier than December 31, 2020 to provide interconnection capacity and/or emissions credits prior to startup of the new generating units:
Redondo Beach Unit 7 - September 30, 2019
Huntington Beach Unit 1 - December 31, 2019
Alamitos Units 1, 2, and 6 - December 31, 2019
The remaining AES OTC generating units in California will be shutdown and permanently retired by December 31, 2020.
Power plants will beare required to comply with the more stringent of state or federal requirements. At present, the California state requirements are more stringent and have earlier compliance dates than the federal EPA requirements, and are therefore applicable to the Company's California assets.
Challenges to the federal EPA's rule have beenwere filed and consolidated in the U.S. Court of Appeals for the Second Circuit, although implementation of the rule haswas not been stayed while the challenges proceed.proceeded. On July 23, 2018, the U.S. Court of Appeals for the Second Circuit upheld the rule. The Second Circuit later denied a petition by environmental groups for rehearing. The Company anticipates once-through cooling andthat compliance with CWA Section 316(b) compliance regulations and associated costs wouldcould have a material impact on our consolidated financial condition or results of operations.
Water Discharges — On June 29, 2015, the EPA and the U.S. Army Corps of Engineers published a final rule defining federal jurisdiction over waters of the United States. This rule, which initially became effective on August 28, 2015, may expand or otherwise change the number and types of waters or features subject to federal permitting. On June 27, 2017, the EPA proposed a rule that would rescind the “Waters of the United States” rule and re-codify the definition of “Waters of the United States” that existed prior to the 2015 rule. However, on February 6, 2018, the EPA published a final rule to delay the original effective date of the 2015 “Waters of the United States” to February 6, 2020, which allows the EPA to create a new rule in the interim period without the 2015 rule taking effect. On June 29, 2018, the agencies signed a supplemental notice of proposed rulemaking clarifying that the proposal is to permanently repeal the 2015 Rule. We cannot predict the outcome of the judicial challenges to the rule or the regulatory process to rescind the rule, but if the “Waters of the United Sates” rule is ultimately implemented in its current or substantially similar form and survives legal challenges, it could have a material impact on our business, financial condition or results of operations. On February 14, 2019, the agencies published a proposed rule to revise the definition of the “Waters of the United States.” We are reviewing the December 11, 2018 proposed rule and it is too early to determine whether this might have a material impact on our business, financial condition or results of operations.
Certain of the Company's U.S.-based businesses are subject to National Pollutant Discharge Elimination System permits that regulate specific industrial waste water and storm water discharges to the waters of the U.S.United States under the CWA. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers published a final rule defining federal jurisdiction over waters of the U.S.. This rule, which became effective on August 28, 2015, may expand or otherwise change the number and types of waters or features subject to federal permitting. On October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order to temporarily stay the "Waters of the U.S." rule nationwide while that court determines whether it has authority to hear the challenges to the rule. The order was in response to challenges brought by 18 states and followed an August 2015 court decision in the U.S. District Court of North Dakota to stay the rule in 13 other states. We cannot predict the duration of the nationwide or partial stay of the rule or the outcome of this litigation; however, if the rule ultimately survives the legal challenges, it could have a material impact on our business, financial condition or results of operations.
On January 7, 2013, the Ohio Environmental Protection Agency issued an NPDES permit for J.M. Stuart Station. The primary issues involve the temperature and thermal discharges from the Station including the point at which the water quality standards are applied, i.e., whether water quality standards apply at the point where the Station discharge canal discharges into the Ohio River, or whether, as the EPA alleges, the discharge canal is an extension of Little Three Mile Creek and the water quality standards apply at the point where water enters the discharge canal. In addition, there are a number of other water-related permit requirements established with respect to metals and other materials contained in the discharges from the Station. The NPDES permit establishes interim standards related to the thermal discharge for 54 months that are comparable to current levels of discharge by
Stuart Station. Permanent standards for both temperature and overall thermal discharges are established as of 55 months after the permit is effective, except that an additional transitional period of approximately 22 months is allowed if compliance with the permanent standards is to be achieved through a plan of construction and various milestones on the construction schedule are met. It is believed that compliance with the permit as written will require capital expenses that will be material to DP&L. The cost of compliance and the timing of such costs is uncertain and may vary considerably depending on a compliance plan that would need to be developed, the type of capital projects that may be necessary, and the uncertainties that may arise in the likely event that permits and approvals from other governmental entities would likely be required to construct and operate any such capital project. DP&L has appealed various aspects of the final permit to the Environmental Review Appeals Commission, although a hearing date is not currently scheduled. The compliance schedule in the final permit has been modified to accommodate the timing of the hearing. The outcome of such appeal is uncertain.
On August 28, 2012, the IDEM issued NPDES permits to the IPL Petersburg, Harding Street and Eagle Valley generating stations, which became effective in October 2012. NPDES permits regulate specific industrial wastewater and storm water discharges to the waters of Indiana under Sections 402 and 405 of the U.S. Clean Water Act. These permitsthat set new water quality-based effluent discharge limits for the IPL Harding Street and Petersburg facilities as well as monitoring and other requirements designed to protect aquatic life, with full compliance ultimately required by October 2015. In April 2013, IPL received an extension to the compliance deadline through September 29, 20172017. The deadline for IPL's Harding Street and Petersburg facilities through agreed orders with IDEM. IPL conducted studies to determine the operational changes and control equipment necessary to comply with the new limitations. In October 2014, IPL filed its wastewater compliance plans for its power plants with the IURC. On July 29, 2015, the IURC approvedcommission a Certificate of Public Convenience and Necessity to convert Unit 7 at the Harding Street Station from coal-fired to natural gas-fired (about 410 MW net capacity) at a cost of up to $71 million (the IURC later approved IPL’s updated cost estimate for the Harding Street Station refuels including $64 million for Unit 7), and also to install and operate wastewater treatment technologies at Harding Street Station and Petersburg Generating Station at a cost of up to $326 million. The IURC order also granted IPL authority for timely rate recovery for 80%portion of the costs of these projects and authoritytreatment system was subsequently extended to defer the remaining 20% as a regulatory asset to be considered for recovery through IPL’s next basic rate case proceeding. However, there can be no assurances that IPL will be successful in that regard.April 11, 2018.
On November 3, 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waters of the U.S. by power plants. These effluent limitations for existing and new sources include dry handling of fly ash, closed-loop or dry handling of bottom ash and more stringent effluent limitations for flue gas de-sulfurization wastewater. ComplianceThe required compliance time lines for existing sources willwas to be established by the applicable permitting authorities and will be set as soon as determined possible, but no sooner thanbetween November 1, 2018 and no later than December 31, 2023. On September 18, 2017, the EPA published a final rule delaying certain compliance dates of the ELG rule for two years while it administratively reconsiders the rule. IPL plans to installPetersburg has installed a dry bottom ash handling system in response to the CCR rule described below and wastewater treatment systems in response to the NPDES permits described above in advance of the ELG compliance date. As such,a result of the impact ofdecision to retire Stuart and Killen generating stations, we do not expect the ELG rule is not expected to be material.have a material impact on these two stations. While we are still evaluating the impactseffects of the final rule for DP&L,on our other U.S. businesses, we anticipate
that the implementation of theits current requirements willcould have a material adverse effect on our results of operations, financial condition and cash flows.flows, and a postponement or reconsideration of the rule that leads to less stringent requirements would likely offset some or all of the adverse effects of the rule.
Selenium Rule—In June 2016, the EPA published the final national chronic aquatic life criterion for the pollutant Selenium in fresh water. NPDES permits may be updated to include Selenium water quality based effluent limits based on a site specificsite-specific evaluation process which includes determining if there is a reasonable potential to exceed the revised final Selenium water quality standards for the specific receiving water body utilizing actual and/or project discharge information for the generating facilities. As a result, it is not yet possible to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material. IPL would seek recovery of these capital expenditures; however, there is no guarantee it would be successful in this regard.
Waste Management — In the course of operations, the Company's facilities generate solid and liquid waste materials requiring eventual disposal or processing. With the exception of coal combustion residuals ("CCR"), the wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. CCR, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at some of our coal-fired power generation plant sites using engineered, permitted landfills. Waste materials generated at our electric power and distribution facilities may include asbestos, CCR, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree and land clearing wastes and PCBpolychlorinated biphenyl contaminated liquids and solids. The Company endeavors to ensure that all of its solid and liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations. On October 19, 2015, an EPA rule regulating CCR under the Resource Conservation and Recovery Act as nonhazardous solid waste became effective. The rule established nationally applicable minimum criteria for the disposal of CCR in new and currently operating landfills and surface impoundments, including location restrictions, design and may impose closure and/oroperating criteria, groundwater monitoring, corrective action and closure requirements for existing CCR landfills and impoundments under certain specified conditions.post-closure care. The primary enforcement mechanisms under this
regulation would be actions commenced by the states and private lawsuits. On December 16, 2016, President Obama signed into law the Water Infrastructure Improvements for the Nation Act (WIN Act), which("WIN Act") was signed into law. This includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. The EPA has indicated that it will implement a phased approach to amending the CCR Rule. It is too early to determine whether the results of the groundwater monitoring data or the outcome of CCR litigation or a potential CCR Remand Rule may have a material impact on our business, financial condition or results of operations.
The existing ash ponds at IPL'sthe Petersburg Station dodid not meet certain structural stability requirements set forth in the CCR rule. As such, IPL would bethe Company was ultimately required to cease use of theall ash ponds at Petersburg by April 17, 2017. However, IDEM has granted IPL a variance extending that deadline to AprilNovember 11, 2018. In order to handle the bottom ash material that would otherwise be sluiced to the ash ponds, IPL plans to install a dry bottom ash handling system at an estimated cost of approximately $47 million. On May 31, 2016, IPL filed its CCR compliance plans with the IURC. IPL is seeking approval for a CPCN to install the bottom ash dewatering system at its Petersburg generating station. IPL expects to recover through its environmental rate adjustment mechanism any operating or capital expenditures related to the installation of this system. Recovery of these costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding. However, there can be no assurances that IPL will be successful in that regard. In light of the uncertainties at this time, we cannot predict the impact of these requirements on our consolidated results of operations, cash flows, or financial condition, but it may be material.
CERCLA — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (aka "Superfund")— This act, also know as "Superfund," may be the source of claims against certain of the Company's U.S. subsidiaries from time to time. There is ongoing litigation at a site known as the South Dayton Landfill where a group of companies already recognized as potentially responsible parties have sued DP&L and other unrelated entities seeking a contribution toward the costs of assessment and remediation. DP&L is actively opposing such claims. In 2003, DP&L received notice that the EPA considers DP&L to be a potentially responsible party at the Tremont City landfill Superfund site. The EPA has taken no further action with respect to DP&L since 2003 regarding the Tremont City landfill. The Company is unable to determine whether there will be any liability, or the size of any liability that may ultimately be assessed against DP&L at these two sites, but any such liability could be material to DP&L.
Unit Retirement and Replacement Generation — In the second quarter of 2013, IPL retired in place five oil-fired peaking units with an average life of approximately 61 years (approximately 168 MW net capacity in total), as such units were not equipped with the advanced environmental control technologies needed to comply with existing and expected environmental regulations. Although these units represented approximately 5% of IPL's generating capacity, they were seldom dispatched by Midcontinent Independent System Operator, Inc. in recent years due to their relatively higher production cost and in some instances repairs were needed. In addition to these recently retired units, IPL has several other generating units that it expects to retire or refuel by 2017. These units are primarily coal-fired and represent 472 MW of net capacity in total. To replace this generation, in April 2013, IPL filed a petition and case-in-chief with the IURC in April 2013 seeking a CPCN to build a 550 to 725 MW CCGT at its Eagle Valley Station site in Indiana and to refuel Harding Street Station Units 5 and 6 from coal to natural gas (106 MW net capacity each). In May 2014, the IURC issued an order on the CPCN authorizing the refueling project and granting approval to build a 644 to 685 MW CCGT at a total budget of $649 million. The current estimated cost of these projects is $632 million. IPL was granted authority to accrue post in-service allowance for debt and equity funds used during construction and to defer the recognition of depreciation expense of the CCGT and refueling project until such time that IPL is allowed to collect both a return and depreciation expense on the CCGT and refueling project. The CCGT is expected to be placed into service in the first half of 2018, and the refueling project was completed in December 2015. The costs to build and operate the CCGT and for the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after the assets have been placed in service. For a discussion of the retirement of AES Southland's OTC generating units due to U.S. cooling water intake regulations, please see — Cooling Water Intake, above.
International Environmental Regulations
For a discussion of the material environmental regulations applicable to the Company's businesses located outside of the U.S., see Environmental Regulation under the discussion of the various countries in which the Company's subsidiaries operate in Business—Our Organization and Segments, above. Customers
We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 20162018 total revenue. In our generation business, we own and/or operate power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. Our utilities sell to end-user customers in the residential, commercial, industrial and governmental sectors in a defined service area.
Executive Officers
The following individuals are our executive officers:
Michael ChiltonSanjeev Addala, 57 years old, was named Senior Vice President, Construction & Engineering, for the Company in December 2014. Prior to his current role, Mr. Chilton was the Managing Director of Construction from 2009 to 2011 and Vice President, Operations Support from 2012 to 2014. Before joining AES, Mr. Chilton held various leadership roles in Kennametal and GE, including: Regional Director for Kennametal Asia (2006-2009), with GE as President & CEO of Xinhua Controls Solutions based in China (2005-2006), Managing Director for Contractual Services Asia based in Singapore (2001-2005), Quality Leader for Energy Services based in Atlanta (1999-2001), Master Black Belt for Energy Sales based in Tokyo (1998-1999) and President of Joint Conversion company in Nuclear Energy based in Wilmington (1995-1998). Mr. Chilton has a BS in Chemical Engineering from University of Missouri, a MBA from University of Arkansas and a JD from Kaplan University.
Bernerd Da Santos, 5453 years old, was appointed Chief Information and Digital officer in October 2018. Prior to joining AES, Mr. Addala was Chief Digital Officer at GE from 2016 to September 2018, Chief Digital Officer at Caterpillar from 2013 to 2015, and Chief Information Officer, Americas, Climate Control Technologies at Ingersoll-Rand from 2008 to 2013. He also previously held business and technology leadership roles at General Motors from 1994 to 2008. He served on Energize Ventures and AppLariat advisory Boards. Mr. Addala is a member of the Board of AES Distributed Energy. Mr. Addala holds a Master of Science degree in Mechanical Engineering from South Dakota School of Mines and Tech. and a Master of Business Administration degree from the Kellogg School of Management at Northwestern University. Mr. Addala has also completed an Executive Leadership program at Duke University.
Bernerd Da Santos, 55 years old, has been Chief Operating Officer and SeniorExecutive Vice President insince December 2014.2017. Previously, Mr. Da Santos held several positions at the Company, including Chief Operating Officer and Senior Vice President from 2014 to 2017, Chief Financial Officer, Global Finance Operations (2012-2014),from 2012 to 2014, Chief Financial Officer of Global Utilities (2011-2012),from 2011 to 2012, Chief Financial Officer of Latin America and Africa (2009-2011),from 2009 to 2011, Chief Financial Officer of Latin America (2007-2009),from 2007 to 2009, Managing Director of Finance for Latin America (2005-2007)from 2005 to 2007 and VP and Controller of EDCLa Electricidad de Caracas ("EDC") (Venezuela). Prior to joining AES in 2000, Mr. Da Santos held a number of financial leadership positions at EDC. Mr. Da Santos is the chairman of AES Gener in Chile and a member of the Board of Directors of Companhia Brasiliana de Energia, AES Tietê, AES Eletropaulo, AES Gener, CompanhiaCompañia de Alumbrado Electrico de San Salvador, ("CAESS"), Empresa Electrica de Oriente, ("EEO"), CompanhiaCompañia de Alumbrado Electrico de Santa Ana, and Indianapolis Power & Light. Mr. Da Santos holds a Bachelor'sbachelor's degree with Cum Laude distinction in Business Administration and Public Administration from Universidad José Maria Vargas, a Bachelor'sbachelor's degree with Cum Laude distinction in Business Management and Finance, and an MBA with Cum Laude distinction from Universidad José Maria Vargas.
Manuel Pérez Dubuc, 55 years old, has served as Senior Vice President, Global New Energy Solutions since October 2018. Previously Mr. Pérez Dubuc served as the President of the South America SBU from March 2018 to October 2018 and President of the MCAC SBU from November 2012 to March 2018. He also served as Vice President and General Manager AES North Asia, President of AES Dominicana and Chief Financial Officer of EDC. Mr. Pérez Dubuc is a member of the Boards of SPower, AES Gener, AES Tiete, Fluence and EnerAB, Ron Santa Teresa SACA and GFR Group Advisory board. Prior to joining AES, Mr. Pérez Dubuc served as a Chairman and CEO of Meiya Power Company based in Hong Kong. Mr. Pérez Dubuc studied electrical engineering at the Universidad Simon Bolivar and with a master’s degree in business administration from IESA (Instituto de Estudios Superiores de Administración) of Caracas, Venezuela. He attended the Executive Leadership Program at the University of Virginia’s Darden School of Business and the Global Executive Leadership Program at Georgetown University’s McDonough School of Business in 2015.
Paul L. Freedman, 48 years old, has been Senior Vice President and General Counsel since February 2018 and was appointed Corporate Secretary in October 2018. Prior to assuming his current position, Mr. Freedman served as Chief of Staff to the Chief Executive Officer from April 2016 to February 2018, Assistant General Counsel from 2014 to 2016, General Counsel, North America Generation, from 2011 to 2014, Senior Corporate Counsel from 2010 to 2011 and Counsel 2007 to 2010. Mr. Freedman is a member of the Boards of IPALCO, AES U.S. Investments, DP&L, Fluence and the Business Council for International Understanding. Prior to joining AES, Mr. Freedman was Chief Counsel for credit programs at the U.S. Agency for International Development and he previously worked as an associate at the law firms of White & Case, LLP and Freshfields. Mr. Freedman received a B.A. from Columbia University and a J.D. from the Georgetown University Law Center.
Andrés R. Gluski, 59 61 years old, has been President, CEOChief Executive Officer and a member of our Board of Directors since September 2011 and is Chairmana member of the StrategyInnovation and Investment Committee of the Board.Technology Committee. Prior to assuming his current position, Mr. Gluski served as EVPExecutive Vice President and Chief Operating Officer ("COO") of the Company since March 2007. Prior to becoming the COOChief Operating Officer of AES, Mr. Gluski was EVPExecutive Vice President and the Regional President of Latin America from 2006 to 2007. Mr. Gluski was Senior Vice President ("SVP") for the Caribbean and Central America from 2003 to 2006, CEOChief Executive Officer of La Electricidad de Caracas ("EDC")EDC from 2002 to 2003 and CEOChief Executive Officer of AES Gener (Chile) in 2001. Prior to joining AES in 2000, Mr. Gluski was EVPExecutive Vice President and Chief Financial Officer ("CFO") of EDC, EVPExecutive Vice President of Banco de Venezuela (Grupo Santander), Vice President ("VP") for Santander Investment, and EVPExecutive Vice President and CFOChief Financial Officer of CANTV (subsidiary of GTE). Mr. Gluski has also worked with the International Monetary Fund in the Treasury and Latin American Departments and served as Director General of the Ministry of Finance of Venezuela. From 2013-2016,2013 to 2016, Mr. Gluski served on President Obama's Export Council. Mr. Gluski currently serves on, the US-Brazil CEO Forum and the US-India CEO Forum. He is a member of the Board of Waste
Management and AES Gener in Chile and AES Brasiliana in Brazil.Chile. Mr. Gluski is also Chairman of the Americas Society/Council of the Americas, and Director of the Edison Electric Institute and the US-Philippines Society.Institute. Mr. Gluski is a magna cum laude graduate of Wake Forest University and holds an M.A. and a Ph.D. in Economics from the University of Virginia.
Elizabeth HackensonLisa Krueger, 5655 years old, was named Chief Information Officer ("CIO")has served, as Senior Vice President and SVPPresident of AES in October 2008.the US SBU since September 2018. Prior to assuming her current position,joining AES, Ms. Hackenson wasKrueger served as an energy consultant from July 2017 to August 2018, Chief Commercial Officer of Cogentrix Energy Power Management, LLC, the SVPportfolio management company of Carlyle Power Partners, from January 2017 to June 2017, and CIO at Alcatel-LucentPresident and Chief Executive Officer of Essential Power, LLC from 2006March 2014 to 2008, where she managed the development of technology programs for Applications, Operations and Infrastructure. Previously, sheJune 2017. Ms. Krueger also served as Vice President - Sustainable Development of First Solar, one of the EVPworld’s largest photovoltaic manufacturers and CIO for MCI from 2004system integrators, where she led the development and implementation of various domestic and internal strategic plans focused on market and business development and served as the President of First Solar Electric. Prior to 2006. Her corporate tenure has spanned several Fortune 100 companies including, British Telecom (Concert), AOL (UUNET) and EDS. She served inFirst Solar, Ms. Krueger held a variety of senior managementexecutive level positions working on the managementwith Dynegy, Inc., including Vice President - Enterprise Risk Control, Vice President - Northeast Commercial Operations, Vice President - Origination and delivery of information technology services to support business needs across a corporate-wide enterprise. Ms. Hackenson serves on the Boards of DP&LRetail Operations, and its parent company DPL, Inc. AES Cochrane and AES Chivor.Vice President, Environmental, Health & Safety. She also serves asheld a Director onvariety of leadership roles at Illinois Power, including positions in transmission planning and system operations, generation planning and system operations, and environmental, health & safety. Ms. Krueger has a Bachelor of Science degree in Chemical Engineering from the Greater Washington BoardMissouri University of TradeScience and Red 5 SecurityTechnology and is a Strategic Advisor to the Paladin Group. Ms. Hackenson earned herMaster of Business Administration degree from New York Statethe Jones Graduate School of Business at Rice University.
Tish Mendoza, 4143 years old, is Chief Human Resources Officer and Senior Vice President, Global Human Resources and Internal Communications.Communications since 2015. Prior to assuming her current position, Ms. Mendoza was the Vice President of Human Resources, Global Utilities from 2011 to 2012 and Vice President of Global Compensation, Benefits and HRIS, including Executive Compensation, from 2008 to 2011 and acted in the same capacity as the Director of the function from 2006 to 2008. In 2015, Ms. Mendoza was appointed a member of the Boards of AES Chivor S.A. and DP&L, and sits on AES' compensation and benefits committees. She is also currently serving as co-chair of Evanta Global HR, and is part of its governing body in Washington, DC.D.C. Prior to joining AES, Ms. Mendoza was Vice President of Human Resources for a product company in the Treasury Services division of JP
Morgan Chase and Vice President of Human Resources and Compensation and Benefits at Vastera, Inc, a former technology and managed services company. Ms. Mendoza earned certificates in leadershipLeadership and human resource management,Human Resource Management, and a Bachelor'sbachelor's degree in Business Administration and Human Resources.
Brian A. MillerLeonardo Moreno, 51 39 years old, has been EVP, General Counsel,served as Senior Vice President, Corporate Strategy and Corporate Secretary ofInvestments and Chief Risk Officer since May 2017. Previously Mr. Moreno served as the Company since 2005.Chief Financial Officer, Europe SBU from May 2015 to April 2017 and as a Managing Director on AES’ Mergers & Acquisitions team from January 2012 to April 2015. Since joining AES in 2006, Mr. Miller is responsible for the management and operation of the company's global legal and governance matters, stakeholder management and regulatory affairs, and ethics and compliance efforts. Mr. Miller joined the Company in 2001 andMoreno has served in various positions including VP, Deputy General Counsel, Corporate Secretary, Business Development, General Counsel for North America and Assistant General Counsel. He is throughout the Company. Mr. Moreno serves as a member of the Board of Directors for the Business Council for International Understanding, a business association established at President Eisenhower's initiative in 1955 to promote international understanding between governmentDP&L and business executives. He also serves on the Board of the US-Kazakhstan Business Association. He is chairman of the Boards of Directors of Dayton Power and Light, and Indianapolis Power and Light, and serves on the Advisory Boards of AES companies in Bulgaria, the Dominican Republic and the Philippines. Previously, Brian served on other international Boards of Directors, including AES Chivor, AES' affiliate in Colombia, from 2013 through 2015; AES Entek, a joint venture, from 2008 through July of 2014, which was created to develop businesses in the energy sector in Turkey; and Silver Ridge, a joint venture between AES and Riverstone Holdings LLC, from 2008 through July of 2014, which was created to develop, manage and operate solar power business in Europe, Asia, Latin America and the United States. Tiete. Prior to joining AES he was counsel in the New York office of the law firm ChadbourneMr. Moreno worked for Ernst & Parke, LLP.Young. Mr. Miller receivedMoreno has a Bachelor's degree in HistoryBusiness Administration from Universidade Federal de Minas Gerais, Brazil and Economics from Boston Collegehas completed executive business and holds a Juris Doctorate fromleadership programs at the London Business School, Georgetown University and the University of Connecticut School Of Law.Virginia.
Thomas M. O'FlynnJulian Nebreda, 5752 years old, has served as EVPSenior Vice President and CFOPresident of the CompanySouth America SBU since September 2012. Previously,October 2018. Prior to assuming his current position Mr. O'FlynnNebreda served as Senior Advisorthe President of the AES Brazil SBU from April 2016 to October 2018, and President of the Private Equity GroupEurope SBU from June 2009 to April 2016. Prior to June 2009, Mr. Nebreda held several senior positions, such as Vice President for Central America and Caribbean, Chief Executive Officer of Blackstone, an investmentEDC and advisory groupPresident of AES Dominicana, in Santo Domingo, Dominican Republic. Mr. Nebreda serves as Chairman of the Board of AES Gener and AES Tiete. Before joining AES, Mr. Nebreda has held this position from 2010 to 2012. During this period, Mr. O'Flynn also served as COOpositions in the public and CFO of Transmission Developers, Inc., a Blackstone-controlled company that develops innovative power transmission projects in an environmentally responsible manner. From 2001 to 2009,private sectors, namely he served as Counsellor to the CFO of PSEG,Executive Director from Panama and Venezuela at the Inter-American Development Bank. Mr. Nebreda earned a New Jersey-based merchant power and utility company.law degree from Universidad Católica Andrés Bello in Caracas, Venezuela. He also earned a Master of Laws in Common Law with a Fulbright Fellowship and a Master of Laws in Securities and Financial Regulations, both from Georgetown University.
Gustavo Pimenta, 40 years old, was appointed Executive Vice President and Chief Financial Officer effective January 1, 2019. Prior to assuming his current position, Mr. Pimenta served as Deputy Chief Financial Officer from February 2018 to December 2018, Chief Financial Officer for the Company’s MCAC SBU from December 2014 to February 2018 and as Chief Financial Officer of AES Brazil from 2013 to December 2014. Prior to joining AES in 2009, Mr. Pimenta held various positions at Citigroup, including Vice President of PSEG Energy HoldingsStrategy and M&A in London and New York City. Mr. Pimenta received a Bachelor’s degree in Economics from 2007Universidade Federal de Minas Gerais and a Master’s degree in Economics and Finance from Fundação Getulio Vargas. He also participated in development programs in Finance, Strategy and Risk Management at New York University, University of Virginia’s Darden School of Business and Georgetown University.
Juan Ignacio Rubiolo, 42 years old, has served Senior Vice President and President of the MCAC SBU since March 2018. Previously Mr. Rubiolo served as the Chief Executive Officer of AES Mexico from 2014 to 2009. From 1986March 2018 and as a Vice President on the Commercial team of the MCAC SBU from 2013 to 2014. Mr. Rubiolo joined AES in 2001 Mr. O'Flynn wasand has worked in AES businesses in the Global PowerPhilippines, Argentina, Mexico, Panama and Utility Group of Morgan Stanley. He served as a Managing Director for his last five years and as head of the North American Power Group from 2000 to 2001. He was responsible for senior client relationships and led a number of large merger, financing, restructuring and advisory transactions.Dominican Republic. Mr. O'Flynn is the chairman of the IPALCO and AES US Investments Boards and previously served as a member ofRubiolo serves on the Boards of DP&LAES Gener, Itabo, AES Andres, and its parent company, DPL, Inc.AES Panama. Mr. O'Flynn served on the Board of Silver Ridge Power, a joint venture between AES and Riverstone Holdings LLC from September 2012 through July 2014. He is also currently on the Board of Directors of the New Jersey Performing Arts Center and was the inaugural Chairman of the Institute for Sustainability and Energy at Northwestern University, of which he is still an active Board member. Mr. O'FlynnRubiolo has a BAScience Degree in EconomicsBusiness from Northwesternthe Universidad Austral of Argentina, a Master of Project Management from the Quebec University in Canada and an MBA in Finance fromhas completed the executive business and leadership program at the University of Chicago.Virginia.
How to Contact AES and Sources of Other Information
Our principal offices are located at 4300 Wilson Boulevard, Arlington, Virginia 22203. Our telephone number is (703) 522-1315. Our website address is http://www.aes.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and any amendments to such reports filed pursuant to Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 (the "Exchange Act") are posted on our website. After the reports are filed with, or furnished to the SEC, they are available from us free of charge. Material contained on our website is not part of and is not incorporated by reference in this Form 10-K. You may also read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website that contains the reports, proxy and information statements and other information that we file electronically with the SEC at www.sec.gov.
Our CEO and our CFO have provided certifications to the SEC as required by Section 302 of the Sarbanes-Oxley Act of 2002. These certifications are included as exhibits to this Annual Report on Form 10-K.
Our CEO provided a certification pursuant to Section 303A of the New York Stock Exchange Listed Company Manual on May 13, 2016.8, 2018.
Our Code of Business Conduct ("Code of Conduct") and Corporate Governance Guidelines have been adopted by our Board of Directors. The Code of Conduct is intended to govern, as a requirement of employment, the actions of everyone who works at AES, including employees of our subsidiaries and affiliates. Our Ethics and Compliance Department provides training, information, and certification programs for AES employees related to the
Code of Conduct. The Ethics and Compliance Department also has programs in place to prevent and detect criminal conduct, promote an organizational culture that encourages ethical behavior and a commitment to compliance with the law, and to monitor and enforce AES policies on corruption, bribery, money laundering and associations with terrorists groups. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on our website. Any person may obtain a copy of the Code of Conduct or the Corporate Governance Guidelines without charge by making a written request to: Corporate Secretary, The AES Corporation, 4300 Wilson Boulevard, Arlington, VA 22203. If any amendments to, or waivers from, the Code of Conduct or the Corporate Governance Guidelines are made, we will disclose such amendments or waivers on our website.
ITEM 1A. RISK FACTORS
You should consider carefully the following risks, along with the other information contained in or incorporated by reference in this Form 10-K. Additional risks and uncertainties also may adversely affect our business and operations, including those discussed in Item 7.7.—Management's Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K. If any of the following events actually occur, our business, financial results and financial condition could be materially adversely affected.affected.
We routinely encounter and address risks, some of which may cause our future results to be different, sometimes materially different, than we presently anticipate. The categories of risk we have identified in Item 1A.—Risk Factors of this Form 10-K include the following:
risks related to our high level of indebtedness;
risks associated with our ability to raise needed capital;indebtedness and financial condition;
external risks associated with revenue and earnings volatility;
risks associated with our operations; and
risks associated with governmental regulation and laws.
These risk factors should be read in conjunction with Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations, and the Consolidated Financial Statements and related notes included elsewhere in this report.
Risks Related to our High Level of Indebtedness and Financial Condition
We have a significant amount of debt, a large percentage of which is secured, whichthat could adversely affect our business and theour ability to fulfill our obligations.
As of December 31, 2016,2018, we had approximately $20.5$19 billion of outstanding indebtedness on a consolidated basis. All outstanding borrowings, if any, under The AES Corporation's senior secured credit facility and secured term loan are secured by certain of our assets, including the pledge of capital stock of many of The AES Corporation's directly held subsidiaries. Most of the debt of The AES Corporation's subsidiaries is secured by substantially all of the assets of those subsidiaries. Since we have such a high level of debt, a substantial portion of cash flow from operations must be used to make payments on this debt. Furthermore, since a significant percentage of our assets are used to secure this debt, this reduces the amount of collateral that is available for future secured debt or credit support and reduces our flexibility in dealing withoperating these secured assets. This high level of indebtedness and related security could have other important consequences to us and our investors, including:
making it more difficult to satisfy debt service and other obligations at the holding company and/or individual subsidiaries;
increasing the likelihood of a downgrade of our debt, which could cause future debt costs and/or payments to increase under our debt and related hedging instruments and consume an even greater portion of cash flow;
increasing our vulnerability to general adverse industry and economic conditions, including but not limited to adverse changes in foreign exchange rates, interest rates and commodity prices;
reducing the availability ofavailable 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.
The agreements governing our indebtedness, including the indebtedness of our subsidiaries, limit, but do not prohibit the incurrence of additional indebtedness. To the extentIf we were to become more leveraged, the risks described
above would increase. Further, our actual cash requirements in the future may be greater than expected. Accordingly, our cash flows may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets, raise equity or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. In addition, our ability to refinance existing or future indebtedness will depend on the capital markets and our financial condition at such time. Any refinancing of our debt could come at higher interest rates or may require us to comply with onerous covenants, which could restrict our business operations. See Note 1110.—Debt included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for a schedule of our debt maturities. The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.
The AES Corporation is a holding company with no material assets other than the stock of its subsidiaries. All of The AES Corporation's revenue is generated through its subsidiaries. Accordingly, almostAlmost all of The AES Corporation's cash flow is generated by the operating activities of its subsidiaries. Therefore, The AES Corporation's ability to make payments on its indebtedness and to fund its other obligations is dependent not only on the ability of its subsidiaries to generate cash, but also on the ability of the subsidiaries to distribute cash to it in the form of dividends, fees, interest, tax sharing payments, loans or otherwise.
However, our subsidiaries face various restrictions in their ability to distribute cash to The AES Corporation. Most of the subsidiaries are obligated, pursuant to loan agreements, indentures or non-recourse financing arrangements, to satisfy certain restricted payment covenants or other conditions before they may make distributions to The AES Corporation. In addition, the payment of dividends or the making of loans, advances or other payments to The AES Corporation may be subject to other contractual, legal or regulatory restrictions or may be prohibited altogether. Business performance and local accounting and tax rules may also limit the amount of retained earnings that may be distributed to us as a dividend.dividend distributions. Subsidiaries in foreign countries may also be prevented from distributing funds to The AES Corporation as a result of foreign governments restricting the repatriation of funds or the conversion of currencies. Any right that The AES Corporation has to receive any assets of any of its subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, bankruptcy, insolvency or similar proceedings (and the consequent right of the holders of The AES Corporation's indebtedness to participate in the distribution of, or to realize proceeds from, those assets) will be effectively subordinated to the claims of any such subsidiary's creditors (including trade creditors and holders of debt issued by such subsidiary).
The AES Corporation's subsidiaries are separate and distinct legal entities and, unless they have expressly guaranteed any of The AES Corporation's indebtedness, have no obligation, contingent or otherwise, to pay any amounts due pursuant to such debt or to make any funds available whether by dividends, fees, loans or other payments.
Even though The AES Corporation is a holding company, existingExisting and potential future defaults by subsidiaries or affiliates could adversely affect The AES Corporation.
We attempt to finance our domestic and foreign projects primarily under loan agreements and related documents which,that, except as noted below, require the loans to be repaid solely from the project's revenues and provide that the repayment of the loans (and interest thereon) is secured solely by the capital stock, physical assets, contracts and cash flow of that project subsidiary or affiliate. This type of financing is usually referred to as
non-recourse debt or "non-recourse financing." In some non-recourse financings, The AES Corporation has explicitly agreed to undertake certain limited obligations and contingent liabilities, most of which by their terms will only be effective or will be terminated upon the occurrence of future events. These obligations and liabilities take the form of guarantees, indemnities, letters of credit, letter of credit reimbursement agreements and agreements to pay, in certain circumstances, the project lenders or other parties.
As of December 31, 2016,2018, we had approximately $20.5$19.3 billion of outstanding indebtedness on a consolidated basis, of which approximately $4.7$3.7 billion was recourse debt of The AES Corporation and approximately $15.8$15.6 billion was non-recourse debt. In addition, we have outstanding guarantees, indemnities, letters of credit, and other credit support commitments which are further described in this Form 10-K in Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Parent Company Liquidity.
Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total debt classified as current in our Consolidated Balance Sheets related to such defaults was $128$351 million as of December 31, 2016.2018. While the lenders under our non-recourse financings generally do not have direct recourse to The AES Corporation (other than to the extent of any credit support given by The AES Corporation), defaults thereunder can still have important consequences for The AES Corporation, including, without limitation:
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 hasmay have provided to or on behalf of such subsidiary;
causing The AES Corporation to record a loss in the event the lender forecloses on the assets;
triggering defaults in The AES Corporation's outstanding debt and trust preferred securities.debt. For example, The AES Corporation's senior secured credit facility, secured term loan, and outstanding senior notes include events of default for certain bankruptcy related events involving material subsidiaries. In addition, The AES Corporation's senior secured credit facility includes certain events of default relating to accelerations of outstanding material debt of material subsidiaries or any subsidiaries that in the aggregate constitute a material subsidiary;
the loss or impairment of investor confidence in the Company; or
foreclosure on the assets that are pledged under the non-recourse loans, thereforeresulting in write-downs of assets and eliminating any and all potential future benefits derived from those assets.
None of the projects that are currently in default are owned by subsidiaries that individually or in the aggregate meet the applicable standard of materiality in The AES Corporation's senior secured credit facility or other debt agreements in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. However, as a result of future mix of distributions, write-down of assets, dispositions and other matters that affect our financial position and results of operations, it is possible that one or more of these subsidiaries, individually or in the aggregate, could fall within the applicable standard of materiality and thereby upon an acceleration of such subsidiary's debt, trigger an event of default and possible acceleration of the indebtedness under The AES Corporation's senior secured credit facility or other indebtedness of The AES Corporation.
Risks Associated with our Ability to Raise Needed Capital
The AES Corporation, or the Parent Company, has significant cash requirements and limited sources of liquidity.
The AES Corporation requires cash primarily to fund:
principal repayments of debt;
interest and preferred dividends;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.
The AES Corporation's principal sources of liquidity are:
dividends and other distributions from its subsidiaries;
proceeds from debt and equity financings at the Parent Company level; and
proceeds from asset sales.
While we believe that these sources will be adequate to meet our obligations at the Parent Company level for the foreseeable future, this belief is based on a number of material assumptions, which could prove incorrect, including, without limitation, assumptions about our ability to access the capital or commercial lending markets, the operating and financial performance of our subsidiaries, exchange rates, our ability to sell assets, and the ability of our subsidiaries to pay dividends and other distributions. Any number of assumptions could prove to be incorrect, and, therefore thereThere can be no assurance that these sources will be available when needed or that our actual cash requirements will not be greater than expected. For example, in recent years, certain financial institutions have gone bankrupt. In the event that a bank who is party to our senior secured credit facility or other facilities goes bankrupt or is otherwise unable
to fund its commitments, we would need to replace that bank in our syndicate or risk a reduction in the size of the facility, which would reduce our liquidity. In addition, our cash flow may not be sufficient to repay at maturity the entire principal outstanding under our credit facility, term loan, and our debt securities and we may have to refinance such obligations. There can be no assurance that we will be successful in obtaining such refinancing on terms acceptable to us or at all and any of these events could have a material effect on us.
Our ability to grow our business could be materially adversely affected if we were unabledepends on our ability to raise capital on favorable terms.
From time to time, we rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. Our ability to arrange for financing on either a recourse or non-recourse basis and the costs of such capital are dependent on numerous factors, some of which are beyond our control, including:
general economic and capital market conditions;
the availability of bank credit;
investor confidence;
the financial condition, performance and prospects of The AES Corporation in general and/or that of any subsidiary requiring the financing as well asfinancing;
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.
Should future access to capital not be available to us, we may have to sell assets or decide not to build new plants, or expand or improve existing facilities, either of which would affect our future growth, results of operations or financial condition.
A downgrade in the credit ratings of The AES Corporation or its subsidiaries could adversely affect our abilityaccess to access the capital markets, which could increase our interest costs and/or adversely affect our liquidity and cash flow.
If any of the credit ratings of The AES Corporation or its subsidiaries were to be downgraded, our ability to raise capital on favorable terms could be impaired and our borrowing costs could increase. Furthermore, depending on The AES Corporation's credit ratings and the trading prices of its equity and debt securities, counterparties may no longer be as willing to accept general unsecured commitments by The AES Corporation to provide credit support. Accordingly, with respect to both new and existing commitments, The AES Corporation may be required to provide some other form of assurance, such as a letter of credit and/or collateral, to backstop or replace any credit support by The AES Corporation. There can be no assurance that such counterparties will accept such guarantees or that AES could arrange such further assurances in the future. In addition, to the extent The AES Corporation is required and able to provide letters of credit or other collateral to such counterparties, it will limit the amount of credit available to The AES Corporation to meet its other liquidity needs.
We may not be able to raise sufficient capital to fund developingdevelopment projects in certain less developed economies, which could change or in some cases adversely affect our growth strategy.
Part of our strategy is to grow our business by developing businesses in less developed economies where the return on our investment may be greater than projects in more developed economies. Commercial lending institutions sometimes refuse to provide non-recourse project financing in certain less developed economies, and in these situations we have sought and willmay continue to seek direct or indirect (through credit support or guarantees) project financing from a limited number of multilateral or bilateral international financial institutions or agencies. As a precondition to making such project financing available, the lending institutions may also require governmental guarantees for certain project and sovereign relatedsovereign-related risks. There can be no assurance, however, that project financing from the international financial agencies or that governmental guarantees will be available when needed,
and if they are not, we may have to abandon the relevant project or invest more of our own funds, which may not be in line with our investment objectives and would leave less funds for other projects.
External Risks Associated with Revenue and Earnings Volatility
Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance.markets.
Some of our businesses sell electricity in the spot markets in cases wherewhen they operate at levels in excess of their power sales agreements or retail load obligations.obligations or when they do not have any powers sales agreements. Our businesses may also buy electricity in the wholesale spot markets. As a result, we are exposed to the risks of rising and falling prices in those markets. The open market wholesale prices for electricity can be volatile and oftengenerally reflect the variable cost of the source generation which could include renewable sources at near zero pricing or thermal sources subject to fluctuating cost of fuels such as coal, natural gas
or oil derivative fuels in addition to other factors described below. Consequently, any changes in the generation supply stack and cost of coal, natural gas, or oil derivative fuels may impact the open market wholesale price of electricity.
Volatility in market prices for fuel and electricity may result from, among other things:
plant availability in the markets generally;
availability and effectiveness of transmission facilities owned and operated by third parties;
competition;
electricity usage;
seasonality;
foreign exchange rate fluctuation;
availability and price of emission credits;
hydrology and other weather conditions;
illiquid markets;
transmission, or transportation constraints, inefficiencies and/or inefficiencies;availability;
availability of competitively priced renewables sources;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, and coal;products;
generating unit performance;
natural disasters, terrorism, wars, embargoes, and other catastrophic events;
energy, market and environmental regulation, legislation and policies;
geopolitical concerns affecting global supply of oil and natural gas;
general economic conditions globally as well as in areas where we operate whichthat impact demand and energy consumption; and
bidding behavior and market bidding rules.
Adverse economic developments in China could have a negative impact on demand for electricity in many of our markets.
The Chinese market has been driving global materials demand and pricing for commodities over the past decade. Many of these commodities are produced in areas that are also our key markets for the sale of electricity. After experiencing rapid growth for more than a decade, China’s economy has experienced decreasing foreign and domestic demand, weak investment, factory overcapacity and oversupply in the property market, and has experienced a significant slowdown in recent years. U.S. tariffs are also expected to have a negative impact on China's economic growth. Continued slowing in China’s economic growth, demand for commodities and/or material changes in policy could result in lower economic growth and lower demand for electricity in our key markets, which could have a material adverse effect on our results of operations, financial condition and prospects.
Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.
Our exposure to currency exchange rate fluctuations results primarily from the translation exposure associated with the preparation of the Consolidated Financial Statements, as well as from transaction exposure associated with transactions in currencies other than an entity's functional currency. While the Consolidated Financial Statements are reported in U.S. Dollars,dollars, the financial statements of manyseveral of our subsidiaries outside the U.S.United States are prepared using the local currency as the functional currency and translated into U.S. Dollarsdollars by applying appropriate exchange rates. As a result, fluctuations in the exchange rate of the U.S. Dollardollar relative to the local currencies
where our subsidiaries outside the U.S.United States report could cause significant fluctuations in our results. In addition, while our expenses with respect to foreign operations are generally denominated in the same currency as corresponding sales, we have transaction exposure to the extent receipts and expenditures are not denominated in the subsidiary's functional currency. Moreover, the costs of doing business abroad may increase as a result of adverse exchange rate fluctuations. Our financial position and results of operations could be affected by fluctuations in the value of a number of currencies. See Item 7A.—Quantitative
Wholesale power prices are declining in many markets and Qualitative Disclosures about Market Riskthis could have a material adverse effect on our operations and opportunities for future growth.
The wholesale prices offered for electricity have declined significantly in recent years in many markets in which the Company has businesses. This price decline is due to this Form 10-Ka variety of factors, including the increased penetration of renewable generation resources, low-priced natural gas and demand side management. The levelized cost of electricity from new solar and wind generation sources has dropped substantially in recent years as solar panel costs and wind turbine costs have declined, while wind and solar capacity factors have increased. These renewable resources have no fuel costs and very low operational costs. In many instances, energy from these facilities are bid into the wholesale spot market at a price of zero or close to zero during certain times of the day, driving down the clearing price for further information.all generators selling power in the relevant spot market. Also, in many markets new PPAs have been awarded for renewable generation at prices significantly lower than the prices being awarded just a few years ago.
This trend of declining wholesale prices could continue and could have a material adverse impact on the financial performance of our existing generation assets to the extent they currently sell power into the spot market or will seek to sell power into the spot market once their PPAs expire. The trend of declining prices can also make it more difficult for us to obtain attractive prices under new long-term PPAs for any new generation facilities we may seek to develop. As a result, the trend can have an adverse impact on our opportunities for new investments.
We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.
We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity, fuel requirements and other commodities to lower our financial exposure related to commodity price fluctuations. As part of this strategy, we routinely utilize fixed price or indexed forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. We also enter into contracts which help us manage our interest rate exposure. However, we may not cover the entire exposure of our assets or positions to market price or interest rate volatility, and the coverage will vary over time. Furthermore, the risk management practices we have in place may not always perform as planned. In particular, if prices of commodities or interest rates significantly deviate from historical prices or interest rates or if the price or interest rate volatility or distribution of these changes deviates from historical norms, our risk management practices may not protect us from significant losses. As a result, fluctuating commodity prices or interest rates may negatively impact our financial results to the extent we have unhedged or inadequately hedged positions. In addition, certain types of economic hedging activities may not qualify for hedge accounting under U.S. GAAP, resulting in increased
volatility in our net income. The Company may also suffer losses associated with "basis risk"risk," which is the difference in performance between the hedge instrument and the targeted underlying exposure.exposure (usually the pricing node of the generation facility). Furthermore, there is a risk that the current counterparties to these arrangements may fail or are unable to perform part or all of their obligations under these arrangements.
Our coal-fired facilitiesarrangements, while we seek to protect against that by utilizing strong credit requirements and exchange trades, these protections may not fully cover the exposure in the U.S. continue to face substantial challenges asevent of a result of high coal prices relative to natural gas, particularly those which are merchant plants that are exposed to market risk and those that have hybrid merchant risk, meaning those businesses that have a PPA in place but purchase fuel at market prices or under short term contracts. counterparty default.
For our businesses with PPA pricing that does not perfectlycompletely pass through our fuel costs, the businesses attempt to manage the exposure through flexible fuel purchasing and timing of entry and terms of our fuel supply agreements; however, these risk management efforts may not be successful and the resulting commodity exposure could have a material impact on these businesses and/or our results of operations.
Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks.
We often rely on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of certainsome of our facilities. If these suppliers cannot perform, we would seek to meet our fuel requirements by purchasing fuel at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price, which could adversely impact the profitability of the affected business and our results of operations, and could result in a breach of agreements with other counterparties, including, without limitation, offtakers or lenders.
At times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility. We have also hedged a portion of our exposure to power price fluctuations through forward fixed price power sales. Counterparties to these agreements may breach or may be unable to perform their obligations.obligations, due to bankruptcy, insolvency, financial distress or other factors. Furthermore, in the event of a bankruptcy or similar insolvency-type proceeding, our counterparty can seek to reject our existing PPA under the U.S. Bankruptcy Code or similar bankruptcy laws, including those in Puerto Rico. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements, or at all. If we were unable to enter into replacement PPAs, these businesses may have to sell power at market prices. A breach by a counterparty of a PPA or other agreement could also result in the breach of other agreements, including, without limitation, the debt documents of the affected business.
The financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers. Any failure of anya supplier or customer to fulfill its contractual obligations to The AES Corporation or our subsidiaries could have a material adverse effect on our financial results. Consequently, the financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.
The market pricingprice of our common stock has been volatile and may continue to be volatile in future periods.volatile.
The market price for our common stock has been volatile in the past, and the pricetrading volumes of our common stock could fluctuate substantially in the future. Stock price movements on a quarter-by-quarter basis for the past two years are presented in Item 5.—Market—Market Information of this Form 10-K. Factors that could affect the price of our common stock in the future include, among other factors, general conditions in our industry inand the power markets in which we participate, and in the world, including environmental and economic developments, over which we have no control,and general credit and capital markets conditions, as well as developments specific to us, including risks that could result in revenue and earnings volatility, as well asfailing to meet our publicly announced guidance or other risk factors described in Item 1A.—Risk Factors and thosekey trends and other matters described in Item 7.—Management's Discussion and Analysis of Financial Conditions and Results of Operations.
Risks Associated with our Operations
We do a significant amount of business outside the U.S.,United States, including in developing countries, which presents significant risks.
A significant amount of our revenue is generated outside the U.S.United States and a significant portion of our international operations is conducted in developing countries. Part of our growth strategy is to expand our business in certain developing countries in which AES has an existing presence as suchpresence. We believe these countries may have higher growth rates and offer greater opportunities, to expand from our platforms, with potentially higher returns than in some more developed countries. 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;
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 fiscalenvironmental policies;
high inflation and monetary fluctuations;
restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;
threatened or consummated expropriation or nationalization of our assets by foreign governments;
unexpected delays in permitting and governmental approvals;
unexpected changes or instability affecting our strategic partners in developing countries;
risks relating to the failure to comply with the U.S. Foreign Corrupt Practices Act, United KingdomUK Bribery Act or other anti-bribery laws applicable to our operations;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;
difficulties in hiring, training and retaining qualified personnel, particularly finance and accounting personnel with GAAP expertise;
unwillingness of governments and their agencies, similar organizations or other counterparties to honor their contracts;
unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and economically unfavorableless 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;
difficulties in enforcing our contractual rights or enforcing judgments or obtaining a favorable result in local jurisdictions; and
potentially adverse tax consequences of operating in multiple jurisdictions.
Any of these factors, by itself or in combination with others, could materially and adversely affect our business, results of operations and financial condition. Our operations may experience volatility in revenues and operating margin 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 and currency devaluations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses. A number of our businesses are facing challenges associated with regulatory changes.
The operation of power generation, distribution and transmission facilities involves significant risks that could adversely affect our financial results. We and/or our subsidiaries may not have adequate risk mitigation and/or insurance coverage for liabilities.
We are in the business of generating and distributing electricity, which involves certain risks that can adversely affect financial and operating performance, including:
changes in the availability of our generation facilities or distribution systems due to increases in scheduled and unscheduled plant outages, equipment failure, failure of transmission systems, labor disputes, disruptions in fuel supply, poor hydrologic and wind conditions, inability to comply with regulatory or permit requirements or catastrophic events such as fires, floods, storms, hurricanes, earthquakes, dam failures, tsunamis, explosions, terrorist acts, cyber attacks or other similar occurrences; and
changes in our operating cost structure, including, but not limited to, increases in costs relating to gas, coal, oil and other fuel; fuel transportation; purchased electricity; operations, maintenance and repair; environmental compliance, including the cost of purchasing emissions offsets and capital expenditures to install environmental emission equipment; transmission access; and insurance.
Our businesses require reliable transportation sources (including related infrastructure such as roads, ports and rail), power sources and water sources to access and conduct operations. The availability and cost of this infrastructure affects capital and operating costs and levels of production and sales. Limitations, or interruptions in this infrastructure or at the facilities of our subsidiaries, including as a result of third parties intentionally or unintentionally disrupting this infrastructure or the facilities of our subsidiaries, could impede their ability to produce electricity. This could have a material adverse effect on our businesses' results of operations, financial condition and prospects.
In addition, a portion of our generation facilities were constructed many years ago. Older generating equipment may require significant capital expenditures for maintenance. The equipment at our plants, whether old or new, is also likely to require periodic upgrading, improvement or repair, and replacement equipment or parts may be difficult to obtain in circumstances where we rely on a single supplier or a small number of suppliers. The inability to obtain replacement equipment or parts may impact the ability of our plants to perform and could, therefore, have a material impact on our business and results of operations. Breakdown or failure of one of our operating facilities may prevent the facility from performing under applicable power sales agreements which, in certain situations, could result in termination of a power purchase or other agreement or incurrence of a liability for
liquidated damages and/or other penalties.
As a result of the above risks and other potential hazards associated with the power generation, distribution and transmission industries, we may from time to time become exposed to significant liabilities for which we may not have adequate risk mitigation and/or insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error or actions of third parties or other external events. The control and management of these risks depend upon adequate development and training of personnel and on the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems which reduce, but do not eliminate, the possibility of the occurrence and impact of these risks.
The hazards described above, along with other safety hazards associated with our operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties.
We and/or our subsidiaries may not have adequate risk mitigation and/or insurance coverage for liabilities.
Power generation, distribution and transmission involves hazardous activities. We may from time to time become exposed to significant liabilities for which we may not have adequate risk mitigation and/or insurance coverage. We maintain an amount of insurance protection that we believe is customary, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A claim for which we areOur insurance does not fully insured or insuredcover every potential risk associated with our operations. Adequate coverage at all could hurt our financial resultsreasonable rates is not always obtainable and materially harm our financial condition. Further, due to the cyclical nature of the insurance markets, we cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently available to us or at all. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.
Our businesses' insurance does not cover every potential risk associated with its operations. Adequate coverage at reasonable rates is not always obtainable. In addition, insurance may not fully cover the liability or the consequences of any business interruptions such as equipment failure or labor dispute.
The occurrence of a significant adverse event not fully or partially covered by insurance could have a material adverse effect on the Company'sour business, results or operations, financial condition, and prospects.
Any of the above risks could have a material adverse effect on our business and results of operations.
We may not be able to attract and retain skilled people, which could have a material adverse effect on our operations.
Our operating success and ability to carry out growth initiatives depends in part on our ability to retain executives and to attract and retain additional qualified personnel who have experience in our industry and in operating a company of our size and complexity, including people in our foreign businesses. The inability to attract and retain qualified personnel could have a material adverse effect on our business, because of the difficulty of promptly finding qualified replacements. For example, we routinely are required to assess the financial impacts of complicated business transactions which occur on a worldwide basis. These assessments are dependent on hiring personnel on a worldwide basis with sufficient expertise in U.S. GAAP to timely and accurately comply with U.S. reporting obligations. An inability to maintain adequate internal accounting and managerial controls and hire and retain qualified personnel could have an adverse effect on our financial and tax reporting.
We have contractual obligations to certain customers to provide full requirements service, which makes it difficult to predict and plan for load requirements and may result in increased operating costs to certain of our businesses.
We have contractual obligations to certain customers to supply power to satisfy all or a portion of their energy requirements. The uncertainty regarding the amount of power that our power generation and distribution facilities must be prepared to supply to customers may increase our operating costs. A significant under- or over-estimation of load requirements could result in our facilities not having enough or having too much power to cover their obligations, in which case we would be required to buy or sell power from or to third parties at prevailing market prices. Those prices may not be favorable and thus could increase our operating costs.
We may not be able to enter into long-term contracts whichthat reduce volatility in our results of operations. Even when we successfully enter into long-term contracts, our generation businesses are often dependent on one or a limited number of customers and a limited number of fuel suppliers.
Many of our generation plants conduct business under long-term sales and supply contracts, which helps these businesses to manage risks by reducing the volatility associated with power and input costs and providing a
stable revenue and cost structure. In these instances, we rely on power sales contracts with one or a limited number of customers for the majority of, and in some cases all of, the relevant plant's output and revenues over the term of the power sales contract. The remaining terms of the power sales contracts of our generation plants range from one to 25more than 20 years. In many cases, we also limit our exposure to fluctuations in fuel prices by entering into long-term contracts for fuel with a limited number of suppliers. In these instances, the cash flows and results of operations are dependent on the continued ability of customers and suppliers to meet their obligations under the relevant power sales contract or fuel supply contract, respectively. Some of our long-term power sales agreements are at prices above current spot market prices and some of our long-term fuel supply contracts are at prices below current market prices. The loss of significant power sales contracts or fuel supply contracts, or the failure by any of the parties to such contracts that prevents us from fulfilling our obligations thereunder, could adversely impact our strategy by resulting in costs that exceed revenue, which could have a material adverse impact on our business, results of operations and financial condition. In addition, depending on market conditions and regulatory regimes, it may be difficult for us to secure long-term contracts, either where our current contracts are expiring or for new development projects. The inability to enter into long-term contracts could require many of our businesses to purchase inputs at market prices and sell electricity into spot markets, which may not be favorable.
We have sought to reduce counterparty credit risk under our long-term contracts in part by entering into power sales contracts with utilities or other customers of strong credit quality and by obtaining guarantees from certain sovereign governments of the customer's obligations. However, many of our customers do not have, or have failed to maintain, an investment-grade credit rating, and our generation business cannot always obtain government guarantees and if they do, the government does not always have an investment grade credit rating. We have also sought to reduce our credit risk by locating our plants in different geographic areas in order to mitigate the effects of regional economic downturns. However,downturns; however, there can be no assurance that our efforts to mitigate this risk will be successful.
Competition is increasing and could adversely affect us.
The power production markets in which we operate are characterized by numerous strong and capable competitors, many of whom may have extensive and diversified developmental or operating experience (including both domestic and international) and financial resources similar to, or greater than, ours. Further, in recent years, the power production industry has been characterized by strong and increasing competition with respect to both obtaining power sales agreements and acquiring existing power generation assets. In certain markets, these factors have caused reductions in prices contained in new power sales agreements and, in many cases, have caused higher acquisition prices for existing assets through competitive bidding practices. The evolution of competitive electricity markets and the development of highly efficient gas-fired power plants and renewables such as wind and solar have also caused, or are anticipatedand could continue to cause, price pressure in certain power markets where we sell or intend to sell power. These competitive factorsIn addition, the introduction of low-cost disruptive technologies or the entry of non-traditional competitors into our sector and markets could adversely affect our ability to compete, which could have a material adverse effect on us.our businesses, operating results and financial condition.
SomeOur businesses will need to continue to adapt to technological change and we may incur significant expenditures to adapt to these changes.
Emerging technologies may be superior to, or may not be compatible with, some of our subsidiaries participate in defined benefit pension plansexisting technologies, investments and their net pension plan obligationsinfrastructure, and may require additionalus to make significant contributions.expenditures to remain competitive, or may result in the obsolescence of certain of our operating assets. Our future success will depend, in part, on our ability to anticipate and successfully adapt to technological changes, to offer services and products that meet customer demands and evolving industry standards.
Technological changes that could impact our businesses include:
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.
Emerging technologies may also allow new competitors to more effectively compete in our markets or disintermediate the services we provide our customers, including traditional utility and centralized generation services. If we incur significant expenditures in adapting to technological changes, fail to adapt to significant technological changes, fail to obtain access to important new technologies, fail to recover a significant portion of any remaining investment in obsolete assets, or if implemented technology fails to operate as intended, our businesses, operating results and financial condition could be materially adversely affected.
Certain of our subsidiariesbusinesses are sensitive to variations in weather and hydrology.
Our businesses are affected by variations in general weather patterns and unusually severe weather. Our businesses forecast electric sales based on best available information and expectations for weather, which represents a long-term historical average. While we also consider possible variations in normal weather patterns and potential impacts on our facilities and our businesses, there can be no assurance that such planning can prevent these impacts, which can adversely affect our business. Generally, demand for electricity peaks in winter and summer. Typically, when winters are warmer than expected and summers are cooler than expected, demand for energy is lower, resulting in less demand for electricity than forecasted. Significant variations from normal weather where our businesses are located could have defined benefit pension plans covering substantially alla material impact on our results of their respective employees. Ofoperations.
Changes in weather can also affect the thirty one such defined benefit plans, fiveproduction of electricity at power generation facilities, including, but not limited to, our wind and solar facilities. For example, the level of wind resource affects the revenue produced by wind generation facilities. Because the levels of wind and solar resources are variable and difficult to predict, our results of operations for individual wind and solar facilities specifically, and our results of operations generally, may vary significantly from period to period, depending on the level of available resources. To the extent that resources are not available at U.S. subsidiariesplanned levels, the financial results from these facilities may be less than expected.
In addition, we are dependent upon hydrological conditions prevailing from time to time in the broad geographic regions in which our hydroelectric generation facilities are located. Changes in temperature, precipitation and snow pack conditions also could affect the amount and timing of hydroelectric generation.
If hydrological conditions result in droughts or other conditions that negatively affect our hydroelectric generation business, our results of operations could be materially adversely affected. Additionally, our contracts in certain markets where hydroelectric facilities are prevalent may require us to purchase power in the spot markets when our facilities are unable to operate (or operate at lower than anticipated levels) and the remaining plans areprice of such spot power may increase substantially in times of low hydrology.
Severe weather and natural disasters may present significant risks to our business and adversely affect our financial results.
Weather conditions directly influence the demand for electricity and natural gas and other fuels and affect the price of energy and energy-related commodities. In addition, severe weather and natural disasters, such as hurricanes, floods, tornadoes, icing events, earthquakes, dam failures and tsunamis can be destructive and could prevent us from operating our business in the normal course by causing power outages and property damage, reducing revenue, affecting the availability of fuel and water, causing injuries and loss of life, and requiring us to incur additional costs, for example, to restore service and repair damaged facilities, to obtain replacement power and to access available financing sources. Our power plants could be placed at foreign subsidiaries. Pension costs are based upon a numbergreater risk of actuarial assumptions, including an expected long-term rate of return on pension plan assets,damage should changes in the expected life span of pension plan beneficiariesglobal climate produce unusual variations in temperature and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be wrong,weather patterns, resulting in a shortfallmore intense, frequent and extreme weather events, including heatwaves, fewer cold temperature extremes, abnormal levels of pension plan assets comparedprecipitation resulting in
river and coastal urban floods in North America or reduced water availability and increased flooding across Central and South America, and changes in coast lines due to pension obligations undersea level change.
Depending on the pension plan. The Company periodically evaluates the valuenature and location of the pension plan assetsfacilities and infrastructure affected, any such incident also could cause catastrophic fires; releases of natural gas, natural gas odorant, or other greenhouse gases; explosions, spills or other significant damage to ensurenatural resources or property belonging to third parties; personal injuries, health impacts or fatalities; or present a nuisance to impacted communities. Such incidents that they will be sufficientdo not directly affect our facilities may impact our business partners, supply chains and transportation, which could negatively impact construction projects and our ability to fund the respective pension obligations. The Company's exposureprovide electricity and natural gas to market volatility is mitigated to some extent due to the fact that the asset allocations in our largest plans include a significant weightingcustomers.
A disruption or failure of investments in fixed income securities that are less volatile than investments in equity securities. Future downturnselectric generation, transmission or distribution systems or natural gas production, transmission, storage or distribution systems in the debt and/event of a hurricane, tornado or equity markets,other severe weather event, or otherwise, could prevent us from operating our business in the inaccuracy of any of our significant assumptions underlying the estimates of our subsidiaries' pension plan obligations,normal course and could result in an increase in pension expenseany of the adverse consequences described above. At our businesses where cost recovery is available, recovery of costs to restore service and future funding requirements, whichrepair damaged facilities is or may be material. Our subsidiaries who participate in these plans are responsible for satisfyingsubject to regulatory approval, and any determination by the funding requirements required by law in their respective jurisdiction for any shortfall of pension plan assets comparedregulator not to pension obligations under the pension plan. This may necessitate additional cash contributions to the pension plans that could adversely affect the Parent Companypermit timely and our subsidiaries' liquidity.
For additional information regarding the funding positionfull recovery of the Company's pension plans, see Item 7.—Management's Discussioncosts incurred.
Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, reputation and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Pension and Other Postretirement Plans and Note 15—Benefit Plans included in Item 8.—Financial Statements and Supplementary Data included in this Form 10-K.
prospects.
Our business isdevelopment projects are subject to substantial development uncertainties.
Certain of our subsidiaries and affiliates are in various stages of developing and constructing power plants, someplants. Some but not all of whichthese power plant projects have signed long-term contracts or made similar arrangements for the sale of electricity. Successful completion of the development of these projects depends upon overcoming substantial risks, including, but not limited to, risks relating to siting, financing, engineering and construction, permitting, governmental approvals, commissioning delays, or the potential for termination of the power sales contract as a result of a failure to meet certain milestones. For additional information regarding our projects under construction see Item 1.—Business—Business—Our Organization and Segments included in this Form 10-K. In certain cases, our subsidiaries may enter into obligations in the development process even though the subsidiaries have not yet secured financing, power purchase arrangements, or other aspects of the development process.important elements for a successful project. For example, in certain cases, our subsidiaries may instruct contractors to begin the construction process or seek to procure equipment even where they do not have financing, a PPA or a power purchase agreementcritical permits in place (or conversely, to enter into a power purchase,PPA, procurement agreement or other agreement without financing in place). If the project does not proceed, our subsidiaries may remain obligated for certain liabilities even though the project will not proceed. Development is inherently uncertain and we may forgo certain development opportunities and we may undertake significant development costs before determining that we will not proceed with a particular project. We believe that capitalized costs for projects under development are recoverable; however, there can be no assurance that any individual project will be completed and reach commercial operation. If these development efforts are not successful, we may abandon a project under development and write off the costs incurred in connection with such project. At the time of abandonment, we would expense all capitalized development costs incurred in connection therewith and could incur additional losses associated with any related contingent liabilities.
In someWe do not control certain aspects of our joint venture projects and businesses, we have granted protective rights to minority shareholders or we own less than a majority of the equity in the project or business and do not manage or otherwise control the project or business, which entails certain risks.ventures.
We have invested in some joint ventures wherein which our subsidiaries share operational, management, investment and/or other control rights with our joint venture partners. In many cases, we may exert influence over the joint venture pursuant to a management contract, by holding positions on the board of the joint venture company or on management committees and/or through certain limited governance rights, such as rights to veto significant actions. However, we do not always have this type of influence over the project or business in every instance and we may be dependent on our joint venture partners or the management team of the joint venture to operate, manage, invest or otherwise control such projects or businesses. Our joint venture partners or the management team of our joint ventures may not have the level of experience, technical expertise, human resources, management and other attributes necessary to operate these projects or businesses optimally, and they may not share our business priorities. In some joint venture agreements wherein which we do have majority control of the voting securities, we have entered into shareholder agreements granting protective minority rights to the other shareholders.
The approval of joint venture partners also may be required for us to receive distributions of funds from jointly owned entities or to transfer our interest in projects or businesses. The control or influence exerted by our joint venture partners may result in operational management and/or investment decisions whichthat are different from the decisions our subsidiaries would make if they operated independently and could impact the profitability and value of these joint ventures. In addition, in the event that a joint venture partner becomes insolvent or bankrupt or is
otherwise unable to meet its obligations to the joint venture or its share of liabilities at the joint venture, we may be subject to joint and several liability for these joint ventures, which means that we may be responsible for meeting certain obligations of the joint ventures, should our joint venture partner be unable to do so, if and to the extent provided for in our governing documents or applicable law.
Our renewable energy projects and other initiatives face considerable uncertainties, including development, operational, and regulatory challenges.
Wind, generation, our solar, projects and our investments in projects such as energy storage projects are subject to substantial risks. Projects of this nature have been developed through advancement in technologies which may not be proven or whose commercial application is limited, and which are unrelated to our core business. Some of these business lines are dependent upon favorable regulatory incentives to support continued investment, and there is significant uncertainty about the extent to which such favorable regulatory incentives will be available in the future.
Furthermore, production levels for our wind and solar projects may be dependent upon adequate wind or sunlight resulting in volatility in production levels and profitability. For example, for our wind projects, wind resource estimates are based on historical experience when available and on wind resource studies conducted by an independent engineer, andengineer. These wind resource estimates are not expected to reflect actual wind energy production in any given year.
year, but long-term averages of a resource.
As a result, these types of renewable energy projects face considerable risk, relative to our core business, including the risk that favorable regulatory regimes expire or are adversely modified. In addition, because certain of these projects depend on technology outside of our expertise in generation and utility businesses, there are risks associated with our ability to develop and manage such projects profitably. Furthermore, at the development or acquisition stage, because of the nascent nature of these industries or theour more limited experience with the relevant technologies, our ability to predict actual performance results may be hindered and the projects may not perform as predicted. There are also risks associated with the fact that some of these projects exist in markets where long-term fixed price contracts for the major cost and revenue components may be unavailable, which in turn may result in these projects having relatively high levels of volatility. Even where available, many of our renewable projects sell power under a Feed-in-Tariff, which may be eliminated or reduced, which can impact the profitability of these projects, or make money through the sale of Emission Reductions products, such as Certified Emissions Reductions, Renewable Energy Certificates or Renewable Obligation Certificates, and the price of these products may be volatile. These projects can be capital-intensive and generally are designed with a view to obtaining third partythird-party financing, which may be difficult to obtain. As a result, these capital constraints may reduce our ability to develop these projects or obtain third partythird-party financing for these projects.
Government incentives and policies that support the development of renewable energy generation projects could change at any time.
AES’ U.S. renewable energy generation growth strategy depends in part on federal, state and local government policies and incentives that support the development, financing, ownership and operation of renewable energy generation projects. These policies and incentives include investment tax credits, production tax credits, accelerated depreciation, renewable portfolio standards, feed-in-tariffs and similar programs, renewable energy credit mechanisms, and tax exemptions. If these policies and incentives are changed or eliminated, or AES is unable to use them, it could result in a material adverse impact on AES’ U.S. renewable growth opportunities, including fewer future PPAs or lower prices for the sale of power in future PPAs, decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing.
We may not be able to attract and retain skilled people, which could have a material adverse effect on our operations.
Our operating success and ability to carry out growth initiatives depends, in part, on our ability to retain executives and to attract and retain additional qualified personnel who have experience in our industry and in operating a company of our size and complexity, including people in our foreign businesses. The inability to attract and retain qualified personnel could have a material adverse effect on our business, because of the difficulty of promptly finding qualified replacements. For example, we routinely assess the financial impacts of complicated business transactions that occur on a worldwide basis. These assessments are dependent on hiring personnel on a worldwide basis with sufficient expertise in U.S. GAAP to timely and accurately comply with U.S. reporting obligations. An inability to maintain adequate internal accounting and managerial controls and hire and retain qualified personnel could have an adverse effect on our financial and tax reporting.
Cyber-attacks and data security breaches could harm our business.
Our business is heavily reliant on electronic systems and network technologies to operate our generation, transmission and distribution infrastructure. We also use various financial, accounting and other infrastructure systems. Our infrastructure may be targeted by nation states, hacktivists, criminals, insiders or terrorist groups. Such an attack, by hacking, malware or other means, may interrupt our operations, cause property damage, affect our ability to control our infrastructure assets, cause the release of sensitive customer information or limit
communications with third parties. Any loss or corruption of confidential or proprietary data through such breach may:
impair our reputation;
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; and
require extensive repair and restoration costs for additional security measures to avert future cyber-attacks.
In addition, a breach of our financial and accounting systems could impact our ability to correctly record, process and report financial information.
In addition, in the ordinary course of business, we collect and retain sensitive information, including personal identification information about customers and employees, customer energy usage and other information. The theft, damage or improper disclosure of sensitive electronic data can subject us to penalties for violation of applicable privacy laws, subject us to claims from third parties, require compliance with notification and monitoring regulations, and harm our reputation. The EU GDPR recently came into force and applies to the processing of personal information collected from individuals located in the EU. The GDPR creates new compliance obligations and significantly increases fines for noncompliance.
We have implemented measures to help prevent unauthorized access to our systems and facilities, including certain measures to comply with mandatory regulatory reliability standards. To date, cyber-attacks on our business and operations have not had a material impact on our operations or financial results. We continue to assess potential threats and vulnerabilities and make investments to address them, including global monitoring of networks and systems, identifying and implementing new technology, improving user awareness through employee security training, and updating our security policies as well as those for third-party providers. We cannot guarantee the extent to which our security measures will prevent future cyber-attacks and security breaches or that our insurance coverage will adequately cover any losses we may experience.
Our utilities businesses may be negatively affected by a lack of growth or slower growth in the number of customers or in customer usage.
Customer growth and customer usage in our utilities businesses are affected by a number of factors outside our control, such as mandated energy efficiency measures, demand side management requirements, and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. A lack of growth, or a decline, in the number of customers or in customer demand for electricity may cause us to fail to fully realize the anticipated benefits from significant investments and expenditures and could have a material adverse effect on our growth, business, financial condition, results of operations and prospects.
Some of our subsidiaries participate in defined benefit pension plans and their net pension plan obligations may require additional significant contributions.
We have 30 defined benefit plans, five at U.S. subsidiaries and the remaining plans at foreign subsidiaries, which cover substantially all of the employees at these subsidiaries. Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be incorrect, resulting in a shortfall of pension plan assets compared to pension obligations under the pension plan. We periodically evaluate the value of the pension plan assets to ensure that they will be sufficient to fund the respective pension obligations. Our exposure to market volatility is mitigated to some extent due to the fact that the asset allocations in our largest plans include a significant weighting of investments in fixed income securities that are generally less volatile than investments in equity securities. Future downturns in the debt and/or equity markets, or the inaccuracy of any of our significant assumptions underlying the estimates of our subsidiaries' pension plan obligations, could result in an increase in pension expense and future funding requirements, which may be material. Our subsidiaries that participate in these plans are responsible for satisfying the funding requirements required by law in their respective jurisdictions for any shortfall of pension plan assets as compared to pension obligations under the pension plan. Satisfying such funding requirements may necessitate additional cash contributions to the pension plans that could adversely affect the Parent Company and our subsidiaries' liquidity. For additional information regarding the funding position of the Company's pension plans, see Item 7.—Management's Discussion and Analysis of Financial Condition and Results
Impairment of goodwill or long-lived assets would negatively impact our consolidated results of operations and net worth.
As of December 31, 2016,2018, the Company had approximately $1.2$1.1 billion of goodwill, which represented approximately 3.2%3% of the total assets on its Consolidated Balance Sheets. Goodwill is not amortized, but is evaluated for impairment at least annually, or more frequently if impairment indicators are present. We may be required to evaluate the potential impairment of goodwill outside of the required annual evaluation process if we experience situations, including but not limited to: deterioration in general economic conditions, or our operating or regulatory environment; increased competitive environment; lower forecasted revenue; increase in fuel costs, particularly when we are unable to pass through the impact to customers; increase in environmental compliance costs; negative or declining cash flows; loss of a key contract or customer, particularly when we are unable to replace it on equally favorable terms; developments in our strategy; divestiture of a significant component of our business; or adverse actions or assessments by a regulator. For example, during the annual goodwill impairment test performed as of October 1, 2018, the Company determined that the fair value of its Gener reporting unit exceeded its carrying value by 7%. Therefore, Gener's $868 million goodwill balance was considered to be "at risk" for impairment as of December 31, 2018 largely due to the fact that a market participant would no longer assume perpetual cash flows from coal-fired power plants due to the increased penetration of renewable energy in Chile. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Impairments. These types of events and the resulting analyses could result in goodwill impairment, which could substantially affect our results of operations for those periods. Additionally, goodwill may be impaired if our acquisitions do not perform as expected. See the risk factor Our acquisitions may not perform as expected for further discussion.
Long-lived assets are initially recorded at fair value and are amortized or depreciated over their estimated useful lives. Long-lived assets are evaluated for impairment only when impairment indicators, similar to those described above for goodwill, are present, whereas goodwill is also evaluated for impairment on an annual basis.
CertainAny of our businesses are sensitive to variations in weather.
Our businesses are affected by variations in general weather patterns and unusually severe weather. Our businesses forecast electric sales on the basis of normal weather, which represents a long-term historical average. While we also consider possible variations in normal weather patterns and potential impacts on our facilities and our businesses, there can be no assurance that such planning can prevent these impacts, which can adversely affect our business. Generally, demand for electricity peaks in winter and summer. Typically, when winters are warmer than expected and summers are cooler than expected, demand for energy is lower, resulting in less demand for electricity than forecasted. Significant variations from normal weather where our businesses are locatedforegoing could have a material impactadverse effect on our results of operations.
In addition, we are dependent upon hydrological conditions prevailing from time to time in the broad geographic regions in which our hydroelectric generation facilities are located. If hydrological conditions result in droughts or other conditions that negatively affect our hydroelectric generation business, ourfinancial condition, results of operations, could be materially adversely affected.
Information security breaches could harm our business.
A security breach of our information technology systems or plant control systems used to manage and monitor operations could impact the reliability of our generation fleets and/or the reliability of our transmission and distribution systems. A security breach that impairs our technology infrastructure could disrupt normal business operations and affect our ability to control our transmission and distribution assets, access customer information and limit our communications with third parties. Our security measures may not prevent such security breaches. Any loss or corruption of confidential or proprietary data through a breach could impair our reputation, expose us to legal claims, or impact our ability to make collections or otherwise impact our operations, and materially adversely affect our business and results of operations.
prospects.
Our acquisitions may not perform as expected.
Historically, acquisitions have been a significant part of our growth strategy. We may continue to grow our business through acquisitions. Although acquired businesses may have significant operating histories, we will have a limited or no history of owning and operating many of these businesses and possibly limited or no experience operating in the country or region where these businesses are located. Some of these businesses may have been government owned and some may be operated as part of a larger integrated utility prior to their acquisition. If we were to acquire any of these types of businesses, there can be no assurance that:
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.
Risks associated with Governmental Regulation and Laws
Our operations are subject to significant government regulation and our business and results of operations could be adversely affected by changes in the law or regulatory schemes.
Our ability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any ability to obtain expected or contracted increases in electricity tariff or contract rates 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 at our utilities 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 to be included in the rates we charge our customers, including but not limited to costs incurred to upgrade our power plants to comply with more stringent environmental regulations;
changes in the determination of what is an appropriate rate of return on invested capital or a determination that a utility's operating income or the rates it charges customers are too high, resulting in a reduction of rates or consumer rebates;
changes in the definition or determination of controllable or non-controllable costs;
adverse changes in tax law;
changes in law or regulation which limit or otherwise affect the ability of our counterparties (including sovereign or private parties) to fulfill their obligations (including payment obligations) to us or our subsidiaries;
changes in environmental law which impose additional costs or limit the dispatch of our generating facilities within our subsidiaries;
changes in the definition of events which may or may not qualify as changes in economic equilibrium;
changes in the timing of tariff increases;
other changes in the regulatory determinations under the relevant concessions;
other changes related to licensing or permitting which affect our ability to conduct business; or
other changes that impact the shortshort- or long termlong-term price-setting mechanism in the markets where we operate.
Any of the above events may result in lower operating margins for the affected businesses, which can adversely affect our business.
In many countries where we conduct business, the regulatory environment is constantly changing and it may be difficult to predict the impact of the regulations on our businesses. On July 21, 2010, President Obama signed the Dodd-Frank Act. While the bulk of regulations contained in the Dodd-Frank Act regulate financial institutions and their products, there are several provisions related to corporate governance, executive compensation, disclosure and other matters which relate to public companies generally. The types of provisions described above are currently not expected to have a material impact on the Company or its results of operations. Furthermore, while the Dodd-Frank Act substantially expands the regulation regarding the trading, clearing and reporting of derivative transactions, the Dodd-Frank Act provides for commercial end-user exemptions which may apply to our derivative transactions. However, even with the exemption, the Dodd-Frank Act could still have a material adverse impact on
the Company, as the regulation of derivatives (which includes capital and margin requirements for non-exempt companies), could limit the availability of derivative transactions that we use to reduce interest rate, commodity and currency risks, which would increase our exposure to these risks. Even if derivative transactions remain available, the costs to enter into these transactions may increase, which could adversely (1) affect the operating results of certain projects; (2) cause us to default on certain types of contracts where we are contractually obligated to hedge certain risks, such as project financing agreements; (3) prevent us from developing new projects where interest rate hedging is required; (4) cause the Company to abandon certain of its hedging strategies and transactions, thereby increasing our exposure to interest rate, commodity and currency risk; (5) and/or consume substantial liquidity by forcing the Company to post cash and/or other permitted collateral in support of these derivatives. In addition to the Dodd-Frank Act, in 2012, the EMIR became effective. EMIR includes regulations related to the trading, reporting and clearing of derivatives and the impacts described above could also result from our (or our subsidiaries') efforts to comply with EMIR.European Market Infrastructure Regulation, which includes regulations related to the trading, reporting and clearing of derivatives. It is also possible that additional similar regulations may be passed in other jurisdictions where we conduct business. Any of these outcomes could have a material adverse effect on the Company.
Several of our businesses are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR.
CCR, which consists of bottom ash, fly ash and air pollution control wastes generated at our current and former coal-fired generation plant sites, is currently handled and/or has been handled in the past in the following ways: placement in onsite CCR ponds; disposal and beneficial use in onsite and offsite permitted, engineered landfills; use in various beneficial use applications, including encapsulated uses and structural fill; and used in permitted offsite mine reclamation. CCR currently remains onsite at several of our facilities, including in CCR ponds. The U.S. EPA's final CCR rule, which became effective in October 2015, regulates CCR as nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR ponds, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. On December 16, 2016, President Obama signed the WIN Act into law, which includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. The primary enforcement mechanisms under this regulation could be actions commenced by U.S. EPA, states, or territories, and private lawsuits. Compliance with the U.S. federal CCR rule; amendments to the federal CCR rule; or federal, state, territory, or foreign rules or programs addressing CCR may require us to incur substantial costs. In addition, the Company and our businesses may face CCR-related lawsuits in the United States and/or internationally that may expose us to unexpected potential liabilities. Furthermore, CCR-related litigation may also expose us to unexpected costs. In addition, CCR, and its production at several of our facilities, have been the subject of significant interest from environmental non-governmental organizations and have received national and local media attention. The direct and indirect effects of such media attention, and the demands of responding to and addressing it, may divert management time and attention. Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, reputation and prospects.
Our business in the United States is subject to the provisions of various laws and regulations administered in whole or in part by the FERC and NERC, including PURPA, the Federal Power Act, and the EPAct 2005. Actions by the FERC, NERC and by state utility commissions can have a material effect on our operations.
EPActThe AES Corporation is a registered electric holding company under the 2005 authorizes the FERC to remove the obligation of electric utilities under Section 210 of PURPA to enter into new contracts for the purchase or sale of electricity from or to QFs if certain market conditions are met. Pursuant to this authority, the FERC has instituted a rebuttable presumption that utilities located within the control areasPUHCA as enacted as part of the Midwest Independent Transmission System Operator, Inc., PJM Interconnection, L.L.C., ISO New England, Inc., the NYISO and the Electric Reliability Council of Texas, Inc. are not required to purchase or sell power from or to QFs above a certain size. In addition, the FERC is authorized under EPAct 2005. PUHCA 2005 to remove the purchase/sale obligations of individual utilities on a case-by-case basis. While this law does not affect existing contracts, as a resulteliminated many of the changesrestrictions that had been in place under the 1935 PUCHA, while continuing to PURPA, our QFs may face a more difficult market environment when their current long-term contracts expire.
EPAct 2005 repealed PUHCA 1935 and enacted PUHCA 2005 in its place. PUHCA 1935 had the effect of requiring utility holding companies to operate in geographically proximate regions and therefore limited the range of potential combinations and mergers among utilities. By comparison, PUHCA 2005 has no such restrictions and simply provides theprovide FERC and state utility commissions with enhanced access to the books and records of certain utility holding companies. The repeal of PUHCA 1935 removed2005 also creates additional potential challenges and opportunities. By removing some barriers to mergers and other potential combinations, which could result in the creation of large, geographically dispersed utility holding companies.companies is more likely. These entities may have enhanced financial strength and therefore an increased ability to compete with us in the U.S. generation market.
Other parts of the EPAct 2005 allow FERC to remove the PURPA purchase/sale obligations from utilities if there are adequate opportunities to sell into competitive markets. FERC has exercised this power with a rebuttable presumption that utilities located within the control areas of MISO, PJM, ISO New England, Inc., the New York Independent System Operator, Inc., and ERCOT are not required to purchase or sell power from or to QFs above a certain size. Additionally, FERC has the power to remove the purchase/sale obligations of individual utilities on a case-by-case basis. While these changes do not affect existing contracts, certain of our QFs that have had sales contracts expire are now facing a more difficult market environment and that is likely to continue for other AES QFs with existing contracts that will expire over time.
In accordance with Congressional mandates in the EPAct 1992 and now inthe EPAct 2005, the FERC has strongly encouraged competition in wholesale electric markets. Increased competition may have the effect of lowering our operating margins. Among other steps, the FERC has encouraged RTOs and ISOs to develop demand response bidding programs as a mechanism for responding to peak electric demand. These programs may reduce the value of our peaking assets which rely on very high prices during a relatively small number of hours to recover their costs.generation assets. Similarly, the FERC is encouraging the construction of new transmission infrastructure in accordance with provisions of EPAct 2005. Although new transmission lines may increase market opportunities, they may also increase the competition in our existing markets.
While the FERC continues to promote competition, some state utility commissions have reversed course and begun to encourage the construction of generation facilities by traditional utilities to be paid for on a cost-of-service basis by retail ratepayers. Such actions have the effect of reducing sale opportunities in the competitive wholesale generating markets in which we operate.
FERC has civil penalty authority over violations of any provision of Part II of the FPA, which concerns wholesale generation or transmission, as well as any rule or order issued thereunder. FERC is authorized to assess a maximum civil penalty of $1 million per violation for each day that the violation continues. The FPA also provides for the assessment of criminal fines and imprisonment for violations under the FPA. This penalty authority was enhanced in EPAct 2005. As a result, FERC is authorized to assess a maximum penalty authority established by statute and such penalty authority has been and will continue to be adjusted periodically to account for inflation. With this expanded enforcement authority, violations of the FPA and FERC's regulations could potentially have more serious consequences than in the past.
Pursuant to EPAct 2005, the NERC has been certified by FERC as the Electric Reliability Organization ("ERO") to develop mandatory and enforceable electric system reliability standards applicable throughout the U.S. to improve the overall reliability of the electric grid. These standards are subject to FERC review and approval.
Once approved, the reliability standards may be enforced by FERC independently, or, alternatively, by the ERO and regional reliability organizations with responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to FERC oversight. Monetary penaltiesViolations of upNERC reliability standards are subject to $1 million per day per violation may be assessed for violations ofFERC's penalty authority under the reliability standards.FPA and EPAct 2005.
Our utility businesses in the U.S. face significant regulation by their respective state utility commissions. The regulatory discretion is reasonably broad in both Indiana and Ohio and includes regulation as to services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, the increase or decrease in retail rates and charges, the issuance of certain securities, the acquisition and sale of some public utility properties or securities and certain other matters. These businesses face the risk of unexpected or adverse regulatory action which could have a material adverse effect on our results of operations, financial condition, and cash flows. See Item 1.—Business—Business—US SBU—SBU—U.S. Businesses—Businesses—U.S. Utilities for further information on the regulation faced by our U.S. utilities. Our businesses are subject to stringent environmental laws, rules and regulations.
Our businesses are subject to stringent environmental laws and regulations by many federal, regional, state and local authorities, international treaties and foreign governmental authorities. These laws and regulations generally concern emissions into the air, effluents into the water, use of water, wetlands preservation, remediation of contamination, waste disposal, endangered species and noise regulation, among others.regulation. Failure to comply with such laws and regulations or to obtain or comply with any necessaryassociated environmental permits pursuant to such laws and regulations could result in fines or other sanctions. Environmental lawsFor example, in recent years, the EPA has issued notices of violation (NOVs) to a number of coal-fired
generating plants alleging wide-spread violations of the new source review and regulations affectingprevention of significant deterioration provisions of the CAA. The EPA has brought suit against and obtained settlements with many companies for allegedly making major modifications to a coal-fired generating units without proper permit approvals and without installing best available control technology. The primary focus of these NOVs has been emissions of SO2 and NOx and the EPA has imposed fines and required companies to install improved pollution control technologies to reduce such emissions. In addition, state regulatory agencies and non-governmental environmental organizations have pursued civil lawsuits against power generation and distribution are complex andplants in situations that have tended to become more stringent over time. resulted in judgments and/or settlements requiring the installation of expensive pollution controls or the accelerated retirement of certain electric generating units.
Furthermore,Congress and other domestic and foreign governmental authorities have either considered or implemented various laws and regulations to restrict or tax certain emissions, particularly those involving air emissions and water discharges. See the various descriptions of these laws and regulations contained in Item 1.—Business of this Form 10-K. These laws and regulations have imposed, and proposed laws and regulations could impose in the future, additional costs on the operation of our power plants. See the various descriptions of these laws and regulations contained in Item 1.—Business—Environmental and Land-Use Regulations of this Form 10-K. We have incurred and will continue to incur significant capital and other expenditures to comply with these and other environmental laws and regulations. Changes in, or new development of, environmental restrictions may force the Companyus to incur significant expenses or expenses that may exceed our estimates. There can be no assurance that we would be able to recover all or any increased environmental costs from our customers or that our business, financial condition, including recorded asset values or results of operations, would not be materially and adversely affected by such expenditures or any changes in domestic or foreign environmental laws and regulations.
Our businesses are subject to enforcement initiatives from environmental regulatory agencies.
The EPA has pursued an enforcement initiative against coal-fired generating plants alleging wide-spread violations of the new source review and prevention of significant deterioration provisions of the CAA. The EPA has brought suit against a number of companies and has obtained settlements with many of these companies over such allegations. The allegations typically involve claims that a company made major modifications to a coal-fired generating unit without proper permit approval and without installing best available control technology. The principal, but not exclusive, focus of this EPA enforcement initiative is emissions of SO2 and NOx. In connection with this enforcement initiative, the EPA has imposed fines and required companies to install improved pollution control technologies to reduce emissions of SO2 and NOx. There can be no assurance that foreign environmental regulatory agencies in countries in which our subsidiaries operate will not pursue similar enforcement initiatives under relevant laws and regulations.
Regulators, politicians, non-governmental organizations and other private parties have expressed concernConcerns about greenhouse gas, or GHG emissions and the potential risks associated with climate change have led to increased regulation and are takingother actions whichthat could have a material adverse impact on our consolidated results of operations, financial condition and cash flows.businesses.
As discussed in Item 1.—Business, at the international,International, federal and various regional and state levels, rules are in effect and policies are under development toauthorities regulate GHG emissions thereby effectively putting a cost on such emissions in order to createand have created financial incentives to reduce them. In 2016,2018, the Company's subsidiaries operated businesses whichthat had total CO2 emissions of approximately 67.755 million metric tonnes, approximately 30.223 million of which were emitted by our U.S. businesses located in the U.S. (both figures are ownership adjusted). The Company uses CO2 emission estimation methodologies supported by "The Greenhouse Gas Protocol" reporting standard on GHG emissions. For existing power generation plants, CO2emissions data are either obtained directly from plant continuous emission monitoring systems or calculated from actual fuel heat inputs and fuel type CO2 emission factors. The estimated annual CO2 emissions from fossil fuelfuel-fired electric power generation facilities of the Company's
subsidiaries that are in construction or development and have received the necessary air permits for commercial operations are approximately 7.77 million metric tonnes (ownership adjusted). This overall estimate is based on a number of projections and assumptions that may prove to be incorrect, such as the forecasted dispatch, anticipated plant efficiency, fuel type, CO2 emissions rates and our subsidiaries' achieving completion of such construction and development projects. However, it is certain that the projects under construction or development when completed will increase emissions of our portfolio and therefore could increase the risks associated with regulation of GHG emissions. Because there is significant uncertainty regarding these estimates, actual emissions from these projects under construction or development may vary substantially from these estimates.
The non-utility,There currently is no U.S. federal legislation imposing mandatory GHG emission reductions (including for CO2) that affects our electric power generation subsidiariesfacilities; however, in 2015, the EPA promulgated a rule establishing New Source Performance Standards for CO2 emissions for newly constructed and modified/reconstructed fossil-fueled EUSGUs larger than 25 MW. Also in 2015, the EPA promulgated the Clean Power Plan (CPP), which requires interim reductions by preexisting EUSGUs beginning in 2022, with full compliance achieved by 2030. These actions have been challenged in court and the current Administration has announced plans to significantly amend or rescind the rules. In 2016, the EPA adopted regulations pertaining to GHG emissions that require new and existing sources of GHG emissions to potentially obtain new source review permits from the EPA prior to construction or modification, but only if such sources also must obtain a new source review permit for increases in other regulated pollutants.
For further discussion of the Company often seek to pass on any costs arising from CO2 emissions to contract counterparties, but there can be no assurance that such subsidiaries of the Company will effectively pass such costs onto the contract counterparties or that the cost and burden associated with any dispute over which party bears such costs would not be burdensome and costly to the relevant subsidiaries of the Company. The utility subsidiaries of the Company may seek to pass on any costs arising from CO2 emissions to customers, but there can be no assurance that such subsidiaries of the Company will effectively pass such costs to the customers, or that they will be able to fully or timely recover such costs.
In December 2015, the Parties to the United Nations Framework Convention on Climate Change convened for the 21st Conference of the Company's subsidiariesParties and the resulting Paris Agreement established a long-term goal of keeping the
increase in global average temperature well below 2°C above pre-industrial levels. We anticipate that the Paris Agreement will continue the trend toward efforts to de-carbonize the global economy and to further limit GHG emissions.
The impact of GHG regulation on our operations will depend on a number of factors, including among others, the degree and timing of GHG emissions reductions required under any such legislation or regulation, the cost of emissions reduction equipment and the price and availability of offsets, the extent to which market based compliance options are available, the extent to which our subsidiaries would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on the ability of our subsidiaries to recover costs incurred through rate increases or otherwise. As a result of these factors, our costThe costs of compliance could be substantial and could have a material adverse impactsubstantial.
Our non-utility, generation subsidiaries seek to pass on any costs arising from CO2 emissions to contract counterparties. Likewise, our results of operations.
In January 2005, basedutility subsidiaries seek to pass on European Community "Directive 2003/87/EC on Greenhouse Gas Emission Allowance Trading," the EU ETS commenced operation as the largest multi-country GHG emission trading scheme in the world. On February 16, 2005, the Kyoto Protocol became effective. The Kyoto Protocol requires all developed countries that have ratified it to substantially reduce their GHG emissions, includingany costs arising from CO2. emissions to customers. However, there can be no assurance that we will effectively pass such costs onto the United States never ratified the Kyoto Protocol and, to date, compliance with the Kyoto Protocol and the EU ETS has not had a material adverse effect on the Company's consolidated results of operations, financial condition and cash flows.
In December 2015, the Parties to the United Nations Framework Convention on Climate Change ("UNFCCC") convened for the 21st Conference of the Parties in Paris, France. The result was the so-called Paris Agreement. The Paris Agreement has a long-term goal of keeping the increase in global average temperature to well below 2°C above pre-industrial levels. In furtherance of this goal, participating countries submitted comprehensive national climate action plans and have agreed to meet every five years to set more ambitious targets as required by science, to report to each other and the public on how well they are doing to implement their targets and to track progress towards the long-term goal through a robust transparency and accountability system. We anticipatecontract counterparties or customers, respectively, or that the Paris Agreement will continue the trend towards the efforts to de-carbonize the global economycost and to further limit GHG emissions, including in those countries where the Company does business. It is difficult to predict the nature, timing and scope of such regulation but it could have a material adverse effect on the Company's financial performance.
In the U.S., there currently is no federal legislation imposing a mandatory GHG emission reduction programs (including for CO2) affecting the electric power generation facilities of the Company's subsidiaries. However, the EPA has adopted regulations pertaining to GHG emissions that require new sources of GHG emissions ofburden associated with any dispute over 100,000 tons per year, and existing sources planning physical changes that would increase their GHG emissions by more than 75,000 tons per year, to obtain new source review permits from the EPA prior to construction or modification. Additionally, the EPA has promulgated a rule establishing New Source Performance Standards for CO2 emissions for newly constructed and modified/reconstructed fossil-fueled EUSGUs larger than 25 MW. The EPA has also promulgated a rule, the CPP, which requires existing EUSGUs to begin reducing GHG emissions starting in 2022 with the full reduction requirement in 2030. Under the CPP, states are required to develop and submit plans that establish performance standards or, through emissions trading programs, otherwise meet a state-wide emissions rate average or mass-based goal. For further discussion of the regulation of GHG emission, including the U.S. Supreme Court's issued an order staying implementation of the CPP, see Item 1.—Business—Environmental and Land-Use Regulations—United States Environmental and Land-Use Legislation and Regulations—Greenhouse Gas Emissions above.
Such regulations, and in particular regulations applying to modified or existing EUSGUs, could increase our costs directly and indirectly and have a material adverse effect on our business and/or results of operations. See Item 1.—Business of this Form 10-K for further discussion about these environmental agreements, laws and regulations.
At the state level, the RGGI, a cap-and-trade program covering CO2 emissions from electric power generation facilities in the Northeast, became effective in January 2009, and California has adopted comprehensive legislation and regulation that requires GHG reductions from multiple industrial sectors, including the electric power generation industry. At this time, other than with regard to RGGI (further described below) and proposed Hawaii regulations relating to the collection of fees on GHG emissions, the impact of both of which we do not expect to be material, the Company cannot estimate the costs of compliance with U.S. federal, regional or state GHG emissions reduction legislation or initiatives, due to the fact that most of these proposals are not being actively pursued or are in the early stages of development and any final regulations or laws, if adopted, could vary drastically from current proposals; in the case of California, we anticipate no material impact due to the fact that we expectparty bears such costs willwould not be passed through to our offtakers under the terms of existing tolling agreements.burdensome and costly.
The auctions of RGGI allowances needed by power generators to comply with state programs implementing RGGI occur approximately every quarter. Our subsidiary in Maryland is our only subsidiary that was subject to RGGI in 2016. Of the approximately 30.2 million metric tonnes of CO2 emitted in the United States by our subsidiaries in 2016 (ownership adjusted), approximately 1.1 million metric tonnes were emitted by our subsidiary in Maryland. The Company estimates that the RGGI compliance costs could be approximately $3.2 million for 2017. There is a risk that our actual compliance costs under RGGI will differ from our estimates by a material amount and that our model could underestimate our costs of compliance.
In addition to government regulators, othermany groups such as, including politicians, environmentalists, the investor community and other private parties have expressed increasing concern about GHG emissions. For example, certain financial institutionsNegative public perception of our GHG emissions could have expressed concern about providing financing for facilities which would emit GHGs, which can affectan adverse effect on our relationships with third parties, our ability to obtain capital,attract additional customers or if we can obtain capital, to receive it on commercially viable terms. Further, rating agencies may decide to downgrade our credit ratings based on the emissions of the businesses operated by our subsidiaries or increased compliance costs which could make financing unattractive.business development opportunities. In addition, plaintiffs havepreviously brought tort lawsuits against the Company because of its subsidiaries' GHG emissions. While the litigation mentioned has beenthese lawsuits were dismissed, it is impossible to predict whetherfuture similar future lawsuits are likely tomay prevail or result in damages awards or other relief. Consequently, it is impossibleWe may also be subject to determine whether such lawsuitsrisks associated with the impact on weather conditions. See Item 1A.—Risk Factors—Certain of our businesses are likelysensitive to have a material adverse effect on the Company's consolidated results of operationsvariations in weather and financial condition.
Furthermore, accordinghydrology and Severe weather and natural disasters may present significant risks to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow-fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect the Company'sour business and operations, and any such potential impact may render it more difficult for our businesses to obtain financing. For example, extreme weather events could result in increased downtime and operation and maintenance costs at the electric power generation facilities and support facilities of the Company's subsidiaries. Variations in weather conditions, primarily temperature and humidity also would be expected to affect the energy needs of customers. A decrease in energy consumption could decrease the revenues of the Company's subsidiaries. In addition, while revenues would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of the fossil fuel-fired electric power generation facilities of the Company's subsidiaries. Changes in temperature, precipitation and snow pack conditions also could affect the amount and timing of hydroelectric generation.
In addition to potential physical risks noted by the Intergovernmental Panel on Climate Change, there could be damage to the reputation of the Company and its subsidiaries due to public perception of GHG emissions by the Company's subsidiaries, and any such negative public perception or concerns could ultimately result in a decreased demandour financial results for electric power generation or distribution from our subsidiaries. The level of GHG emissions made by subsidiaries of the Company is not a factor in the compensation of executives of the Company.more information.
If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on theour electric power generation businesses of the Company's subsidiaries and on the Company'sour consolidated results of operations, financial condition,cash flows and cash flows.
reputation.
Tax legislation initiatives or challenges to our tax positions could adversely affect our results of operations and financial condition.
Our subsidiaries have operations in the U.S. and various non-U.S. jurisdictions. As such, we are subject to the tax laws and regulations of the U.S. federal, state and local governments and of many non-U.S. jurisdictions. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative measures.
For example,The TCJA enacted December 22, 2017 introduced significant changes to current U.S. federal tax law, including but not limited to lowering the corporate income tax rate, introducing new limits on interest expense deductibility, and changing the way in which foreign earnings are taxed. These changes are complex and are subject to additional guidance to be issued by the U.S. Treasury and the Internal Revenue Service. In addition, the reaction to the federal tax changes by the individual states is considering corporateevolving. Our interpretations and assumptions around U.S. tax reform that may significantly change corporateevolve in future periods as further administrative guidance and regulations are issued, which may materially affect our effective tax rates, business rules such as interest deductibilityrate or tax payments. For further details, please see Item 7.—Management's Discussion and capital expenditure cost recovery,Analysis of Financial Condition and U.S. international tax rules. Results of Operations—Key Trends and Uncertainties in this Form 10-K.Additionally, longstanding international tax norms that determine how and where cross-border international trade is subjected to tax are evolving. The Organization for Economic Cooperation and Development, ("OECD"), in coordination with the G8 and G20, through its Base Erosion and Profit Shifting project (“BEPS") introduced a series of recommendations that many tax jurisdictions have adopted, or may adopt in the future, as law. As these and other tax laws, related regulations and double-tax conventions change, our financial results could be materially impacted. Given the unpredictability of these possible changes and their potential interdependency, it is very difficult to assess whether the overall effect of such potential tax changes would be cumulatively positive or negative for our earnings and cash flow, but such changes could adversely impact our results of operations.
In addition, U.S. federal, state and local, as well as non-U.S., tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there could be a material impact on our results of operations.
We and our affiliates are subject to material litigation and regulatory proceedings.
We and our affiliates are parties to material litigation and regulatory proceedings. See Item 3.—Legal Proceedings below. There can be no assurances that the outcome of such matters will not have a material adverse effect on our consolidated financial position. ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We maintain offices in many places around the world, generally pursuant to the provisions of long- and short-term leases, none of which we believe are material. With a few exceptions, our facilities, which are described in Item 1—Businessof this Form 10-K, are subject to mortgages or other liens or encumbrances as part of the project's related finance facility. In addition, the majority of our facilities are located on land that is leased. However, in a few instances, no accompanying project financing exists for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned outright by the subsidiary or affiliate. ITEM 3. LEGAL PROCEEDINGS
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims wherewhen it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company's consolidated financial statements. It is reasonably possible, however, 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 that cannot be estimated as of December 31, 2016.
In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the state of Rio de Janeiro (“FDC”) against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties' financing agreement. In April 1999, the FDC found in favor of Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$2.0 billion ($602 million) from Eletropaulo as estimated by Eletropaulo (or approximately R$2.6 billion ($802 million) as of September 2016, as estimated by Eletrobrás, and possibly legal costs) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off of EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo's defenses in the execution suit. On appeal, the case was remanded to the FDC for further proceedings to determine whether Eletropaulo is liable for the debt. In December 2012, the FDC issued a decision that Eletropaulo is liable for the
debt. However, that decision was annulled on appeal and the case was remanded to the FDC for further proceedings. On remand at the FDC, the FDC appointed an accounting expert to analyze the issues in the case. In September 2015, the expert issued a preliminary report concluding that Eletropaulo is liable for the debt, without quantifying the debt. Eletropaulo thereafter submitted questions to the expert and reports rebutting the expert's preliminary report. In April 2016, Eletrobrás requested that the expert determine both the criteria to calculate the debt and the amount of the debt. The FDC is considering whether the criteria can be determined by the expert or must be determined by the FDC. After that issue is resolved, the expert may issue a final report. Ultimately, a decision will be issued by the FDC, which will be free to reject or adopt in whole or in part the expert's report. If the FDC again determines that Eletropaulo is liable for the debt, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In addition, in February 2008, CTEEP filed a lawsuit in the FDC against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts. If Eletrobrás requests the seizure of the security noted above and the FDC grants such request (or if a court determines that Eletropaulo is liable for the debt), Eletropaulo's results of operations may be materially adversely affected and, in turn, the Company's results of operations may also be materially adversely affected. Eletropaulo and the Company could face a loss of earnings and/or cash flows and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value, and/or face the possibility that Eletropaulo cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.
In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the state of São Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$2 million ($614 thousand) as of December 31, 2015, or pay an indemnification amount of approximately R$15 million ($5 million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court's decision, the case has been remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision. In January 2014, Eletropaulo informed the court that it intended to comply with the court's decision by donating a green area inside a protection zone and restore watersheds, the aggregate cost of which is expected to be approximately R$2 million ($614 thousand). Eletropaulo also requested that the court add the current owner of the land where the Associação facilities are located, Empresa Metropolitana de Águas e Energia S.A. (“EMAE”), as a party to the lawsuit and order EMAE to perform the demolition and reforestation aspects of the court's decision. In July 2014, the court requested the Secretary of the Environment for the State of São Paulo to notify the court of its opinion regarding the acceptability of the green areas to be donated by Eletropaulo to the State of São Paulo. In January 2015, the Secretary of the Environment for the State of São Paulo notified Eletropaulo and the court that it would not accept Eletropaulo's proposed green areas donation. Instead of such green areas donation, the Secretary of the Environment proposed in March 2015 that Eletropaulo undertake an environmental project to offset the alleged environmental damage. Since March 2015, Eletropaulo and the Secretary of Environment have been working together to define an environmental project, which will be submitted for approval by the Public Prosecutor. The cost of such project is currently estimated to be R$3 million ($1 million).2018.
In December 2001, GRIDCOGrid Corporation of Odisha (“GRIDCO”) served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the shareholders agreement between GRIDCO, the Company, AES ODPL, Jyoti and the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company. In the arbitration, GRIDCO asserted that a comfort letter issued by the Company in connection with the Company's indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO's financial obligations to GRIDCO. GRIDCO appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by GRIDCO. The Company counterclaimed against GRIDCO for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting GRIDCO's claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to GRIDCO. The respondents' counterclaims were also rejected. A majority of the tribunal later awarded the respondents, including the Company, some of their costs relating to the arbitration. GRIDCO filed challenges of the tribunal's awards with the local Indian court. GRIDCO's challenge of the costs award has been dismissed by the court, but its challenge of the liability award remains pending. A hearing on the liability award has not taken place to date. The Company believes that it has
meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified Eletropaulo that it had commenced an inquiry into the BNDES financings provided to AES Elpa and AES Transgás, the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo, and the quality of service provided by Eletropaulo to its customers. The MPF requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FCSP”) alleging that BNDES violated Law 8429/92 (“the Administrative Misconduct Act”) and BNDES's internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo's preferred shares at a stock-market auction; (4) accepting Eletropaulo's preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES's alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. In April 2015, the FCA issued a decision holding that the FCSP should consider all five alleged violations. AES Elpa and AES Brasiliana (the successor of AES Transgás) have appealed the April 2015 decision to the Superior Court of Justice. The lawsuit remains pending before the FCSP. AES Elpa and AES Brasiliana believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
Pursuant to their environmental audit, AES Sul and AES Florestal discovered 200 barrels of solid creosote waste and other contaminants at a pole factory that AES Florestal had been operating. The conclusion of the audit was that a prior operator of the pole factory, Companhia Estadual de Energia (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. On their initiative, AES Sul and AES Florestal communicated with Brazilian authorities and CEEE about the adoption of containment and remediation measures. In March 2008, the State Attorney of the state of Rio Grande do Sul, Brazil filed a public civil action against AES Sul, AES Florestal and CEEE seeking an order requiring the companies to recovermitigate the contaminated area located on the grounds of the pole factory and an indemnity payment of approximately R$6 million ($2 million) to the state's Environmental Fund.. In October 2011, the State Attorney Office filed a request for an injunction ordering the defendant companies to contain and remove the contamination immediately. The court granted injunctive relief on October 18, 2011, but determined only that defendantonly CEEE was required to proceed withperform the removal work. In May 2012, CEEE began the removal work in compliance with the injunction. The case is now awaiting judgment. The removal costs are estimated to be approximately R$6029 million ($188 million), and there could be additional remediation costs which cannot be estimated at this time. In June 2016 the work was completed in February 2014. In parallel with the removal activities, a court-appointed expert investigation took place, which was concluded in May 2014. The court-appointed expert final report was presented to the State Attorneys in October 2014, and in January 2015 to the defendant companies. In March 2015,Company sold AES Sul to CPFL Energia S.A. and as part of the sale, AES Florestal submitted comments and supplementary questions regardingGuaiba, a holding Company of AES Sul, retained the expert report.potential liability relating to this matter. The Company believes that it hasthere are meritorious
defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) in Brazil initiated arbitration against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF's breach of the parties' gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration against AESU and two unrelated parties, Companhia de Gas do Estado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF sought an unspecified amount of damages from AESU, a declaration that YPF's performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserted that if AESU were found liable for terminating the GSA, AESU should also be found liable for TGM's alleged losses, under the TA. In April 2011, the arbitrations were consolidated into a single proceeding. In May 2013, the arbitral tribunal issued an award finding YPF liable to AESU and TGM. Thereafter, in April 2016, the tribunal issued a damages award ordering YPF to pay damages to AESU and TGM. In January 2017, AESU and YPF settled their dispute.
In October 2009, IPL received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleges violations of the CAA at IPL's three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment
New Source Review requirements under the CAA. IPL management previously met with EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.
In June 2011, the São Paulo Municipal Tax Authority (the “Tax Authority”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking to collect services tax (“ISS”) that allegedly had not been paid on revenues for services rendered by Eletropaulo. Eletropaulo challenged the assessments on the grounds that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court (“FIAC”) determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$3.3 billion ($1.0 billion) as estimated by Eletropaulo. Eletropaulo thereafter appealed to the Second Instance Administrative Court (“SIAC”). In January 2016, the Tax Authority nullified most of the ISS sought from Eletropaulo.In January 2017, the SIAC issued a decision confirming the reduction and rejecting certain other amounts of ISS as time-barred, but finding that Eletropaulo was liable for the remainder of ISS totaling approximately R$200 million ($61 million). The matter is on appeal before the Municipal Council of Taxes. Eletropaulo believes it has meritorious defenses and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2012, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê had paid PIS and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê challenged the assessment on the grounds that the tax rate was set in the applicable legislation. In April 2013, the FIAC determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable for unpaid taxes, interest, and penalties totaling approximately R$960 million1.21 billion ($295312 million) as estimated by AES Tietê. AES Tietê appealed to the SIAC. In January 2015, the SIACSecond Instance Administrative Court ("SIAC") issued a decision in AES Tietê's favor, finding that AES Tietê was not liable for unpaid taxes. The public prosecutor subsequently filed an appeal, which was denied as untimely. The Tax Authority thereafter filed a motion for clarification of the SIAC's decision, which was denied in September 2016. The Tax Authority later filed a special appeal but that appeal(“Special Appeal”), which was rejected as untimely in October 2017.2016. The Tax Authority hasthereafter filed an interlocutory appeal which is pending.with the Superior Administrative Court (“SAC”). In March 2017, the President of the SAC determined that the SAC would analyze the Special Appeal. AES Tietê challenged the Special Appeal. In May 2018, the SAC rejected the Special Appeal on the merits. In August 2018, the Tax Authority filed a motion for clarification. AES Tietê believes it has meritorious defenses to the claim and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2015, DPL received NOVs from the EPA alleging violations of opacity at Stuart and Killen Stations, and in October 2015, IPL received a similar NOV alleging violations at Petersburg Station. In February 2017, the EPA issued a second NOV for DPL Stuart Station, alleging violations of opacity in 2016. Moreover, in February 2016, IPL received an NOV from the EPA alleging violations of New Source Review (“NSR”)NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Station. It is too early to determine whether the NOVs could have a material impact on our business, financial condition or results of our operations. IPL would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard.
In September 2015, AES Southland Development, LLC and AES Redondo Beach, LLC filed a lawsuit against the California Coastal Commission (the “CCC”) over the CCC's determination that the site of AES Redondo Beach included approximately 5.93 acres of CCC-jurisdictional wetlands. The CCC has asserted that AES Redondo Beach has improperly installed and operated water pumps affecting the alleged wetlands in violation of the California Coastal Act and Redondo Beach Local Coastal Program and has ordered AES Redondo Beach to restore the site. Additional potential outcomes of the CCC determination could include an order requiring AES Redondo Beach to fund a wetland mitigation project and/or pay fines or penalties. AES Redondo Beach believes that it has meritorious arguments and intends to vigorously prosecute such lawsuit, but there can be no assurances that it will be successful.
In October 2015, Ganadera Guerra, S.A. (“GG”) and Constructora Tymsa, S.A. (“CT”) filed separate lawsuits against AES Panama in the local courts of Panama. The claimants allege that AES Panama profited from a hydropower facility (La Estrella) being partially located on land owned initiallyby GG and currently by CT, and that AES Panama must pay compensation for its use of the land. The damages sought from AES Panama are approximately $685 million (GG) and $100 million (CT). In October 2016, the court dismissed GG's claim because of GG's failure to comply with a court order requiring GG to disclose certain information. It is expected that GG will refilehas refiled its lawsuit. Also, there are ongoing administrative proceedings concerning whether AES Panama is entitled to
acquire an easement over the land and whether AES Panama can continue to occupy the land. AES Panama believes it has meritorious defenses and claims and will assert themvigorously; however, there can be no assurances that it will be successful in its efforts.
In January 2017, the Superintendencia del Medio Ambiente (“SMA”) issued a Formulation of Charges asserting that Alto Maipo is in violation of certain conditions of the Environmental Approval Resolution (“RCA”) governing the construction of Alto Maipo’s hydropower project, for, among other things, operating vehicles at unauthorized times and failing to mitigate the impact of water infiltration during tunnel construction (“Infiltration Water”). In February 2017, Alto Maipo submitted a compliance plan (“Compliance Plan”) to the SMA which, if approved by the agency, would resolve the matter without materially impacting construction of the project. Thereafter, the SMA made three separate requests for information about the Compliance Plan, to which Alto Maipo duly responded. In April 2018, the SMA approved the Compliance Plan (“April 2018 Approval”). Among other things the Compliance Plan as approved by the SMA requires Alto Maipo to obtain from the Environmental Evaluation Service (“SEA”) an acceptable interpretation of the RCA’s provisions concerning the authorized times to operate certain vehicles. In addition, Alto Maipo must obtain the SEA’s approval concerning the control, discharge, and treatment of Infiltration Water. Alto Maipo continues to seek the relevant final approvals from the SEA. Furthermore,
in May 2018, three lawsuits were filed with the Environmental Court of Santiago (“ECS”) challenging the April 2018 Approval. Alto Maipo does not believe that there are grounds to challenge the April 2018 Approval. The ECS has not decided the lawsuits to date. If Alto Maipo complies with the requirements of the Compliance Plan, and if the above-referenced lawsuits are dismissed, the Formulation of Charges will be discharged without penalty. Otherwise, Alto Maipo could be subject to penalties, and the construction of the project could be negatively impacted. Alto Maipo will pursue its interests vigorously in these matters; however, there can be no assurances that it will be successful in its efforts.
In June 2017, Alto Maipo terminated one of its contractors, Constructora Nuevo Maipo S.A. (“CNM”), given CNM’s stoppage of tunneling works, its failure to produce a completion plan, and its other breaches of contract. Also, Alto Maipo drew $73 million under letters of credit (“LC Funds”) in connection with its termination of CNM. Alto Maipo is pursuing arbitration against CNM to recover excess completion costs and other damages totaling over $230 million (net of the LC Funds) relating to CNM’s breaches (“First Arbitration”). CNM denies liability and seeks a declaration that its termination was wrongful, damages, and other relief. CNM has made submissions alleging that it is entitled to damages ranging from $90 million to $150 million (which include the LC Funds) plus interest and costs. Alto Maipo has contested these submissions. There will be another round of briefing. The evidentiary hearing is scheduled for May 20-31, 2019. Also, in August 2018, CNM purported to initiate a separate arbitration against AES Gener and the Company (“Second Arbitration”). In the Second Arbitration, CNM seeks to pierce Alto Maipo’s corporate veil and appears to seek an award requiring AES Gener and the Company to pay any amounts that are found to be due to CNM in the First Arbitration or otherwise. Alto Maipo requested in the First Arbitration an interim order restraining CNM from proceeding with the Second Arbitration until the conclusion of the First Arbitration. That request was denied. Separately, AES Gener and the Company requested that the relevant arbitral institution decide that the Second Arbitration shall not proceed, given that (among other reasons) there is no arbitration agreement between AES Gener and the Company and CNM. That request was not granted. Subsequently, AES Gener and the Company requested that the Second Arbitration be consolidated into the First Arbitration. That request was granted. The schedule has not yet been established on CNM’s claims against AES Gener and the Company. Each of the above-referenced AES companies believes it has meritorious claims and/or defenses and will pursue its interests vigorously; however, there can be no assurances that each of the AES companies will be successful in its efforts.
In February 2018, Tau Power B.V. and Altai Power LLP (collectively, “AES Claimants”) initiated arbitration against the Republic of Kazakhstan (“ROK”) for the ROK’s failure to pay approximately $75 million (“Return Transfer Payment”) for the return of two hydropower plants (“HPPs”) pursuant to a concession agreement. In April 2018, the ROK responded by denying liability and asserting purported counterclaims concerning the annual payment provisions in the concession agreement, a bonus allegedly due for the 1997 takeover of the HPPs, and dividends paid by the HPPs. The ROK seeks to recover the Return Transfer Payment (which is in an escrow account maintained by a third party) and appears to be seeking over $480 million on its counterclaims. The AES Claimants believe that the ROK’s defenses and counterclaims are without merit. An arbitrator has been appointed to decide the case. The final evidentiary hearing is scheduled for July 22 to 26, 2019. The AES Claimants will pursue their case and assert their defenses vigorously; however, there can be no assurances that they will be successful in their efforts.
In December 2018, a lawsuit was filed in Dominican Republic civil court against the Company, AES Puerto Rico, and three other AES affiliates. The lawsuit purports to be brought on behalf of over 100 Dominican claimants, living and deceased, and appears to seek relief relating to CCRs that were delivered to the Dominican Republic in 2004. The lawsuit generally alleges that the CCRs caused personal injuries and deaths and demands $476 million in alleged damages. The lawsuit does not identify, or provide any supporting information concerning, the alleged injuries of the claimants individually. Nor does the lawsuit provide any information supporting the demand for damages or explaining how the quantum was derived. The relevant AES companies believe that they have meritorious defenses to the claims asserted against them and will defend themselves vigorously in this proceeding; however, there can be no assurances that they will be successful in their efforts.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Stock Repurchase Program — The Board authorization permits the Parent Company to repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The Stock Repurchase Program does not have an expiration date and can be modified or terminated by the Board of Directors at any time. During the year ended December 31, 2016, the Company repurchased 8.7 million shares of its common stock at a total cost of $79 million under the existing stock repurchase program. The cumulative repurchase from the commencement of the Stock Repurchase Program in July 2010 through December 31, 20162018 is 154.3 million shares at 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, 2016, $2462018, $264 million remained available for repurchase under the Stock Repurchase Program.
No repurchases were made by The AES Corporation of its common stock during the fourth quarterin 2018 and 2017, respectively. The Parent Company repurchased 8,686,983 shares of its common stock in 2016.
Market Information
Our common stock is traded on the NYSENew York Stock Exchange under the symbol "AES." The closing price of our common stock as reported by the NYSE on February 17, 2017, was $11.46 per share. The Company repurchased 8,686,983, 39,684,131, and 21,900,246 shares of its common stock in 2016, 2015 and 2014, respectively. The following tables present the high and low intraday sale prices of our common stock and cash dividends declared for the indicated periods.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2016 | | 2015 |
| | Sales Price | | Cash Dividends | | Sales Price | | Cash Dividends |
| | High | | Low | | Declared | | High | | Low | | Declared |
| First Quarter | $ | 11.80 |
| | $ | 8.22 |
| | $ | 0.11 |
| | $ | 13.87 |
| | $ | 11.53 |
| | $ | — |
|
| Second Quarter | 12.48 |
| | 10.49 |
| | — |
| | 14.02 |
| | 12.64 |
| | 0.10 |
|
| Third Quarter | 13.32 |
| | 11.85 |
| | 0.11 |
| | 13.40 |
| | 9.42 |
| | 0.10 |
|
| Fourth Quarter | 12.75 |
| | 10.98 |
| | 0.23 |
| | 11.21 |
| | 8.76 |
| | 0.21 |
|
Dividends
The Parent Company commenced a quarterly cash dividend beginning in the fourth quarter of 2012. The Parent Company has increased this dividend annually asand the quarterly cash dividend for the last three years are displayed below.
| | | Commencing the fourth quarter of | | 2016 | | 2015 | | 2014 | | 2013 | | 2012 | | 2018 | | 2017 | | 2016 |
| Cash dividend | | $0.12 | | $0.11 | | $0.10 | | $0.05 | | $0.04 | | $0.1365 | | $0.13 | | $0.12 |
The fourth quarter 20162018 cash dividend is to be paid beginning in the first quarter of 20172019. There can be no assurance that the AES Board will declare a dividend in the future or, if declared, the amount of any dividend. Our ability to pay dividends will also depend on receipt of dividends from our various subsidiaries across our portfolio.
Under the terms of our senior secured credit facility, which we entered into with a commercial bank syndicate, we have limitations on our ability to pay cash dividends and/or repurchase stock. Our subsidiaries' ability to declare and pay cash dividends to us is also subject to certain limitations contained in the project loans, governmental provisions and other agreements to which our subsidiaries are subject. See the information contained under Item 12.—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Matters—Securities Authorized for Issuance under Equity Compensation Plans of this Form 10-K. Holders
As of February 17, 2017,21, 2019, there were approximately 4,3353,875 record holders of our common stock.
Performance Graph
THE AES CORPORATION
PEER GROUP INDEX/STOCK PRICE PERFORMANCE
Source: Bloomberg
We have selected the Standard and Poor's ("S&P") 500 Utilities Index as our peer group index. The S&P 500 Utilities Index is a published sector index comprising the 2827 electric and gas utilities included in the S&P 500.
The five year total return chart assumes $100 invested on December 31, 20102013 in AES Common Stock, the S&P 500 Index and the S&P 500 Utilities Index. The information included under the heading Performance Graph shall not be considered "filed" for purposes of Section 18 of the Securities Exchange Act of 1934 or incorporated by reference in any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents our selected financial data as of the dates and for the periods indicated. YouThis data should be read this data together with Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and the notes thereto included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K. The selected financial data for each of the years in the five year period ended December 31, 20162018 have been derived from our audited Consolidated Financial Statements. Prior period amounts have been restated to reflect discontinued operations in all periods presented. Prior to July 1, 2014, a discontinued operation was a component of the Company that either had been disposed of or was classified as held-for-sale and where the Company did not expect to have significant cash flows or significant continuing involvement with the component as of one year after its disposal or sale. Effective July 1, 2014, the Company adopted new accounting guidance under which the Company reports a business as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on discontinued operations.the Company’s operations and financial results when the business is sold or classified as held-for-sale. Please refer to Note 1 1—General and Summary of Significant Accounting Policies in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further explanation. Our historical results are not necessarily indicative of our future results.
Acquisitions, disposals, reclassifications and changes in accounting principles affect the comparability of information included in the tables below. Please refer to the Notes to the Consolidated Financial Statements included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further explanation of the effect of such activities. Please also refer to Item 1A.—Risk Factors of this Form 10-K and Note 26—Risks and Uncertainties to the Consolidated Financial Statements included in Item 8.—Financial Statements and
Supplementary Data of this Form 10-K for certain risks and uncertainties that may cause the data reflected herein not to be indicative of our future financial condition or results of operations.
SELECTED FINANCIAL DATA
| | | | 2016 | | 2015 | | 2014 | | 2013 | | 2012 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Statement of Operations Data for the Years Ended December 31: | (in millions, except per share amounts) | (in millions, except per share amounts) |
| Revenue | $ | 13,586 |
| | $ | 14,155 |
| | $ | 16,124 |
| | $ | 15,093 |
| | $ | 16,072 |
| $ | 10,736 |
| | $ | 10,530 |
| | $ | 10,281 |
| | $ | 11,260 |
| | $ | 12,604 |
|
Income (loss) from continuing operations (1) | 361 |
| | 787 |
| | 1,091 |
| | 700 |
| | (518 | ) | 1,349 |
| | (148 | ) | | 191 |
| | 682 |
| | 941 |
|
| Income (loss) from continuing operations attributable to The AES Corporation, net of tax | 8 |
| | 331 |
| | 705 |
| | 254 |
| | (1,058 | ) | 985 |
| | (507 | ) | | (20 | ) | | 318 |
| | 678 |
|
Income (loss) from discontinued operations attributable to The AES Corporation, net of tax | (1,138 | ) | | (25 | ) | | 64 |
| | (140 | ) | | 146 |
| 218 |
| | (654 | ) | | (1,110 | ) | | (12 | ) | | 91 |
|
| Net income (loss) attributable to The AES Corporation | $ | (1,130 | ) | | $ | 306 |
| | $ | 769 |
| | $ | 114 |
| | $ | (912 | ) | $ | 1,203 |
| | $ | (1,161 | ) | | $ | (1,130 | ) | | $ | 306 |
| | $ | 769 |
|
| Per Common Share Data | | | | | | | | | | | | | | | | | | |
| Basic earnings (loss) per share: | | | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations attributable to The AES Corporation, net of tax | $ | — |
| | $ | 0.48 |
| | $ | 0.98 |
| | $ | 0.34 |
| | $ | (1.40 | ) | |
| Income (loss) from discontinued operations attributable to The AES Corporation, net of tax | (1.72 | ) | | (0.03 | ) | | 0.09 |
| | (0.19 | ) | | 0.19 |
| |
| Basic earnings (loss) per share | $ | (1.72 | ) | | $ | 0.45 |
| | $ | 1.07 |
| | $ | 0.15 |
| | $ | (1.21 | ) | |
| Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax | | $ | 1.49 |
| | $ | (0.77 | ) | | $ | (0.04 | ) | | $ | 0.46 |
| | $ | 0.94 |
|
| Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax | | 0.33 |
| | (0.99 | ) | | (1.68 | ) | | (0.01 | ) | | 0.13 |
|
| Net income (loss) attributable to The AES Corporation common stockholders | | $ | 1.82 |
| | $ | (1.76 | ) | | $ | (1.72 | ) | | $ | 0.45 |
| | $ | 1.07 |
|
| Diluted earnings (loss) per share: | | | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations attributable to The AES Corporation, net of tax | $ | — |
| | $ | 0.48 |
| | $ | 0.97 |
| | $ | 0.34 |
| | $ | (1.40 | ) | |
| Income (loss) from discontinued operations attributable to The AES Corporation, net of tax | (1.71 | ) | | (0.04 | ) | | 0.09 |
| | (0.19 | ) | | 0.19 |
| |
| Diluted earnings (loss) per share | $ | (1.71 | ) | | $ | 0.44 |
| | $ | 1.06 |
| | $ | 0.15 |
| | $ | (1.21 | ) | |
| Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax | | $ | 1.48 |
| | $ | (0.77 | ) | | $ | (0.04 | ) | | $ | 0.46 |
| | $ | 0.94 |
|
| Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax | | 0.33 |
| | (0.99 | ) | | (1.68 | ) | | (0.02 | ) | | 0.12 |
|
| Net income (loss) attributable to The AES Corporation common stockholders | | $ | 1.81 |
| | $ | (1.76 | ) | | $ | (1.72 | ) | | $ | 0.44 |
| | $ | 1.06 |
|
| Dividends Declared Per Common Share | $ | 0.45 |
| | 0.41 |
| | 0.25 |
| | 0.17 |
| | 0.08 |
| $ | 0.53 |
| | $ | 0.49 |
| | $ | 0.45 |
| | $ | 0.41 |
| | $ | 0.25 |
|
| Cash Flow Data for the Years Ended December 31: | | | | | | | | | | | | | | | | | | |
| Net cash provided by operating activities | $ | 2,884 |
| | $ | 2,134 |
| | $ | 1,791 |
| | $ | 2,715 |
| | $ | 2,901 |
| $ | 2,343 |
| | $ | 2,504 |
| | $ | 2,897 |
| | $ | 2,136 |
| | $ | 1,800 |
|
| Net cash used in investing activities | (2,108 | ) | | (2,366 | ) | | (656 | ) | | (1,774 | ) | | (895 | ) | (505 | ) | | (2,599 | ) | | (2,136 | ) | | (2,128 | ) | | (1,075 | ) |
| Net cash provided by (used in) financing activities | (747 | ) | | 28 |
| | (1,262 | ) | | (1,136 | ) | | (1,867 | ) | (1,643 | ) | | 43 |
| | (747 | ) | | 28 |
| | (1,262 | ) |
| Total (decrease) increase in cash and cash equivalents | 48 |
| | (260 | ) | | (119 | ) | | (253 | ) | | 280 |
| |
| Cash and cash equivalents, ending | 1,305 |
| | 1,257 |
| | 1,517 |
| | 1,636 |
| | 1,889 |
| |
| Total increase (decrease) in cash, cash equivalents and restricted cash | | 215 |
| | (172 | ) | | 9 |
| | (10 | ) | | (529 | ) |
| Cash, cash equivalents and restricted cash, ending | | 2,003 |
| | 1,788 |
| | 1,960 |
| | 1,951 |
| | 1,961 |
|
| Balance Sheet Data at December 31: | | |
| Total assets | $ | 36,119 |
| | $ | 36,470 |
| | $ | 38,562 |
| | $ | 39,981 |
| | $ | 41,498 |
| $ | 32,521 |
| | $ | 33,112 |
| | $ | 36,124 |
| | $ | 36,545 |
| | $ | 38,676 |
|
| Non-recourse debt (noncurrent) | 14,489 |
| | 12,943 |
| | 13,046 |
| | 12,646 |
| | 11,734 |
| 13,986 |
| | 13,176 |
| | 13,731 |
| | 12,184 |
| | 12,077 |
|
| Non-recourse debt (noncurrent)—Discontinued operations | — |
| | 13 |
| | 257 |
| | 469 |
| | 636 |
| — |
| | — |
| | 758 |
| | 772 |
| | 1,226 |
|
| Recourse debt (noncurrent) | 4,671 |
| | 4,966 |
| | 5,047 |
| | 5,485 |
| | 5,883 |
| 3,650 |
| | 4,625 |
| | 4,671 |
| | 4,966 |
| | 5,047 |
|
| Redeemable stock of subsidiaries | 782 |
| | 538 |
| | 78 |
| | 78 |
| | 78 |
| 879 |
| | 837 |
| | 782 |
| | 538 |
| | 78 |
|
| Retained earnings (accumulated deficit) | (1,146 | ) | | 143 |
| | 512 |
| | (150 | ) | | (264 | ) | (1,005 | ) | | (2,276 | ) | | (1,146 | ) | | 143 |
| | 512 |
|
| The AES Corporation stockholders' equity | 2,794 |
| | 3,149 |
| | 4,272 |
| | 4,330 |
| | 4,569 |
| 3,208 |
| | 2,465 |
| | 2,794 |
| | 3,149 |
| | 4,272 |
|
_____________________________
| |
(1) | Includes pretax impairment expensepre-tax gains on sales of $1.1 billion, $602business interests of $984 million, $383$29 million, $596$29 million and $1.9 billion$358 million for the years ended December 31, 2018, 2016, 2015 and 2014, 2013respectively, and 2012,pre-tax losses of $52 million for the year ended December 31, 2017; pre-tax impairment expense of $208 million, $537 million, $1.1 billion, $602 million and $383 million for the years ended December 31, 2018, 2017, 2016, 2015 and 2014, respectively; other-than-temporary impairments of equity method investments of $147 million and $128 million for the years ended December 31, 2018 and 2014, respectively; 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. See Note 8—Other Non-Operating Expense23—Held-for-Sale and Dispositions, Note 9—8—Goodwill and Other Intangible Assets and, Note 20—Asset Impairment Expense, Note 7—Investments in and Advances to AffiliatesandNote 21—Income Taxesincluded 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 22—Discontinued Operationsincluded in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. |
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Key TopicsExecutive Summary
In 2018, AES delivered strong financial results and achieved significant milestones on its strategic goals, including continuing to enhance the resilience of the portfolio and growing the backlog of renewable projects. The Company achieved a key investment grade metric, completed construction of 1.3 GW of new projects and signed long-term PPAs for 2 GW of renewable capacity. See Overview of our Strategy included in Management's DiscussionItem 1.—Business of this Form 10-K for further information.
During 2018, the Company saw increased margins at its South America, MCAC and AnalysisUS and Utilities SBUs. These increases were primarily due to higher tariffs and rates in Argentina and the U.S., higher contract prices in Colombia, new PPAs in Chile, and increased sales due to the commencement of operations at the Colon combined cycle facility in Panama and Eagle Valley CCGT in the U.S. The Company also experienced decreased margins in the Eurasia SBU due to completed sales of Masinloc in 2018 and the Kazakhstan facilities in 2017. In addition, the Company reduced its recourse debt by approximately $1 billion in 2018, resulting in a decrease in Parent Company interest.
Our discussion covers the following:
Overview of 20162018 Results
Earnings Per Share Results in 2018 (in millions, except per share amounts)
|
| | | | | | | | | | | |
| Years Ended December 31, | 2018 | | 2017 | | 2016 |
| Diluted earnings (loss) per share from continuing operations | $ | 1.48 |
| | $ | (0.77 | ) | | $ | (0.04 | ) |
Adjusted EPS (a non-GAAP measure) (1) | 1.24 |
| | 1.08 |
| | 0.94 |
|
_____________________________
Diluted earnings per share from continuing operations increased $2.25 to $1.48 for the year ended December 31, 2018, as compared to a loss of $0.77 for the year ended December 31, 2017. This increase was primarily due to the current year gains on sales of Masinloc, CTNG and Strategic PerformanceElectrica Santiago, prior year loss on sale of the Kazakhstan CHPs and HPPs, prior year impairments at DPL, Laurel Mountain and in Kazakhstan, lower interest expense at the Parent Company and Gener, a one-time transition tax on foreign earnings following the enactment of the TCJA in the prior year, and higher margins. These increases were partially offset by higher current year tax expense due to the new GILTI rules in the U.S. in large part due to the sale of our interest in Masinloc, the current year impairment at Shady Point, other-than-temporary impairment of the Guacolda equity method investment in Chile, foreign exchange losses mainly due to the devaluation of the Argentine peso and foreign currency gains in the prior year, higher current year losses on extinguishment of debt, and a favorable legal settlement at Uruguaiana in the prior year.
Adjusted EPS, a non-GAAP measure, increased $0.16, or 15%, to $1.24, reflecting higher margins at the South America, US and Utilities and MCAC SBUs and lower interest on Parent Company debt. These increases were partially offset by lower margin at the Eurasia SBU mainly driven by the sales of Masinloc and Kazakhstan.
Review of Consolidated Results of Operations
|
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, | 2018 | | 2017 | | 2016 | | % Change 2018 vs. 2017 | | % Change 2017 vs. 2016 |
| (in millions, except per share amounts) | | | | | |
| Revenue: | | | |
| US and Utilities SBU | $ | 4,230 |
| | $ | 4,162 |
| | $ | 4,330 |
| | 2 | % | | -4 | % |
| South America SBU | 3,533 |
| | 3,252 |
| | 2,956 |
| | 9 | % | | 10 | % |
| MCAC SBU | 1,728 |
| | 1,519 |
| | 1,274 |
| | 14 | % | | 19 | % |
| Eurasia SBU | 1,255 |
| | 1,590 |
| | 1,670 |
| | -21 | % | | -5 | % |
| Corporate and Other | 41 |
| | 35 |
| | 77 |
| | 17 | % | | -55 | % |
| Eliminations | (51 | ) | | (28 | ) | | (26 | ) | | -82 | % | | -8 | % |
| Total Revenue | 10,736 |
| | 10,530 |
| | 10,281 |
| | 2 | % | | 2 | % |
| Operating Margin: | | | | | | | | | |
| US and Utilities SBU | 733 |
| | 693 |
| | 719 |
| | 6 | % | | -4 | % |
| South America SBU | 1,017 |
| | 862 |
| | 823 |
| | 18 | % | | 5 | % |
| MCAC SBU | 534 |
| | 465 |
| | 390 |
| | 15 | % | | 19 | % |
| Eurasia SBU | 227 |
| | 422 |
| | 427 |
| | -46 | % | | -1 | % |
| Corporate and Other | 58 |
| | 23 |
| | 14 |
| | NM |
| | 64 | % |
| Eliminations | 4 |
| | — |
| | 10 |
| | NM |
| | -100 | % |
| Total Operating Margin | 2,573 |
| | 2,465 |
| | 2,383 |
| | 4 | % | | 3 | % |
| General and administrative expenses | (192 | ) | | (215 | ) | | (194 | ) | | -11 | % | | 11 | % |
| Interest expense | (1,056 | ) | | (1,170 | ) | | (1,134 | ) | | -10 | % | | 3 | % |
| Interest income | 310 |
| | 244 |
| | 245 |
| | 27 | % | | — | % |
| Loss on extinguishment of debt | (188 | ) | | (68 | ) | | (13 | ) | | NM |
| | NM |
|
| Other expense | (58 | ) | | (58 | ) | | (80 | ) | | — | % | | -28 | % |
| Other income | 72 |
| | 120 |
| | 64 |
| | -40 | % | | 88 | % |
| Gain (loss) on disposal and sale of business interests | 984 |
| | (52 | ) | | 29 |
| | NM |
| | NM |
|
| Asset impairment expense | (208 | ) | | (537 | ) | | (1,096 | ) | | -61 | % | | -51 | % |
| Foreign currency transaction gains (losses) | (72 | ) | | 42 |
| | (15 | ) | | NM |
| | NM |
|
| Other non-operating expense | (147 | ) | | — |
| | (2 | ) | | NM |
| | -100 | % |
| Income tax expense | (708 | ) | | (990 | ) | | (32 | ) | | -28 | % | | NM |
|
| Net equity in earnings of affiliates | 39 |
| | 71 |
| | 36 |
| | -45 | % | | 97 | % |
| INCOME (LOSS) FROM CONTINUING OPERATIONS | 1,349 |
| | (148 | ) | | 191 |
| | NM |
| | NM |
|
| Income (loss) from operations of discontinued businesses, net of income tax benefit (expense) of $(2), $(21), and $229, respectively | (9 | ) | | (18 | ) | | 151 |
| | -50 | % | | NM |
|
| Gain (loss) from disposal and impairments of discontinued businesses, net of income tax benefit (expense) of $(44), $0, and $266, respectively | 225 |
| | (611 | ) | | (1,119 | ) | | NM |
| | -45 | % |
| NET INCOME (LOSS) | 1,565 |
| | (777 | ) | | (777 | ) | | NM |
| | — | % |
| Noncontrolling interests: | | | | | | | | | |
| Less: Income from continuing operations attributable to noncontrolling interests and redeemable stock of subsidiaries | (364 | ) | | (359 | ) | | (211 | ) | | 1 | % | | 70 | % |
| Less: Loss (income) from discontinued operations attributable to noncontrolling interests | 2 |
| | (25 | ) | | (142 | ) | | NM |
| | -82 | % |
| NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION | $ | 1,203 |
| | $ | (1,161 | ) | | $ | (1,130 | ) | | NM |
| | 3 | % |
| AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS: | | | | | | |
| |
|
| Income (loss) from continuing operations, net of tax | $ | 985 |
| | $ | (507 | ) | | $ | (20 | ) | | NM |
| | NM |
|
| Income (loss) from discontinued operations, net of tax | 218 |
| | (654 | ) | | (1,110 | ) | | NM |
| | -41 | % |
| NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION | $ | 1,203 |
| | $ | (1,161 | ) | | $ | (1,130 | ) | | NM |
| | 3 | % |
| Net cash provided by operating activities | $ | 2,343 |
| | $ | 2,504 |
| | $ | 2,897 |
| | -6 | % | | -14 | % |
| DIVIDENDS DECLARED PER COMMON SHARE | $ | 0.53 |
| | $ | 0.49 |
| | $ | 0.45 |
| | 8 | % | | 9 | % |
Components of Revenue, Cost of Sales and Operating Margin — Revenue includes revenue earned from the sale of energy from our utilities and the capacity and production of energy from our generation plants, which are classified as regulated and non-regulated, respectively, on the Consolidated Statements of Operations. Revenue also includes the gains or losses on derivatives associated with the sale of electricity.
Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, operations and maintenance costs, depreciation and amortization expense, bad debt expense and recoveries, and general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.
Operating margin is defined as revenue less cost of sales.
Consolidated Revenue and Operating Margin
Year Ended December 31, 2018
Revenue
(in millions)
Consolidated Revenue— Revenue increased $206 million, or 2%, in 2018 compared to 2017. Excluding the unfavorable FX impact of $52 million, primarily in South America partially offset by Eurasia, this increase was driven by:
$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
$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.
These favorable impacts were partially offset by decreases of $366 million in Eurasia due to the sale of the Masinloc power plant in March 2018, as well as the sale of the Kazakhstan CHPs and expiration of the Kazakhstan HPP concession agreement in 2017.
Operating Margin
(in millions)
Consolidated Operating Margin— Operating margin increased $108 million, or 4%, in 2018 compared to 2017. Excluding the favorable impact of FX of $8 million, primarily driven by Eurasia, this increase was driven by:
$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.
These favorable impacts were partially offset by a decrease of $204 million in Eurasia due to the drivers discussed above.
Year Ended December 31, 2017
Revenue
(in millions)
Consolidated Revenue— Revenue increased $249 million, or 2%, in 2017 compared to 2016. Excluding the net favorable FX impact of $38 million, primarily in South America, the increase was driven by:
$249 million in South America primarily due to the start of commercial operations at Cochrane as well as higher availability at Argentina, partially offset by lower spot sales at Chivor; and
$248 million in MCAC primarily due to the commencement of the combined cycle operations at Los Mina in June 2017 as well as higher rates in the Dominican Republic.
These favorable impacts were partially offset by decreases of $168 million in US & Utilities mainly due to lower retail tariffs, lower wholesale volume and price at DPL as well as hurricane impacts at Puerto Rico, partially offset by higher pass through costs in El Salvador.
Operating Margin
(in millions)
Consolidated Operating Margin— Operating margin increased $82 million, or 3%, in 2017 compared to 2016. Excluding the favorable impact of FX of $39 million, primarily in Brazil, Argentina, and Colombia, the increase was primarily driven by:
$73 million in MCAC due to the commencement of the Los Mina combined cycle operations in June 2017 in the Dominican Republic as well as higher availability due to forced outages in 2016 at Mexico.
These positive impacts were partially offset by a decreases of $26 million in US and Utilities driven by lower retain margin, lower volumes, and lower commercial availability at DPL as well as a negative impact at IPL mainly due to one-off accruals due to the implementation of new base rates in Q2 2016.
Consolidated Results of Operations — Other
General and administrative expenses
General and administrative expenses include expenses related to corporate staff functions and initiatives, executive management, finance, legal, human resources and information systems, as well as global development costs.
General and administrative expenses decreased $23 million, or 11%, to $192 million for 2018, compared to $215 million for 2017 primarily due to reduced people costs, professional fees and business development activity.
General and administrative expenses increased $21 million, or 11%, to $215 million for 2017, compared to $194 million for 2016 primarily due to severance costs related to workforce reductions associated with a major restructuring program, increased professional fees and increased business development activity.
Interest expense
Interest expense decreased $114 million, or 10%, to $1,056 million for 2018, compared to $1,170 million for 2017 primarily due to the reduction of debt at the Parent Company, favorable impacts from interest rate swaps in Chile and increased capitalized interest at Alto Maipo.
Interest expense increased $36 million, or 3%, to $1,170 million for 2017, compared to $1,134 million for 2016 primarily due to an increase at the South America SBU, driven by lower capitalized interest in 2017 due to the Cochrane plant starting commercial operations in the second half of 2016.
Interest income
Interest income increased $66 million, or 27%, to $310 million for 2018, compared to $244 million for 2017 primarily due to higher interest rates and increased long term receivables as a result of the adoption of the new revenue recognition standard. See Note 1—General and Summary of Significant Accounting Policies included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Interest income decreased $1 million in 2017 from 2016 with no material drivers.
Loss on extinguishment of debt
Loss on extinguishment of debt increased $120 million to $188 million for 2018, compared to $68 million for 2017. This increase was primarily due to higher losses at the Parent Company of $79 million from the redemption of senior notes and a prior year gain on early retirement of debt at AES Argentina of $65 million; partially offset by lower losses at other subsidiaries of $24 million in 2018.
Loss on extinguishment of debt increased $55 million to $68 million for 2017, compared to $13 million for 2016 primarily related to losses of $92 million, $20 million, and $9 million on debt extinguishments at the Parent Company, AES Gener, and IPALCO, respectively. The loss was partially offset by a gain on early retirement of debt at AES Argentina of $65 million.
Other income
Other income decreased $48 million, or 40%, to $72 million for 2018, compared to $120 million for 2017 primarily due to the 2017 favorable settlement of legal proceedings at Uruguaiana related to YPF's breach of the parties’ gas supply agreement and a decrease in allowance for funds used during construction in the US and Utilities SBU. These decreases were partially offset by a gain on remeasurement of contingent liabilities for projects in Hawaii in 2018.
Other income increased $56 million, or 88%, to $120 million for 2017, compared to $64 million for 2016 primarily due to the 2017 favorable legal settlement mentioned above.
Other expense
Other expense remained flat at $58 million for 2018, compared to 2017 primarily due to a loss resulting from damage associated with a lightning incident at the Andres facility in the Dominican Republic in 2018 and higher non-service pension and other postretirement costs in 2018. This was offset by the 2017 write-off of water rights for projects that were no longer being pursued in the South America SBU and a loss on disposal of assets at DPL as a result of the decision to close the coal-fired and diesel-fired generating units at Stuart and Killen.
Other expense decreased $22 million, or 28%, to $58 million for 2017, compared to $80 million for 2016 primarily due to the 2016 recognition of a full allowance on a non-trade receivable in the MCAC SBU as a result of payment delays. This decrease was partially offset by the 2017 loss on disposal of assets at DPL as a result of the decision to close the coal-fired and diesel-fired generating units at Stuart and Killen and the write-off of water rights in the South America SBU for projects that are no longer being pursued.
See Note 19—Other Income and Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. Gain (loss) on disposal and sale of business interests
Gain on disposal and sale of business interests was $984 million for 2018 primarily due to the $772 million gain on sale of Masinloc and the $129 million and $69 million gains on sales of CTNG and Electrica Santiago, respectively, in Chile.
Loss on disposal and sale of business interests was $52 million for 2017 primarily due to the $49 million and $33 million losses on sale of Kazakhstan CHPs and HPPs, respectively, partially offset by the recognition of a $23 million gain related to the expiration of a contingency at Masinloc.
Gain on disposal and sale of business interests was $29 million for 2016 primarily due to the $49 million gain on sale of DPLER, partially offset by the $20 million loss on the deconsolidation of U.K. Wind.
Goodwill impairment expense
There were no goodwill impairments for the years ended December 31, 2018, 2017, or 2016.
Asset impairment expense
Asset impairment expense decreased $329 million, or 61%, to $208 million for 2018, compared to $537 million for 2017 mainly driven by prior year impairments of $186 million recognized in Kazakhstan due to the classification of the CHPs and HPPs as held-for-sale and $296 million in the U.S. as a result of the decision to sell the DPL peaker assets and a decline in forward pricing at Laurel Mountain, partially offset by a current year impairment of $157 million due to decreased future cash flows and the decision to sell Shady Point.
Asset impairment expense decreased $559 million, or 51%, to $537 million for 2017, compared to $1,096 million for 2016 mainly driven by the impairment of $859 million at DPL in 2016, partially offset by a $121 million impairment at Laurel Mountain in 2017 as a result of a decline in forward pricing.
See Note 20—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. Foreign currency transaction gains (losses)
Foreign currency transaction gains (losses) in millions were as follows:
|
| | | | | | | | | | | |
| Years Ended December 31, | 2018 | | 2017 | | 2016 |
Argentina (1) | $ | (71 | ) | | $ | 1 |
| | $ | 37 |
|
| Chile | (13 | ) | | 8 |
| | (9 | ) |
| Bulgaria | (6 | ) | | 14 |
| | (8 | ) |
| United Kingdom | (2 | ) | | (3 | ) | | 13 |
|
| Philippines | (1 | ) | | 15 |
| | 12 |
|
| Mexico | — |
| | 17 |
| | (8 | ) |
| Colombia | 6 |
| | (23 | ) | | (8 | ) |
| Corporate | 11 |
| | 3 |
| | (50 | ) |
| Other | 4 |
| | 10 |
| | 6 |
|
Total (2) | $ | (72 | ) | | $ | 42 |
| | $ | (15 | ) |
_____________________________
| |
(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 6—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. |
| |
(2) | Includes gains of $23 million, losses of $21 million, andgainsof$17 million on foreign currency derivative contracts for the years ended December 31, 2018, 2017 and 2016, respectively. |
The Company recognized net foreign currency transaction losses of $72 million for the year ended December 31, 2018 primarily due to the unrealized losses from the devaluation of receivables denominated in Argentine pesos and realized losses from Chilean pesos. These losses were partially offset by foreign currency derivative gains at the Parent Company.
The Company recognized net foreign currency transaction gains of $42 million for the year ended December 31, 2017 primarily driven by transactions associated with VAT activity in Mexico, the amortization of frozen embedded derivatives in the Philippines, and appreciation of the Euro in Bulgaria. These gains were partially offset by foreign currency derivative losses in Colombia due to a change in functional currency.
The Company recognized net foreign currency transaction losses of $15 million for the year ended December 31, 2016 primarily due to remeasurement losses on intercompany notes, and losses on swaps and options at the Parent Company. These losses were partially offset by foreign currency derivative gains related to government receivables in Argentina.
Other non-operating expense
Other non-operating expense was $147 million in 2018 primarily due to the $144 million other-than-temporary impairment of the Guacolda equity method investment as a result of increased renewable generation in Chile lowering energy prices and impacting the ability of Guacolda to re-contract its existing PPAs after they expire.
There were no significant other non-operating expenses in 2017 and 2016.
Income tax expense
Income tax expense decreased $282 million to $708 million in 2018 as compared to $990 million for 2017. The Company's effective tax rates were 35% and 128% for the years ended December 31, 2018 and 2017, respectively.
The net decrease in the 2018 effective tax rate was primarily due to greater 2017 impacts related to U.S. tax reform one-time transition tax and remeasurement of deferred tax assets, relative to the 2018 U.S. tax reform impact to adjust the provisional estimate recorded under SAB 118, which provides SEC guidance on the application of the accounting standards for the initial enactment impacts of the TCJA. This net decrease was also attributable to the impact of the sale of the Company's entire 51% equity interest in Masinloc, offset by taxation of our foreign subsidiaries under U.S. GILTI rules.
Income tax expense increased $958 million to $990 million in 2017 as compared to $32 million for 2016. The Company's effective tax rates were 128% and 17% for the years ended December 31, 2017 and 2016, respectively.
The net increase in the 2017 effective tax rate was due primarily to the enactment of the TCJA in the U.S., partially offset by the impacts of the 2016 Chilean tax law reform and the 2016 devaluation of the Mexican peso. See Note 21—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional information regarding the 2016 Chilean income tax law reform. Our effective tax rate reflects the tax effect of significant operations outside the U.S., which are generally taxed at rates different than the U.S. statutory rate. Foreign earnings may be taxed at rates higher than the U.S. corporate rate of 21% and are also subject to current U.S. taxation under the GILTI rules introduced by the TCJA. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate. The Company also benefits from reduced tax rates in certain countries as a result of satisfying specific commitments regarding employment and capital investment. See Note 21—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional information regarding these reduced rates. Net equity in earnings of affiliates
Net equity in earnings of affiliates decreased $32 million, or 45%, to $39 million for 2018, compared to $71 million for 2017 primarily due to losses at Fluence, which was formed in the first quarter of 2018, decreased income at Guacolda, and larger gains on projects that achieved commercial operations in 2017 than in 2018 at sPower, which was purchased in the third quarter of 2017.
Net equity in earnings of affiliates increased $35 million, or 97%, to $71 million in 2017, compared to $36 million for 2016 primarily due to earnings at the sPower equity method investment purchased in 2017, partially offset by fixed asset impairments in 2017 at the Distributed Energy entities, accounted for as equity affiliates.
Net income (loss) from discontinued operations
Net income from discontinued operations was $216 million for the year ended December 31, 2018 primarily due to the after-tax gain on sale of Eletropaulo of $199 million recognized in the second quarter of 2018 and the recognition of a $26 million deferred gain upon liquidation of Borsod in October 2018.
Net loss from discontinued operations was $629 million for the year ended December 31, 2017 primarily due to the after-tax loss on deconsolidation of Eletropaulo of $611 million recognized in the fourth quarter of 2017. The remaining loss was due to a loss contingency recognized by our equity affiliate, partially offset by the income from operations of Eletropaulo prior to the date of deconsolidation.
Net loss from discontinued operations was $968 million for the year ended December 31, 2016 due to the sale of Sul, partially offset by the income from operations of Eletropaulo. The loss includes an after-tax loss on the impairment of Sul of $382 million recognized in the second quarter of 2016 and an additional after-tax loss on the sale of Sul of $737 million recognized upon disposal in October 2016. There was no significant loss from operations related to the Sul discontinued business.
See Note 22—Discontinued Operationsincluded in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. Net income attributable to noncontrolling interests and redeemable stock of subsidiaries
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries decreased $22 million, or 6%, to $362 million in 2018, compared to $384 million in 2017. This decrease was primarily due to:
•Current year other-than-temporary impairment of Guacolda;
•Prior year favorable impact of a legal settlement at Uruguaiana; and
•Lower earnings due to deconsolidation of Eletropaulo in November 2017 and the sale of Masinloc in March 2018.
These decreases were partially offset by:
•Current year gains on sales of Electrica Santiago and CTNG in Chile;
•Higher earnings in Colombia primarily due to higher contract sales and prices; and
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries increased $31 million, or 9%, to $384 million in 2017, compared to $353 million in 2016. This increase was primarily due to:
•Asset impairments at Buffalo Gap I and II in 2016.
These increases were partially offset by:
•Income tax benefits at Eletropaulo in 2016 (reflected within discontinued operations).
Net income (loss) attributable to The AES Corporation
Net income attributable to The AES Corporation increased $2,364 million to $1,203 million in 2018, compared to a loss of $1,161 million in 2017. This increase was primarily due to:
Gains on the sales of Masinloc, Eletropaulo (reflected within discontinued operations), CTNG, and Electrica Santiago, and prior year losses on the sales of Kazakhstan CHPs and HPPs;
Prior year loss on deconsolidation of Eletropaulo (reflected within discontinued operations);
Prior year impact of U.S. tax reform enacted in December 2017;
Prior year asset impairments at DPL, Laurel Mountain and in Kazakhstan;
Lower interest expense at the Parent Company and Gener; and
Higher margins at our South America, MCAC and US and Utilities SBUs.
These increases were partially offset by:
Higher current year tax expense due to the new GILTI rules in the U.S.;
Current year impairment at Shady Point;
Current year other-than-temporary impairment of Guacolda;
Higher losses on extinguishment of debt in the current year;
Current year foreign exchange losses primarily due to the devaluation of the Argentine peso and foreign currency gains in the prior year;
Prior year favorable impact of a legal settlement at Uruguaiana; and
Lower margins in the current year at our Eurasia SBU as a result of the sales of Masinloc and Kazakhstan.
Net loss attributable to The AES Corporation increased $31 million, or 3%, to $1,161 million in 2017, compared to $1,130 million in 2016. This increase was primarily due to:
Impact of U.S. tax reform enacted in December 2017;
Losses on the sales of Kazakhstan CHPs and HPPs;
Loss on deconsolidation of Eletropaulo (reflected within discontinued operations);
Impairments at Laurel Mountain, Kilroot and in Kazakhstan; and
Higher loss on extinguishment of debt.
These increases were partially offset by:
Impairments at DPL in 2016;
Loss on sale of Sul in 2016 (reflected within discontinued operations);
Favorable impact of a legal settlement at Uruguaiana;
Higher gains on foreign currency transactions; and
Higher margins at our MCAC SBU.
Consolidated Revenue and Operating Margin
Year Ended December 31, 2018
Revenue
(in millions)
Consolidated Revenue— Revenue increased $206 million, or 2%, in 2018 compared to 2017. Excluding the unfavorable FX impact of $52 million, primarily in South America partially offset by Eurasia, this increase was driven by:
$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
$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.
These favorable impacts were partially offset by decreases of $366 million in Eurasia due to the sale of the Masinloc power plant in March 2018, as well as the sale of the Kazakhstan CHPs and expiration of the Kazakhstan HPP concession agreement in 2017.
Operating Margin
(in millions)
Consolidated Operating Margin— Operating margin increased $108 million, or 4%, in 2018 compared to 2017. Excluding the favorable impact of FX of $8 million, primarily driven by Eurasia, this increase was driven by:
$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.
These favorable impacts were partially offset by a decrease of $204 million in Eurasia due to the drivers discussed above.
Year Ended December 31, 2017
Revenue
(in millions)
Consolidated Revenue— Revenue increased $249 million, or 2%, in 2017 compared to 2016. Excluding the net favorable FX impact of $38 million, primarily in South America, the increase was driven by:
$249 million in South America primarily due to the start of commercial operations at Cochrane as well as higher availability at Argentina, partially offset by lower spot sales at Chivor; and
$248 million in MCAC primarily due to the commencement of the combined cycle operations at Los Mina in June 2017 as well as higher rates in the Dominican Republic.
These favorable impacts were partially offset by decreases of $168 million in US & Utilities mainly due to lower retail tariffs, lower wholesale volume and price at DPL as well as hurricane impacts at Puerto Rico, partially offset by higher pass through costs in El Salvador.
Operating Margin
(in millions)
Consolidated Operating Margin— Operating margin increased $82 million, or 3%, in 2017 compared to 2016. Excluding the favorable impact of FX of $39 million, primarily in Brazil, Argentina, and Colombia, the increase was primarily driven by:
$73 million in MCAC due to the commencement of the Los Mina combined cycle operations in June 2017 in the Dominican Republic as well as higher availability due to forced outages in 2016 at Mexico.
These positive impacts were partially offset by a decreases of $26 million in US and Utilities driven by lower retain margin, lower volumes, and lower commercial availability at DPL as well as a negative impact at IPL mainly due to one-off accruals due to the implementation of new base rates in Q2 2016.
Key Trendsof this Form 10-K for additional discussion and Uncertainties
Capital Resources and Liquidityanalysis of operating results for each SBU.
ExecutiveConsolidated Results of Operations — Other
General and administrative expenses
General and administrative expenses include expenses related to corporate staff functions and initiatives, executive management, finance, legal, human resources and information systems, as well as global development costs.
General and administrative expenses decreased $23 million, or 11%, to $192 million for 2018, compared to $215 million for 2017 primarily due to reduced people costs, professional fees and business development activity.
General and administrative expenses increased $21 million, or 11%, to $215 million for 2017, compared to $194 million for 2016 primarily due to severance costs related to workforce reductions associated with a major restructuring program, increased professional fees and increased business development activity.
Interest expense
Interest expense decreased $114 million, or 10%, to $1,056 million for 2018, compared to $1,170 million for 2017 primarily due to the reduction of debt at the Parent Company, favorable impacts from interest rate swaps in Chile and increased capitalized interest at Alto Maipo.
Interest expense increased $36 million, or 3%, to $1,170 million for 2017, compared to $1,134 million for 2016 primarily due to an increase at the South America SBU, driven by lower capitalized interest in 2017 due to the Cochrane plant starting commercial operations in the second half of 2016.
Interest income
Interest income increased $66 million, or 27%, to $310 million for 2018, compared to $244 million for 2017 primarily due to higher interest rates and increased long term receivables as a result of the adoption of the new revenue recognition standard. See Note 1—General and Summary of Significant Accounting Policies included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Consolidated Net Cash ProvidedInterest income decreased $1 million in 2017 from 2016 with no material drivers.
Loss on extinguishment of debt
Loss on extinguishment of debt increased $120 million to $188 million for 2018, compared to $68 million for 2017. This increase was primarily due to higher losses at the Parent Company of $79 million from the redemption of senior notes and a prior year gain on early retirement of debt at AES Argentina of $65 million; partially offset by Operating Activitieslower losses at other subsidiaries of $24 million in 2018.
Loss on extinguishment of debt increased $55 million to $68 million for 2017, compared to $13 million for 2016 primarily related to losses of $92 million, $20 million, and $9 million on debt extinguishments at the Parent Company, AES Gener, and IPALCO, respectively. The loss was partially offset by a gain on early retirement of debt at AES Argentina of $65 million.
Other income
Other income decreased $48 million, or 40%, to $72 million for 2018, compared to $120 million for 2017 primarily due to the 2017 favorable settlement of legal proceedings at Uruguaiana related to YPF's breach of the parties’ gas supply agreement and a decrease in allowance for funds used during construction in the US and Utilities SBU. These decreases were partially offset by a gain on remeasurement of contingent liabilities for projects in Hawaii in 2018.
Other income increased $56 million, or 88%, to $120 million for 2017, compared to $64 million for 2016 primarily due to the 2017 favorable legal settlement mentioned above.
Other expense
Other expense remained flat at $58 million for 2018, compared to 2017 primarily due to a loss resulting from damage associated with a lightning incident at the Andres facility in the Dominican Republic in 2018 and higher non-service pension and other postretirement costs in 2018. This was offset by the 2017 write-off of water rights for projects that were no longer being pursued in the South America SBU and a loss on disposal of assets at DPL as a result of the decision to close the coal-fired and diesel-fired generating units at Stuart and Killen.
Other expense decreased $22 million, or 28%, to $58 million for 2017, compared to $80 million for 2016 primarily due to the 2016 recognition of a full allowance on a non-trade receivable in the MCAC SBU as a result of payment delays. This decrease was partially offset by the 2017 loss on disposal of assets at DPL as a result of the decision to close the coal-fired and diesel-fired generating units at Stuart and Killen and the write-off of water rights in the South America SBU for projects that are no longer being pursued.
See Note 19—Other Income and Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. Gain (loss) on disposal and sale of business interests
Gain on disposal and sale of business interests was $984 million for 2018 primarily due to the $772 million gain on sale of Masinloc and the $129 million and $69 million gains on sales of CTNG and Electrica Santiago, respectively, in Chile.
Loss on disposal and sale of business interests was $52 million for 2017 primarily due to the $49 million and $33 million losses on sale of Kazakhstan CHPs and HPPs, respectively, partially offset by the recognition of a $23 million gain related to the expiration of a contingency at Masinloc.
Gain on disposal and sale of business interests was $29 million for 2016 primarily due to the $49 million gain on sale of DPLER, partially offset by the $20 million loss on the deconsolidation of U.K. Wind.
Goodwill impairment expense
There were no goodwill impairments for the years ended December 31, 2018, 2017, or 2016.
Asset impairment expense
Asset impairment expense decreased $329 million, or 61%, to $208 million for 2018, compared to $537 million for 2017 mainly driven by prior year impairments of $186 million recognized in Kazakhstan due to the classification of the CHPs and HPPs as held-for-sale and $296 million in the U.S. as a result of the decision to sell the DPL peaker assets and a decline in forward pricing at Laurel Mountain, partially offset by a current year impairment of $157 million due to decreased future cash flows and the decision to sell Shady Point.
Asset impairment expense decreased $559 million, or 51%, to $537 million for 2017, compared to $1,096 million for 2016 mainly driven by the impairment of $859 million at DPL in 2016, partially offset by a $121 million impairment at Laurel Mountain in 2017 as a result of a decline in forward pricing.
See Note 20—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. Foreign currency transaction gains (losses)
Foreign currency transaction gains (losses) in millions were as follows:
|
| | | | | | | | | | | |
| Years Ended December 31, | 2018 | | 2017 | | 2016 |
Argentina (1) | $ | (71 | ) | | $ | 1 |
| | $ | 37 |
|
| Chile | (13 | ) | | 8 |
| | (9 | ) |
| Bulgaria | (6 | ) | | 14 |
| | (8 | ) |
| United Kingdom | (2 | ) | | (3 | ) | | 13 |
|
| Philippines | (1 | ) | | 15 |
| | 12 |
|
| Mexico | — |
| | 17 |
| | (8 | ) |
| Colombia | 6 |
| | (23 | ) | | (8 | ) |
| Corporate | 11 |
| | 3 |
| | (50 | ) |
| Other | 4 |
| | 10 |
| | 6 |
|
Total (2) | $ | (72 | ) | | $ | 42 |
| | $ | (15 | ) |
_____________________________
| |
(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 6—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. |
| |
(2) | Includes gains of $23 million, losses of $21 million, andgainsof$17 million on foreign currency derivative contracts for the years ended December 31, 2018, 2017 and 2016, respectively. |
The Company recognized net foreign currency transaction losses of $72 million for the year ended December 31, 2018 primarily due to the unrealized losses from the devaluation of receivables denominated in Argentine pesos and realized losses from Chilean pesos. These losses were partially offset by foreign currency derivative gains at the Parent Company.
The Company recognized net foreign currency transaction gains of $42 million for the year ended December 31, 2017 primarily driven by transactions associated with VAT activity in Mexico, the amortization of frozen embedded derivatives in the Philippines, and appreciation of the Euro in Bulgaria. These gains were partially offset by foreign currency derivative losses in Colombia due to a change in functional currency.
The Company recognized net foreign currency transaction losses of $15 million for the year ended December 31, 2016 primarily due to remeasurement losses on intercompany notes, and losses on swaps and options at the Parent Company. These losses were partially offset by foreign currency derivative gains related to government receivables in Argentina.
Other non-operating expense
Other non-operating expense was $2,884$147 million an increasein 2018 primarily due to the $144 million other-than-temporary impairment of $750the Guacolda equity method investment as a result of increased renewable generation in Chile lowering energy prices and impacting the ability of Guacolda to re-contract its existing PPAs after they expire.
There were no significant other non-operating expenses in 2017 and 2016.
Income tax expense
Income tax expense decreased $282 million to $708 million in 2018 as compared to $990 million for 2017. The Company's effective tax rates were 35% and 128% for the years ended December 31, 2018 and 2017, respectively.
The net decrease in the 2018 effective tax rate was primarily due to greater 2017 impacts related to U.S. tax reform one-time transition tax and remeasurement of deferred tax assets, relative to the 2018 U.S. tax reform impact to adjust the provisional estimate recorded under SAB 118, which provides SEC guidance on the application of the accounting standards for the initial enactment impacts of the TCJA. This net decrease was also attributable to the impact of the sale of the Company's entire 51% equity interest in Masinloc, offset by taxation of our foreign subsidiaries under U.S. GILTI rules.
Income tax expense increased $958 million to $990 million in 2017 as compared to $32 million for 2016. The Company's effective tax rates were 128% and 17% for the years ended December 31, 2017 and 2016, respectively.
The net increase in the 2017 effective tax rate was due primarily to the enactment of the TCJA in the U.S., partially offset by the impacts of the 2016 Chilean tax law reform and the 2016 devaluation of the Mexican peso. See Note 21—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional information regarding the 2016 Chilean income tax law reform. Our effective tax rate reflects the tax effect of significant operations outside the U.S., which are generally taxed at rates different than the U.S. statutory rate. Foreign earnings may be taxed at rates higher than the U.S. corporate rate of 21% and are also subject to current U.S. taxation under the GILTI rules introduced by the TCJA. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate. The Company also benefits from reduced tax rates in certain countries as a result of satisfying specific commitments regarding employment and capital investment. See Note 21—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional information regarding these reduced rates. Net equity in earnings of affiliates
Net equity in earnings of affiliates decreased $32 million, or 45%, to $39 million for 2018, compared to $71 million for 2017 primarily due to losses at Fluence, which was formed in the first quarter of 2018, decreased income at Guacolda, and larger gains on projects that achieved commercial operations in 2017 than in 2018 at sPower, which was purchased in the third quarter of 2017.
Net equity in earnings of affiliates increased $35 million, or 97%, to $71 million in 2017, compared to $36 million for 2016 primarily due to earnings at the sPower equity method investment purchased in 2017, partially offset by fixed asset impairments in 2017 at the Distributed Energy entities, accounted for as equity affiliates.
Net income (loss) from discontinued operations
Net income from discontinued operations was $216 million for the year ended December 31, 2015. The increase was2018 primarily driven by higher collections atdue to the Company’s distribution businessafter-tax gain on sale of Eletropaulo of $199 million recognized in Brazil, Eletropaulo and Sul,the second quarter of 2018 and the settlementrecognition of overdue receivables at Maritzaa $26 million deferred gain upon liquidation of Borsod in Bulgaria. These positive contributions wereOctober 2018.
Net loss from discontinued operations was $629 million for the year ended December 31, 2017 primarily due to the after-tax loss on deconsolidation of Eletropaulo of $611 million recognized in the fourth quarter of 2017. The remaining loss was due to a loss contingency recognized by our equity affiliate, partially offset by lower margins across the SBUs (primarily dueincome from operations of Eletropaulo prior to lower wholesale prices and lower contributionsthe date of deconsolidation.
Net loss from regulated customers in the U.S., lower contracted rates in Tietê, the prior year liability reversal in Eletropaulo and unfavorable FX in Kazakhstan), as well as the recovery of overdue receivables in the Dominican Republic in 2015, which benefited
2015 results. Proportional Free Cash Flow (a non-GAAP financial measure)discontinued operations was $968 million for the year ended December 31, 2016 increased $176 million to $1,417 million compared to the year ended December 31, 2015, primarily due to the same factors as Consolidated Net Cash Providedsale of Sul, partially offset by Operating Activities.the income from operations of Eletropaulo. The loss includes an after-tax loss on the impairment of Sul of $382 million recognized in the second quarter of 2016 and an additional after-tax loss on the sale of Sul of $737 million recognized upon disposal in October 2016. There was no significant loss from operations related to the Sul discontinued business.
See Note 22—Discontinued Operationsincluded in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. OverviewNet income attributable to noncontrolling interests and redeemable stock of 2016 Resultssubsidiaries
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries decreased $22 million, or 6%, to $362 million in 2018, compared to $384 million in 2017. This decrease was primarily due to: Earnings Per Share•Current year other-than-temporary impairment of Guacolda;
•Prior year favorable impact of a legal settlement at Uruguaiana; and Proportional Free Cash Flow Results
•Lower earnings due to deconsolidation of Eletropaulo in 2016 (in millions, except per share amounts)November 2017 and the sale of Masinloc in March 2018.
These decreases were partially offset by: |
| | | | | | | | | | | |
| Years Ended December 31, | 2016 | | 2015 | | 2014 |
| Diluted earnings per share from continuing operations | $ | — |
| | $ | 0.48 |
| | $ | 0.97 |
|
Adjusted earnings per share (a non-GAAP measure) (1) | 0.98 |
| | 1.25 |
| | 1.18 |
|
| Net cash provided by operating activities | 2,884 |
| | 2,134 |
| | 1,791 |
|
Proportional Free Cash Flow (a non-GAAP measure) (1) (2) | 1,417 |
| | 1,241 |
| | 891 |
|
_____________________________
| |
(1)
| See reconciliation and definition under SBU Performance Analysis—Non-GAAP Measures.
|
| |
(2)
| Disclosure of Proportional Free Cash Flow will be discontinued beginning in the first quarter of 2017. See further discussion under SBU Performance Analysis—Non-GAAP Measures.
|
Diluted•Higher earnings per share from continuing operations decreasedin Colombia primarily due to higher impairmentcontract sales and prices; and
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries increased $31 million, or 9%, to $384 million in 2017, compared to $353 million in 2016. This increase was primarily due to:
•Asset impairments at Buffalo Gap I and II in 2016.
These increases were partially offset by:
•Income tax benefits at Eletropaulo in 2016 (reflected within discontinued operations).
Net income (loss) attributable to The AES Corporation
Net income attributable to The AES Corporation increased $2,364 million to $1,203 million in 2018, compared to a loss of $1,161 million in 2017. This increase was primarily due to:
Gains on the sales of Masinloc, Eletropaulo (reflected within discontinued operations), CTNG, and Electrica Santiago, and prior year losses on the sales of Kazakhstan CHPs and HPPs;
Prior year loss on deconsolidation of Eletropaulo (reflected within discontinued operations);
Prior year impact of U.S. tax reform enacted in December 2017;
Prior year asset impairments at DPL, Laurel Mountain and in Kazakhstan;
Lower interest expense on long lived assets, lower gains on foreign currency derivatives, lower operatingat the Parent Company and Gener; and
Higher margins at our South America, MCAC and US Brazil and Europe SBUs, and lower equity in earnings of affiliatesUtilities SBUs.
These increases were partially offset by:
Higher current year tax expense due to the gain earned in 2015 from the restructuring of Guacolda; partially offset by a lower effective tax rate, the absence of goodwill impairment expensenew GILTI rules in the currentU.S.;
Current year lowerimpairment at Shady Point;
Current year other-than-temporary impairment of Guacolda;
Higher losses on extinguishment of debt in the current year;
Current year foreign exchange losses primarily due to the devaluation of the Argentine peso and lower share count.foreign currency gains in the prior year;
Adjusted EPS,Prior year favorable impact of a non-GAAP measure, decreased by 22%legal settlement at Uruguaiana; and
Lower margins in the current year at our Eurasia SBU as a result of the sales of Masinloc and Kazakhstan.
Net loss attributable to $0.98The AES Corporation increased $31 million, or 3%, to $1,161 million in 2017, compared to $1,130 million in 2016. This increase was primarily driven by lower operatingdue to:
Impact of U.S. tax reform enacted in December 2017;
Losses on the sales of Kazakhstan CHPs and HPPs;
Loss on deconsolidation of Eletropaulo (reflected within discontinued operations);
Impairments at Laurel Mountain, Kilroot and in Kazakhstan; and
Higher loss on extinguishment of debt.
These increases were partially offset by:
Impairments at DPL in 2016;
Loss on sale of Sul in 2016 (reflected within discontinued operations);
Favorable impact of a legal settlement at Uruguaiana;
Higher gains on foreign currency transactions; and
Higher margins at our US, Brazil, and Europe SBUs, lower equity in earnings of affiliates due to the gain earned in 2015 from the restructuring of Guacolda; partially offset by a lower adjusted effective tax rate and lower share count.
Net cash provided by operating activities increased by 35% to $2.9 billion primarily driven by an increase in collections at our Brazil utilities, the collection of overdue receivables at Maritza, and lower costs associated with the fulfillment of our service concession arrangement and lower working capital requirements at Mong Duong. These positive impacts were partially offset by the timing of payments at our Brazil utilities for higher energy purchases made in the prior year, collections of overdue receivables in the prior year in the Dominican Republic, and lower net income adjusted for non-cash items.
Proportional free cash flow, a non-GAAP measure, increased by 14% to $1.4 billion primarily driven by an increase in collections at our Brazil utilities, the collection of overdue receivables at Maritza, and lower working capital requirements at Mong Duong. These positive impacts were partially offset by the timing of payments at our Brazil utilities for higher energy purchases made in the prior year, collections of overdue receivables in the prior year in the Dominican Republic, and a decrease in Adjusted Operating Margin (a non-GAAP measure).
Review of Consolidated Results of Operations
|
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, | 2016 | | 2015 | | 2014 | | % Change 2016 vs. 2015 | | % Change 2015 vs. 2014 |
| (in millions, except per share amounts) | | | | | |
| Revenue: | | | |
| US SBU | $ | 3,429 |
| | $ | 3,593 |
| | $ | 3,826 |
| | -5 | % | | -6 | % |
| Andes SBU | 2,506 |
| | 2,489 |
| | 2,642 |
| | 1 | % | | -6 | % |
| Brazil SBU | 3,755 |
| | 3,858 |
| | 4,987 |
| | -3 | % | | -23 | % |
| MCAC SBU | 2,172 |
| | 2,353 |
| | 2,682 |
| | -8 | % | | -12 | % |
| Europe SBU | 918 |
| | 1,191 |
| | 1,439 |
| | -23 | % | | -17 | % |
| Asia SBU | 752 |
| | 684 |
| | 558 |
| | 10 | % | | 23 | % |
| Corporate and Other | 77 |
| | 31 |
| | 15 |
| | NM |
| | NM |
|
| Intersegment eliminations | (23 | ) | | (44 | ) | | (25 | ) | | 48 | % | | -76 | % |
| Total Revenue | 13,586 |
| | 14,155 |
| | 16,124 |
| | -4 | % | | -12 | % |
| Operating Margin: | | | | | | | | | |
| US SBU | 582 |
| | 621 |
| | 699 |
| | -6 | % | | -11 | % |
| Andes SBU | 634 |
| | 618 |
| | 587 |
| | 3 | % | | 5 | % |
| Brazil SBU | 239 |
| | 592 |
| | 634 |
| | -60 | % | | -7 | % |
| MCAC SBU | 523 |
| | 543 |
| | 541 |
| | -4 | % | | — | % |
| Europe SBU | 259 |
| | 303 |
| | 403 |
| | -15 | % | | -25 | % |
| Asia SBU | 170 |
| | 149 |
| | 76 |
| | 14 | % | | 96 | % |
| Corporate and Other | 15 |
| | 33 |
| | 53 |
| | -55 | % | | -38 | % |
| Intersegment eliminations | 11 |
| | (1 | ) | | (13 | ) | | NM |
| | 92 | % |
| Total Operating Margin | 2,433 |
| | 2,858 |
| | 2,980 |
| | -15 | % | | -4 | % |
| General and administrative expenses | (194 | ) | | (196 | ) | | (187 | ) | | -1 | % | | 5 | % |
| Interest expense | (1,431 | ) | | (1,344 | ) | | (1,451 | ) | | 6 | % | | -7 | % |
| Interest income | 464 |
| | 460 |
| | 320 |
| | 1 | % | | 44 | % |
| Loss on extinguishment of debt | (13 | ) | | (182 | ) | | (261 | ) | | -93 | % | | -30 | % |
| Other expense | (103 | ) | | (58 | ) | | (65 | ) | | 78 | % | | -11 | % |
| Other income | 65 |
| | 82 |
| | 121 |
| | -21 | % | | -32 | % |
| Gain on disposal and sale of businesses | 29 |
| | 29 |
| | 358 |
| | — | % | | -92 | % |
| Goodwill impairment expense | — |
| | (317 | ) | | (164 | ) | | NM |
| | 93 | % |
| Asset impairment expense | (1,096 | ) | | (285 | ) | | (91 | ) | | NM |
| | NM |
|
| Foreign currency transaction gains (losses) | (15 | ) | | 107 |
| | 11 |
| | NM |
| | NM |
|
| Other non-operating expense | (2 | ) | | — |
| | (128 | ) | | NM |
| | NM |
|
| Income tax benefit (expense) | 188 |
| | (472 | ) | | (371 | ) | | NM |
| | 27 | % |
| Net equity in earnings of affiliates | 36 |
| | 105 |
| | 19 |
| | -66 | % | | NM |
|
| INCOME FROM CONTINUING OPERATIONS | 361 |
| | 787 |
| | 1,091 |
| | -54 | % | | -28 | % |
| Income (loss) from operations of discontinued businesses | (19 | ) | | (25 | ) | | 111 |
| | -24 | % | | NM |
|
| Net loss from disposal and impairments of discontinued operations | (1,119 | ) | | — |
| | (55 | ) | | NM |
| | NM |
|
| NET INCOME (LOSS) | (777 | ) | | 762 |
| | 1,147 |
| | NM |
| | -34 | % |
| Noncontrolling interests: | | | | | | | | | |
| (Income) from continuing operations attributable to noncontrolling interests | (364 | ) | | (456 | ) | | (386 | ) | | -20 | % | | 18 | % |
| Net loss attributable to redeemable stocks of subsidiaries | 11 |
| | — |
| | — |
| | NM |
| | NM |
|
| Loss from discontinued operations attributable to noncontrolling interests | — |
| | — |
| | 8 |
| | NM |
| | NM |
|
| NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION | $ | (1,130 | ) | | $ | 306 |
| | $ | 769 |
| | NM |
| | -60 | % |
| AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS: | | | | | | |
| |
|
| Income from continuing operations, net of tax | $ | 8 |
| | $ | 331 |
| | $ | 705 |
| | -98 | % | | -53 | % |
| Income (loss) from discontinued operations, net of tax | (1,138 | ) | | (25 | ) | | 64 |
| | NM |
| | NM |
|
| NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION | $ | (1,130 | ) | | $ | 306 |
| | $ | 769 |
| | NM |
| | -60 | % |
| Net cash provided by operating activities | $ | 2,884 |
| | $ | 2,134 |
| | $ | 1,791 |
| | 35 | % | | 19 | % |
| DIVIDENDS DECLARED PER COMMON SHARE | $ | 0.45 |
| | $ | 0.41 |
| | $ | 0.25 |
| | 10 | % | | 64 | % |
_____________________________
NM — Not meaningfulMCAC SBU.
Components of Revenue, Cost of Sales and Operating Margin — Revenue includes revenue earned from the sale of energy from our utilities and the production of energy from our generation plants, which are classified as regulated and non-regulated, respectively, on the Consolidated Statements of Operations. Revenue also includes the gains or losses on derivatives associated with the sale of electricity.
Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, operations & maintenance costs, depreciation and amortization expense, bad debt expense and recoveries, and general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.
Operating margin is defined as revenue less cost of sales.
Consolidated Revenue and Operating Margin
(in millions)
Year Ended December 31, 20162018
Revenue
(in millions)
Consolidated Revenue— Revenue decreasedincreased $206 million, or 2%, in 20162018 compared to 20152017. Excluding the unfavorable FX impact of $52 million, primarily in South America partially offset by Eurasia, this increase was driven by:
$357 million in South America primarily due to: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;
Unfavorable$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
$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.
These favorable impacts were partially offset by decreases of $366 million in Eurasia due to the sale of the Masinloc power plant in March 2018, as well as the sale of the Kazakhstan CHPs and expiration of the Kazakhstan HPP concession agreement in 2017.
Operating Margin
(in millions)
Consolidated Operating Margin— Operating margin increased $108 million, or 4%, in 2018 compared to 2017. Excluding the favorable impact of FX of $8 million, primarily driven by Eurasia, this increase was driven by:
$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.
These favorable impacts were partially offset by a decrease of $511$204 million in Eurasia due to the drivers discussed above.
Year Ended December 31, 2017
Revenue
(in millions)
Consolidated Revenue— Revenue increased $249 million, or 2%, in 2017 compared to 2016. Excluding the net favorable FX impact of $38 million, primarily in South America, the increase was driven by:
$249 million in South America primarily due to the start of commercial operations at Cochrane as well as higher availability at Argentina, partially offset by lower spot sales at Chivor; and
$248 million in MCAC primarily due to the commencement of the combined cycle operations at Los Mina in June 2017 as well as higher rates in the Dominican Republic.
These favorable impacts were partially offset by decreases of $168 million in US & Utilities mainly due to lower retail tariffs, lower wholesale volume and price at DPL as well as hurricane impacts at Puerto Rico, partially offset by higher pass through costs in El Salvador.
Operating Margin
(in millions)
Consolidated Operating Margin— Operating margin increased $82 million, or 3%, in 2017 compared to 2016. Excluding the favorable impact of FX of $39 million, primarily in Brazil, of $213 million, Argentina, of $94 million, Kazakhstan of $63 million and Colombia, of $54 million.the increase was primarily driven by:
Brazil$73 million in MCAC due to lower rates for energy sold in Brazil under new contracts at Tietê;the commencement of the Los Mina combined cycle operations in 2015 but notJune 2017 in 2016 at Uruguiana; the reversal of a contingent regulatory liability in 2015, and lower demand, partially offset by the annual tariff adjustment at Eletropaulo.
Lower pass-through costs at El Salvador and IPP4 in Jordan, the sale of DPLER in January 2016, and lower rates at DPL.
These decreases were partially offset by:
The full operations at Mong Duong in 2016 compared to Unit 1 in March 2015 with principal operations commencing in April 2015
The commencement of operations at Cochrane in Chile with Unit 1 operational in July 2016 and principal operations in October).
Higher environmental returns and new rate case at IPL.
Consolidated Operating Margin— Operating margin decreased in 2016 compared to 2015 primarily due to:
Unfavorable FX impacts of $80 million, primarily in Kazakhstan, Argentina, and Colombia.
Brazil driven by the revenue drivers aboveDominican Republic as well as higher fixed costsavailability due to forced outages in 2016 at Eletropaulo.Mexico.
These decreasespositive impacts were partially offset by:
Higherby a decreases of $26 million in US and Utilities driven by lower retain margin, lower volumes, and lower commercial availability at Gener,DPL as well as a negative impact from full operations at Mong Duong in Vietnam and Cochrane in Chile, and higher margins at IPL as discussed above.
Year Ended December 31, 2015
Consolidated Revenue— Revenue decreased in 2015 compared to 2014 primarily due to:
Unfavorable FX impacts of $2.2 billion, mainly in Brazil of $1.8 billion, Colombia of $179 million, and Bulgaria of $74 million.
US Utilities due to lower volumes primarily at DPL and outages, milder weather, and lower demand at IPL.
Lower prices in the Dominican Republic and El Salvador (primarily resulting from lower pass-through costs).
These decreases were partially offset by:
Brazilone-off accruals due to higher tariffs at Eletropaulo (including higher pass-through costs) and the reversalimplementation of a contingent regulatory liability at Eletropaulo.
Higher capacity prices at DPL.
Commencement of principal operations at Mong Duongnew base rates in April 2015.Q2 2016.
Consolidated Operating Margin— Operating margin decreased in 2015 compared to 2014 primarily due to:
Unfavorable FX impacts of $362 million, primarily in Brazil of $228 million and Colombia of $83 million.
Brazil due to lower demand, lower hydrology, and higher fixed costs.
The Dominican Republic due to lower prices and lower availability.
These decreases were partially offset by:
Higher tariffs in Brazil as discussed above and lower spot prices on energy purchases at Tietê.
Higher generation and lower energy purchases driven by improved hydrological conditions in Panama.
Higher prices at Chivor driven by a strong El Niño.
Higher availability at Gener and Masinloc.
Consolidated Results of Operations — Other
General and administrative expenses
General and administrative expenses include expenses related to corporate staff functions and/orand initiatives, executive management, finance, legal, human resources and information systems, as well as global development costs.
General and administrative expenses decreased in 2016 from 2015$23 million, or 11%, to $192 million for 2018, compared to $215 million for 2017 primarily due to decreased employee-relatedreduced people costs, partially offset by increasedprofessional fees and business development costs.activity.
General and administrative expenses increased in 2015 from 2014$21 million, or 11%, to $215 million for 2017, compared to $194 million for 2016 primarily due to severance costs related to workforce reductions associated with a major restructuring program, increased professional fees and increased business development costs and employee-related costs partially offset by decreased professional fees.activity.
Interest expense
Interest expense increased in 2016 from 2015decreased $114 million, or 10%, to $1,056 million for 2018, compared to $1,170 million for 2017 primarily due to a $97the reduction of debt at the Parent Company, favorable impacts from interest rate swaps in Chile and increased capitalized interest at Alto Maipo.
Interest expense increased $36 million, or 3%, to $1,170 million for 2017, compared to $1,134 million for 2016 primarily due to an increase at Eletropaulothe South America SBU, driven by lower capitalized interest in 2017 due to the Cochrane plant starting commercial operations in the second half of 2016.
Interest income
Interest income increased $66 million, or 27%, to $310 million for 2018, compared to $244 million for 2017 primarily due to higher interest rates and increased long term receivables as a result of the prior year reversal of $64 million in interest expense, previously recognized on a contingent regulatory liability, and increased interest expense due to higher regulatory liabilities and interest rates in the current year. Additionally, there was a $26 million increase at Mong Duong, mainly due to this entity no longer capitalizing interest as a resultadoption of the commencementnew revenue recognition standard. See Note 1—General and Summary of operationsSignificant Accounting Policies included in April 2015. These increases were partially offset by lower interest expenseItem 8.—Financial Statements and Supplementary Data of $22 million due to a reduction in debt principal at the Parent Company.
Interest expense decreased in 2015 from 2014 primarily due to lower interest expense of $63 million at the Parent Company due to a reduction in debt principal, and a $64 million reversal of interest expense previously recognized on a contingent regulatory liability at Eletropaulo. These decreases were partially offset by an increase at Mong Duong as the plant commenced operations in April 2015 and ceased capitalizing interest.
Interest incomethis Form 10-K for further information.
Interest income increased in 2016 from 2015 primarily due to higher interest income of $19 million recognized on the financing element of the service concession arrangement at Mong Duong, which became fully operational in April 2015, partially offset by lower interest income of $16decreased $1 million in Argentina due to prior year recognition of accumulated interest on VAT balances related to CAMESSA.
Interest income increased in 20152017 from 2014 primarily due to interest income of $114 million recognized in 2015 on the financing element of the service concession arrangement at Muong Duong, as well as an increase of $36 million at Eletropaulo resulting from higher interest rates and an increase in regulatory assets.2016 with no material drivers.
Loss on extinguishment of debt
Loss on extinguishment of debt was $13increased $120 million to $188 million for the year ended December 31, 20162018, compared to $68 million for 2017. This increase was primarily relateddue to expense of $14 million recognized on debt extinguishmenthigher losses at the Parent Company.Company of $79 million from the redemption of senior notes and a prior year gain on early retirement of debt at AES Argentina of $65 million; partially offset by lower losses at other subsidiaries of $24 million in 2018.
Loss on extinguishment of debt was $182increased $55 million to $68 million for the year ended December 31, 2015. This loss was2017, compared to $13 million for 2016 primarily related to expenselosses of $105$92 million, $22$20 million, and $19$9 million recognized on debt extinguishments at the Parent Company, IPL,AES Gener, and the Dominican Republic,IPALCO, respectively.
Loss The loss was partially offset by a gain on extinguishmentearly retirement of debt was $261 million for the year ended December 31, 2014. This was primarily related to expenseat AES Argentina of $193 million, $31 million, and $20 million recognized on debt extinguishments at the Parent
Company, DPL, and Gener, respectively.$65 million.
Other income and expense
Other income decreased in 2016 from 2015$48 million, or 40%, to $72 million for 2018, compared to $120 million for 2017 primarily due to gains on early contract termination in 2015the 2017 favorable settlement of legal proceedings at Uruguaiana related to YPF's breach of the parties’ gas supply agreement and lower gains on asset sales in 2016; partially offset by an increasea decrease in allowance for funds used during construction in the US and Utilities SBU. These decreases were partially offset by a gain on remeasurement of contingent liabilities for projects in Hawaii in 2018.
Other income increased $56 million, or 88%, to $120 million for 2017, compared to $64 million for 2016 primarily due to the 2017 favorable legal settlement mentioned above.
Other expense
Other expense remained flat at $58 million for 2018, compared to 2017 primarily due to a loss resulting from damage associated with a lightning incident at the Andres facility in the Dominican Republic in 2018 and higher non-service pension and other postretirement costs in 2018. This was offset by the 2017 write-off of water rights for projects that were no longer being pursued in the South America SBU and a loss on disposal of assets at DPL as a result of increased construction activitythe decision to close the coal-fired and diesel-fired generating units at IPL.Stuart and Killen.
Other income decreased in 2015 from 2014 primarily due to lower gains on asset sales in 2015 and the 2014 reversal of a liability in Kazakhstan due to the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES.
Other expense increased indecreased $22 million, or 28%, to $58 million for 2017, compared to $80 million for 2016 from 2015 primarily due to the 2016 recognition of a full allowance on a non-trade receivable in the MCAC SBU as a result of payment delays and discussions withdelays. This decrease was partially offset by the counterparty. The allowance relates to certain reimbursements the Company was expecting in connection with a legal matter. Management believes the counterparty is obligated to pay and plans to continue to attempt to fully collect the non-trade receivable.
Other expense decreased in 2015 from 2014 primarily due to lower losses2017 loss on sales and disposal of assets at Termo AndesDPL as a result of the decision to close the coal-fired and Eletropaulo.diesel-fired generating units at Stuart and Killen and the write-off of water rights in the South America SBU for projects that are no longer being pursued.
See Note 19—Other Income and Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. Gain (loss) on disposal and sale of business interests
Gain on disposal and sale of businessesbusiness interests was $984 million for 2018 primarily due to the $772 million gain on sale of Masinloc and the $129 million and $69 million gains on sales of CTNG and Electrica Santiago, respectively, in Chile.
Loss on disposal and sale of business interests was $52 million for 2017 primarily due to the $49 million and $33 million losses on sale of Kazakhstan CHPs and HPPs, respectively, partially offset by the recognition of a $23 million gain related to the expiration of a contingency at Masinloc.
Gain on disposal and sale of businessesbusiness interests was $29 million for the year ended December 31, 2016 which was primarily relateddue to the $49 million gain on sale of DPLER, partially offset by athe $20 million loss on the deconsolidation of U.K. Wind.
Gain on saleSee Note 23—Held-For-Sale and Dispositions included in Item 8.—Financial Statements and Supplementary Data of businesses was $29 millionthis Form 10-K for the year ended December 31, 2015, which was primarily related to the sale of Armenia Mountain.Gain on disposal and sale of investments for the year ended December 31, 2014 was $358 million, which was primarily related to the sale of 45% of the Company's interest in Masinloc, as well as the sale of U.K. Wind (Operating Projects).further information.
Goodwill impairment expense
There were no goodwill impairments for the yearyears ended December 31, 2018, 2017, or 2016.
Asset impairment expense
Asset impairment expense was $317decreased $329 million, or 61%, to $208 million for 2018, compared to $537 million for 2017 mainly driven by prior year impairments of $186 million recognized in Kazakhstan due to the classification of the CHPs and HPPs as held-for-sale and $296 million in the U.S. as a result of the decision to sell the DPL peaker assets and a decline in forward pricing at Laurel Mountain, partially offset by a current year impairment of $157 million due to decreased future cash flows and the decision to sell Shady Point.
Asset impairment expense decreased $559 million, or 51%, to $537 million for 2017, compared to $1,096 million for 2016 mainly driven by the impairment of $859 million at DPL in 2016, partially offset by a $121 million impairment at Laurel Mountain in 2017 as a result of a decline in forward pricing.
See Note 20—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. Foreign currency transaction gains (losses)
Foreign currency transaction gains (losses) in millions were as follows:
|
| | | | | | | | | | | |
| Years Ended December 31, | 2018 | | 2017 | | 2016 |
Argentina (1) | $ | (71 | ) | | $ | 1 |
| | $ | 37 |
|
| Chile | (13 | ) | | 8 |
| | (9 | ) |
| Bulgaria | (6 | ) | | 14 |
| | (8 | ) |
| United Kingdom | (2 | ) | | (3 | ) | | 13 |
|
| Philippines | (1 | ) | | 15 |
| | 12 |
|
| Mexico | — |
| | 17 |
| | (8 | ) |
| Colombia | 6 |
| | (23 | ) | | (8 | ) |
| Corporate | 11 |
| | 3 |
| | (50 | ) |
| Other | 4 |
| | 10 |
| | 6 |
|
Total (2) | $ | (72 | ) | | $ | 42 |
| | $ | (15 | ) |
_____________________________
| |
(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 6—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. |
| |
(2) | Includes gains of $23 million, losses of $21 million, andgainsof$17 million on foreign currency derivative contracts for the years ended December 31, 2018, 2017 and 2016, respectively. |
The Company recognized net foreign currency transaction losses of $72 million for the year ended December 31, 20152018 primarily due to a goodwill impairmentthe unrealized losses from the devaluation of receivables denominated in Argentine pesos and realized losses from Chilean pesos. These losses were partially offset by foreign currency derivative gains at DP&L.the Parent Company.
Goodwill impairment expense was $164The Company recognized net foreign currency transaction gains of $42 million for the year ended December 31, 2014. This2017 primarily driven by transactions associated with VAT activity in Mexico, the amortization of frozen embedded derivatives in the Philippines, and appreciation of the Euro in Bulgaria. These gains were partially offset by foreign currency derivative losses in Colombia due to a change in functional currency.
The Company recognized net foreign currency transaction losses of $15 million for the year ended December 31, 2016 primarily due to remeasurement losses on intercompany notes, and losses on swaps and options at the Parent Company. These losses were partially offset by foreign currency derivative gains related to government receivables in Argentina.
Other non-operating expense consisted
Other non-operating expense was $147 million in 2018 primarily due to the $144 million other-than-temporary impairment of $136 million, $20 millionthe Guacolda equity method investment as a result of increased renewable generation in Chile lowering energy prices and $8 millionimpacting the ability of goodwill impairments at DPLER, Buffalo Gap IIGuacolda to re-contract its existing PPAs after they expire.
There were no significant other non-operating expenses in 2017 and Buffalo Gap I, respectively.2016.
Asset impairment expense
Asset impairment expense was $1.1 billion for the year ended December 31, 2016. This was primarily related to asset impairments of $859 million, $159 million and $77 million at DPL, Buffalo Gap II and Buffalo Gap I, respectively.
Asset impairment expense was $285 million for the year ended December 31, 2015 primarily due to asset impairments of $121 million, $116 million and $37 million at Kilroot, Buffalo Gap III and U.K. Wind, respectively.
Asset impairment expense was $91 million for the year ended December 31, 2014 primarily due to asset impairments of $67 million, $12 million and $12 million at Ebute, U.K. Wind and DPL, respectively.
See Note 20—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Income tax expense
Income tax expense decreased $282 million to a benefit of $188$708 million in 20162018 as compared to expense of $472$990 million in 2015.for 2017. The Company's effective tax rates were (137%)35% and 41%128% for the years ended December 31, 20162018 and 2015,2017, respectively.
The net decrease in the 2018 effective tax rate was primarily due to greater 2017 impacts related to U.S. tax reform one-time transition tax and remeasurement of deferred tax assets, relative to the 2018 U.S. tax reform impact to adjust the provisional estimate recorded under SAB 118, which provides SEC guidance on the application of the accounting standards for the initial enactment impacts of the TCJA. This net decrease was also attributable to the impact of the sale of the Company's entire 51% equity interest in Masinloc, offset by taxation of our foreign subsidiaries under U.S. GILTI rules.
Income tax expense increased $958 million to $990 million in 2017 as compared to $32 million for 2016. The Company's effective tax rates were 128% and 17% for the years ended December 31, 2017 and 2016, respectively.
The net increase in the 2017 effective tax rate was due in part,primarily to the 2016 asset impairmentsenactment of the TCJA in the U.S. and to the current year benefit related to a restructuring of one of our Brazilian businesses that increases tax basis in long-term assets. Further, the 2015 rate was impacted, partially offset by the items described below.impacts of the 2016 Chilean tax law reform and the 2016 devaluation of the Mexican peso. See Note 20—Asset Impairment Expense21—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional information regarding the 2016 U.S. asset impairments. Income tax expense increased $101 million, or 27%, to $472 million in 2015. The Company's effective tax rates were 41% and 26% for the years ended December 31, 2015 and 2014, respectively.
The net increase in the 2015 effective tax rate was due, in part, to the nondeductible 2015 impairment of goodwill at our U.S. utility, DP&L and Chilean withholding taxes offset by the release of valuation allowance at certain of our businesses in Brazil, Vietnam and the U.S. Further, the 2014 rate was impacted by the sale of approximately 45% of the Company’s interest in Masin AES Pte Ltd., which owns the Company’s business interests in the Philippines and the 2014 sale of the Company’s interests in four U.K. wind operating projects. Neither of these transactions gave rise to income tax expense. See Note 15—Equity for additional information regarding the sale of approximately 45% of the Company’s interest in Masin-AES Pte Ltd. See Note 23—Dispositions for additional information regarding the sale of the Company’s interests in four U.K. wind operatingprojects.law reform.
Our effective tax rate reflects the tax effect of significant operations outside the U.S., which are generally taxed at rates lowerdifferent than the U.S. statutory rate. Foreign earnings may be taxed at rates higher than the U.S. corporate rate of 35%.21% and are also subject to current U.S. taxation under the GILTI rules introduced by the TCJA. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate. The Company also benefits from reduced tax rates in certain countries as a result of satisfying specific commitments regarding employment and capital investment. See Note 21—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional information regarding these reduced rates. Foreign currency transaction gains (losses)
Foreign currency transaction gains (losses) in millions were as follows:
|
| | | | | | | | | | | |
| Years Ended December 31, | 2016 | | 2015 | | 2014 |
| AES Corporation | $ | (50 | ) | | $ | (31 | ) | | $ | (34 | ) |
| Chile | (9 | ) | | (18 | ) | | (30 | ) |
| Colombia | (8 | ) | | 29 |
| | 17 |
|
| Mexico | (8 | ) | | (6 | ) | | (14 | ) |
| Philippines | 12 |
| | 8 |
| | 11 |
|
| United Kingdom | 13 |
| | 11 |
| | 12 |
|
| Argentina | 37 |
| | 124 |
| | 66 |
|
| Other | (2 | ) | | (10 | ) | | (17 | ) |
Total (1) | $ | (15 | ) | | $ | 107 |
| | $ | 11 |
|
_____________________________
| |
(1)
| Includes gains of $17 million, $247 million and $172 million on foreign currency derivative contracts for the years ended December 31, 2016, 2015 and 2014, respectively. |
The Company recognized a net foreign currency transaction loss of $15 million for the year ended December 31, 2016 primarily due to losses of $50 million at The AES Corporation mainly due to remeasurement losses on intercompany notes, and losses on swaps and options.
This loss was partially offset by gains of $37 million in Argentina, mainly due to the favorable impact of foreign currency derivatives related to government receivables.
The Company recognized a net foreign currency transaction gain of $107 million for the year ended December 31, 2015 primarily due to gains of:
$124 million in Argentina, due to the favorable impact from foreign currency derivatives related to government receivables, partially offset by losses from the devaluation of the Argentine Peso associated with U.S. Dollar denominated debt, and losses at Termoandes (a U.S. Dollar functional currency subsidiary) primarily associated with cash and accounts receivable balances in local currency,
$29 million in Colombia, mainly due to the depreciation of the Colombian Peso, positively impacting Chivor (a U.S. Dollar functional currency subsidiary) due to liabilities denominated in Colombian Pesos,
$11 million in the United Kingdom, mainly due to the depreciation of the Pound Sterling, resulting in gains at Ballylumford Holdings (a U.S. Dollar functional currency subsidiary) associated with intercompany notes payable denominated in Pound Sterling, and
These gains were partially offset by losses of:
$31 million at The AES Corporation primarily due to decreases in the valuation of intercompany notes receivable denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the year, partially offset by gains related to foreign currency option purchases, and
$18 million in Chile primarily due to the devaluation of the Chilean Peso at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos, partially offset by gains on foreign currency derivatives.
The Company recognized a net foreign currency transaction gains of $11 million for the year ended December 31, 2014 primarily due to gains of:
$66 million in Argentina, due to the favorable impact from foreign currency derivatives related to government receivables, partially offset by losses from the devaluation of the Argentine Peso associated with U.S. Dollar denominated debt, and losses at Termoandes (a U.S. Dollar functional currency subsidiary) primarily associated with cash and accounts receivable balances in local currency, and the purchase of Argentine sovereign bonds,
$17 million in Colombia, mainly due to a 23% depreciation of the Colombian Peso, positively impacting Chivor (a U.S. Dollar functional currency subsidiary) due to liabilities denominated in Colombian Pesos, primarily income tax payable and accounts payable,
$12 million in the United Kingdom, mainly due to a 6% depreciation of the Pound Sterling, resulting in gains at Ballylumford Holdings (a U.S. Dollar functional currency subsidiary) associated with intercompany notes payable denominated in Pound Sterling, and gains related to foreign currency derivatives, and
$11 million in the Philippines, mainly due to amortization of frozen embedded derivatives and a 4% appreciation of the Philippine Peso against the U.S. Dollar, resulting in a revaluation of cash accounts, customer receivables, and deferred tax asset.
These gains were partially offset by losses of:
$34 million at The AES Corporation primarily due to decreases in the valuation of intercompany notes receivable denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the year, partially offset by gains related to foreign currency option purchases,
$30 million in Chile primarily due to a 16% devaluation of the Chilean Peso, resulting in a $39 million loss at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos, primarily cash, accounts receivable and VAT receivables, partially offset by income of $9 million on foreign currency derivatives, and
$14 million in Mexico, primarily due to a 13% devaluation of the Mexican Peso, resulting in a loss at TEGTEP and Merida (U.S. Dollar functional currency subsidiaries) from working capital denominated in Pesos (primarily cash, recoverable tax, and VAT).
Other non-operating expense
There were no significant non-operating expenses for the years ended December 31, 2016 and 2015.
Other non-operating expense was $128 million for the year ended December 31, 2014 due to impairments recognized at Entek and Silver Ridge.
See Note 8—Other Non-Operating Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Net equity in earnings of affiliates
Net equity in earnings of affiliates decreased in 2016$32 million, or 45%, to $39 million for 2018, compared to 2015 as a result$71 million for 2017 primarily due to losses at Fluence, which was formed in the first quarter of 2018, decreased income at Guacolda, and larger gains on projects that achieved commercial operations in 2017 than in 2018 at sPower, which was purchased in the restructuringthird quarter of Guacolda in September 2015, which resulted in a $66 million benefit. No comparable transaction occurred in 2016.2017.
Net equity in earnings of affiliates increased $35 million, or 97%, to $71 million in 20152017, compared to 2014$36 million for 2016 primarily due to earnings at the sPower equity method investment purchased in 2017, partially offset by fixed asset impairments in 2017 at the Distributed Energy entities, accounted for as a result of the restructuring of Guacolda in September 2015, which resulted in a $66 million benefit, as well as the impairment at Elsta in 2014.equity affiliates.
Net income (loss) from discontinued operations
IncomeNet income from continuingdiscontinued operations attributable to noncontrolling interests
Income from continuing operations attributable to noncontrolling interests decreased in 2016 compared to 2015 as a result of:
a decrease at Tietê due to lower earnings
a decrease at Eletropaulo resulting fromwas $216 million for the the reversal of a contingent regulatory liability in 2015, and
asset impairments at Buffalo Gap I and II;
Partially offset by:
a lower asset impairment at Buffalo Gap III in 2015, and
income tax benefits at Eletropaulo.
Income from continuing operations attributable to noncontrolling interests increased in 2015 compared to 2014 as a result of:
an increase at Mong Duong due to commencement of operations in 2015,
an increase at Generyear ended December 31, 2018 primarily due to the restructuringafter-tax gain on sale of Guacolda,
an increase at Masinloc due to increased earningsEletropaulo of $199 million recognized in 2015the second quarter of 2018 and the 2014 salerecognition of a noncontrolling interest$26 million deferred gain upon liquidation of Borsod in that businessOctober 2018.
Partially offset by:
a decrease at Buffalo Gap III resulting from the asset impairment expense allocation to the tax equity partner, and
a decrease at Eletropaulo resulting from unfavorable foreign exchange and lower demand.
Loss from discontinued operations
TotalNet loss from discontinued operations was $629 million for the year ended December 31, 2017 primarily due to the after-tax loss on deconsolidation of Eletropaulo of $611 million recognized in the fourth quarter of 2017. The remaining loss was due to a loss contingency recognized by our equity affiliate, partially offset by the income from operations of Eletropaulo prior to the date of deconsolidation.
Net loss from discontinued operations was $968 million for the year ended December 31, 2016 and 2015 was due to the sale of AES Sul.Sul, partially offset by the income from operations of Eletropaulo. The loss in 2016 includes an after taxafter-tax loss on the impairment of Sul of $382 million recognized in the second quarter of 2016 and an additional after taxafter-tax loss on the sale of Sul of $737 million recognized upon disposal of AES Sul in October 2016. There werewas no significant changes in loss from operations related to the AES Sul discontinued business.
Total income from discontinued operations for the year ended December 31, 2014 was primarily due to AES Sul, Cameroon, Saurashtra and U.S. wind projects.
See Note 22—Discontinued Operationsincluded in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. Net income attributable to noncontrolling interests and redeemable stock of subsidiaries
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries decreased $22 million, or 6%, to $362 million in 2018, compared to $384 million in 2017. This decrease was primarily due to:
•Current year other-than-temporary impairment of Guacolda;
•Prior year favorable impact of a legal settlement at Uruguaiana; and
•Lower earnings due to deconsolidation of Eletropaulo in November 2017 and the sale of Masinloc in March 2018.
These decreases were partially offset by:
•Current year gains on sales of Electrica Santiago and CTNG in Chile;
•Higher earnings in Colombia primarily due to higher contract sales and prices; and
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries increased $31 million, or 9%, to $384 million in 2017, compared to $353 million in 2016. This increase was primarily due to:
•Asset impairments at Buffalo Gap I and II in 2016.
These increases were partially offset by:
•Income tax benefits at Eletropaulo in 2016 (reflected within discontinued operations).
Net income (loss) attributable to The AES Corporation
Net income (loss) attributable to The AES Corporation decreasedincreased $2,364 million to $1,203 million in 20162018, compared to 2015 as a result of:loss of $1,161 million in 2017. This increase was primarily due to:
impairmentsGains on the sales of Masinloc, Eletropaulo (reflected within discontinued operations), CTNG, and Electrica Santiago, and prior year losses on the sales of Kazakhstan CHPs and HPPs;
Prior year loss on saledeconsolidation of Eletropaulo (reflected within discontinued operations);
Prior year impact of U.S. tax reform enacted in December 2017;
Prior year asset impairments at discontinued businesses;DPL, Laurel Mountain and in Kazakhstan;
higher impairmentLower interest expense on long lived assets;at the Parent Company and Gener; and
lower operatingHigher margins at our South America, MCAC and US Brazil and Europe SBUs;
lower equity in earnings of affiliates due to the 2015 restructuring at Guacolda; and
lower gains on foreign currency derivatives.Utilities SBUs.
These decreasesincreases were partially offset by:
lower effectiveHigher current year tax rate;expense due to the new GILTI rules in the U.S.;
lowerCurrent year impairment at Shady Point;
Current year other-than-temporary impairment of Guacolda;
Higher losses on extinguishment of debt extinguishment expense;in the current year;
Current year foreign exchange losses primarily due to the devaluation of the Argentine peso and foreign currency gains in the prior year;
Prior year favorable impact of a legal settlement at Uruguaiana; and
absenceLower margins in the current year at our Eurasia SBU as a result of goodwill impairment expense.
the sales of Masinloc and Kazakhstan. Net incomeloss attributable to The AES Corporation decreasedincreased $31 million, or 3%, to $1,161 million in 20152017, compared to 2014 as result of:$1,130 million in 2016. This increase was primarily due to:
Impact of U.S. tax reform enacted in December 2017;
Losses on the sales of Kazakhstan CHPs and HPPs;
Loss on deconsolidation of Eletropaulo (reflected within discontinued operations);
Impairments at Laurel Mountain, Kilroot and in Kazakhstan; and
Higher impairment expense
Lower gains from the saleloss on extinguishment of businessesdebt.
These decreasesincreases were partially offset by:
Lower debt extinguishment expenseImpairments at DPL in 2016;
Loss on sale of Sul in 2016 (reflected within discontinued operations);
Favorable impact of a legal settlement at Uruguaiana;
Higher gains on foreign currency transactions; and
Higher margins at our MCAC SBU.
SBU Performance Analysis
Segments
We are organized into four market-oriented SBUs: US and Utilities (United States, Puerto Rico and El Salvador); South America (Chile, Colombia, Argentina and Brazil); MCAC (Mexico, Central America and the Caribbean); and Eurasia (Europe and Asia). During the first quarter of 2018, the Andes and Brazil SBUs were merged in order to leverage scale and are now reported together as part of the South America SBU. Further, the Puerto Rico and El Salvador businesses, formerly part of the MCAC SBU, were combined with the US SBU, which is now reported as the US and Utilities SBU.
Non-GAAP Measures
Adjusted Operating Margin, Adjusted PTC and Adjusted EPS and Proportional Free Cash Flow are non-GAAP supplemental measures that are used by management and external users of our consolidated financial statementsConsolidated Financial Statements such as investors, industry analysts and lenders.
Effective January 1, 2018, the Company changed the definitions of Adjusted PTC and Adjusted EPS to exclude unrealized gains or losses from equity securities resulting from a newly effective accounting standard. We believe excluding these gains or losses provides a more accurate picture of continuing operations. Factors in this determination include the variability due to unrealized gains or losses related to equity securities remeasurement.
Adjusted Operating Margin
We define Adjusted Operating Margin as Operating Margin, adjusted for the impact of NCI, excluding (a) unrealized gains or losses related to derivative transactions.transactions; (b) benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures; and (c) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations and office consolidation. The allocation of HLBV earnings to noncontrolling interests is not adjusted out of Adjusted Operating Margin. See Review of Consolidated Results of Operations for definitions of Operating Margin and cost of sales.
The GAAP measure most comparable to Adjusted Operating Margin is Operating Margin. We believe that Adjusted Operating Margin better reflects the underlying business performance of the Company. Factors in this determination include the impact of NCI, where AES consolidates the results of a subsidiary that is not wholly owned by the Company, as well as the variability due to unrealized derivatives gains or losses.losses related to derivative transactions and strategic decisions to dispose of or acquire business interests. Adjusted Operating Margin should not be construed as an alternative to Operating Margin, which is determined in accordance with GAAP.
| | | Reconciliation of Adjusted Operating Margin (in millions) | Years Ended December 31, | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2018 | | 2017 | | 2016 |
| Operating Margin | $ | 2,433 |
| | $ | 2,858 |
| | $ | 2,980 |
| $ | 2,573 |
| | $ | 2,465 |
| | $ | 2,383 |
|
| Noncontrolling Interests Adjustment | (689 | ) | | (869 | ) | | (760 | ) | |
| Derivatives Adjustment | 9 |
| | 19 |
| | 8 |
| |
Noncontrolling interests adjustment (1) | | (686 | ) | | (689 | ) | | (645 | ) |
| Unrealized derivative losses (gains) | | 19 |
| | (5 | ) | | 9 |
|
| Disposition/acquisition losses | | 21 |
| | 22 |
| | — |
|
Restructuring costs (2) | | 1 |
| | 22 |
| | — |
|
| Total Adjusted Operating Margin | $ | 1,753 |
| | $ | 2,008 |
| | $ | 2,228 |
| $ | 1,928 |
| | $ | 1,815 |
| | $ | 1,747 |
|
| |
(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. |
Adjusted PTC
We define Adjusted PTC as pretaxpre-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,losses; (c) gains, or losses, due tobenefits and costs associated with dispositions and acquisitions of business interests, including early plant closures; (d) losses due to impairments,impairments; (e) gains, losses and (e) costs due to the early retirement of debt.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.
Adjusted PTC reflects the impact of NCI and excludes the items specified in the definition above. In addition to the revenue and cost of sales reflected in Operating Margin, Adjusted PTC includes the other components of our income statement,Consolidated Statement of Operations, such as general and administrative expenseexpenses in the corporateCorporate segment, as well as business development costs; costs, interest expense and interest income,; other expense and other income,; realized foreign currency transaction gains and losses,; and net equity in earnings of affiliates.
The GAAP measure most comparable to Adjusted PTC is income from continuing operations attributable to The AES Corporation. We believe that 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.performance of its segments. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose of or acquire business interests, or retire debt or implement restructuring initiatives, which affect results in a given period or periods. In addition, earnings before tax represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. 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.
Adjusted PTC should not be construed as an alternative to income from continuing operations attributable to The AES Corporation, which is determined in accordance with GAAP.
|
| | | | | | | | | | | |
| Reconciliation of Adjusted PTC (in millions) | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| Income from continuing operations, net of tax, attributable to The AES Corporation | $ | 8 |
| | $ | 331 |
| | $ | 705 |
|
| Income tax (benefit) expense attributable to The AES Corporation | (148 | ) | | 275 |
| | 179 |
|
| Pretax contribution | (140 | ) | | 606 |
| | 884 |
|
| Unrealized derivative (gains) losses | (9 | ) | | (166 | ) | | (135 | ) |
| Unrealized foreign currency losses | 23 |
| | 96 |
| | 110 |
|
| Disposition/acquisition (gains) losses | 6 |
| | (42 | ) | | (361 | ) |
| Impairment losses | 933 |
| | 504 |
| | 415 |
|
| Loss on extinguishment of debt | 29 |
| | 179 |
| | 274 |
|
| Total Adjusted PTC | $ | 842 |
| | $ | 1,177 |
| | $ | 1,187 |
|
|
| | | | | | | | | | | |
| Reconciliation of Adjusted PTC (in millions) | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Income (loss) from continuing operations, net of tax, attributable to The AES Corporation | $ | 985 |
| | $ | (507 | ) | | $ | (20 | ) |
| Income tax expense (benefit) attributable to The AES Corporation | 563 |
| | 828 |
| | (111 | ) |
| Pre-tax contribution | 1,548 |
| | 321 |
| | (131 | ) |
| Unrealized derivative and equity securities losses (gains) | 33 |
| | (3 | ) | | (9 | ) |
| Unrealized foreign currency losses (gains) | 51 |
| | (59 | ) | | 22 |
|
| Disposition/acquisition losses (gains) | (934 | ) | | 123 |
| | 6 |
|
| Impairment expense | 307 |
| | 542 |
| | 933 |
|
| Loss on extinguishment of debt | 180 |
| | 62 |
| | 29 |
|
Restructuring costs (1) | — |
| | 31 |
| | — |
|
| Total Adjusted PTC | $ | 1,185 |
| | $ | 1,017 |
| | $ | 850 |
|
_____________________________
| |
(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. |
Adjusted EPS
We define Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses,losses; (c) gains, or losses, due tobenefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and the tax impact from the repatriation of sales proceeds; (d) losses due to impairments,impairments; (e) gains, losses and (e) costs due to the early retirement of debt.debt; (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations and office consolidation; and (g) tax benefit or expense related to the enactment effects of 2017 U.S. tax law reform and related regulations and any subsequent period adjustments related to enactment effects.
The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. We believe that Adjusted EPS better reflects the underlying business performance of the Company and is considered in the Company's internal evaluation of financial performance. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose of or acquire business interests, or retire debt or implement restructuring initiatives, which affect results in a given period or periods. Adjusted EPS should not be construed as an alternative to diluted earnings per share from continuing operations, which is determined in accordance with GAAP.
The Company reported a loss from continuing operations of $0.77 and $0.04 per share for the years ended December 31, 2017 and 2016, respectively. For purposes of measuring diluted loss per share under GAAP, common stock equivalents were excluded from weighted average shares as their inclusion would be anti-dilutive. However, for purposes of computing Adjusted EPS, the Company has included the impact of anti-dilutive common stock equivalents. The table below reconciles the weighted average shares used in GAAP diluted loss per share to
the weighted average shares used in calculating the non-GAAP measure of Adjusted EPS. No reconciliation is necessary for the year ended December 31, 2018 as the Company reported income from continuing operations.
|
| | | | | | | | | | | | | | | | | | | | | | |
| Reconciliation of Denominator Used For Adjusted Earnings Per Share | | Year Ended December 31, 2017 | | Year Ended December 31, 2016 |
| (in millions, except per share data) | | Loss | | Shares | | $ per share | | Loss | | Shares | | $ per share |
| GAAP DILUTED LOSS PER SHARE | | | | | | | | | | | | |
| Loss from continuing operations attributable to The AES Corporation common stockholders | | $ | (507 | ) | | 660 |
| | $ | (0.77 | ) | | $ | (25 | ) | | 660 |
| | $ | (0.04 | ) |
| EFFECT OF ANTI-DILUTIVE SECURITIES | | | | | | | | | | | | |
| Restricted stock units | | — |
| | 2 |
| | 0.01 |
| | — |
| | 2 |
| | — |
|
| NON-GAAP DILUTED LOSS PER SHARE | | $ | (507 | ) | | 662 |
| | $ | (0.76 | ) | | $ | (25 | ) | | 662 |
| | $ | (0.04 | ) |
|
| | | | | | | | | | | | |
| Adjusted EPS | Years Ended December 31, | |
| | 2016 | | 2015 | | 2014 | |
| Diluted earnings per share from continuing operations | $ | — |
| | $ | 0.48 |
| | $ | 0.97 |
| |
| Unrealized derivative gains | (0.02 | ) | | (0.24 | ) | | (0.19 | ) | |
| Unrealized foreign currency losses | 0.04 |
| | 0.14 |
| | 0.16 |
| |
| Disposition/acquisition (gains) losses | 0.01 |
| (1) | (0.06 | ) | (2) | (0.50 | ) | (3) |
| Impairment losses | 1.41 |
| (4) | 0.73 |
| (5) | 0.57 |
| (6) |
| Loss on extinguishment of debt | 0.05 |
| (7) | 0.26 |
| (8) | 0.38 |
| (9) |
| Less: Net income tax benefit | (0.51 | ) | (10) | (0.06 | ) | (11) | (0.21 | ) | (12) |
| Adjusted EPS | $ | 0.98 |
| | $ | 1.25 |
| | $ | 1.18 |
| |
|
| | | | | | | | | | | | |
| Reconciliation of Adjusted EPS | Years Ended December 31, | |
| | 2018 | | 2017 | | 2016 | |
| Diluted earnings (loss) per share from continuing operations | $ | 1.48 |
| | $ | (0.76 | ) | | $ | (0.04 | ) | |
| Unrealized derivative and equity securities losses (gains) | 0.05 |
| | — |
| | (0.01 | ) | |
| Unrealized foreign currency losses (gains) | 0.09 |
| (1) | (0.10 | ) | | 0.03 |
| |
| Disposition/acquisition losses (gains) | (1.41 | ) | (2) | 0.19 |
| (3) | 0.01 |
| |
| Impairment expense | 0.46 |
| (4) | 0.82 |
| (5) | 1.41 |
| (6) |
| Loss on extinguishment of debt | 0.27 |
| (7) | 0.09 |
| (8) | 0.05 |
| (9) |
| Restructuring costs | — |
| | 0.05 |
| | — |
| |
| U.S. Tax Law Reform Impact | 0.18 |
| (10) | 1.08 |
| (11) | — |
| |
| Less: Net income tax expense (benefit) | 0.12 |
| (12) | (0.29 | ) | (13) | (0.51 | ) | (14) |
| Adjusted EPS | $ | 1.24 |
| | $ | 1.08 |
| | $ | 0.94 |
| |
_____________________________
| |
(1) | Amount primarily relates to the loss on deconsolidationunrealized FX losses of UK Wind of $20$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 Euros and British pounds at the Parent Company. |
| |
(2) | 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. |
| |
(3) | 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 $10$38 million, or $0.02;$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 thegain on Masinloc contingent consideration of $23 million, or $0.03 per share and gain on sale of DPLERMiami Fort and Zimmer of $22$13 million, or $0.03$0.02 per share. |
| |
(4) | 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. |
| |
(2)(5)
| Amount primarily relates to the gains on the saleasset impairments at Kazakhstan CHPs of Armenia$94 million, or $0.14 per share, at Kazakhstan HPPs of $92 million, or $0.14 per share, at Laurel Mountain of $22$121 million, or $0.03$0.18 per share, at DPL of $175 million, or $0.27 per share and from the saleat Kilroot of Solar Spain and Solar Italy of $7$37 million, or $0.01$0.05 per share. |
| |
(3)(6)
| Amount primarily relates to the gain on the sale of a noncontrolling interest in Masinloc of $283 million, or $0.39 per share; and the gain from the sale of the U.K. wind projects of $78 million, or $0.11 per share. |
| |
(4)
| Amount primarily relates to asset impairments at DPL of $859 million, or $1.30 per share; $159 millionshare, at Buffalo Gap II of $159 million ($49 million, or $0.07 per share, net of NCI); and $77 million at Buffalo Gap I of $77 million ($23 million, or $0.03 per share, net of NCI). |
| |
(5)(7)
| Amount primarily relates to loss on early retirement of debt at the goodwill impairment at DPLParent Company of $317$171 million, or $0.46 per share, and asset impairments at Kilroot of $121 million ($119 million, or $0.17 per share, net of NCI), at Buffalo Gap III of $116 million ($27 million, or $0.04 per share, net of NCI), and at U.K. Wind (Development Projects) of $38 million ($30 million, or $0.04 per share, net of NCI). |
| |
(6)
| Amount primarily relates to the goodwill impairments at DPLER of $136 million, or $0.19 per share, and at Buffalo Gap I & II of $28 million, or $0.04 per share; and asset impairments at Ebute of $67 million ($64 million, or $0.09 per share, net of NCI), at Elsta of $41 million, or $0.06 per share; and the other-than-temporary impairments at Entek of $86 million, $0.12 per share and at Silver Ridge Power of $42 million, or $0.06$0.26 per share. |
| |
(7)(8)
| Amount primarily relates to losses on early retirement of debt at the Parent Company of $92 million, or $0.14 per share, at AES Gener of $20 million, or $0.02 per share, and at 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. |
| |
(9) | Amount primarily relates to the loss on early retirement of debt at the Parent Company of $19 million, or $0.03 per share. |
| |
(8)(10)
| 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. |
| |
(11) | 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. |
| |
(12) | 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 $116$36 million, or $0.17$0.05 per share, and income tax benefits associated with the impairment at IPLShady Point of $22 million ($17$33 million, or $0.02$0.05 per share, net of NCI). |
| |
share. (9) | Amount primarily relates to the loss on early retirement of debt at the Parent Company of $200 million, or $0.28 per share, at DPL of $31 million, or $0.04 per share, at Angamos of $20 million ($14 million, or $0.02 per share, net of NCI) and at U.K. wind projects of $18 million, or $0.02 per share. |
| |
(10)
| Amount primarily relates to the per share income tax benefit associated with asset impairment of $332 million, or $0.50 per share in the twelve months ended December 31, 2016.
|
| |
(11)(13)
| Amount primarily relates to the per share income tax benefit associated with losses on extinguishmentasset impairments of debt of $55$148 million, or $0.08$0.22 per share in the twelve months ended December 31, 2015.share. |
| |
(12)(14)
| Amount primarily relates to the per share income tax benefit associated with losses on extinguishmentasset impairments of debt of $90$332 million, or $0.12$0.50 per share and dispositions/acquisitions of $67 million, or $0.09 per share in the twelve months ended December 31, 2014.share. |
Proportional Free Cash FlowWe define proportional free cash flow as cash flows from operating activities less maintenance capital expenditures (including non-recoverable environmental capital expenditures), adjustedUS AND UTILITIES SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions) for the estimated impact of noncontrolling interests. The proportionate share of cash flows and related adjustments attributable to noncontrolling interests in our subsidiaries comprise the proportional adjustment factor presented in the reconciliation below. Upon the Company's adoption of the accounting guidance for service concession arrangements effective January 1, 2015, capital expenditures related to service concession assets that would have been classified as investing activities on the Consolidated Statement of Cash Flows are now classified as operating activities. See Note 1—General and Summary of Significant Accounting Policies of this Form 10-K for further information on the adoption of this guidance.
Beginning in the quarter ended March 31, 2015, the Company changed the definition of proportional free cash flow to exclude the cash flows for capital expenditures related to service concession assets that are now classified within net cash provided by operating activities on the Consolidated Statement of Cash Flows. The proportional adjustment factor for these capital expenditures is presented in the reconciliation below.
We also exclude environmental capital expenditures that are expected to be recovered through regulatory, contractual or other mechanisms. An example of recoverable environmental capital expenditures is IPL's investment in MATS-related environmental upgrades that are recovered through a tracker. See Item 1.—US SBU—IPL—Environmental Matters for details of these investments.
The GAAP measure most comparable to proportional free cash flow is cash flows from operating activities. We believe that proportional free cash flow better reflects the underlying business performance of the Company, as it measures the cash generated by the business, after the funding of maintenance capital expenditures, that may be available for investing in growth opportunities or repaying debt. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly-owned by the Company.
The presentation of free cash flow has material limitations. Proportional free cash flow should not be construed as an alternative to cash from operating activities, which is determined in accordance with GAAP. Proportional free cash flow does not represent our cash flow available for discretionary payments because it excludes certain payments that are required or to which we have committed, such as debt service requirements and dividend payments. Our definition of proportional free cash flow may not be comparable to similarly titled measures presented by other companies.
Beginning in the first quarter of 2017, we will no longer include these non-GAAP proportional free cash flow disclosures that have historically been provided and will instead disclose non-GAAP free cash flows only on a consolidated basis. Our use of proportional free cash flow was intended to provide investors with an understanding of the portion of free cash flows attributable to AES after the impact of non-controlling interests. However, since the concept of a non-controlling interest is not contemplated under GAAP with respect to the statement of cash flows, we will no longer be able to disclose proportional free cash flow in light of recent interpretive guidance issued by the SEC staff.periods indicated:
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| | | | | | | | | | | | | | | | | | | | |
| Reconciliation of Proportional Free Cash Flow (in millions) | | Years Ended December 31, | | | | |
| | | 2016 | | 2015 | | 2014 | | 2016/2015 Change | | 2015/2014 Change |
| Net Cash Provided by Operating Activities | | $ | 2,884 |
| | $ | 2,134 |
| | $ | 1,791 |
| | $ | 750 |
| | $ | 343 |
|
Add: capital expenditures related to service concession assets (1) | | 29 |
| | 165 |
| | — |
| | (136 | ) | | 165 |
|
| Adjusted Operating Cash Flow | | 2,913 |
| | 2,299 |
| | 1,791 |
| | 614 |
| | 508 |
|
Less: proportional adjustment factor on operating cash activities (2) (3) | | (1,032 | ) | | (558 | ) | | (359 | ) | | (474 | ) | | (199 | ) |
| Proportional Adjusted Operating Cash Flow | | 1,881 |
| | 1,741 |
| | 1,432 |
| | 140 |
| | 309 |
|
Less: proportional maintenance capital expenditures, net of reinsurance proceeds (2) | | (425 | ) | | (449 | ) | | (485 | ) | | 24 |
| | 36 |
|
Less: proportional non-recoverable environmental capital expenditures (2) (4) | | (39 | ) | | (51 | ) | | (56 | ) | | 12 |
| | 5 |
|
| Proportional Free Cash Flow | | $ | 1,417 |
| | $ | 1,241 |
| | $ | 891 |
| | $ | 176 |
| | $ | 350 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2018 | | 2017 | | 2016 | | $ Change 2018 vs. 2017 | | % Change 2018 vs. 2017 | | $ Change 2017 vs. 2016 | | % Change 2017 vs. 2016 |
| Operating Margin | | $ | 733 |
| | $ | 693 |
| | $ | 719 |
| | $ | 40 |
| | 6 | % | | $ | (26 | ) | | -4 | % |
Adjusted Operating Margin (1) | | 678 |
| | 623 |
| | 637 |
| | 55 |
| | 9 | % | | (14 | ) | | -2 | % |
Adjusted PTC (1) | | 511 |
| | 424 |
| | 392 |
| | 87 |
| | 21 | % | | 32 |
| | 8 | % |
_____________________________
| |
(1) | Service concession asset expenditures are excluded from the proportional free cash flowA non-GAAP metric. |
| |
(2)
| The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds) and proportional non-recoverable environmental capital expenditures are calculated by multiplying the percentage owned by noncontrolling interests for each entity by its corresponding consolidated cash flow metric and are totaled to the resulting figures. For example, Parent Company A owns 20% of Subsidiary Company B, a consolidated subsidiary. Thus, Subsidiary Company B has an 80% noncontrolling interest. Assuming a consolidated net cash flow from operating activities of $100 from Subsidiary B, the proportional adjustment factor for Subsidiary B would equal $80 (or $100 x 80%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then sums these amounts to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to noncontrolling interests as a result of (a) non-cash items which impact income but not cash and (b) AES' ownership interest in the subsidiary where such items occur. |
| |
(3)
| Includes proportional adjustment amount for service concession asset expenditures of $15 million and $84 millionfinancial measure, adjusted for the years ended December 31, 2016impact of NCI. See SBU Performance Analysis—Non-GAAP Measures for definition and 2015, respectively. The Company adopted service concession accounting effective January 1, 2015. |
| |
(4)
| Excludes IPL's proportional recoverable environmental capital expenditures of $132 million, $205 million and $163 million for the years ended December 31, 2016, 2015 and 2014, respectively. |
Parent Free Cash Flow (a non-GAAP measure)
The Company defines Parent Free Cash Flow as dividends and other distributions received from our operating businesses less certain cash costs at the Parent Company level, primarily interest payments, overhead, and development costs. Parent Free Cash Flow is used to fund shareholder dividends, share repurchases, growth investments, recourse debt repayments, and other uses by the Parent Company. Refer to Item 1—Business—Overview for further discussion of the Parent Company's capital allocation strategy.
US SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow ($ in millions) is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2016 | | 2015 | | 2014 | | $ Change 2016 vs. 2015 | | $ Change 2015 vs. 2014 | | % Change 2016 vs. 2015 | | % Change 2015 vs. 2014 |
| Operating Margin | | $ | 582 |
| | $ | 621 |
| | $ | 699 |
| | $ | (39 | ) | | $ | (78 | ) | | -6 | % | | -11 | % |
Noncontrolling Interests Adjustment (1) | | (75 | ) | | (38 | ) | | — |
| | | | | | | | |
| Derivatives Adjustment | | 6 |
| | 15 |
| | 12 |
| | | | | | | | |
| Adjusted Operating Margin | | $ | 513 |
| | $ | 598 |
| | $ | 711 |
| | $ | (85 | ) | | $ | (113 | ) | | -14 | % | | -16 | % |
| Adjusted PTC | | $ | 347 |
| | $ | 360 |
| | $ | 445 |
| | $ | (13 | ) | | $ | (85 | ) | | -4 | % |
| -19 | % |
| Proportional Free Cash Flow | | $ | 614 |
| | $ | 591 |
| | $ | 646 |
| | $ | 23 |
| | $ | (55 | ) | | 4 | % | | -9 | % |
_____________________________
| |
(1)
| See Item 1.—Business for the respective ownership interest for key business. In addition, AES owns 70% of IPL as of March 2016 compared to 75% beginning April 2015, 85% beginning in February 2015 and 100% prior to February 2015.businesses. |
Fiscal year 20162018 versus 20152017
Operating margin decreased $39Margin increased $40 million, or 6%, which was driven primarily by the following:following (in millions):
|
| | | |
| US Generation | |
| Southland related to an increase in depreciation expense as a result of a change in estimated useful lives of the plants | $ | (17 | ) |
| Impact from sale of Armenia Mountain in July 2015 | (10 | ) |
| Warrior Run due to lower availability and higher maintenance cost primarily due to major outages in 2016 | (8 | ) |
| Laurel Mountain due to lower regulation dispatch as well as lower energy and regulation pricing | (8 | ) |
| Other | (4 | ) |
| Total US Generation Decrease | (47 | ) |
| DPL | |
| Impact of lower wholesale prices and completion of DP&L’s transition to a competitive-bid market | (42 | ) |
| Decrease in RTO capacity and other revenues primarily due to lower capacity cleared in the auction | (21 | ) |
| Lower depreciation expense due to June 2016 fixed asset impairment and decrease in generating facility maintenance and other expenses | 17 |
|
| Other | 2 |
|
| Total DPL Decrease | (44 | ) |
| IPL | |
| Higher retail margin driven by environmental revenues and higher rates due to a new rate order | 36 |
|
| Change in accrual resulting from the implementation of new rates | 18 |
|
| Other | (2 | ) |
| Total IPL Increase | 52 |
|
| Total US SBU Operating Margin Decrease | $ | (39 | ) |
|
| | | |
| Increase at DPL primarily due to higher regulated rates following the approval of the 2017 ESP and the 2018 distribution rate order and favorable weather | $ | 35 |
|
| Increase at DPL driven by a one-time credit to depreciation expense, primarily as a result of a reduction in the ARO liability at DPL's closed plants, Stuart and Killen | 32 |
|
| Increase at IPL due to higher wholesale margins driven by Eagle Valley coming online and higher retail margins due to favorable weather | 23 |
|
| Increase at Southland driven by higher market energy sales, partially offset by a decrease in capacity sales and lower ancillary services due to the expiration of long-term agreements | 12 |
|
| Decrease at Hawaii primarily due to higher coal prices and lower gain on valuation of MTM commodity swaps | (24 | ) |
| Impact of the sale and closure of generation plants at DPL | (12 | ) |
| Decrease at IPL due to higher maintenance expense due to increased current year outages | (21 | ) |
| Other | (5 | ) |
| Total US and Utilities SBU Operating Margin Increase | $ | 40 |
|
Adjusted Operating Margin decreased $85increased $55 million for the US SBUprimarily due to the drivers above, excluding the impact of unrealized derivative gains and losses and adjusted for a $24 million unrealized loss on coal derivatives in Hawaii partially offset by restructuring charges in the impact of noncontrolling interests.prior year.
Adjusted PTC decreased $13 million driven by the decrease of $85 million in Adjusted Operating Margin described above, partially offset by a gain on contract termination at DP&L, lower interest expense at DPL and IPL in part due to the sell-down impacts as discussed above and the impact of HLBV at our Distributed Energy business as a result of new projects achieving COD in 2016.
Proportional Free Cash Flow increased $23$87 million, primarily driven by a $93 million decrease in coal purchases due to the ongoing conversion of coal generation assets to natural gas at IPL, a build-up of inventory due to mild winter weather in December 2015, and inventory optimization efforts at DPL. Additionally, Proportional Free Cash Flow benefited from a $32 million increase in accounts payable due to the timing of vendor payments, $17 million in net settlements of accounts receivable primarily resulting from the sale of DPLER in 2016, and lower interest payments of $19 million due to timing and lower interest rates. These positive impacts were partially offset by an $81 million decrease in Adjusted Operating Margin (net of non-cash impacts of $4 million, primarily related to the implementation of IPL’s new rates and depreciation), and a $84 million decrease in the timing of receivables collections resulting primarily from higher rates at IPL, more favorable weather in 2016, and the impact of DPLER’s declining customer base in 2015.
Fiscal year 2015 versus 2014
Operating margin decreased by $78 million, or 11%, which was driven primarily by the following:
|
| | | |
| DPL | |
| Impact of more of DP&L's generation being sold in the wholesale market at lower prices in 2015 compared to supplying DP&L retail customers in 2014, lower generation driven by plant outages in 2015, and unfavorable weather; partially offset by the impact of outages and lower gas availability occurring in Q1 2014 | $ | (53 | ) |
| Increase in capacity margin due to increase in PJM capacity price | 26 |
|
| Total DPL Decrease | (27 | ) |
| US Generation | |
| Lower production and prices across the US Wind businesses | (20 | ) |
| Lower availability and dispatch at Hawaii | (10 | ) |
| Other | 4 |
|
| Total US Generation Decrease | (26 | ) |
| IPL | |
| Lower wholesale margin due to lower market prices of electricity and outages | (26 | ) |
| Higher fixed costs primarily due to higher maintenance expense attributed to plant outages and higher depreciation expense due to MATS assets | (18 | ) |
| Higher retail margins | 20 |
|
| Other | (1 | ) |
| Total IPL Decrease | (25 | ) |
| Total US SBU Operating Margin Decrease | $ | (78 | ) |
Adjusted Operating Margin decreased $113 million at the US SBU due to the drivers above, excluding the
impact of unrealized derivative gains and losses and adjusted for the impact of noncontrolling interests.
Adjusted PTC decreased $85 million driven by the decrease of $113 million in Adjusted Operating Margin described above, as well as a decreasean increase in the Company's share of earnings underat Distributed Energy due to new solar project growth, lower interest expense and the HLBV allocation of noncontrolling interest earnings at Buffalo Gap, partially offset by IPLlower allowance for equity funds used during construction at IPALCO.
Fiscal year 2017 versus 2016
Operating Margin decreased $26 million, or 4%, which was driven primarily by the following (in millions):
|
| | | |
| Decrease at DPL driven by lower retail margins due to lower regulated rates | $ | (22 | ) |
Decrease at DPL primarily due to lower volumes due to the shutdown of Stuart Unit 1 and lower commercial availability
| (21 | ) |
| Decrease at IPL due to implementation of new base rates in Q2 2016 which resulted in a favorable change in accrual | (18 | ) |
| Increase at DPL as a result of lower depreciation expense due to lower PP&E carrying values from impairments in 2016 and 2017 | 26 |
|
| Other | 9 |
|
| Total US and Utilities SBU Operating Margin Decrease | $ | (26 | ) |
Adjusted Operating Margin decreased $14 million primarily due to lower interest expense relatedthe drivers above, excluding unrealized gains and losses on derivatives, restructuring charges and costs associated with early plant closures.
Adjusted PTC increased $32 million, driven by earnings from equity affiliates due to the impact2017 acquisition of sPower, the sell down and increased AFUDC, and DPLCompany's share of earnings at Distributed Energy due to lower interest expense.
Proportional Free Cash Flow decreased $55 million, primarily drivennew solar project growth and an increase in insurance recoveries at DPL. The increase in Adjusted PTC was partially offset by the $113decrease of $14 million decrease in Adjusted Operating Margin described above and a $22 million increase in maintenance and non-recoverable capital expenditures. These negative impacts were partially offset by a $22 million increase due to the collection of previously deferred storm costs, a one-time payment of $19 million in 2014 to terminate an unfavorable coal2016 gain on contract higher collections of $16 million due to settlement of a receivable balance related to the sale of MC2 in 2015, and the timing of inventory payments of $16 milliontermination at DPL. Additionally, Proportional Free Cash Flow was favorably impacted by the timing of power purchase payments of $7 million and the timing of $9 million of receivables collections at IPL.DP&L.
SOUTH AMERICA SBU
A summary ofThe following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC and Proportional Free Cash Flow ($ in(in millions) is as follows:for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2016 | | 2015 | | 2014 | | $ Change 2016 vs. 2015 | | $ Change 2015 vs. 2014 | | % Change 2016 vs. 2015 | | % Change 2015 vs. 2014 |
| Operating Margin | | $ | 634 |
| | $ | 618 |
| | $ | 587 |
| | $ | 16 |
| | $ | 31 |
| | 3 | % | | 5 | % |
Noncontrolling Interests Adjustment (1) | | (192 | ) | | (152 | ) | | (143 | ) | | | | | | | | |
| Adjusted Operating Margin | | $ | 442 |
| | $ | 466 |
| | $ | 444 |
| | $ | (24 | ) | | $ | 22 |
| | -5 | % | | 5 | % |
| Adjusted PTC | | $ | 390 |
| | $ | 482 |
| | $ | 421 |
| | $ | (92 | ) | | $ | 61 |
| | -19 | % | | 14 | % |
| Proportional Free Cash Flow | | $ | 264 |
| | $ | 224 |
| | $ | 176 |
| | $ | 40 |
| | $ | 48 |
| | 18 | % | | 27 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2018 | | 2017 | | 2016 | | $ Change 2018 vs. 2017 | | % Change 2018 vs. 2017 | | $ Change 2017 vs. 2016 | | % Change 2017 vs. 2016 |
| Operating Margin | | $ | 1,017 |
| | $ | 862 |
| | $ | 823 |
| | $ | 155 |
| | 18 | % | | $ | 39 |
| | 5 | % |
Adjusted Operating Margin (1) | | 612 |
| | 500 |
| | 486 |
| | 112 |
| | 22 | % | | 14 |
| | 3 | % |
Adjusted PTC (1) | | 519 |
| | 446 |
| | 428 |
| | 73 |
| | 16 | % | | 18 |
| | 4 | % |
_____________________________
| |
(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 business. In addition, AES owned 71% of Gener and Chivor prior to sell down effective December 2015 which resulted in ownership of 67%. The Alto Maipo (under construction) and Cochrane plants are owned 40%.businesses. |
Fiscal year 20162018 versus 20152017
Operating Margin increased $155 million, or 18%, which was driven primarily by the following (in millions):
|
| | | |
| Increase in Argentina mainly related to higher capacity prices resulting from market reforms enacted in 2017 and lower fixed costs primarily due to the devaluation of the Argentine peso | $ | 71 |
|
| Increase in Colombia mainly related to higher contract pricing in 2018 and higher generation | 64 |
|
| Margin on new PPAs in Chile at Gener, Angamos and Cochrane | 50 |
|
| Impact of the sale of Electrica Santiago | (38 | ) |
| Lower fixed costs at Gener associated with planned maintenance performed in Q3 2017 | 21 |
|
| Lower contract sales to distribution companies in Chile net of higher revenue associated with a contract termination | (24 | ) |
| Other | 11 |
|
| Total South America SBU Operating Margin Increase | $ | 155 |
|
Adjusted Operating Margin increased $112 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC increased $73 million, mainly due to the increase in Adjusted Operating Margin described above and lower interest in Chile, partially offset by a $28 million decrease associated with a gain recognized in the prior year from the settlement of a legal dispute with YPF at Uruguaiana, higher interest expense in Brazil, lower equity earnings in Chile and higher realized foreign currency losses in Argentina.
Fiscal year 2017 versus 2016
Including the unfavorablefavorable impact of foreign currency translation and remeasurement of $36$38 million, operating margin increased $16 million, or 3%, which was driven primarily by the following:
|
| | | |
| Gener | |
| Lower spot prices on energy and fuel purchases | $ | 82 |
|
| Start of operations of Cochrane Plant | 36 |
|
| Other | (3 | ) |
| Total Gener Increase | 115 |
|
| Argentina | |
| Higher rates driven by annual price review granted by Resolution 22/2016 | 61 |
|
| Lower availability mainly associated with planned major maintenance | (20 | ) |
| Higher fixed costs primarily driven by higher inflation and by higher maintenance cost | (44 | ) |
| Unfavorable FX remeasurement impacts | (21 | ) |
| Total Argentina Decrease | (24 | ) |
| Chivor | |
| Higher volume of energy sales to Spot Market | 14 |
|
| Unfavorable FX remeasurement impacts | (15 | ) |
| Lower spot sales prices | (72 | ) |
| Other | (2 | ) |
| Total Chivor Decrease | (75 | ) |
| Total Andes SBU Operating Margin Increase | $ | 16 |
|
Adjusted Operating Margin decreased $24 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests.
Adjusted PTC decreased $92 million, driven by the decrease in Equity Earnings of $54 million mainly related to Guacolda’s reorganization in September 2015, the decrease of $24 million in Adjusted Operating Margin and the increase of $12 million in interest expense primarily associated to lower interest capitalization after beginning of commercial operations at Cochrane.
Proportional Free Cash Flow increased $40 million, primarily driven by $57 million in collections of financing receivables and the timing of maintenance remuneration from CAMMESSA in Argentina, a $25 million positive impact related to a one-time interest rate swap termination payment at Ventanas in July 2015, a decrease of $58 million in working capital requirements at Chivor mainly related to collections of prior period sales, and a $23 million reduction in proportional maintenance and non-recoverable capital expenditures due to lower expenditures on
emissions control equipment at Chile. These positive impacts were partially offset by a reduction of $4 million in Adjusted Operating Margin (net of non-cash impacts), $43 million of lower VAT refunds related to our Cochrane and Alto Maipo construction projects, higher net tax payments of $56 million primarily related to withholding taxes paid on Chilean distributions to AES Affiliates and higher taxable income in Colombia, and $18 million of higher interest payments primarily as a consequence of debt refinancing at higher interest rates and lower interest capitalization under construction projects.
Fiscal year 2015 versus 2014
Including the unfavorable impact of foreign currency translation and remeasurement of $87 million, operating margin increased $31$39 million, or 5%, which was driven primarily by the following:following (in millions):
|
| | | |
| Gener | |
| Higher margins associated to Nueva Renca Plant tolling agreement | $ | 26 |
|
| Higher volume of energy sales mainly related to higher availability | 21 |
|
| Other | (2 | ) |
| Total Gener Increase | 45 |
|
| Argentina | |
| Higher rates driven by an annual price review and additional contributions introduced by Resolution 482 | 49 |
|
| Higher fixed costs primarily driven by higher inflation and by higher maintenance cost | (45 | ) |
| Unfavorable FX remeasurement impacts | (4 | ) |
| Other | 4 |
|
| Total Argentina Increase | 4 |
|
| Chivor | |
| Unfavorable FX remeasurement impacts | (83 | ) |
| Higher rates driven by a strong El Niño impact on prices | 60 |
|
| Higher volume of energy sales mainly associated to higher generation | 12 |
|
| Other | (7 | ) |
| Total Chivor Decrease | (18 | ) |
| Total Andes SBU Operating Margin Increase | $ | 31 |
|
|
| | | |
| Start of operations at Cochrane Units I and II in July and October 2016, respectively | $ | 72 |
|
| Higher capacity payments in Argentina primarily due to changes in regulation in 2017 | 64 |
|
| Net impact of volume and prices of lower energy purchased in spot market at Tietê | 71 |
|
| Higher contract sales at Chivor primarily due to an increase in contracted capacity at higher prices | 35 |
|
| Higher volume due to acquisition of new wind entities - Alto Sertão II | 23 |
|
| Favorable FX impacts at Tietê | 21 |
|
| Net impact of volume and prices of bilateral contracts due to higher energy purchased at Tietê | (100 | ) |
| Negative impact in Gener due to new regulation on emissions (Green Taxes) | (41 | ) |
| Lower spot sales at Chivor mainly due to lower generation and lower spot prices | (37 | ) |
| Lower availability of efficient generation resulting in higher replacement energy and fixed costs, mainly associated with major maintenance at Ventanas Complex in Chile | (29 | ) |
| Lower margin at the SING market primarily due to lower contract sales and increase in coal prices at Norgener partially offset by higher spot sales | (21 | ) |
| Lower generation at CTSN mainly due to lower demand | (26 | ) |
| Other | 7 |
|
| Total South America SBU Operating Margin Increase | $ | 39 |
|
Adjusted Operating Margin increased $22$14 million for the yearprimarily due to the drivers above, adjusted for the impact of noncontrolling interests.NCI.
Adjusted PTC increased $61$18 million, driven by a restructuring$28 million increase from the settlement of Guacoldaa legal dispute with YPF at Uruguaiana in Chile which increased our equity investment and resulted in additional Equity Earnings of $46 million as well as realized FX gains, lower interest expense at Chivor2017 and the $22$14 million in Adjusted Operating Margin described above. This was partially offset by lower equity earnings at Guacolda of $16 million (excluding restructuring impact above) mainly driven by a 2014 gain on sale of a transmission line.
Proportional Free Cash Flow increased $48 million, primarily driven by $107 million higher VAT refunds at Cochrane and Alto Maipo, $27 million of non-recurring maintenance collections in Argentina, and a $17 million decrease in interest payments. These positive impacts were partially offset by $49 million of higher tax payments and $25 million of lower collections primarily from contract customers at Chivor, and a $25 million impact related to a one-time interest rate swap termination payment at Ventanas in July 2015.
BRAZIL SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow ($ in millions) is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2016 | | 2015 | | 2014 | | $ Change 2016 vs. 2015 | | $ Change 2015 vs. 2014 | | % Change 2016 vs. 2015 | | % Change 2015 vs. 2014 |
| Operating Margin | | $ | 239 |
| | $ | 592 |
| | $ | 634 |
| | $ | (353 | ) | | $ | (42 | ) | | -60 | % | | -7 | % |
Noncontrolling Interests Adjustment (1) | | (190 | ) | | (464 | ) | | (507 | ) | | | | | | | | |
| Adjusted Operating Margin | | $ | 49 |
| | $ | 128 |
| | $ | 127 |
| | $ | (79 | ) | | $ | 1 |
| | -62 | % | | 1 | % |
| Adjusted PTC | | $ | 29 |
| | $ | 118 |
| | $ | 108 |
| | $ | (89 | ) | | $ | 10 |
| | -75 | % | | 9 | % |
| Proportional Free Cash Flow | | $ | 110 |
| | $ | (29 | ) | | $ | 13 |
| | $ | 139 |
| | $ | (42 | ) | | 479 | % | | -323 | % |
_____________________________
| |
(1)
| See Item 1. Business for the respective ownership interest for key business.
|
Fiscal year 2016 versus 2015
Including the unfavorable impact of foreign currency translation of $6 million, operating margin decreased $353 million, or 60%, which was driven primarily by the following:
|
| | | |
| Tietê | |
| Lower rates for energy sold under new contracts | $ | (239 | ) |
| Unfavorable FX impacts | (14 | ) |
| Higher fixed costs due to higher legal settlements | (13 | ) |
| Lower rates for energy purchases mainly due to decrease in spot market prices | 78 |
|
| Other | (2 | ) |
| Total Tietê Decrease | (190 | ) |
| Eletropaulo | |
| Negative impact of reversal of contingent regulatory liability in 2015 | (97 | ) |
| Higher fixed costs mainly due to higher bad debt and employee-related costs | (68 | ) |
| Lower demand mainly due to economic decline | (59 | ) |
| Higher regulatory penalties in 2016 partially offset by regulatory penalties contingency provision in 2015 | (30 | ) |
| Higher tariffs | 116 |
|
| Other | (3 | ) |
| Total Eletropaulo Decrease | (141 | ) |
| Uruguaiana | |
| Operations in 2015 compared to not operating in 2016 | (20 | ) |
| Total Uruguaiana Decrease | (20 | ) |
| Other Business Drivers | (2 | ) |
| Total Brazil SBU Operating Margin Decrease | $ | (353 | ) |
Adjusted Operating Margin decreased $79 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests.
Adjusted PTC decreased $89 million, driven by the decrease of $79 millionincrease in Adjusted Operating Margin described above, as well as higher interest expense of $10 million related to the reversal of a contingent regulatory liability at Eletropaulo in 2015.
Proportional Free Cash Flow increased by $139 million, primarily driven by favorable timing of $309 million in net collections of higher costs deferred in net regulatory assets in the prior year at Eletropaulo and Sul as a result of unfavorable hydrology in prior periods, favorable timing of $133 million in collections on current year energy sales, and lower energy purchases of $23 million at Tietê due to favorable hydrology. These positive impacts were partially offset by unfavorable timing of $241 million in payments for energy purchases and regulatory charges at Eletropaulo and Sul, and a $72 million decrease in in Adjusted Operating Margin (net of $7 million in non-cash impacts, primarily due to the reversal of a contingent regulatory liability at Eletropaulo in 2015).
Fiscal year 2015 versus 2014
Including the unfavorable impact of foreign currency translation of $228 million, operating margin decreased $42 million, or 7%, which was driven primarily by the following:
|
| | | |
| Tietê | |
| Energy purchases at lower rates primarily due to lower spot prices | $ | 311 |
|
| Unfavorable FX impacts | (152 | ) |
| Higher volume purchased on the spot market due to higher assured energy requirement | (113 | ) |
| Other | (8 | ) |
| Total Tietê Increase | 38 |
|
| Uruguaiana | |
| Higher generation from a longer period of temporary restart of operations | 11 |
|
| Total Uruguaiana Increase | 11 |
|
| Eletropaulo | |
| Higher fixed costs, primarily due to higher bad debt expense, storms and employee-related costs | (142 | ) |
| Unfavorable FX impacts | (74 | ) |
| Contingency related to performance indicators | (59 | ) |
| Lower volumes due to lower demand | (35 | ) |
| Reversal of a contingent regulatory liability (excluding FX) | 135 |
|
| Higher tariffs | 82 |
|
| Total Eletropaulo Decrease | (93 | ) |
| Other Business Drivers | 2 |
|
| Total Brazil SBU Operating Margin Decrease | $ | (42 | ) |
Adjusted Operating Margin increased $1 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests.
Adjusted PTC increased $10 million, driven by the increase of $1 milliongains in Adjusted Operating Margin described above as well as favorable net interest income recognized on receivables at Eletropaulo.
Proportional Free Cash Flow decreased by $42 million, primarily driven by a $99 million decrease in Sul's Adjusted Operating Margin classified as a discontinued operation (not included in the $1 million increase in Adjusted Operating Margin described above), higher energy purchases of $59 million at Tietê due to the timing of purchases in the spot market at higher prices, unfavorable timing of $32 million of higher costs deferred in net regulatory assets at Sul as result of unfavorable hydrology, and $17 million of higher interest payments at Sul due to a higher debt balance and higher interest rate. These negative impacts were partially offset by favorable timing of $121 million in payments for energy purchases and regulatory charges at Eletropaulo and Sul, $31 million of lower income tax payments at Tietê, and favorable timing of $14 million in net collections of higher costs deferred in net regulatory assets in the prior year at Eletropaulo.
MCAC SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow ($ in millions) is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2016 | | 2015 | | 2014 | | $ Change 2016 vs. 2015 | | $ Change 2015 vs. 2014 | | % Change 2016 vs. 2015 | | % Change 2015 vs. 2014 |
| Operating Margin | | $ | 523 |
| | $ | 543 |
| | $ | 541 |
| | $ | (20 | ) | | $ | 2 |
| | -4 | % | | — | % |
Noncontrolling Interests Adjustment (1) | | (108 | ) | | (106 | ) | | (59 | ) | | | | | | | | |
| Derivatives Adjustment | | (2 | ) | | 1 |
| | — |
| | | | | | | | |
| Adjusted Operating Margin | | $ | 413 |
| | $ | 438 |
| | $ | 482 |
| | $ | (25 | ) | | $ | (44 | ) | | -6 | % | | (9 | )% |
| Adjusted PTC | | $ | 267 |
| | $ | 327 |
| | $ | 352 |
| | $ | (60 | ) | | $ | (25 | ) | | -18 | % | | (7 | )% |
| Proportional Free Cash Flow | | $ | 168 |
| | $ | 498 |
| | $ | 281 |
| | $ | (330 | ) | | $ | 217 |
| | -66 | % | | 77 | % |
_____________________________
| |
(1)
| See Item 1. Business for the respective ownership interest for key business. In addition, AES owned 92% of Andres and Los Mina and 46% of Itabo in the Dominican Republic until December 2015 when the ownership changed to 90% at Andres and Los Mina and 45% at Itabo.
|
Fiscal year 2016 versus 2015
Operating margin decreased $20 million, or 4%, which was driven primarily by the following:
|
| | | |
| Mexico | |
| Lower availability and related costs | $ | (11 | ) |
| Other | (6 | ) |
| Total Mexico Decrease | (17 | ) |
| El Salvador | |
| Higher fixed costs | (6 | ) |
| Lower energy sales margin | (4 | ) |
| Total El Salvador Decrease | (10 | ) |
| Panama | |
| Expenses related to the ongoing construction of a natural gas generation plant and a liquefied natural gas terminal | (19 | ) |
| Commencement of power barge operations at the end of March 2015 | 13 |
|
| Other | (3 | ) |
| Total Panama Decrease | (9 | ) |
| Dominican Republic | |
| Higher contracted and spot energy sales | 24 |
|
| Total Dominican Republic Increase | 24 |
|
| Other Business Drivers | (8 | ) |
| Total MCAC SBU Operating Margin Decrease | $ | (20 | ) |
Adjusted Operating Margin decreased $25 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC decreased $60 million, driven by the decrease in Adjusted Operating Margin of $25 million as described above as well as a 2015 compensation agreement regarding early termination of the original Barge PPA of $10 million and a $26 million allowance recognized in 2016 at Puerto Rico.
Proportional Free Cash Flow decreased $330 million, primarily driven by $212 million of lower collections in the Dominican Republic mainly due to collections of overdue receivables in September 2015, the $25 million decrease in Adjusted Operating Margin described above, $47 million of decreased collections in Puerto Rico due to lower sales, $14 million of higher tax payments in El Salvador due to higher taxable income in 2015, and a $10 million impact from compensation received in the prior-year from the off-taker in Panama related to an early termination of the barge PPA.
Fiscal year 2015 versus 2014
Operating margin increased $2 million, or 0.4%, which was driven primarily by the following:
|
| | | |
| Panama | |
| Higher generation and lower energy purchases, driven by improved hydrological conditions | $ | 118 |
|
| Commencement of power barge operations at the end of March 2015 | 18 |
|
| Lower compensation from the government of Panama due to lower volumes of energy purchased at lower spot prices | (34 | ) |
| Other | (6 | ) |
| Total Panama Increase | 96 |
|
| El Salvador | |
| One-time unfavorable adjustment to unbilled revenue in 2014 | 12 |
|
| Lower energy losses and higher demand | 11 |
|
| Total El Salvador Increase | 23 |
|
| Dominican Republic | |
| Lower commodity prices resulting in lower spot prices and lower than expected gas sales demand with excess gas used for generation at lower margins | (29 | ) |
| Lower availability | (28 | ) |
| Lower frequency regulation revenues | (21 | ) |
| Total Dominican Republic Decrease | (78 | ) |
| Puerto Rico | |
| One-time reversal of bad debt in 2014 and higher maintenance expense | (11 | ) |
| Total Puerto Rico Decrease | (11 | ) |
| Mexico | |
| Higher fuel costs, lower spot sales and lower availability | (29 | ) |
| Total Mexico Decrease | (29 | ) |
| Other Business Drivers | 1 |
|
| Total MCAC SBU Operating Margin Increase | $ | 2 |
|
Adjusted Operating Margin decreased $44 million due to the drivers above adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC decreased $25 million, driven by the decrease in Adjusted Operating Margin of $44 million described above. These results were partially offset by a compensation agreement regarding early termination of the original Barge PPA of $10 million and 2014 losses on a legal dispute settlement of $4 million in Panama as well as lower interest expense due to lower debt at Puerto Rico.
Proportional Free Cash Flow increased $217 million, primarily due to the favorable timing of $220 million of collections, mainly related toArgentina associated with the collection of overduefinancing receivables, prepayment of financial debt denominated in the Dominican RepublicU.S. dollars in September 2015. Proportional Free Cash Flow also benefited from a $17 million impact of2017 and lower energy purchases in El Salvador due to lower fuel prices, and a $10 million impact from compensation received from the off-taker in Panama related to an early termination of the barge PPA. These favorable impacts were partially offset by the $44 million decrease in Adjusted Operating Margin as described above.
EUROPE SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow ($ in millions) is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2016 | | 2015 | | 2014 | | $ Change 2016 vs. 2015 | | $ Change 2015 vs. 2014 | | % Change 2016 vs. 2015 | | % Change 2015 vs. 2014 |
| Operating Margin | | $ | 259 |
| | $ | 303 |
| | $ | 403 |
| | $ | (44 | ) | | $ | (100 | ) | | -15 | % | | -25 | % |
Noncontrolling Interests Adjustment (1) | | (33 | ) | | (30 | ) | | (26 | ) | | | | | | | | |
| Derivatives Adjustment | | (1 | ) | | 3 |
| | (4 | ) | | | | | | | | |
| Adjusted Operating Margin | | $ | 225 |
| | $ | 276 |
| | $ | 373 |
| | $ | (51 | ) | | $ | (97 | ) | | -18 | % | | -26 | % |
| Adjusted PTC | | $ | 187 |
| | $ | 235 |
| | $ | 348 |
| | $ | (48 | ) | | $ | (113 | ) | | -20 | % |
| -32 | % |
| Proportional Free Cash Flow | | $ | 552 |
| | $ | 238 |
| | $ | 197 |
| | $ | 314 |
| | $ | 41 |
| | 132 | % | | 21 | % |
_____________________________
| |
(1)
| See Item 1. Business for the respective ownership interest for key business.
|
Fiscal year 2016 versus 2015
Including the unfavorable impact of foreign currency translation of $36 million, operating margin decreased $44 million, or 15%, which was driven primarily by the following:
|
| | | |
| Kazakhstan | |
| Unfavorable FX impact due to KZT depreciation against USD | $ | (29 | ) |
| Other | (1 | ) |
| Total Kazakhstan Decrease | (30 | ) |
| Maritza | |
| Lower contracted capacity prices due to PPA amendment | (18 | ) |
| Other | (2 | ) |
| Total Maritza Decrease | (20 | ) |
| Ballylumford | |
| Higher contracted revenues | 27 |
|
| Lower plant capacity resulting from the retirement of one generation facility | (21 | ) |
| Total Ballylumford Increase | 6 |
|
| Total Europe SBU Operating Margin Decrease | $ | (44 | ) |
Adjusted Operating Margin decreased $51 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC decreased $48 million, driven primarily by the decrease of $51 million in Adjusted Operating Margin described above.
Proportional Free Cash Flow increased $314 million, primarily driven by $360 million of increased collections at Maritza from NEK, net of payments to the fuel supplier (MMI), and a decrease in maintenance and non-recoverable environmental capital expenditures of $21 million. These favorable increases were partially offset by the $51 million decrease in Adjusted Operating Margin and a $24 million decrease in CO2 allowances due to a price decrease.
Fiscal year 2015 versus 2014
Including the unfavorable impact of foreign currency translation of $47 million, operating margin decreased $100 million, or 25%, which was driven primarily by the following:
|
| | | |
| Maritza | |
| Unfavorable FX impacts due to Euro depreciation against USD | $ | (30 | ) |
| Lower rates due to non-operating costs passed through the tariff | (8 | ) |
| Higher availability in 2015 | 8 |
|
| Total Maritza Decrease | (30 | ) |
| Kilroot | |
| Lower dispatch and lower market prices due to gas/coal spread as well as lower capacity prices | (23 | ) |
| Higher fixed costs primarily driven by maintenance cost due to timing of outages | (3 | ) |
| Lower depreciation due to impairment in Q3 2015 | 7 |
|
| Other | 1 |
|
| Total Kilroot Decrease | (18 | ) |
| Ballylumford | |
| Lower availability and lower capacity prices | (8 | ) |
| Write down of non-primary fuel inventory | (4 | ) |
| Total Ballylumford Decrease | (12 | ) |
| Other | |
| Reduction due to the sale of Ebute in 2014 | (34 | ) |
| Lower Heat Rate margin at Jordan | (6 | ) |
| Total Other Decrease | (40 | ) |
| Total Europe SBU Operating Margin Decrease | $ | (100 | ) |
Adjusted Operating Margin decreased $97 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC decreased $113 million, driven by the decrease of $97 million in Adjusted Operating Margin described above, and by higher depreciation and unfavorable FX impact from Elsta as well as unfavorable impact due to the reversal of a liability in 2014 in Kazakhstan. These results partially offset by lower interest expenses in Bulgaria.
Proportional Free Cash Flow increased $41 million, primarily driven by $69 million of increased collections at Maritza from NEK, net of payments to the fuel supplier (MMI), a $22 million benefit at IPP4 Jordan due to the commencement of operations in July 2014, and lower interest expense of $38 million due primarily toassociated with the sale of UK Wind in 2014. These favorable increases were partially offset by the $97 million decrease in Adjusted Operating
Margin described above.
ASIA SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow ($ in millions) is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2016 | | 2015 | | 2014 | | $ Change 2016 vs. 2015 | | $ Change 2015 vs. 2014 | | % Change 2016 vs. 2015 | | % Change 2015 vs. 2014 |
| Operating Margin | | $ | 170 |
| | $ | 149 |
| | $ | 76 |
| | $ | 21 |
| | $ | 73 |
| | 14 | % | | 96 | % |
Noncontrolling Interests Adjustment (1) | | (91 | ) | | (79 | ) | | (25 | ) | | | | | | | | |
| Derivatives Adjustment | | 1 |
| | — |
| | — |
| | | | | | | | |
| Adjusted Operating Margin | | $ | 80 |
| | $ | 70 |
| | $ | 51 |
| | $ | 10 |
| | $ | 19 |
| | 14 | % | | 37 | % |
| Adjusted PTC | | $ | 96 |
| | $ | 96 |
| | $ | 46 |
| | $ | — |
| | $ | 50 |
| | — | % |
| 109 | % |
| Proportional Free Cash Flow | | $ | 136 |
| | $ | 87 |
| | $ | 82 |
| | $ | 49 |
| | $ | 5 |
| | 56 | % | | 6 | % |
_____________________________
| |
(1)
| See Item 1. Business for the respective ownership interest for key business.
|
Fiscal year 2016 versus 2015
Operating margin increased $21 million, or 14%, which was driven primarily by the following:
|
| | | |
| Mong Duong | |
| Impact of full year operations for 2016 compared to commencement of principal operations in April 2015 | $ | 16 |
|
| Total Mong Duong Increase | 16 |
|
| Other business drivers | 5 |
|
| Total Asia SBU Operating Margin Increase | $ | 21 |
|
Adjusted Operating Margin increased $10 million due to the drivers above adjusted for the impact of noncontrolling interests.
Adjusted PTC was neutral driven by the increase of $10 million in Adjusted Operating Margin described above offset by lower equity earningsArgentina’s sovereign bonds at OPGC in India due to lower tariffs and the net impact of higher interest expense and higher interest income at Mong Duong.
Proportional Free Cash Flow increased $49 million, primarily driven by a decrease of $29 million in working capital requirements at Mong Duong due to a build up in the prior year in preparation for commencement of plant operations, and an increase in Adjusted Operating Margin of $35 million (net of non-cash service concession expense of $24 million).Termoandes. These positive impacts were partially offset by higher interest expense, mainly due to the acquisition of $18 million asAlto Sertão II debt, issuance of debt at Argentina and lower interest capitalization in Cochrane and Chivor, and the write-off of water rights at Gener resulting from a business development project that is no longer capitalized as part of service concession asset expenditures.pursued.
MCAC SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions) for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2018 | | 2017 | | 2016 | | $ Change 2018 vs. 2017 | | % Change 2018 vs. 2017 | | $ Change 2017 vs. 2016 | | % Change 2017 vs. 2016 |
| Operating Margin | | $ | 534 |
| | $ | 465 |
| | $ | 390 |
| | $ | 69 |
| | 15 | % | | $ | 75 |
| | 19 | % |
Adjusted Operating Margin (1) | | 391 |
| | 358 |
| | 292 |
| | 33 |
| | 9 | % | | 66 |
| | 23 | % |
Adjusted PTC (1) | | 300 |
| | 277 |
| | 222 |
| | 23 |
| | 8 | % | | 55 |
| | 25 | % |
_____________________________
| |
(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. |
Fiscal year 20152018 versus 20142017
Operating marginMargin increased $73$69 million, or 96%15%, which was driven primarily by the following:following (in millions):
|
| | | |
| Masinloc | |
| Higher availability | $ | 27 |
|
| One-time unfavorable impact in 2014 due to market operator's retrospective adjustment to energy prices in Nov and Dec 2013 | 15 |
|
| Lower fixed costs and lower tax assessments in 2015 relative to 2014 | 7 |
|
| Other | 3 |
|
| Total Masinloc Increase | 52 |
|
| Mong Duong | |
| Commencement of principal operations in April 2015 | 24 |
|
| Total Mong Duong Increase | 24 |
|
| Other Business Drivers | (3 | ) |
| Total Asia SBU Operating Margin Increase | $ | 73 |
|
|
| | | |
| Increase in Dominican Republic due to higher spot prices | $ | 32 |
|
| Higher contracted energy sales in Panama mainly driven by the commencement of operations at the Colon combined cycle facility in September 2018 | 21 |
|
| Higher availability driven by improved hydrology in Panama | 17 |
|
| Higher contracted energy sales in Dominican Republic mainly driven by the commencement of operations at the Los Mina combined cycle facility in June 2017 and lower forced maintenance outages | 12 |
|
| Decrease in Mexico due to pension plan pass-through adjustments and higher fuel costs | (8 | ) |
| Other | (5 | ) |
| Total MCAC SBU Operating Margin Increase | $ | 69 |
|
Adjusted Operating Margin increased $19$33 million primarily due to the drivers above, adjusted for the impact of noncontrolling interests.NCI.
Adjusted PTC increased $50$23 million, mainly driven by the increase in Adjusted Operating Margin as described above, partially offset by lower capitalized interest due to project completions in Panama and Dominican Republic and lower foreign currency gains in Mexico.
Fiscal year 2017 versus 2016
Operating Margin increased $75 million, or 19%, which was driven primarily by the following (in millions):
|
| | | |
| Higher contracted energy sales in Dominican Republic net of LNG fuel consumption, mainly driven by Los Mina combined cycle commencement of operations in June 2017 | $ | 34 |
|
Higher availability driven by improved hydrology in Panama
| 26 |
|
| Higher availability in Mexico mainly driven by unplanned maintenance in 2016 | 13 |
|
| Other | 2 |
|
| Total MCAC SBU Operating Margin Increase | $ | 75 |
|
Adjusted Operating Margin increased $66 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC increased $55 million, driven by the increase of $19 million in Adjusted Operating Margin of $66 million as described above,above.
EURASIA SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions) for the additional netperiods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2018 | | 2017 | | 2016 | | $ Change 2018 vs. 2017 | | % Change 2018 vs. 2017 | | $ Change 2017 vs. 2016 | | % Change 2017 vs. 2016 |
| Operating Margin | | $ | 227 |
| | $ | 422 |
| | $ | 427 |
| | $ | (195 | ) | | -46 | % | | $ | (5 | ) | | -1 | % |
Adjusted Operating Margin (1) | | 194 |
| | 306 |
| | 303 |
| | (112 | ) | | -37 | % | | 3 |
| | 1 | % |
Adjusted PTC (1) | | 222 |
| | 290 |
| | 283 |
| | (68 | ) | | -23 | % | | 7 |
| | 2 | % |
_____________________________
| |
(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. |
Fiscal year 2018 versus 2017
Including favorable FX impacts of $28$8 million, at Mong DuongOperating Margin decreased $195 million, or 46%, which was driven primarily by the following (in millions):
|
| | | |
Impact of the sale of Masinloc power plant in March 2018
| $ | (122 | ) |
Impact of the sale of the Kazakhstan CHPs and the expiration of HPP concession in 2017
| (36 | ) |
Decrease in Vietnam due to adoption of the new revenue recognition standard in 2018 and higher maintenance costs
| (33 | ) |
| Other | (4 | ) |
| Total Eurasia SBU Operating Margin Decrease | $ | (195 | ) |
Adjusted Operating Margin decreased $112 million, or 37%, primarily due to athe drivers above, adjusted for NCI.
Adjusted PTC decreased $68 million, primarily driven by the decrease in Adjusted Operating Margin discussed above, partially offset by the positive impact in Vietnam due to increased interest income from the higher financing component of service concessioncontract consideration as a result of adoption of the new revenue recognized as interest income, net of higher interest expense as interest is no longer capitalized.recognition standard in 2018. See Note 1—General and Summary of Significant Accounting Policies—New Accounting Standards Adopted included in Part II.—Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information regarding the accounting for service concession arrangements.information.
Proportional Free Cash FlowFiscal year 2017 versus 2016
Operating Margin decreased $5 million, or 1%, and Adjusted Operating Margin increased $5$3 million, or 1%, with no material drivers.
Adjusted PTC increased $7 million, primarily driven by anthe increase in Adjusted Operating Margin, of $28 million (net of $9 million in non-cash items, primarily service concession expenseadjusted for NCI and the
retrospective adjustment to energy prices noted above),excluding unrealized gains and $58 million in higher interest income recognized at Mong Duong as a result of the financing component under service concession accounting. These positive impacts were partially offset by $26 million in higher working capital requirements at Mong Duong due to a build-up in preparation of the commencement of operations, $22 million in higher interest payments at Mong Duong, $11 million of higher tax payments at Masinloc, and $9 million in higher working capital requirements at Masinloc due primarily to the timing of coal purchases.losses on derivatives.
Key Trends and Uncertainties
During 20172019 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses, and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may impact our operating margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1.—Business and Item 1A.—Risk Factors of this Form 10-K. Macroeconomic and Political
During 2016, theThe macroeconomic and political environments in some countries where our subsidiaries conduct business have changed whichduring 2018. This could result in significant impacts to tax laws and environmental and energy policies. Additionally, we operate in multiple countries and as such are subject to volatility in exchange rates at the subsidiary level. See Item 7A.—Quantitative and Qualitative Disclosures About Market Risk for further information.Brazil United States Tax Law Reform
In December 2017, the United States enacted the TCJA. The legislation significantly revised the U.S. corporate income tax system by, among other things, lowering the corporate income tax rate, introducing new limitations on interest expense deductions, subjecting foreign earnings in excess of an allowable return to current U.S. taxation, and adopting a semi-territorial corporate tax system. These changes impacted our 2018 effective tax rate and will materially impact our effective tax rate in future periods. Furthermore, we anticipate that higher U.S. tax expense may fully utilize our remaining net operating loss carryforwards in the near term, which could lead to material cash tax payments in the United States. Specific provisions of the TCJA and their potential impacts on the Company are noted below. Our interpretation of the TCJA may change as the U.S. Treasury and the Internal Revenue Service issue additional guidance. Such changes may be material.
Transition Tax— President Michel Temer,As further explained in Note 21—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K we have concluded our analysis of the implementation impacts of the TCJA and included adjustments to our previous estimates in accordance with majority congressional support, continuesthe guidance of SAB 118. Our revised estimates took into account interpretative guidance issued in 2018 by the U.S. Treasury in proposed regulations. In the first quarter of 2019, the U.S. Treasury issued final regulations related to implement the fiscal reforms needed to improveone-time transition tax which further amended the country’s finances. While uncertainty dominatesguidance of the political arena, if enacted, President Temer's market reforms would improveproposed regulations. We are still evaluating the the economic outlook,final regulations which may benefithave a material impact on our businesses in Brazil. In October 2016, AES completed the salefinancial statements. The impacts of the Company's 100% ownershipfinal regulations will be reflected in our financial statements during the quarter ended March 31, 2019.
Limitation on Interest Expense Deductions— The TCJA introduced a new limitation on the deductibility of net interest expense beginning January 1, 2018. The deduction will be limited to interest income, plus 30 percent of tax basis EBITDA through 2021 (30 percent of EBIT beginning January 1, 2022). This determination is made at the consolidated group level, although it applies separately to partnerships. While interest expense of regulated utilities may be exempt from the limitation, the proposed regulations issued by the U.S. Treasury in AES Sul2018 would effectively limit interest expense of our U.S. utilities. The proposed regulations may change before they are fully enacted in final form and recognized an after-tax loss on disposalare not retroactive; we have not early adopted the proposed regulations. Given typical project financing and current U.S. holding company debt levels, we anticipate that this limitation will materially, negatively impact our effective tax rate.
Global Intangible Low Taxed Income (“GILTI”) —The TCJA subjects the earnings of $737 million. This after-tax loss excludes the impact of contingent proceeds linkedforeign subsidiaries to current U.S. taxation to the favorable settlementextent that those earnings exceed an allowable economic return on investment. The foreign earnings subject to current taxation under the GILTI provision are not limited to those derived from intangible property and may include gains derived from some future asset sales. The GILTI provision will subject a significant portion of pending litigation,our foreign earnings to current U.S. taxation. In 2018, the GILTI provision materially, negatively impacted our effective tax rate and we expect this to continue in future years. Prospectively, the consequences of the new GILTI provision may be partially mitigated by foreign tax credits. Proposed regulations
were issued in 2018 by the U.S. Treasury which isprovided further guidance on GILTI and the related foreign tax credit, however there are further regulations expected and they may change before enacted in final form.
State Taxes—The reactions of the individual states to federal tax reform are still evolving. Most states will assess whether and how the federal changes will be incorporated into their state tax legislation. Some states have already decided whether to conform to new provisions of the federal tax law, such as the one-time transition tax and GILTI, while many other states have not guaranteed. If the case is decidedyet enacted final legislation. As we expect higher taxable income in the Company's favor, amounts wouldfuture due to the federal changes, this may also lead to higher state taxable income. Our current state tax provisions predominantly have full valuation allowances against state net operating losses. These positions will be remittedre-assessed in the future as state tax law evolves and may result in material changes in position.
Tax Equity Structures — Our U.S. renewable energy portfolio operates primarily through tax equity partnerships. We cannot be certain of the impacts U.S. tax reform may have on availability or pricing of tax equity for future growth opportunities. Impacts of provisions such as the lower tax rate and immediate expensing may impact the amount and timing of returns allocable to AES over an unknown period of time. Any potential gain from the eventual resolution of this contingency would be presented separately as Discontinued Operations.our partners in our existing tax equity structures.
Puerto Rico — Our subsidiaries in Puerto Rico have a long-term PPA with state-owned PREPA, which has been facing economic challenges that could result in a material adverse effect on our business in Puerto Rico.
The Puerto Rico Oversight, Management, and Economic Stability Act (“PROMESA”) was enacted to create a structure for exercising federal oversight over the fiscal affairs of U.S. territories and created procedures for adjusting debt accumulated by the Puerto Rico government and, potentially, other territories (“Title III”). Finally, PROMESA expedites the approval of key energy projects and other critical projects in Puerto Rico.
PROMESA allowed for the establishment of an Oversight Board with broad powers of budgetary and financial control over Puerto Rico. The Oversight Board filed for bankruptcy on behalf of PREPA under Title III in July 2017. As a result of the bankruptcy filing, AES Puerto Rico and AES Ilumina’s non-recourse debt of $317 million and $34 million, respectively, continue to be in default and are classified as current as of December 31, 2018. The Company is in compliance with its debt payment obligations as of December 31, 2018.
After the events of Hurricanes Irma and Maria in September 2017, Puerto Rico’s infrastructure was severely damaged, including electric infrastructure and transmission lines. AES Puerto Rico resumed generation during the first quarter of 2018 and continues to be the lowest cost and EPA compliant energy provider in Puerto Rico and a critical supplier to PREPA. According to the US Federal Emergency Management Agency, as of January 2019 PREPA's recovery status is at 99%.
The Company's receivable balances in Puerto Rico as of December 31, 2018 totaled $68 million, of which $18 million was overdue. Despite the disruption caused by the hurricanes and the Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns.
A proposed Energy Public Policy law was introduced in October 2018 which includes the elimination of coal as a source for electricity generation by January 1, 2028 and the accelerated deployment of renewables (20% by 2025; 50% by 2040 and 100% by 2050). AES Puerto Rico's long-term PPA with PREPA expires December 31, 2027. Puerto Rico's Senate and House of Representatives are still debating certain amendments.
Considering the information available as of the filing date, Management believes the carrying amount of our assets in Puerto Rico of $598 million is recoverable as of December 31, 2018.
Argentina — During the second quarter of 2018, all of the three-year cumulative inflation rates commonly used to evaluate Argentina’s inflation exceeded 100%. Therefore, Argentina’s economy was determined to be highly inflationary. Since the tariffs and debt at our primary businesses in Argentina are denominated in USD, the functional currency of those businesses is USD. As such, the determination that the Argentina economy is highly inflationary is not expected to have a material impact on the Company’s financial statements.
United Kingdom — OnIn June 23, 2016, the United Kingdom (U.K.)UK held a referendum in which voters approved an exit from the European Union (“E.U.”),EU, commonly referred to as “Brexit”. As“Brexit.” In January 2019, the UK parliament rejected a result ofproposed withdrawal agreement that the referendum, itEU had supported. The UK is expected thatto exit the British government will begin negotiating the terms of the U.K.’s future relationship with the E.U. Although it is unclear what the long-term global implications will be, it is possible that the European or U.K. economy could weaken and our businesses may experience a decline in demand.EU on March 29, 2019. While the full impact of the Brexit isremains uncertain, these changes may adversely affectare not expected to have a material adverse effect on our operations and consolidated financial results. The most immediate impact has been a devaluation of the pound and euro against the U.S. dollar. For 2016 and 2017, the Company has hedged against these foreign currency movements, however, the impact could be greater in future years.
Puerto Rico LIBOR Phase Out— Our subsidiaries in Puerto Rico have long term PPAs with state-owned PREPA. DueIn July 2017, the UK Financial Conduct Authority announced the phase out of LIBOR by the end of 2021. The Alternative Reference Rate Committee at the Federal Reserve is working to establish a new benchmark replacement rate. While AES maintains financial instruments that use LIBOR as an interest rate
benchmark, the ongoing economic situation infull impact of the territory, PREPA faces significant financial challenges. There have been no significant adverse impacts to AES Puerto Rico due to PREPA’s financial challenges.phase out is uncertain until a new replacement benchmark is determined and implementation plans are more fully developed.
Regulatory
Maritza PPA Review— The DG Comp continues to face challenges,review whether Maritza’s PPA with NEK is compliant with the European Commission’s state aid rules. Although no formal investigation has been launched by DG Comp to date, Maritza has engaged in discussions with the DG Comp case team and representatives of Bulgaria to discuss the agency’s review. In the near term, Maritza expects that it will engage in discussions with Bulgaria to attempt to reach a negotiated resolution concerning DG Comp’s review. The anticipated discussions could involve a range of potential outcomes, including but not limited to termination of the PPA and payment of some level of compensation to Maritza. Any negotiated resolution would be subject to mutually acceptable terms, lender consent, and DG Comp approval. At this time, we cannot predict the outcome of the anticipated discussions between Maritza and Bulgaria, nor can we predict how DG Comp might resolve its review if the discussions fail to result in an agreement concerning the review. Maritza believes that its PPA is legal and in compliance with all applicable laws, and it will take all actions necessary to protect its interests, whether through negotiated agreement or those challenges worsen, or otherwise impact PREPA’s ability to make payments to AES Puerto Rico,otherwise. However, there can be no assurances that this matter will be resolved favorably; if it is not, there could be a material adverse impact on Maritza’s and the Company.Company’s respective financial statements.
United States of America — The outcomeConsidering the information available as of the 2016 U.S. elections could result in significant changes to U.S. tax laws, and environmental and energy policies,filing date, Management believes the impactcarrying value of whichour long-lived assets at Maritza of approximately $1.1 billion is uncertain.
Philippines — The outcomerecoverable as of the 2016 Philippines election could result in changes in policies towards the U.S., China or other nations the impact of which on our business is uncertain.December 31, 2018.
Foreign Exchange and Commodities
Our businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal and environmental credits. In 2016, there were more than 50% improvement in both oil and natural gas prices, which had a positive impact on our businesses in the Dominican Republic, Ohio and Northern Ireland. Since weWe operate in multiple countries weand as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between our functional currency, the U.S.
Dollar,USD, and currencies of the countries in which we operate. In 2016, we had2018, there was a significant devaluation in the Argentine Peso. The Brazilian Real, Colombian Peso and Kazakhstani Tenge recovered duringpeso against the year, but remain devalued as compared to the beginning of 2015,USD, which had an offsetting impact on our 20162018 results. Continued material devaluation of the Argentine peso against the USD could have an impact on our future results. For additional information, refer to Item 7A.—Quantitative and Qualitative Disclosures About Market Risk.
Alto Maipo
During 2016, the Alto Maipo project in Chilehas experienced technical difficulties in constructioncost overruns which have resulted in an increase inincreased projected costs of up to 22% over the original $2 billion budget. TheseConstruction at the project is continuing, and the project is 75% complete.
In February 2018, Alto Maipo entered into a new construction contract with Strabag. The new contract is fixed-price and lump sum, transfers geological and construction risk to Strabag and provides a date certain for completion with strong performance and completion guarantees.
In May 2018, Alto Maipo and the project's senior lenders executed the financial restructuring of the project. The restructuring, among other things, includes additional costs have ledfunding commitments of up to $400 million of which $200 million was already contributed by AES Gener. Any unused portion of AES Gener's commitment will be used to prepay project debt.
If Alto Maipo is unable to meet certain construction milestones, there could be a series of negotiations withmaterial impact to the main contractors, financiersfinancing and partnersvalue of the project with the intention to restructure the existing financing and obtain additional financing to guarantee project completion. On January 19, 2017, the parties agreedwhich could have a material impact on the basisCompany. The carrying value of the restructuring process, including new project milestones. These agreements are subject to the negotiationlong-lived assets and finalizationdeferred tax assets of the specific restructuring terms and conditions; and the negotiation and approvalAlto Maipo as of the terms and conditions of each of the financing documents. Currently, the Company's indirect equity interest in the project is 40%.
Impairments
Long-lived Assets— During the year ended December 31, 2016, the Company recognized asset impairment expense of $1.1 billion. Due to decreased wind production2018 was approximately $2 billion and a decline in forward power curves in 2016, the Company tested the recoverability of its long-lived assets at Buffalo Gap I, II, and III. After recognizing asset impairment expense of $236$60 million, at Buffalo Gap I and II,respectively. Management believes the carrying value of the long-lived asset groups at Buffalo Gap I, II, and III totaled $242 million atgroup is recoverable as of December 31, 2016.2018. In addition, Management believes it is more likely than not the deferred tax assets will be realized; however, the deferred tax assets could be reduced if estimates of future taxable income are decreased.
Andres
On September 3, 2018, lightning affected the Andres 319 MW combined cycle natural gas facility in the Dominican Republic (“the Plant”) resulting in significant damage to its steam turbine and generator. The Company has business interruption and property damage insurance coverage, subject to pre-defined deductibles, under its existing programs.
On September 25, 2018, the Plant restarted operations running the gas turbine in simple cycle at partial load of approximately 120 MW. Management estimates that the Plant will operate the gas turbine in simple cycle at full load of approximately 185 MW starting in the second quarter of 2019, and in combined cycle at full capacity by the fourth quarter of 2019.
To mitigate the impact of the reduced capacity in the local energy market, the Company recognizedinstalled 120 MW of rental power (gas turbines) until the combined cycle facility is at full load. The rental units were fully operational beginning in December 2018.
Considering the information available as of the filing date, Management believes the carrying amount of our long-lived assets in Andres of $395 million is recoverable as of December 31, 2018.
Changuinola Tunnel Leak
Increased water levels were noted in a creek near the Changuinola power plant, a 223 MW hydroelectric power facility in Panama. After the completion of an assetassessment, the Company has confirmed loss of water in specific sections of the tunnel. The plant is in operation and can generate up to its maximum capacity. Repairs will be needed to ensure the long term performance of the facility, during which time the affected units of the plant will be out of service. Subject to final inspection, the repairs may take up to 10 months to complete and are expected to commence during the first quarter of 2019. The Company has notified its insurers of a potential claim and has asserted claims against its construction contractor. However, there can be no assurance of collection. The Company continues to monitor the situation to identify any potential changes to the tunnel. The Company has not identified any indicators of impairment expense of $859 million at DPL in 2016. After recognizing asset impairment expense at DPL,and believes the carrying value of the long-lived asset group of $931 million is recoverable as of December 31, 2018.
Impairments
Long-lived Assets and Equity Affiliates — During the year ended December 31, 2018, the Company recognized asset and other-than-temporary impairment expense of $355 million. See Note 7—Investments In and Advances To Affiliates and Note 20—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. After recognizing this impairment expense, the carrying value of the equity affiliates and the asset groups, at DPL, including long-lived assets, and those asset groups that were assessed and not impaired, totaled $498$661 million at December 31, 2016. See Note 20—Asset Impairment Expense in Item 8.—Financial Statements and Supplementary Data for further information regarding the impairments at Buffalo Gap and DPL.2018. Events or changes in circumstances that may necessitate further recoverability tests and potential impairments of long-lived assets may 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 that it is more likely than not that the asset will be disposed of before the end of its previously estimated useful life.
Goodwill— The Company currently has no reporting units considered to be "at risk."Aconsiders a reporting unit is considered "at risk"at risk of impairment when its fair value isdoes not higher thanexceed its carrying amount by more than 10%. During the annual goodwill impairment test performed as of October 1, 2018, the Company determined that the fair value of its Gener reporting unit exceeded its carrying value by 7%. Therefore, Gener's $868 million goodwill balance was considered to be "at risk" as of December 31, 2018, largely due to the fact that a market participant would no longer assume perpetual cash flows from coal-fired power plants due to the increased penetration of renewable energy in Chile.
Through 2028, Gener’s plants remain largely contracted, with most of its PPAs expiring between 2029 and 2037. The Company utilized the income approach in deriving the fair value of the Gener reporting unit, which included estimated cash flows assuming a 20-year annuity for thermal generation and longer term cash flows for hydro generation. These cash flows were discounted using a weighted average cost of capital of 7%, which was determined based on the Capital Asset Pricing Model. See Item 7.—Critical Accounting Policies and Estimates—Fair Value of Nonfinancial Assets and Liabilities and Note 8—Goodwill and Other Intangible Assets included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. The Company monitors its reporting units at risk of Step 1 failure on an ongoing basis. It is possiblebasis, and believes that the Company may incurestimates and assumptions used in the calculations are reasonable. 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 at any reporting units containing goodwillmay be necessary in future periods if adverse changes in their business or operating environments occur. See Note 9—Goodwill and Other Intangible Assets in Item 8.—Financial Statements and Supplementary Data for further information.periods.
Capital Resources and Liquidity
Overview — As of December 31, 2016,2018, the Company had unrestricted cash and cash equivalents of $1.3$1.2 billion, of which $100$24 million was held at the Parent Company and qualified holding companies. The Company also had $798$313 million in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $871$837 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.8$15.6 billion and $4.7$3.7 billion, respectively. Of the approximately $1.3$1.7 billion of our current non-recourse debt, $1.2 billion$825 million was presented as such because it is due in the next twelve months, and $128 $351
million relates to debt considered in default due to covenant violations. Theviolations, and $483 million relates to debt at Colon which is in compliance with its covenants, but is presented as current since it is probable that the Company cannot meet a technical covenant requirement by its deadline. None of the defaults are not payment defaults, but are instead technical defaults triggered by failure to comply with other covenants and/or other conditions such as (but not limited to) failure to meet information covenants, complete construction or other milestones in an allocated time, meet certain minimum or maximum financial ratios, or other requirements contained in the non-recourse debt documents of the Company.
The Company expects to modify the Colon loan agreement in 2019 to amend the requirements of this technical covenant, after which the debt will be re-classified as noncurrent.
We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates, or through opportunistic refinancing activity or some combination thereof. NoneWe have $5 million of our recourse debt which matures within the next twelve months. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes that such securities are attractively priced. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements and other factors. The amounts involved in any such repurchases may be material.
We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals, export credit agencies and local regional banks.
Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company's only material un-hedgedunhedged exposure to variable interest rate debt relates to indebtedness under its floating rate senior unsecured notes$366 million outstanding secured term loan due 2019.2022. On a consolidated basis, of the Company's $20.5$19.7 billion of total gross debt outstanding as of December 31, 2016,2018, approximately $3.5$3.2 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate. Brazil holds $1.3$1.1 billion of our floating rate non-recourse exposure as we have no ability to fix local debt interest rates efficiently.
In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project's non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business' obligations up to the amount provided for in the relevant guarantee or other credit support. At December 31, 2016,2018, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $535$712 million in aggregate (excluding those collateralized by letters of credit and other obligations discussed below).
As a result of the Parent Company's below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity
needs. At December 31, 2016,2018, we had $6$78 million in letters of credit outstanding, provided under our senior secured credit facility, $245$368 million in letters of credit outstanding, provided under our un-senior secured credit facility and $3 million in cash collateralized letters of credit outstanding outside of ourunsecured senior secured credit facility. These letters of credit operate to guarantee performance relating to certain project development and construction activities and business operations. During the year ended December 31, 2016,2018, the Company paid letter of credit fees ranging from 0.2%1% to 2.5%3% per annum on the outstanding amounts.
We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available
on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.
Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses.
Long-Term Receivables — As of December 31, 2016,2018, the Company had approximately $264$116 million of accounts receivable classified as Noncurrent assets—otherOther noncurrent assets primarily related to certain of its generation businesses in Argentina and the U.S. and its utility business in Brazil. TheArgentina. These noncurrent portion primarily consistsreceivables mostly consist of accounts receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond December 31, 2017,2019, or one year from the latest balance sheet date. The majority of Argentinian receivables have been converted into long-term financing for the construction of power plants. See Note 6—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data and Item 1.—Business—Business—Regulatory Matters—Argentina of this Form 10-K for further information. As of December 31, 2018, the Company had approximately $1.4 billion of loans receivable primarily related to the Mong Duong II facility constructed under a build, operate, and transfer contract in Vietnam. This loan receivable represents contract consideration related to the construction of the facility, which was substantially completed in 2015, and will be collected over the 25 year term of the plant's PPA. See Note 18—Revenue included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Cash Sources and Uses
The primary sources of cash for the Company in the year ended December 31, 2018 were cash flows from operating activities, proceeds from the sales of business interests, and debt financings. The primary uses of cash in the year ended December 31, 2018 were repayments of debt, capital expenditures, and purchases of short-term investments.
The primary sources of cash for the Company in the year ended December 31, 2017 were cash flows from operating activities, debt financings, and sales of short-term investments. The primary uses of cash in the year ended December 31, 2017 were repayments of debt, purchases of short-term investments, and capital expenditures.
The primary sources of cash for the Company in the year ended December 31, 2016 were cash flows from operating activities, debt financings, and sales of short-term investments. The primary uses of cash in the year ended December 31, 2016 were repayments of debt, purchases of short-term investments, and capital expenditures.
A summary of cash-based activities are as follows (in millions):
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| Cash Sources: | 2018 | | 2017 | | 2016 |
Net income, adjusted for non-cash items (1) | $ | 2,529 |
| | $ | 2,569 |
| | $ | 2,344 |
|
| Proceeds from the sale of business interests, net of cash and restricted cash sold | 2,020 |
| | 108 |
| | 538 |
|
| Issuance of non-recourse debt | 1,928 |
| | 3,222 |
| | 2,978 |
|
| Borrowings under revolving credit facilities | 1,865 |
| | 2,156 |
| | 1,465 |
|
| Sale of short-term investments | 1,302 |
| | 3,540 |
| | 4,904 |
|
| Issuance of recourse debt | 1,000 |
| | 1,025 |
| | 500 |
|
| Contributions from noncontrolling interests and redeemable security holders | 43 |
| | 73 |
| | 190 |
|
Release of working capital(2) | — |
| | — |
| | 553 |
|
| Other | 175 |
| | 102 |
| | 171 |
|
| Total Cash Sources | $ | 10,862 |
| | $ | 12,795 |
| | $ | 13,643 |
|
| | | | | | |
| Cash Uses: | | | | | |
| Repayments under revolving credit facilities | $ | (2,238 | ) | | $ | (1,742 | ) | | $ | (1,433 | ) |
| Capital expenditures | (2,121 | ) | | (2,177 | ) | | (2,345 | ) |
| Repayments of recourse debt | (1,933 | ) | | (1,353 | ) | | (808 | ) |
| Purchase of short-term investments | (1,411 | ) | | (3,310 | ) | | (5,151 | ) |
| Repayments of non-recourse debt | (1,411 | ) | | (2,360 | ) | | (2,666 | ) |
| Dividends paid on AES common stock | (344 | ) | | (317 | ) | | (290 | ) |
| Distributions to noncontrolling interests | (340 | ) | | (424 | ) | | (476 | ) |
| Payments for financed capital expenditures | (275 | ) | | (179 | ) | | (113 | ) |
Increase in working capital(2) | (186 | ) | | (65 | ) | | — |
|
| Contributions to equity affiliates | (145 | ) | | (89 | ) | | (6 | ) |
| Acquisitions of businesses, net of cash acquired, and equity method investments | (66 | ) | | (609 | ) | | (52 | ) |
| Payments for financing fees | (39 | ) | | (100 | ) | | (105 | ) |
| Other | (138 | ) | | (242 | ) | | (189 | ) |
| Total Cash Uses | $ | (10,647 | ) | | $ | (12,967 | ) | | $ | (13,634 | ) |
| Net increase (decrease) in Cash, Cash Equivalents, and Restricted Cash | $ | 215 |
| | $ | (172 | ) | | $ | 9 |
|
_____________________________
| |
(1) | Refer to the table within the Operating Activities section below for a reconciliation of non-cash items affecting net income during the applicable period. |
| |
(2) | Refer to the table within the Operating Activities section below for explanations of the variance in working capital requirements. |
Consolidated Cash Flows
The following table reflects the changes in operating, investing, and financing cash flows for the comparative twelve month periods (in millions):
| | | | | December 31, | | $ Change | | December 31, | | $ Change |
| Cash flows provided by (used in): | | 2016 | | 2015 | | 2014 | | 2016 vs. 2015 | | 2015 vs. 2014 | | 2018 | | 2017 | | 2016 | | 2018 vs. 2017 | | 2017 vs. 2016 |
| Operating activities | | $ | 2,884 |
| | $ | 2,134 |
| | $ | 1,791 |
| | $ | 750 |
| | $ | 343 |
| | $ | 2,343 |
| | $ | 2,504 |
| | $ | 2,897 |
| | $ | (161 | ) | | $ | (393 | ) |
| Investing activities | | (2,108 | ) | | (2,366 | ) | | (656 | ) | | 258 |
| | (1,710 | ) | | (505 | ) | | (2,599 | ) | | (2,136 | ) | | 2,094 |
| | (463 | ) |
| Financing activities | | (747 | ) | | 28 |
| | (1,262 | ) | | (775 | ) | | 1,290 |
| | (1,643 | ) | | 43 |
| | (747 | ) | | (1,686 | ) | | 790 |
|
Operating Activities
The following table summarizes the key components of our consolidated operating cash flows (in millions):
| | | | | December 31, | | $ Change | | December 31, | | $ Change |
| | | 2016 | | 2015 | | 2014 | | 2016 vs. 2015 | | 2015 vs. 2014 | | 2018 | | 2017 | | 2016 | | 2018 vs. 2017 | | 2017 vs. 2016 |
| Net Income (Loss) | | $ | (777 | ) | | $ | 762 |
| | $ | 1,147 |
| | $ | (1,539 | ) | | $ | (385 | ) | |
| Net income (loss) | | | $ | 1,565 |
| | $ | (777 | ) | | $ | (777 | ) | | $ | 2,342 |
| | $ | — |
|
| Depreciation and amortization | | 1,176 |
| | 1,144 |
| | 1,245 |
| | 32 |
| | (101 | ) | | 1,003 |
| | 1,169 |
| | 1,176 |
| | (166 | ) | | (7 | ) |
| Loss (gain) on disposal and sale of business interests | | | (984 | ) | | 52 |
| | (29 | ) | | (1,036 | ) | | 81 |
|
| Impairment expenses | | 2,481 |
| | 602 |
| | 433 |
| | 1,879 |
| | 169 |
| | 355 |
| | 537 |
| | 1,098 |
| | (182 | ) | | (561 | ) |
| Loss on the extinguishment of debt | | 20 |
| | 186 |
| | 261 |
| | (166 | ) | | (75 | ) | |
| Deferred Income Taxes | | (793 | ) | | (50 | ) | | 47 |
| | (743 | ) | | (97 | ) | |
| Loss on extinguishment of debt | | | 188 |
| | 68 |
| | 20 |
| | 120 |
| | 48 |
|
| Deferred income taxes | | | 313 |
| | 672 |
| | (793 | ) | | (359 | ) | | 1,465 |
|
| Net loss (gain) from disposal and impairments of discontinued businesses | | | (269 | ) | | 611 |
| | 1,383 |
| | (880 | ) | | (772 | ) |
| Other adjustments to net income | | 225 |
| | (73 | ) | | (320 | ) | | 298 |
| | 247 |
| | 358 |
| | 237 |
| | 266 |
| | 121 |
| | (29 | ) |
| Non-cash adjustments to net income | | 3,109 |
| | 1,809 |
| | 1,666 |
| | 1,300 |
| | 143 |
| |
| Non-cash adjustments to net income (loss) | | | 964 |
| | 3,346 |
| | 3,121 |
| | (2,382 | ) | | 225 |
|
| Net income, adjusted for non-cash items | | $ | 2,332 |
| | $ | 2,571 |
| | $ | 2,813 |
| | $ | (239 | ) | | $ | (242 | ) | | $ | 2,529 |
| | $ | 2,569 |
| | $ | 2,344 |
| | $ | (40 | ) | | $ | 225 |
|
Net change in operating assets and liabilities (1) | | 552 |
| | (437 | ) | | (1,022 | ) | | 989 |
| | 585 |
| |
Changes in working capital (1) | | | (186 | ) | | (65 | ) | | 553 |
| | (121 | ) | | (618 | ) |
Net cash provided by operating activities (2) | | $ | 2,884 |
| | $ | 2,134 |
| | $ | 1,791 |
| | $ | 750 |
| | $ | 343 |
| | $ | 2,343 |
| | $ | 2,504 |
| | $ | 2,897 |
| | $ | (161 | ) | | $ | (393 | ) |
