0000874761 us-gaap:PrivateEquityFundsMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 20152018
-OR-
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| ¨ | TRANSITION REPORT FILED PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | COMMISSION FILE NUMBER 1-12291 |
THE AES CORPORATION
(Exact name of registrant as specified in its charter)
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| Delaware | | 54 1163725 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| 4300 Wilson Boulevard Arlington, Virginia | | 22203 |
| (Address of principal executive offices) | | (Zip Code) |
| Registrant's telephone number, including area code: (703) 522-1315 |
| Securities registered pursuant to Section 12(b) of the Act: |
| Title of Each Class | | Name of Each Exchange on Which Registered |
| Common Stock, par value $0.01 per share | | New York Stock Exchange |
AES Trust III, $3.375 Trust Convertible Preferred Securities | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes ox No xo
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer x | | Accelerated filer o¨ | Non-accelerated filer o
| Smaller reporting company o¨ |
| | (Do not check if a smaller
reporting company)Emerging growth company ¨
| | Non-accelerated filer ¨ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
The aggregate market value of the voting and non-voting common equity held by non-affiliates on June 30, 2015,29, 2018, the last business day of the Registrant's most recently completed second fiscal quarter (based on the adjusted closing sale price of $12.88$13.05 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $8.79$8.63 billion.
The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, on February 18, 201621, 2019 was 659,733,335662,358,244.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant's Proxy Statement for its 20162019 annual meeting of stockholders are incorporated by reference in Parts II and III
THE AES CORPORATION FISCAL YEAR 20152018 FORM 10-K
TABLE OF CONTENTS
GLOSSARY OF TERMS
When theThe following terms and abbreviations appear in the text of this report theyand have the meaningsdefinitions indicated below:
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| Adjusted EPS | Adjusted Earnings Per Share, a non-GAAP measure |
| Adjusted PTC | Adjusted PretaxPre-tax Contribution, a non-GAAP measure of operating performance |
| AES | The Parent Company and its subsidiaries and affiliates |
AFUDCAOCI | Allowance for Funds Used During Construction |
ANEEL | Brazilian National Electric Energy AgencyAccumulated Other Comprehensive Income |
| AOCL | Accumulated Other Comprehensive Loss |
| ASC | Accounting Standards Codification |
| ASEP | National Authority of Public Services |
| BACT | Best Available Control Technology |
| BART | Best Available Retrofit Technology |
BNDES | Brazilian Development Bank |
| BOT | Build, Operate and Transfer |
BOT Company | AES-VCM Mong Duong Power Company Limited |
| BTA | Best Technology Available |
| CAA | United States Clean Air Act |
| CAMMESA | Wholesale Electric Market Administrator in Argentina |
| CCGT | Combined Cycle Gas Turbine |
CDECCCR | Economic Load Dispatch Center |
CDI | Brazilian equivalent to LIBORCoal Combustion Residuals, which includes bottom ash, fly ash and air pollution control wastes generated at coal-fired generation plant sites. |
| CDPQ | La Caisse de depotdépôt et placement du QuebecQuebéc |
CDEEECEN | Dominican Corporation of State Electrical CompaniesCoordinador Electrico Nacional |
| CEO | Chief Executive Officer |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act of 1980 (also known as "Superfund") |
CESCO | Central Electricity Supply Company of Orissa Ltd. |
CFB | Circulating Fluidized Bed Boiler |
| CFE | Federal Commission of Electricity |
CND | National Dispatch Center |
CNE | National Energy Commission |
CODCHP | Commercial Operation DateCombined Heat and Power |
| COFINS | Contribuição para o Financiamento da Seguridade Social |
CO2 | Carbon Dioxide |
| COSO | Committee of Sponsoring Organizations of the Treadway Commission |
| CP | Capacity Performance |
CPCN | Certificate of Public Convenience and Necessity |
| CPI | United States Consumer Price Index |
| CPP | Clean Power Plan |
| CRES | Competitive Retail Electric Service |
| CSAPR | Cross-State Air Pollution Rule |
| CTNG | Compañia Transmisora del Norte Grande |
| CWA | U.S. Clean Water Act |
| DG Comp | Directorate-General for Competition of the European Commission |
Dodd-Frank Act | Dodd-Frank Wall Street Reform and Consumer Protection Act |
| DP&L | The Dayton Power & Light Company |
| DPL | DPL Inc. |
DPLE | DPL Energy, LLC, a wholly-owned subsidiary of DPL (renamed AES Ohio Generation, LLC effective 2/1/2016) |
| DPLER | DPL Energy Resources, Inc. |
| DPP | Dominican Power Partners |
| EBITDA | Earnings before Interest, Taxes, Depreciation & Amortization |
ECCRA | Environmental Compliance Cost Recovery Adjustment |
EGCO Group | Electricity Generating Public Company Limited |
ELV | Emission Limit Values |
EMIR | European Market Infrastructure Regulation |
EOOD | Single person private limited liability company in Bulgaria |
| EPA | United States Environmental Protection Agency |
| EPC | Engineering, Procurement, and Construction |
EPIRAERCOT | Electric Power Industry Reform ActReliability Council of 2001 |
ERC | Energy Regulatory Commission |
ESO | Electricity System OperatorTexas |
| ESP | Electric Security Plan |
EU ETS | European Union Greenhouse Gas Emission Trading Scheme |
| EURIBOR | Euro Inter Bank Offered Rate |
| EUSGU | Electric Utility Steam Generating Unit |
| EVN | Electricity of Vietnam |
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EVP | Executive Vice President |
EWG | Exempt Wholesale Generators |
FAC | Fuel Adjustment Charges |
| FASB | Financial Accounting Standards Board |
FCA | Federal Court of Appeals |
| FERC | Federal Energy Regulatory Commission |
| FONINVEMEM | Fund for the Investment Needed to Increase the Supply of Electricity in the Wholesale Market |
| FPA | Federal Power Act |
| FX | Foreign Exchange |
G&A | General and Administrative |
| GAAP | Generally Accepted Accounting Principles in the United States |
GELGDPR | General Electricity LawData Protection Regulation |
| GHG | Greenhouse Gas |
GNPIPDGILTI | Gross National Product - Implicit Price DeflatorGlobal Intangible Low Taxed Income
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GSAGRIDCO | Gas Supply AgreementGrid Corporation of Odisha Ltd. |
| GWh | Gigawatt Hours |
| HLBV | Hypothetical Liquidation Book Value |
HTA | Heads of Terms Agreement |
ICC | International Chamber of Commerce |
ICM | Industrial and Commerce Ministry |
| IDEM | Indiana Department of Environmental Management |
IEDITC | Industrial Emission Directive |
IFC | International Finance Corporation |
IOA | Investment Obligation AgreementImputed Tax Credit |
| IPALCO | IPALCO Enterprises, Inc. |
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| IPL | Indiana, Indianapolis Power & Light Company |
| IPP | Independent Power Producers |
IRTI-SEM | Annual Tariff Adjustment in BrazilIntegrated Single Electricity Market |
| ISO | Independent System Operator |
| IURC | Indiana Utility Regulatory Commission |
KPI | Key Performance Indicator |
kWh | Kilowatt Hours |
| LIBOR | London Inter Bank Offered Rate |
| LNG | Liquefied Natural Gas |
MACT | Maximum Achievable Control Technology |
| MATS | Mercury and Air Toxics Standards |
| MISO | Midcontinent Independent System Operator, Inc. |
MME | Ministry of Mines and Energy |
| MRE | Energy Reallocation Mechanism |
| MW | Megawatts |
| MWh | Megawatt Hours |
| NAAQS | National Ambient Air Quality Standards |
| NCI | Noncontrolling Interest |
| NCRE | Non-conventionalNon-Conventional Renewable Energy |
| NEK | Natsionalna Elektricheska Kompania (state-owned electricity public supplier in Bulgaria) |
| NEPCO | National Electric Power Company |
| NERC | North American Electric Reliability Corporation |
NGCCNM | Natural Gas Combined CycleNot Meaningful |
| NOV | Notice of Violation |
NOX | Nitrogen Dioxide |
| NPDES | National Pollutant Discharge Elimination System |
| NSPS | New Source Performance Standards |
NSR | New Source Review |
NYISO | New York Independent System Operator, Inc. |
NYSE | New York Stock Exchange |
| O&M | Operations and Maintenance |
| OERC | Orissa Electricity Regulatory Commission |
| ONS | National System Operator |
| OPGC | Odisha Power Generation Corporation, Ltd. |
| OTC Policy | Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling |
| Parent Company | The AES Corporation |
PCBPCU | Polychlorinated biphenylPerformance Cash Units |
| Pet Coke | Petroleum Coke |
| PIS | Partially Integrated System |
| PJM | PJM Interconnection, LLC |
| PM | Particulate Matter |
| PPA | Power Purchase Agreement |
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| PREPA | Puerto Rico Electric Power Authority |
PRPPSD | Potentially Responsible PartiesPrevention of Significant Deterioration |
| PSU | Performance Stock Unit |
| PUCO | The Public Utilities Commission of Ohio |
| PURPA | Public Utility Regulatory Policies Act |
| QF | Qualifying Facility |
RCOA | Retail Competition & Open Access |
RGGI | Regional Greenhouse Gas Initiative |
| RMRR | Routine Maintenance, Repair and Replacement |
ROE | Return on Equity |
RPM | Reliability Pricing Model |
| RSU | Restricted Stock Unit |
| RTO | Regional Transmission Organization |
| SADI | Argentine Interconnected System |
SAIDI | System Average Interruption Duration Index |
SAIFI | System Average Interruption Frequency Index |
| SBU | Strategic Business Unit |
| SCE | Southern California Edison |
| SEC | United States Securities and Exchange Commission |
| SEM | Single Electricity Market |
| SEN | National Power System |
SEWRC | Bulgaria's State Energy and Water Regulatory CommissionSistema Electrico Nacional |
| SIC | Central Interconnected Electricity System |
SIE | Superintendence of Electricity |
| SIN | National Interconnected System |
| SING | Northern Interconnected Electricity System |
| SIP | State Implementation Plan |
| SNE | National Secretary of Energy |
SO2 | Sulfur Dioxide |
SPP | Southwest Power Pool Electric Energy Network |
| SSO | Standard Service Offer |
SSRSWRCB | Service Stability RiderCalifornia State Water Resources Board |
TATCJA | Transportation AgreementTax Cuts and Jobs Act
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| TECONS | Term Convertible Preferred Securities |
TIPRA | Tax Increase Prevention and Reconciliation Act of 2005 |
TNP | Transitional National Plan |
TSR | Total Shareholder Return |
UPME | Mining and Energetic Planning Unit |
| U.S. | United States |
| UK | United Kingdom |
| USD | U.S. dollar |
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| VAT | Value Added Tax |
| VIE | Variable Interest Entity |
| Vinacomin | Vietnam National Coal-Mineral Industries Holding Corporation Ltd. |
WACCYPF | Weighted Average Cost of Capital |
WECC | Western Electric Coordinating Council |
WESM | Wholesale Electricity Spot MarketArgentina state-owned gas company |
PART I
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.
FORWARD-LOOKING INFORMATION
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;
our ability to fulfill our obligations, manage liquidity and comply with covenants under our recourse and non-recourse debt, including our ability to manage our significant liquidity needs and to comply with covenants under our senior secured credit facility and other existing financing obligations;
our ability to receive funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise;
changes in our or any of our subsidiaries' corporate credit ratings or the ratings of our or any of our subsidiaries' debt securities or preferred stock, and changes in the rating agencies' ratings criteria;
our ability to purchase and sell assets at attractive prices and on other attractive terms;
our ability to compete in markets where we do business;
our ability to operate power generation, distribution and transmission facilities, including managing availability, outages and equipment failures;
our ability to manage our operational and maintenance costs, the performance and reliability of our generating plants, including our ability to reduce unscheduled down times;
our ability to locate and acquire attractive "greenfield" or "brownfield" projects and our ability to finance, construct and begin operating our "greenfield" or "brownfield" projects on schedule and within budget;
our ability to enter into long-term contracts, which limit volatility in our results of operations and cash flow, such as PPAs, fuel supply, and other agreements and to manage counterparty credit risks in these agreements;
variations in weather, especially mild winters and cooler summers in the areas in which we operate, the occurrence of difficult hydrological conditions for our hydropower plants, as well as hurricanes and other storms and disasters, wildfires and low levels of wind or sunlight for our wind and solar facilities;
the performance of our contracts by our contract counterparties, including suppliers or customers;
severe weather and natural disasters;
our ability to meetraise sufficient capital to fund development projects or to successfully execute our expectations in the development construction, operation and performance of our new facilities, whether greenfield, brownfield or investments in the expansion of existing facilities;projects;
the success of our initiatives in other renewable energy projects as well as GHG emissions reduction projects and energy storage projects;
the availability of government incentives or policies that support the development of renewable energy generation projects;
our ability to keep up with advances in technology;
the potential effectsgrowth in number of threatenedcustomers or actual acts of terrorism and war;in customer usage;
the expropriation or nationalizationoperations of our businesses or assets by foreign governments, with or without adequate compensation;joint ventures that we do not control;
our ability to achieve reasonable rate treatment in our utility businesses;
changes in laws, rules and regulations affecting our international businesses;businesses, particularly in developing countries;
changes in laws, rules and regulations affecting our North America business,utilities businesses, including, but not limited to, regulations which may affect competition, the ability to recover net utility assets and other potential stranded costs by our utilities;
changes in law resulting from new local, state, federal or international energy legislation and changes in political or regulatory oversight or incentives affecting our wind business and solar projects, our other renewables projects and our initiatives in GHG reductions and energy storage, including government policies or tax incentives;
changes in environmental laws, including requirements for reduced emissions, of sulfur, nitrogen, carbon, mercury, hazardous air pollutants and other substances, GHG legislation, regulation, and/or treaties and coal ash regulation;CCR regulation and remediation;
changes in tax laws, including U.S. tax reform, and the effects ofchallenges to our strategies to reduce tax payments;positions;
the effects of litigation and government and regulatory investigations;
the performance of our acquisitions;
our ability to maintain adequate insurance;
decreases in the value of pension plan assets, increases in pension plan expenses, and our ability to fund defined benefit pension and other postretirement plans at our subsidiaries;
losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets;
changes in accounting standards, corporate governance and securities law requirements;
our ability to maintain effective internal controls over financial reporting;
our ability to attract and retain talented directors, management and other personnel, 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
cyber-attacks and information security breaches.
These factors in addition to others described elsewhere in this Form 10-K, including those described under Item 1A.—Risk Factors, and in subsequent securities filings, should not be construed as a comprehensive listing of factors that could cause results to vary from our forward-looking information.
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.
ITEM 1. BUSINESS
Overview
We were incorporated in 1981 and are a diversified power generation and utility company organized into six market-oriented SBUs: US (United States), Andes (Chile, Colombia, and Argentina), Brazil, MCAC (Mexico, Central America and Caribbean), Europe, and Asia.
Item 1.—Business is an outline of our strategy and our businesses by SBU, including key financial drivers. Additional items that may have an impact on our businesses are discussed in Item 1A.—Risk Factors and Item 3.—Legal Proceedings. Executive Summary
Incorporated in 1981, AES is a power generation and utility company, providing affordable, sustainable energy through our diverse portfolio of thermal and renewable generation facilities and distribution businesses. Our mission is to improve lives by accelerating a safer and greener energy future. We do this by leveraging our unique electricity platforms and the knowledge of our people to provide the energy and infrastructure solutions our customers need. Our people share a passion to help meet the world's current and increasing energy needs, while providing communities and countries the opportunity for economic growth through the availability of reliable, affordable electric power.
Overview of Our Strategy
Future growth across our company will be heavily weighted toward less carbon-intensive wind, solar and natural gas generation and infrastructure. Our robust backlog of projects under construction or under signed PPAs continues to increase, driven by our focus on select markets where we can take advantage of our global scale and synergies with our existing businesses. In 2018, we signed long-term PPAs for 2 GW of capacity and we are on pace to sign 2 to 3 GW of new PPAs annually through 2022.
We are also working on enhancing some of our current contracts by blending and extending existing PPAs and by adding renewable energy. We call this approach Green Blend and Extend. With this strategy, we leverage our existing platforms, contracts and relationships to negotiate new long-term renewable PPAs with higher returns than we would otherwise achieve through a bidding process. We see potential opportunities to execute this strategy across many of our markets, including Chile, Mexico and the United States.
In Hawaii, we are delivering pioneering solar plus storage facilities, which will serve baseload energy needs, including satisfying demand with renewable power 24 hours a day, seven days a week.
We have two LNG regasification terminals in Central America and the Caribbean, with a total of 150 TBTU of LNG storage capacity. These terminals were built to supply not only the gas for our co-located combined cycle
plants, but also to meet the growing demand for natural gas in the region.
In Panama, the storage tank at our recently inaugurated Colon power plant and regasification terminal is expected to come on-line in mid-2019. We believe there is significant potential upside associated with increasing utilization beyond the requirements of our co-located power plant.
As a result of our efforts to decrease our exposure to coal-fired generation and increase our portfolio of renewables, energy storage and natural gas capacity, we are significantly reducing our carbon dioxide emissions per MWh of generation. Under our current strategy, we anticipate a reduction of carbon intensity levels of 50% from 2016 to 2022 and of 70% from 2016 to 2030.
We are a leader in deploying new technologies, such as battery-based energy storage, drone applications and digital customer interfaces. The Company's energy storage joint venture with Siemens, Fluence, has now delivered or been awarded 80 projects in 18 countries, with a total capacity of 766 MW.
Strategic Highlights
We continue to improve the returns from our existing portfolio and position AES for long-term, sustainable growth.
In 2018, the Company paid down $1 billion in Parent debt
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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 |
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| ◦ | 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
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| ◦ | Once these sales close, AES' ownership in sPower's operating portfolio will decrease from 50% to 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
In 2018, Fluence was awarded 286 MW of new projects
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(1) | Investments in subsidiaries excludes $2.2 billion investment in 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 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)— 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, mentioned above, 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. For
The following table summarizes our generation and utility businesses by capacity, number of facilities, utility customers and utility GWh sold.within our four SBUs.
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| SBU | | Business Line | | Generation Capacity (Gross MW) | | Generation Facilities | | Utility Customers | | Utility GWh | | Utility Businesses |
US — | | Generation | | 5,604 |
| | 18 |
| | | | | | |
| | | Utilities | | 6,524 |
| | 16 |
| | 1.0 million | | 34,797 |
| | 2 |
|
Andes — | | Generation | | 8,141 |
| | 33 |
| | | | | | |
Brazil — | | Generation | | 3,298 |
| | 13 |
| | | | | | |
| | | Utilities | | | | | | 8.2 million | | 56,861 |
| | 2 |
|
MCAC — | | Generation | | 3,239 |
| | 16 |
| | | | | | |
| | | Utilities | | | | | | 1.3 million | | 3,754 |
| | 4 |
|
Europe — | | Generation | | 6,781 |
| | 12 |
| | | | | | |
Asia — | | Generation | | 2,290 |
| | 3 |
| | | | | | |
| | | | | 35,876 |
| (1) | 111 |
| | 10.5 million | | 95,412 |
| | 8 |
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(1)
| 26,912 proportional MW. Proportional MW is equal to gross MW of a generation facility multiplied by AES' equity ownership percentage in such facility. |
Strategy
In September 2011, we implemented a new strategy to maximize value for our shareholders and over the last four years we have made significant progress towards our goals by executing on the following pillars:
Reducing Complexity. By exiting businesses and markets where we do not have a competitive advantage, we have simplified our portfolio and reduced risk. Over the past four years, we have sold assets to generate $3.4 billion in equity proceeds for AES, decreasing the total number of countries where we have operations from 28 to 17. We exited Sri Lanka early in 2016, by selling our generation business, Kelanitissa, for $18 million. We exited several of these markets, including Ukraine, Turkey and Africa, at opportune times, as risks for these businesses have increased since the sales, which we believe would have adversely impacted the valuations of such businesses. In 2015, we announced or closed $787 million in asset sales proceeds.
Leveraging Our Platforms. We are focusing our growth on platform expansions in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns. We currently have 5,620 MW under construction. These projects represent $7 billion in total capital expenditures, with 85% of AES' $1.2 billion in equity already funded, and we expect the majority of these projects to come on-line through 2018. In 2015, we brought on-line five projects for a total of 1,484 MW. This capacity includes the 1,240 MW coal-fired Mong Duong 2 facility in Vietnam, which we completed six months early and under budget.
Performance Excellence. We strive to be a low-cost manager of a portfolio of international energy assets and to derive synergies and scale from our businesses. In 2011, we set a goal to reduce our G&A expenses by $200 million by 2015, and in 2014, we achieved these reductions one year early. We recently launched a $150 million cost reduction and revenue enhancement initiative. This initiative will include overhead reductions, procurement efficiencies and operational improvements. We expect to achieve at least $50 million in savings in 2016, ramping up to $150 million, including modest revenue enhancements, in 2018.
Expanding Access to Capital. We have raised $2.5 billion in proceeds to AES by building strategic partnerships at the project and business level. Through these partnerships, we aim to optimize our risk-adjusted returns in our existing businesses and growth projects. By selling down portions of certain businesses, we can adjust our global exposure to commodity, fuel, country and macroeconomic risks. Partial sell-downs of our assets can serve to highlight the value of businesses in our portfolio.
Allocating Capital in a Disciplined Manner. Our top priority is to maximize risk-adjusted returns to our shareholders, which we achieve by investing our discretionary cash and recycling the capital we receive from asset sales and strategic partnerships. To that end, since September 2011 we have repurchased $1.5 billion of our shares and benefited from a low interest rate environment, by transacting on $24 billion in debt deals at the Parent and our subsidiaries. These debt transactions represent $14 billion in refinancing and $10 billion in new financing, and we extended the maturities on $3.4 billion in Parent debt.
Note: Investments in subsidiaries excludes $2.3 billion investment in DPL.
Most recently, we increased our quarterly dividend by 10% to $0.11 per share beginning in the first quarter of 2016. This dividend increase reflects our expectation that we will maintain 10% annual growth in our dividend.
Generation
We currently own and/or operate a generation portfolio of 29,35231,792 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, sourcing 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 7 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 including debt and return on capital invested. Although ourdebt. Our project debt may consist of both fixed and floating rate debt for which we typically hedge a significant portion of our exposure to variable interest rates. For foreign exchange, we generally structure the revenue of the business to match the currency of the debt and fixed costs.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 and Short-Term Sales — 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%
37% 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%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.
28%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.
5%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 8,145 MW (4,237 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. See Item 7.—Management's Discussion and Analysis—Key Trends and Uncertainties of this Form 10-K for further details of the impact of dry hydrological conditions. 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 operating and maintenanceO&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' eightsix utility businesses distribute power to 10.52.4 million people in threetwo countries. AES' two utilities in the U.S. also include generation capacity totaling 6,5244,102 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 on 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 a 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, such asutility, 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.
Environmental Matters
We are subject to various international, federal, state, and local regulations in all of our markets. These regulations 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.
We are also subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, suspension or revocation of permits and/or facility shutdowns. See later in Item 1.—Business—Environmental and Land-Use Regulations for further regulatory and environmental discussion.
SBUs
All SBUs include generation facilities and three include utility businesses. The Company measures the operating performance of its SBUs using Adjusted PTC and Proportional Free Cash Flow, both of which are non-GAAP measures (see definitions below).
AES' primary sources of Revenue, Operating Margin, Adjusted PTC and Proportional Free Cash Flow are from generation and utility businesses. The Adjusted PTC and Proportional Free Cash Flow by SBU for the year ended December 31, 2015 are shown below. The percentages for Adjusted PTC are the contribution by each SBU to the gross metric, i.e., the total Adjusted PTC by SBU, before deductions for Corporate. See Item 8.—Financial Statements and Supplementary Data of this Form 10-K for reconciliation.
In 2015, approximately 80% of Adjusted PTC and Proportional Free Cash Flow was contributed by our businesses in the Americas — including the US, Andes, Brazil and MCAC SBUs.
We define Adjusted PTC as pretax income from continuing operations attributable to AES excluding gains or losses due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt. Adjusted PTC in each SBU includes the effect of intercompany transactions with other SBUs other than interest and charges for certain management services.
We define Proportional Free Cash Flow as cash flows from operating activities excluding capital expenditures related to service concession assets, less maintenance and non-recoverable environmental capital costs, adjusted for the estimated impact of noncontrolling interests. Proportional Free Cash Flow in each SBU includes the effect of intercompany transactions with other SBUs except for interest, tax sharing, charges for management fees and transfer pricing.
Our Organization and Segments
The segment reporting structure uses the Company's management reporting structure as its foundation to reflect how the Company manages the business internally andinternally. It is organized by geographic regions which provide bettera socio-political-economic understanding of our business. The management reporting structure is organized along six SBUs — US, Andes, Brazil, MCAC, Europe, and Asia — which are led by our SBU Presidents.
Corporate and Other — For financial reporting purposes, the Company's corporate activities are reported within "Corporate and Other" because they do not require separate disclosure under segment reporting accounting guidance. "Corporate and Other" also includes costs related to corporate overhead which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.disclosure. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 17—15—Segment and Geographic Information included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion of the Company's segment structure (including information on revenue from external customers, Adjusted PTC—a non-GAAP measure, Proportional Free Cash Flow—a non-GAAP measure, and total assets by segment) used for financial reporting purposes.structure.The following describes our businesses within our six SBUs:
US AND UTILITIES SBU
Our US and Utilities SBU has 1829 generation facilities, and two integrated utilities in the United States. Our U.S. operations accounted for the following proportions of consolidated AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow,States, and AES Proportional Free Cash Flow (a non-GAAP measure):four utilities in El Salvador.
|
| | | | | | | | |
US SBU (1) | 2015 | | 2014 | | 2013 |
| % of AES Operating Margin | 22 | % | | 23 | % | | 21 | % |
| % of AES Adjusted PTC (a non-GAAP measure) | 23 | % | | 24 | % | | 24 | % |
| % of AES Operating Cash Flow | 34 | % | | 37 | % | | 28 | % |
| % of AES Proportional Free Cash Flow (a non-GAAP measure) | 36 | % | | 46 | % | | 37 | % |
(1) Percentages reflect the contributions by our US SBU before deductions for Corporate.
The following table provides highlights of our US operations:
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| | |
Generation Capacity | | 12,128 gross MW (11,260 proportional MW) |
Generation Facilities | | 19 (1 under construction) |
Key Generation Businesses | | Southland, Hawaii and US Wind |
Utilities Penetration | | 1,002,000 customers (31,112 GWh) |
Utility Businesses | | 2 integrated utilities (includes 18 generation plants, 4 under construction) |
Key Utility Businesses | | IPL and DPL |
Generation — Operating installed capacity of our US and Utilities SBU totals 12,12811,574 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. Presented in theThe following table below is a list oflists our U.S.US and Utilities SBU generation facilities:
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| | | | | | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Ownership (% Rounded) | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| Southland—Alamitos | | U.S.-CA | | Gas | | 2,075 |
| | 100 | % | | 1998 | | 2018 | | Southern California Edison |
| Southland—Redondo Beach | | U.S.-CA | | Gas | | 1,392 |
| | 100 | % | | 1998 | | 2018 | | Southern California Edison |
| Southland—Huntington Beach | | U.S.-CA | | Gas | | 474 |
| | 100 | % | | 1998 | | 2018 | | 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 |
| Hawaii | | U.S.-HI | | Coal | | 206 |
| | 100 | % | | 1992 | | 2022 | | Hawaiian Electric Co. |
| Warrior Run | | U.S.-MD | | Coal | | 205 |
| | 100 | % | | 2000 | | 2030 | | First Energy |
Buffalo Gap III(1) | | U.S.-TX | | Wind | | 170 |
| | 100 | % | | 2008 | | | | |
Buffalo Gap I(1) | | U.S.-TX | | Wind | | 121 |
| | 100 | % | | 2006 | | 2021 | | Direct Energy |
| Laurel Mountain | | U.S.-WV | | Wind | | 98 |
| | 100 | % | | 2011 | | | | |
Mountain View I & II(1) | | U.S.-CA | | Wind | | 67 |
| | 100 | % | | 2008 | | 2021 | | Southern California Edison |
Distributed PV - Commercial(3) | | U.S.-Various | | Solar | | 56 |
| | 80%-97% |
| | 2009-2015 | | 2029-2041 | | Utility, Municipality, Education, Non-Profit |
| Mountain View IV | | U.S.-CA | | Wind | | 49 |
| | 100 | % | | 2012 | | 2032 | | Southern California Edison |
| Tehachapi | | U.S.-CA | | Wind | | 35 |
| | 100 | % | | 2006 | | 2016 | | Southern California Edison |
| Laurel Mountain ES | | U.S.-WV | | Energy Storage | | 32 |
| | 100 | % | | 2011 | | | | |
| Tait ES | | U.S.-OH | | Energy Storage | | 20 |
| | 100 | % | | 2013 | | | | |
Distributed PV - Residential(3) | | U.S.-Various | | Solar | | 9 |
| | 95 | % | | 2012-2015 | | 2037-2040 | | Residential |
| Advancion Applications Center | | U.S.-PA | | Energy Storage | | 2 |
| | 100 | % | | 2013 | | | | |
| | | | | | | 5,604 |
| | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| Business | | 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 |
| | | | | | | | |
| Southland—Alamitos | | US-CA | | Gas | | 2,075 |
| | 100 | % | | 1998 | | 2019-2020 | | Southern California Edison |
| Southland—Redondo Beach | | 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 | | US-CA | | Gas | | 474 |
| | 100 | % | | 1998 | | 2019-2020 | | Southern California Edison |
Shady Point (2) | | US-OK | | Coal | | 360 |
| | 100 | % | | 1991 | |
| |
|
Buffalo Gap II (3) | | US-TX | | Wind | | 233 |
| | 100 | % | | 2007 | |
| |
|
| Hawaii | | US-HI | | Coal | | 206 |
| | 100 | % | | 1992 | | 2022 | | Hawaiian Electric Co. |
| Warrior Run | | US-MD | | Coal | | 205 |
| | 100 | % | | 2000 | | 2030 | | First Energy |
Buffalo Gap III (3) | | US-TX | | Wind | | 170 |
| | 100 | % | | 2008 | |
| |
|
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 | | US-WV | | Wind | | 98 |
| | 100 | % | | 2011 | |
| |
|
| Mountain View I & II | | US-CA | | Wind | | 65 |
| | 100 | % | | 2008 | | 2021 | | Southern California Edison |
| Mountain View IV | | 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 |
| | | | |
| Ilumina | | US-PR | | Solar | | 24 |
| | 100 | % | | 2012 | | 2032 | | Puerto Rico Electric Power Authority |
| Laurel Mountain ES | | US-WV | | Energy Storage | | 16 |
| | 100 | % | | 2011 | |
| |
|
| AES Gilbert (Salt River) | | US-AZ | | Energy Storage | | 10 |
| | 100 | % | | 2019 | | 2039 | | Salt River Project Agricultural Improvement and Power District |
| Warrior Run ES | | US-MD | | Energy Storage | | 5 |
| | 100 | % | | 2016 | |
| |
|
| United States Subtotal | | | | | | 7,420 |
| | | | | | | | |
| | | | | | | 7,472 |
| | | | | | | | |
_____________________________
| |
(1) | Unconsolidated entity, accounted for as an equity affiliate. |
| |
(2) | Announced the sale of this business in December 2018. |
| |
(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. |
| |
(2)
| Power Purchase Agreement with Direct Energy is for 80% of annual expected energy output. |
| |
(3)
| AES operates these facilities located throughout the U.S. through management or O&M agreements as of 12/31/15. |
Under construction — The following table lists our plants under construction in the US and Utilities SBU:
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest (% Rounded) | | Expected Date of Commercial Operations |
IPL MATS (1) | | U.S.-IN | | Coal | | 1,713 |
| | 75 | % | | 1H 2016 |
Eagle Valley CCGT (1) | | U.S.-IN | | Gas | | 671 |
| | 75 | % | | 1H 2017 |
Harding Street Units 5-7 (1) | | U.S.-IN | | Gas | | 630 |
| | 75 | % | | 1H 2016 |
Harding Street ES (1) | | U.S.-IN | | Energy Storage | | 20 |
| | 75 | % | | 1H 2016 |
| Warrior Run ES | | U.S.-MD | | Energy Storage | | 10 |
| | 100 | % | | 1H 2016 |
| US Total | | | | | | 3,044 |
| | | | |
|
| | | | | | | | | | | | |
| 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 utilities and their generation facilities.
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| | | | | | | | | | | | | | | | | | |
| Business | | 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 | | 1,397,000 |
| | 3,789 |
| | | | | | | | |
DPL (1) | | US-OH | | 525,000 |
| | 7,139 |
| | Coal | | 129 |
| | 100 | % | | 2011 |
IPL (2) | | US-IN | | 498,000 |
| | 15,092 |
| | Coal/Gas/Oil | | 3,973 |
| | 70 | % | | 2001 |
| United States Subtotal | | 1,023,000 |
| | 22,231 |
| | | | 4,102 |
| | | | |
| | | | | 2,420,000 |
| | 26,020 |
| | | | | | | | |
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(1) | In the first quarter of 2015, La Caisse de depot et placement du Quebec ("CDPQ") invested $247 million for a 15%DPL's subsidiary, AES Ohio Generation, LLC, owned an undivided interest in AES US Investments, Inc. (AES US Investments), a subsidiaryConesville Unit 4. In October 2018, the co-owner of AES that owns IPALCO Enterprises, Inc. ("IPALCO"). In the second quarter of 2015, CDPQ invested an additional $214 million and we expect CDPQ to invest an additional $134 million in IPALCO by 2016. After completion of this investment, CDPQ's direct and indirect interests in IPALCO will total 30%, AES will own 85% of AES US Investments, and AES US Investments will own 82.35% of IPALCO. |
Presented below are our U.S. utilities and their generation facilities:
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| Business | | Location | | Approximate Number of Customers Served as of 12/31/2015 | | GWh Sold in 2015 | | Fuel | | Gross MW | | AES Equity Interest (% Rounded) | | Year Acquired or Began Operation |
DPL(1) | | U.S.-OH | | 517,000 |
| | 16,714 |
| | Coal/Gas/Oil | | 3,066 |
| | 100 | % | | 2011 |
IPL(2) | | U.S.-IN | | 485,000 |
| | 14,398 |
| | Coal/Gas/Oil | | 3,458 |
| | 75 | % | | 2001 |
| | | | | 1,002,000 |
| | 31,112 |
| | | | 6,524 |
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(1)
| DPL subsidiary DP&L has the following plants: Tait Units 1-3 and diesels, Yankee Street, Yankee Solar, Monument and Sidney. DP&L jointly owned plants: Conesville Unit 4 Killen, Miami Fort Units 7 & 8, Stuart and Zimmer. In addition 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&L’s share of this generation capacity is approximately 103 MW. DPL Energy, LLC plants: Tait Units 4-7DPL's GWh sold in 2018 represent DPL's wholesale revenues and Montpelier Units 1-4.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. |
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(2) | In the first quarter of 2015, CDPQ invested $247 million for a 15% interest in AES US Investments, Inc. (AES US Investments), a subsidiary of AES that owns IPALCO. In the second quarter of 2015, CDPQ invested an additional $214 million and we expect CDPQ to invest an additional $134 million in IPALCO by 2016. After completion of this investment, CDPQ's direct and indirect interests in IPALCO willwhich total approximately 30%,. AES will ownowns 85% of AES US Investments and AES US Investments will ownowns 82.35% of IPALCO. IPL plants: Eagle Valley, Georgetown, Harding Street, Petersburg and Petersburg.Eagle Valley. 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 485,000 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 934,000.950,000. IPL owns and operates four generating stations. Twostations, all within the state of theIndiana. IPL’s largest generating stations are primarily coal-fired; however, one of these stationsstation, Petersburg, is in the process of being converted tocoal-fired. The second largest station, Harding Street, uses natural gas and will be fully converted in 2016.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, hasEagle Valley, is a combination of units that use coal (baseload capacity),newly constructed 671 MW CCGT natural gas and/or oil (peaking capacity) for fuel to produce electricity.plant. IPL took operational control and commenced commercial operations of this CCGT plant in April 2018. The fourth station, Georgetown, is a small peaking station that uses gas-firednatural gas to power combustion turbine technology for the production of electricity. IPL's net electric generation capacity for winter is 3,233 MW and net summer capacity is 3,115 MW.turbines.
On December 15, 2014,October 31, 2018, the Company executedIURC issued an order approving an uncontested settlement agreement to increase IPL's annual revenues by $44 million, or 3% (the "2018 Rate Order"). The 2018 Rate Order primarily includes recovery through rates of costs associated with CDPQ, a long-term institutional investor headquartered in Quebec, Canada. Pursuant to the agreement, CDPQ purchased 15% of AES US Investments, Inc. ("AES US Investments"), a wholly-owned subsidiary of AES that owns 100% of IPALCO, for $247 million. This transaction closed on February 11, 2015. In addition, in April 2015, IPALCO received an equity capital contribution of $214 million from the issuance of 11,818,828 shares of common stock to CDPQ for funding needs primarily related to IPL's environmental construction program, which IPALCO then made the same investment in IPL. After the April investment, CDPQ's direct and indirect ownership interests in IPALCO totaled 25%. CDPQ has committed to approximately $134 million of additional investments in IPALCO through 2016, which will be used primarily to help fund existing environmental and replacement generation projectsCCGT at IPL. Upon completion of these transactions, CDPQ's direct and indirect interests in IPALCO will total 30%, AES will own 85% of AES US Investments, and AES US Investment will own 82.35% of IPALCO. There will be no change in management or operational control of AES US Investments or IPALCO as a result of these transactions.
Market Structure — IPL is one of many transmission system owner membersEagle Valley, completed in the MISO. MISO is a RTO, which maintains functional control over the combined transmission systemsfirst half 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 constraints2018, 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 basicconstruction projects. New base rates and charges which are set and approved by the IURC after public hearings.became effective on December 5, 2018. The IURC gives consideration to all allowable costs for ratemaking purposesorder also provides customers with approximately $50 million in benefits, 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 ECCRA. 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. IPL's basic rates and charges were last adjusted in 1996; however, IPL filed a petitiontax reform benefits associated with the IURC on December 29, 2014 for authority to increase its basic rates and charges. IPL's proposed rate increase, filed as part of IPL's rebuttal testimony in this proceeding, is $63.3 million, or 5.2%. An order on this proceeding will likely be issued by the IURC early in 2016.
Environmental Matters — MATS — In April 2012, the EPA's rule to establish maximum achievable control technology standards for each hazardous air pollutant regulated under the CAA emitted from coal and oil-fired power plants, known as MATS, became effective.On August 14, 2013, the IURC approved IPL's MATS plan, which includes investing up to $511 million in the installation of new pollution control equipment on IPL's five largest baseload generating units. These coal-fired units are located at IPL's Petersburg and Harding Street generating stations. The IURC also approved IPL's request to recover operating and construction costs for this equipment, includingTCJA, over a return,two-year period through a rate adjustment mechanism with certain stipulations. Funding for these capital expenditures is expected to be obtained from additional debt financing at IPL; equity contributions; borrowing capacitybeginning in March 2019.
Environmental Regulation — For information on IPL's committed credit facilities; and cash generated from operating activities.
Replacement Generation — IPL has several generating units that are expected 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, 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 (approximately 100 MW net capacity each). In May 2014, IPL received an order on the CPCN from the IURC 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 requested and 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 of the CCGT and refueling projects. The CCGT is expected to be placed into service in April 2017, and the refueling project is expected to be completed by early 2016. 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. In October 2014, IPL filed a petition and case-in-chief with the IURC seeking a CPCN to refuel Harding Street Station Unit 7 from coal to natural gas (about 410 MW net capacity). On July 29, 2015 IPL received approval for this CPCN from the IURC. This conversion is part of IPL's overall wastewater compliance plan for its power plants and is expected to be completed in 2016 (as discussed in Environmental Wastewater Requirements below).
Environmental Wastewater Requirements — In August 2012, the IDEM issued NPDES permits to the IPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. In April 2013, IPL received an extension to the compliance deadline through September 2017 for IPL's Harding Street and Petersburg facilities through agreed orders with IDEM. IPL conducted studies to determine the operational changes and/or control equipment necessary to comply with the new limitations. On October 16, 2014, IPL filed its wastewater compliance plans with the IURC. On July 29, 2015, IPL received approval for a CPCN from the IURC to convert Unit 7 at the Harding Street Station from coal-fired to natural gas-fired, and also to install and operate wastewater treatment technologies at Harding Street Station and Petersburg Generation Station in southern Indiana. IPL plans to invest $326 million in these projects to help ensure compliance with the wastewater treatment requirements by 2017. Recovery of these costs is expected through an Indiana statute which 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 basic rate case proceeding; however, there can be no assurances that IPL would be successful in that regard.environmental regulations see Item 1.—United States Environmental and Land-Use Legislation and Regulations.Key Financial Drivers —IPL's financial results are driven primarily by retail demand, weather, and rate base growth. Retail demand is influenced by local macroeconomic conditions.outage costs. In addition, weather, energy efficiency and wholesale prices could also impactIPL's financial results. IPL's rate base growth is influencedresults are likely to be driven by many factors, including, but not limited to:
regulatory outcomes;
the passage of new legislation, implementation of regulations or other changes in regulation;
timely recovery of capital expenditures, as well as passage of new legislation or implementation of regulations.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. Please see aboveAdditionally, IPL is currently evaluating future investments under the Transmission, 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 Inc. ("DPL")
Business Description Regulatory Framework and Market Structure — DPL is an energy holding company whose principal subsidiaries include DP&L DPLE, and DPLER.
DP&L generates, transmits, distributes and sells electricity to approximately 517,000 customers in a 6,000 square mile areaAES Ohio Generation, LLC, both of West Central Ohio. DP&L, solely or through jointly owned facilities, owns 2,510 MW of generation capacity and numerous transmission facilities.
DPLE owns peaking generation units representing 556 MW located in Ohio and Indiana.
DPLER, a competitive retail marketer, sells retail electricity to more than 124,000 retail customers in Ohio and Illinois. Approximately 110,000 of these customers are also distribution customers of DP&Lwhich operate in Ohio. On January 1, 2016, DPL closed on the sale of DPLER to Interstate Gas Supply, Inc. (IGS).
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 had the obligation to supply retail generation service to customers that do not choose an alternative supplier. Beginning in 2014, a portion of therates. The SSO generation supply is no longer supplied by DP&L but is provided by third parties through a competitive bid process. A total of 10%Ohio utilities have the exclusive right to provide transmission and 60% of the SSO load was sourced through competitive biddistribution services in 2014 and 2015, respectively, and 100% will be sourced in this manner beginning in 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.
PJM Operations — 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 Capacity Price ("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 certain 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 the potential exists 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, 2019 through May 30, 2020 are expected to take place in May 2016. 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 2018/19 are as follows:
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| Auction Year (June 01-May 31) | | 2018/19 | | 2017/18 | | 2016/17 | | 2015/16 | | 2014/15 | | 2013/14 |
| Capacity Clearing Price ($/MW-Day) | | $165 | | $152 | | $134 | | $136 | | $126 | | $28 |
The computed average capacity prices by calendar year are as follows:
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| Year | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Computed Average Capacity Price ($/MW-Day) | | $159 | | $145 | | $135 | | $132 | | $85 |
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.
According to the terms of DP&L's RPM rider, a portion of the capacity revenue is credited to SSO customers primarily based on the load still being served to the SSO customers. However, with the transition to market, no amount will be credited beginning January 1, 2016.
Regulatory Framework — Retail Regulation — 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, those to reflect changes in fuel costs to generate electricity or purchased power prices, and 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.
Retail Rate Structure — 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 Electric Security Plan ("ESP") filing. DP&L's wholesale transmission rates are regulated bythrough a competitive bid process for the FERC.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.
The terms and conditions of DP&L's currentrates 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 FERC.
DP&L is 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 members.
Business Description — DP&L transmits, distributes and sells electricity to retail customers in a 6,000 square mile area of West Central Ohio. Ohio consumers have the right to choose the electric generation supplier from whom they purchase retail generation service; however, retail transmission and distribution services are still regulated. DP&L has the exclusive right to provide such transmission and distribution services to those customers. Additionally, DP&L procures retail SSO are provided under the ESP filed in 2012electric service on behalf of residential, commercial, industrial and approved bygovernmental customers.
In September 2018, DP&L received an order from the PUCO order dated September 4, 2013 ("2012 ESP"). The 2012 ESP has been in effect since January 2014 and allows DP&L to collect a non-bypassable Service Stability Rider ("SSR") equal to $110 million per year from 2014 - 2016. It allowedestablishing new base distribution rates for DP&L to recover its PJM-related transmission charges, alternative energy costs, fuel(“the order”), which became effective October 1, 2018. The order approved, without modification, a stipulation and purchased power costs, and established a SEET ("Significant Excessive Earnings Test") threshold of 12% ROE. It also requiredrecommendation previously filed by 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. Beginning January 1, 2016 DP&L's SSO will be 100% sourced through the competitive bid. For calendar years 2012 - 2014, DP&L was subject to a SEET threshold and was required to apply general rules for calculating earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings during a given calendar year. Through the 2012 ESP, the PUCO established DP&L's ROE SEET threshold at 12%. On May 15, 2014, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2013. A stipulation was reachedalong with various intervening parties, with the PUCO staff agreeing thatstaff. The order established a revenue requirement of $248 million for DP&L did not exceed the SEET threshold for 2014. A hearing was held and the PUCO issued an order approving the SEET stipulation. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows.
On October 30, 2015 DP&L publicly announced its intent to file an application to increase its&L's electric service base distribution rates, at the PUCO. On November 30, 2015 DP&L filed its 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 seekingwhich reflects an increase to distribution revenues of $66$30 million per year. The Company has asked for recovery of certain regulatory assets as well as two new riders that would allowIn addition, the Companyorder authorizes DP&L to recover certaincollect from customers costs on an ongoing basis. It has proposedrelated to qualified investments through a modified straight-fixed variable rate design in an effort to decouple distribution revenues from electric sales. If approved as filed the rates are expected to have a total bill impact of approximately 4% on a typical residential customer.
On February 22, 2016 DP&L filed an ESP that would be in effect beginning January 1, 2017. As part of this filing, DP&L is seeking a Reliable Electricity Rider for 10 years, based on the variance between the proposed revenue requirement and the actual revenues net of operating costs of the generation units. This plan establishes the terms and conditions for DP&L's Standard Service Offer (SSO) beginning June 1, 2017 to customers that do not choose a competitive 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 $10 million of regulatory assets. The plan also proposes a new Distribution Investment Rider, changes the Decoupling Rider to allowreduce variability from the impact of weather and demand, partially resolves regulatory issues related to the TCJA, and authorizes DP&L to recoverdefer certain vegetation management costs associatedfor future collection.
In January 2019, DP&L filed a request with future distribution equipmentthe 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 request was made pursuant to the PUCO’s October 2017 ESP order, which approved the DMR and infrastructure needs. Additionally, the plan establishes new ridersoption for DP&L to file for a two-year extension. The extension request is set initially at zero, relateda level expected to energy reductions fromreduce debt obligations at both DP&L's energy efficiency programs, and certain environmental liabilities the Company may incur. There can be no assurance that the ESP will be approved as filed or on a timely basis, and if the ESP is not approved on a timely basis or the final ESP provides for terms that are more adverse than those submitted in DP&L’s application, the Company's consolidated results of operations, financial condition and cash flows could be materially impacted.
Environmental Matters — In relation to MATS, 3,066 MW of DPL's generation capacity is largely compliant with MATS,&L and DPL does not expectand to incur materialposition DP&L to make capital expenditures to ensuremaintain and modernize its electric grid.
Key Financial Drivers — Although recent ESPDPL's financial results are primarily driven by customer growth. Following the issuance of the distribution rate order in September 2018 and Generation Separation decisions provide some clarity on the underlying drivers through 2016, challenges remain for DPL beyond 2016 includingresulting changes to the potential impacts ofdecoupling 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, through 2016, DPLDPL's financial results are likely to be driven by many factors, including, but not limited to, to:
the following:passage of new legislation, new regulations or other changes in regulation;
PJM capacity prices auctioned alreadytimely recovery of transmission and distribution expenditures; and
Non-bypassable revenue: $110 million in 2014 and 2015 and allowed to earn $110 million annually in 2016
Operational performance of generation facilities
Beyond 2016, DPL financial drivers include many factors, such as the following:
PJM capacity prices
Recovery in the power market, particularly as it relates to an expansion in dark spreads
Sale or transfer to a DPL affiliate of DP&Lexiting generation assets currently owned by AES Ohio Generation.
DPL's ability to reduce its cost structure
See Item 1A.—Risk Factors for additional discussion on DPL.
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 $439$628 million inon capital projects for the period 20162019 through 2018 with 61% 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 WECC,Western Electric Coordinating Council, PJM, SPPSouthwest Power Pool Electric Energy Network and Hawaii. AES Southland, in the WECC,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 expiresthat expired on May 31, 2018. Currently, AES Huntington Beach, LLC and AES Alamitos, LLC are contracted though Resource Adequacy Purchase Agreements (the “RAPAs”), approved by the California Public Utilities Commission in mid-2018. 2017. AES Redondo Beach, LLC has also entered into various RAPAs for the period of June 1, 2018 through December 31, 2020.
Under the Tolling Agreement, AES Southland's largest revenue driver is unit availability, as approximately 97% of its revenue comes from availability-related payments. Historically, AES Southland has generally metRAPAs, the generating stations provide resource adequacy capacity, and have no obligation to produce or exceeded its contractual availability requirements under the Tolling Agreement and may capture bonuses for exceeding availability requirements in peak periods.
The offtaker under the Tolling Agreement provides gassell any energy to the three facilities at no cost; therefore, AES Southland is not exposedRAPA counterparty. However, the generating stations are required to significant fuel price risk. AES Southland does, however, guarantee the efficiency of each unit so that any fuel consumed in excess of what would have been consumed had the guaranteed efficiency been achieved is paid for by AES Southland. Additionally, if the units operate at an efficiency better than the guaranteed efficiency, AES Southland gets credit for the gas that is not consumed. The business is also exposed to the cost of replacement power for a limited time period if any of the plants are dispatched by the offtaker and are not able to meet the required dispatch schedule for generation of electric energy.
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.
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 unmatched operational flexibility, enablingput options. If the most
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 finalized in 2016 with construction expected to begin in 2017,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.
Regulatory Framework — Environmental Matters — For a discussion of environmental regulatory matters affecting U.S. Generation, see Item 1.—United States Environmental and Land-Use Legislation and Regulations.
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 thermalRegulatory Framework and wind generating facilities, of which AES Hawaii and our U.S. wind generation business are the most significant.
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 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 GNPIPD. 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.
US Wind — AES has 773 MW of wind capacity in the U.S., located in California, Texas and West Virginia. In July 2015, AES sold its interest in Armenia Mountain, a wind project located in Pennsylvania with an installed capacity of 101 MW. 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 524 MW. Each wind project operates its own PPA with the exception of Buffalo Gap III whose PPA expired in December 2015. 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.
Market Structure — Coal is one ofFor the non-renewable businesses, coal and natural gas are used as the primary fuels used by our U.S. generation facilities that has internationalfuels. Coal prices are set by market factors although the price of the other primary fuel,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 EWGExempt 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.OurBusiness Description — Additional businesses include thermal, wind, and solar generating facilities, of which our U.S. Renewables businesses and AES Hawaii are subjectthe most significant.
U.S. Renewables
sPower owns and/or operates 153 utility and distributed electrical generation systems with a capacity of 1,221 MWh currently in operation across the U.S. sPower is also actively buying, developing and constructing renewable assets in the U.S.
AES Distributed Energy develops, constructs and sells electricity generated by photovoltaic solar energy systems and energy storage systems to emission regulations,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 increased operating costs orvariability 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 ofcommitments through December 2019 and plans to seek additional pollution control equipment if emission levels are exceeded. Our businesses periodically review their obligations for compliance with environmental laws, including site restoration and remediation. Because of the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued, if any. For a discussion of environmental laws and regulations affecting the U.S. business, see Item 1.—USEnvironmental and Land-Use Legislation and Regulations.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 USU.S. Wind are primarily driven by increased production due to faster and less turbulent wind and reduced turbine outages. In addition, PJM and ERCOT power prices impact financial results for the wind projects that are operating without long-term contracts for all or some of their capacity. The financial results of U.S. Solar are primarily driven by the amount of sunshine hours available at the facilities, cell maintenance and growth in projects. For additional details see Key Trends and Uncertainties in Item 7.— Management’s Discussion and Analysis of Financial Condition and Results of Operations. 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
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.
Our Andes operations accounted for the following proportions of consolidated Tietê is a publicly traded company in Brazil. AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow,controls and AES Proportional Free Cash Flow (a non-GAAP measure):
|
| | | | | | | | |
Andes SBU (1) | 2015 | | 2014 | | 2013 |
| % of AES Operating Margin | 22 | % | | 19 | % | | 17 | % |
| % of AES Adjusted PTC (a non-GAAP measure) | 30 | % | | 23 | % | | 19 | % |
| % of AES Operating Cash Flow | 18 | % | | 16 | % | | 11 | % |
| % of AES Proportional Free Cash Flow (a non-GAAP measure) | 14 | % | | 13 | % | | 10 | % |
(1) Percentages reflect the contributions by our Andes SBU before deductions for Corporate.
The following table provides highlights of our Andes operations:
|
| | |
Countries | | Chile, Colombia and Argentina |
Generation Capacity | | 8,141 gross MW (6,008 proportional MW) |
Generation Facilities | | 38 (including 5 under construction) |
Key Generation Businesses | | AES Gener Chile, Chivor and AES Argentina |
consolidates Tietê through its 24% economic interest.Operating installed capacity of our AndesSouth America SBU totals 8,14112,435 MW, of which 44%33%, 44%28%, 8%, and 12% is31% are located in Argentina, Chile, Colombia and Colombia,Brazil, respectively. Presented in theThe following table below is a list oflists our AndesSouth America SBU generation facilities:
| | | Business | | Location | | Fuel | | Gross MW | | AES Equity Interest (% Rounded) | | 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 Subtotal | | 1,000 |
| | | | | 1,020 |
| | | |
Electrica Santiago(1) | | Chile | | Gas/Diesel | | 750 |
| | 67 | % | | 2000 | | |
Gener - SIC(2) | | Chile | | Hydro/Coal/Diesel/Biomass | | 692 |
| | 67 | % | | 2000 | | 2020-2037 | | Various | |
Gener - Chile (1) | | | Chile | | Coal/Hydro/Diesel/Solar/Biomass | | 1,532 |
| | 67 | % | | 2000 | | 2019-2040 | | Various |
Guacolda(3)(2) | | Chile | | Coal/Pet Coke | | 760 |
| | 33 | % | | 2000 | | 2017-2032 | | Various | | 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 |
Gener - SING(4) | | Chile | | Coal/Pet Coke | | 277 |
| | 67 | % | | 2000 | | 2016-2037 | | 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 | |
| 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 | | | 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 | | 3,613 |
| | | | | 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 | | 5,256 |
| | | | | 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 (4) | | | Argentina | | Gas/Diesel | | 576 |
| | — | % | | 2016 | |
Los Caracoles(8)(4) | | Argentina | | Hydro | | 125 |
| | — | % | | 2009 | | 2019 | | Energia Provincial Sociedad del Estado (EPSE) | | Argentina | | Hydro | | 125 |
| | — | % | | 2009 | | 2019 | | Energia Provincial Sociedad del Estado (EPSE) |
| Cabra Corral | | Argentina | | Hydro | | 102 |
| | 100 | % | | 1995 | | | Argentina | | Hydro | | 102 |
| | 100 | % | | 1995 | |
| | Various |
| Ullum | | Argentina | | Hydro | | 45 |
| | 100 | % | | 1996 | | | Argentina | | Hydro | | 45 |
| | 100 | % | | 1996 | |
| | Various |
| Sarmiento | | Argentina | | Gas/Diesel | | 33 |
| | 100 | % | | 1996 | | | Argentina | | Gas/Diesel | | 33 |
| | 100 | % | | 1996 | |
| |
|
| El Tunal | | Argentina | | Hydro | | 10 |
| | 100 | % | | 1995 | | | Argentina | | Hydro | | 10 |
| | 100 | % | | 1995 | |
| | Various |
| Argentina Subtotal | | 2,885 |
| | | | | 3,486 |
| | | |
| Andes Total | | 8,141 |
| | | | |
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 |
| | | |
_____________________________
| |
(1) | Electrica Santiago plants: Nueva Renca, Renca, Los Vientos and Santa Lidia. |
| |
(2)
| Gener - SICChile 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. |
| |
(3)(2)
| Guacolda plants:is comprised of five coal-fired units under Guacolda 1, 2, 3, 4, and 5. Unconsolidated entitiesEnergia 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%. |
| |
(4)(3)
| 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 construction — The following table lists our plants under construction in the AndesSouth America SBU:
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest (% Rounded) | | Expected Year of Commercial Operations |
| Cochrane | | Chile | | Coal | | 532 |
| | 40 | % | | 2H 2016 |
| Alto Maipo | | Chile | | Hydro | | 531 |
| | 40 | % | | 2H 2018/1H 2019 |
| Andes Solar | | Chile | | Solar | | 21 |
| | 67 | % | | 1H 2016 |
| Cochrane ES | | Chile | | Energy Storage | | 20 |
| | 40 | % | | 2H 2016 |
| Chile Subtotal | | | | | | 1,104 |
| | | | |
| Tunjita | | Colombia | | Hydro | | 20 |
| | 67 | % | | 1H 2016 |
| Colombia Subtotal | | | | | | 20 |
| | | | |
| Andes Total | | | | | | 1,124 |
| | | | |
|
| | | | | | | | | | | | |
| 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 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 3,581with 3,400 MW, excluding energy storage , and TermoAndes, andhas a market share of 17.7%approximately 14% as of December 31, 2015.2018.
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 composedprovides flexibility for the management of hydroelectric, coal, gas, dieselcontractual obligations with regulated and biomass facilities, 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 spot market energy. AES Gener has experienced significant growthconditions.
Our commercial strategy in recent years respondingChile aims to market opportunities with the completion of nine generation projects totaling approximately 1,861 MW, including the 152 MW Unit 5 of Guacolda completed in December 2015, and increasing AES Gener's installed capacity by 55% from 2006 to 2015. Additionally,maximize margin while reducing cash flow volatility. To achieve this, we are constructing an additional 1,104 MW, comprised of the 21 MW Andes Solar and 20 MW Cochrane Energy Storage in the SING, the 532 MW coal-fired Cochrane plant in the SING and the 531 MW Alto Maipo run-of-the-river hydroelectric plant in the SIC.
In Chile, we align AES Gener's contracts to reduce the risk and improve margins, contractingcontract a significant portion of their baseload capacity, currentlyour coal and hydroelectric baseload capacity under long-term contractsagreements with a diversified customer base, including both regulated and unregulated customers. AES Gener reserves its higherbase. Power plants not considered within our baseload capacity (higher variable cost units, as designated backup facilities, principally the diesel- and gas-fired units in Chile, for sales tomainly diesel) sell energy on the spot market when operating during scarce system supply conditions, such as
dry hydrological conditions and low hydrology and/or plant outages. In Chile, sales on the spot market are made only to other generation companies thatwho are members of the relevant CDECSEN at the system marginal cost.
AES Gener currently has long-term contracts, with an average termsremaining term of 13 to 16approximately 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 CPI, 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 CDECCEN 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 CNE in the semiannual node price reportNational Energy Commission and indexed to the CPI and other relevant indices.
Environmental Regulation — During November, 2015, AES successfully completed the sale of 4% interest in AES Gener S.A. through its direct shareholder Inversiones Cachagua S.p.A. ("Cachagua") through a private auction. The strategic rationale of this sale was to increase the liquidity of the AES Gener's Share2017 and its exposure on international markets. As a result of this transaction AES now owns 66.7% of AES Gener.
Market Structure — Chile has two main power systems, largely as a result of its geographic shape and size. The SIC is the largest of these systems, with an installed capacity of 15,911 MW as of December 31, 2015. The SIC serves approximately 92% of the Chilean population, including the densely populated Santiago Metropolitan Region, and represents 74% of the country's electricity demand. The SING serves about 6% of the Chilean population, representing 25% of Chile's electricity consumption, and is mostly oriented toward mining companies.
In 2015, thermoelectric generation represented 62% of the total generation in Chile. In the SIC, thermoelectric generation represents 50% 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 96% 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 flow volumes, melting snow 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 2015 hydroelectric generation represented 45% of total energy production.
Regulatory Framework — Electricity Regulation — The government entity that has primary responsibility for the Chilean electricity system is2016, the Ministry of Energy, acting directly or throughEnvironment under the CNEprevious 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. Companies that are owners of a trunk transmission system, generally high voltage transmission lines with capacity of 220 Kv and higher (with bi-directional flows and relevant number of users), cannot participate in the generation or distribution segments.
Companies in the SIC and the SING that possess generation, transmission, sub-transmission or additional transmission facilities, as well as unregulated customers directly connected to transmission facilities, are coordinated through the CDEC, which minimizes the operating costs of the electricity system, while meeting all service quality and reliability requirements. The principal purpose of the CDEC is to ensure that the most efficient electricity generation available to meet demand is dispatched to customers. The CDEC dispatches plants in merit order based on their variable cost of production which allows 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 2 MW. 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.
Other Regulatory Considerations — 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 will begin to apply in 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 will become effective by June 2015. In orderproposed 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 emission standards, AES Gener initiated investmentsdecontamination plan in Chile at its older coal facilities (Ventanas Iearly March 2019 and II and Norgener I and II, constructed between 1964 and 1997) in 2012. Aswe are currently assessing the impact of December 31, 2015, 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 equipment during 2013, spending approximately $185 million (Guacolda I, II and IV) as of December 31, 2015 with the remaining $37 million to be invested in 2016.proposed decontamination plan.
Chilean law requires everyall electricity generatorgenerators to supply a certain portion of itstheir total contractual obligations with 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. 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 ownsolar 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, regarding theMW; these emissions produced during year 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 discos do not have changeallow for the pass through of law clauses. Accordingthese costs.
Key Financial Drivers —Hedge levels at AES Gener limit volatility to its PPAs, the companyunderlying 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.
In June 2015, the Chilean government published Decree N°7/2015, which allowed energy exportation to Argentina using the transmission line which connects the SING (Chilean Northern Grid) with the SADI (Argentine Grid). The AES transmission line has a capacity of approximately 600MW, but will be operated at 200 MW according to technical studies. AES Gener signed an agreement with CAMMESA and other generators (Gas Atacama and ECL) in order to export electricity to Argentina.
Key Financial Drivers —Hedge levels at Gener provide some certainty and clarity on the underlying financial drivers through 2016. However, some risks remain through 2016, including, but not limited to, the following:
Dry hydrology scenarios reduce hydro generation (See Item 7.—Operations—Key Trends and Uncertainties— Operational—Weather sensitivity for further discussion)
Forced outages may impact earnings
Changes in current regulatory rulings could alter the ability to pass through or recover certain costs
AES is exposed to the fluctuation of the Chilean peso, which may pose a risk to earnings; our hedging strategy reduces this risk, but some residual risk to earnings remains
Tax policy changes
Beyond 2016, financial drivers include all of the above factors, but also:
Current legislation is trending towards promoting renewable energy and strengthening regulations on thermal generation assets, posing a risk to future coal margins
Market price risk when re-contracting
Construction and Development — Since 2007, AES Gener has constructed and initiated commercial operations of approximately 1,830 MW of new capacity, representing a significant portion of the increase in installed capacity and investment in the SIC and SING during the period. In Chile, AES Gener has a 21 MW solar project with a scheduled COD in the first half of 2016 and the 532 MW Cochrane project in the SING, expected to begin operations in 2016. The Cochrane project has an adjacent 20 MW energy storage project, which is also scheduled to initiate operations in 2016.
Additionally, in the SIC, AES Gener initiated construction of the 531 MW two unit Uncertainties—Alto Maipo run-of-river hydroelectric project in December 2013, adjacent to our existing Alfalfal power plant, located 50 km from Santiago. Alto Maipo is the largest project in construction in the SIC market and it includes 67 kilometers of tunnel works, 2 caverns, 17 km of transmission lines as part of the construction, and is 90% underground. Alto Maipo has three main contractors and covers three adjacent valleys in the Chilean Andes. As of today, the project employs 4,100 people and expects to reach a peak close to 4,500 in the second half of 2017. The project units are scheduled to reach commercial operation in the second half of 2018 and the first half of 2019..
Colombia
Business Description — Chivor, a subsidiary of AES Gener, owns a hydroelectric facility with installed capacity of 1,000 MW, located approximately 160 km east of Bogota. As of December 31, 2015, AES Gener's net power production in Colombia was 4,112 GWh. The installed capacity represents approximately 6.2% of system capacity as of December 31, 2015. The plant consists of eight 125 MW dam-based hydroelectric generating units in two separate sub-facilities. All of Chivor's installed capacity in Colombia is hydroelectricRegulatory Framework and is therefore dependent on the prevailing hydrological conditions in the region in which it operates. Hydrological conditions largely influence generation and the spot prices at which Chivor sells its non-contracted generation in Colombia.
Chivor's commercial strategy focuses a significant portion of the expected output under contracts, principally with distribution companies, in order to provide cash flow stability. These bilateral contracts with distribution companies are awarded in public bids 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, Chivor receives reliability payments for the availability and reliability of Chivor's reservoir during periods of scarcity, such as adverse hydrological conditions. These payments, referred to as "reliability charge payments" are designed to compensate generation companies for the firm energy that they are capable of providing to the system during critical periods of low supply in order to prevent electricity shortages.
Market Structure — Electricity supply in Colombia is concentrated in one main system, the SIN. The SIN, which encompasses one-third of Colombia's territory, providing coverageelectricity to 96%97% of the country's population. The SIN's installed capacity, primarily hydroelectric (68%) and thermal (31%), totaled 16,22117,392 MW as of December 31, 2015, comprised of 69.0% hydroelectric generation, 30.4% thermoelectric generation and 0.6% 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 2015, 68.2%2018, 84% of total energy demand was supplied by hydroelectric plants with the remaining supply from thermoelectric generation (31.0%) and cogeneration and self-generation power (0.8%). From 2003 to 2015, electricity demand in the SIN has grown at a compound annual growth rate of 3.1% and the UPME projects an average compound annual growth rate in electricity demand of 2.8% per year for the next ten years.plants.
Regulatory Framework — Electricity Regulation — 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 and 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 MME,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 UPME,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.
Other Regulatory Considerations — In 2018, the past few years, Colombian authorities have discussed proposalsMinistry 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 make certain regulatory changes, which have not been implemented as ofbe in commercial operation by December 2015. One proposal2021. The auction is scheduled for February 2019 and the regulator expects to replace or complementadopt the current public auction system in which each distribution company holds an auctionregulation for its specific requirements and subsequently executes bilateral contracts withthe entry of renewable generation or trading companies, with a centralized auction in whichto the market administrator purchases energyduring 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 all distribution companies. During 2015, regulators developed rules to implement Law 1715 passed in 2014 regarding the participationapproximately 6% of renewables sources in the electric sector and the rules for negotiation of excess of energy from self-generators. Due to very high spot prices in the market, the regulator implemented a temporary "spot price cap"
equivalent to the 75% of the first step of rationing cost. Atsystem capacity at the end of 2015, CREG assigned new firm2018. 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 obligationsgenerated by our portfolio is sold to the spot market, including ancillary services. Additionally, AES Chivor receives reliability payments for maintaining the next 3 years (2017-2019). Additionally, regulation for emergency energy situations,plant available during periods of power scarcity, such as severe droughtadverse hydrological conditions, was introduced in 2014 with the objective of avoiding shortages and other negative economic impacts. For 2016, the most probable changes in regulation will relateorder to the AGC ancillary services market as well as a general revision of the reliability charge scheme.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 operations (see Item 7.—Key Trends and Uncertainties—Operational—Weather sensitivity for further discussion).operations. 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%. However, some risks remain beyond 2016.drivers. In addition to hydrology, through 2016, financial results are likely to be driven by many factors, including, but not limited to, the following:to:
Forced outages may impact earningsforced outages;
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 risk to earnings; our hedging strategy reduces this risk, but some residual risk to earnings remains
Beyond 2016, financial drivers include allserves 96% of the above factors, but also: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%).
Chivor has exposureThermoelectric 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 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.
AES Gener is currently constructingArgentina has contributed certain accounts receivable to fund the 20 MW Tunjita run-of-river hydroelectric project,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 is scheduled to start operationspayments are being received. AES Argentina will receive a pro rata ownership interest in these plants once the first halfaccounts receivables have been fully repaid. See Item 7.—Management's Discussion and Analysis of 2016.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. Argentina
Business Description — As of December 31, 2015,2018, AES Argentina operates 3,528plants totaling 4,129 MW, which represents 10.5%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 62% thermoelectric and 38% hydroelectric capacity. All of the thermoelectric capacity has the capability to burn alternative fuels. Approximately 69% of the thermoelectric capacity can operate alternatively with natural gas or diesel oil, and the remaining 31% can operate alternatively 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 2015,2018, approximately 93% of the energy was sold in the wholesale electricelectricity market and 7% was sold under contract, as a result of the Energy Pluscontract sales made by TermoAndes. Market prices are determined
Foreign currency controls were lifted in Argentine Pesos by CAMMESA, the wholesale electric market administrator.
All of the thermoelectric facilities not affected by the Resolution 95/2013, a regulation passed 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 which is connected to the SING by a transmission line owned by AES Gener. 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 mid-December 2011, TermoAndes has been selling the plant's full capacity in the SADI. TermoAndes' electricity permit to export to the SING expired on January 31, 2013 and its potential renewal is being evaluated.
Market Structure — The SADI electricity market is managed by CAMMESA. As of December 31, 2015, the installed capacity of the SADI totaled 33,480 MW. In 2015, 64% of total energy demand was supplied by thermoelectric plants, 31% by hydroelectric plants and 6% 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 — Electricity Regulation — 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 also been made to the electricity regulatory framework. These modifications include tariff conversion to Argentinean Pesos, 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 first two plants are operating and payments are being received, while the third plant is in late stages of the construction process. 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.
On March 26, 2013, the Secretariat of Energy released Resolution 95/2013, which affects the remuneration of generators whose sales prices had been frozen since 2003. This new regulation, which modified the current regulatory framework for the electricity industry, is applicable to generation companies with certain exceptions. It defined a new compensation system based on compensating for fixed costs, non-fuel variable costs and an additional margin. Resolution 95/2013 converted the Argentine electric market towards an "average cost" compensation scheme, increasing revenues of generators that were not selling their production under the Energy Plus scheme or under energy supply contracts with CAMMESA. Resolution 95/2013 applied to all of AES Argentina's plants, excluding TermoAndes. Based on Note 2053 sent by the Ministry of Energy in March 2013, it was understood that TermoAndes' units were not affected by the Resolution since they sell under the Energy Plus scheme.
Thermal units must achieve an availability target which varies by technology in order to receive full fixed cost revenues. The availability of most of AES Argentina's units exceeds this market average. As a result of Resolution 95/2013, revenues to AES Argentina's thermal units increased, but the impact on hydroelectric units is dependent on hydrology. The new 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.
On May 20, 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 renumeration is aimed to cover the expenses that the generator incurs when performing major maintenances in its units.
In the fourth quarter of 2014, the Argentine government passed a resolution to contribute outstanding Resolution 95 receivables into a trust in connection with AES Argentina's commitment to install additional capacity into the system. CAMMESA will finance the investment utilizing the outstanding receivables as a guarantee.
On July 10, 2015, the Argentine government passed Resolution No. 482/2015 ("Resolution 482") which retroactively updated the prices of Resolution 529/2014 to February 1, 2015, including the portion of TermoAndes plant energy generation not committed to Energy Plus Contracts, and created a new trust called "Recursos para las inversions del FONINVEMEM 2015-2018" in order to invest in new generation plants.
In December 2015, the new 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 2015, the Argentinean PesoArgentine peso devalued by approximately 50%. At December 31, 2015, 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, the following: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;
•Level of gas prices for contracted generation (Energy Plus)
Regulatory changes from new government (See Item 7.—Key Trends and Uncertainties—Macroeconomics— Argentina for further discussion)
Brazil SBU
Our Brazil SBU has generation and distribution businesses. Eletropaulo and Tietê are publicly listed companies in Brazil. AES has a 16% economic interest in Eletropaulo and a 24% economic interest in Tietê, and these businesses are consolidated in our financial statements as we maintain control over their operations. Our Brazil operations accounted for the following proportions of consolidated AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow, and AES Proportional Free Cash Flow (a non-GAAP measure):
|
| | | | | | | | |
Brazil SBU (1) | 2015 | | 2014 | | 2013 |
| % of AES Operating Margin | 21 | % | | 24 | % | | 27 | % |
| % of AES Adjusted PTC (a non-GAAP measure) | 6 | % | | 13 | % | | 12 | % |
| % of AES Operating Cash Flow | 5 | % | | 14 | % | | 26 | % |
| % of AES Proportional Free Cash Flow (a non-GAAP measure) | NM(2) |
| | 1 | % | | 6 | % |
(1) Percentages reflect the contributions by our Brazil SBU before deductions for Corporate.
(2) Not meaningful
The following table provides highlights of our Brazil operations:
|
| | |
Generation Capacity• | | 3,298 gross MW (932 proportional MW) |
Generation Facilities | | 13 |
Key Generation Businesses | | Tietêtimely collection of FONINVEMEM installment and Uruguaiana |
Utilities Penetration | | 8.2 million customers (56,861 GWh) |
Utility Businesses | | 2 |
Key Utility Businesses | | Eletropaulooutstanding receivables (See Note 6.—Financing Receivables in Item 8.—Financial Statements and SulSupplementary Data of this Form 10-K for further discussion); and |
natural gas prices and availability for contracted generation.
Generation Brazil
Regulatory Framework and Market Structure — OperatingIn 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 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, 2015,2,658 MW. Tietê represents approximately 12%10% of the total generation capacity in the state of São Paulo and is the third largest private generator in Brazil. We also have another generation plant, AES Uruguaiana, located in southern Brazil with an installed capacity of 640 MW. Listed below are our Brazil SBU generation facilities:
|
| | | | | | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest (% Rounded) | | 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 | | | | |
| Brazil Total | | | | | | 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 — AES owns interests in two distribution businesses in Brazil, Eletropaulo and Sul. 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 20 million people and 6.9 million consumer units, Eletropaulo is the largest power distributor in Brazil, according to the 2012 ranking of the Brazilian Association of the Distributors of Electric Energy (Abradee).
Sul is responsible for supplying electricity to 118 municipalities of the metropolitan region of Porto Alegre on the border with Uruguay and Argentina. The service area covers 99,512 km2, serving approximately 3.7 million people and 1.3 million consumer units.
Presented in the table below is a list of our Brazil SBU distribution facilities:
|
| | | | | | | | | | | | | |
| Business | | Location | | Approximate Number of Customers Served as of 12/31/2015 | | GWh Sold in 2015 | | AES Equity Interest (% Rounded) | | Year Acquired |
| Eletropaulo | | Brazil | | 6,852,690 |
| | 47,357 |
| | 16 | % | | 1998 |
| Sul | | Brazil | | 1,308,224 |
| | 9,504 |
| | 100 | % | | 1997 |
| | | | | 8,160,914 |
| | 56,861 |
| | | | |
The following map illustrates the location of our Brazil facilities:
Brazil Generation Businesses
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 1999hydroelectric plants operate under a 30-year concession expiring in 2029. AES owns a 24% economic interest inof 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 assured capacity, approximately 11,1194 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 Assured Energy, as described in Regulatory Framework section below, in the free marketphysical guarantee 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 contracts (3-5 years).contracts.
As of December 31, 2015, Tietê's contracted portfolio position is 95% and 88% with average prices of R$149/MWh and R$150/MWh for 2016 and 2017, respectively. As Brazil is mostly a hydro-based country with energy prices highly tied to the hydrological situation, the deterioration 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. In 2015, 12 new contracts were signed at an average price of approximately R$154/MWh.Tietê's strategy is to contract most ofgrow by adding renewable capacity to its physical guaranteegeneration platform. In 2017, Tietê acquired Alto Sertão II Wind Complex (“Alto Sertão II”) located in the free market while the remaining portion provides flexibilitystate of Bahia, with an installed capacity of 386 MW and subject to either protect against low hydrology or potentially capture higher spot prices20-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 future. As Brazil doesstate 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 have a developed market with hedge and options instruments forsubject to return at the energy sector, Tietê does not assume any hedging strategy for its portfolio.end of the concession.
Under the concession agreement, Tietê has an obligationis required to increase its capacity by 15%. Tietê as well as other concessionaire generators have not yet met this requirement due to regulatory, environmental, hydrological and fuel constraints. Sao Paulo state does not have a good potential for wind power and also only a small remaining potential for hydro projects, directing the new increase in the state for thermal capacity. With the high complexity process to get an environmental license for coal projects, Tietê decided to fulfill obligation with gas-fired projects in line with Federal government plans. As Petrobras refuses to supply natural gas and to offer capacity in its pipelines and regasification terminals and there are no regulations for natural gas swaps in place, up to now, 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 in 2013 during February and March, in 2014 during March, April, and May, and in 2015 during February, Mach, April and May due to the short-term supply of LNG for the facility. Uruguaiana continues to work toward securing gas on a long-term basis.
Market Structure — Brazil has installed capacity of 140,272 MW, which is 65% hydroelectric, 21.6% thermal and 13.4% renewable (biomass and wind). Brazil's national grid is divided into four subsystems. Tietê is in the Southeast subsystem of the national grid, while Uruguaiana is in the South.
Regulatory Framework — In Brazil, the MME determines the maximum amount of energy that a plant can sell, called Assured Energy, which represents the long-term average expected energy production of the plant. Under current rules, a generation plant's Assured Energy can be sold to distribution companies through long-term (regulated) auctions or under unregulated bilateral contracts with large consumers or energy trading companies.
The 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, and a mechanism known as MRE was created to share hydrological risk across all hydro generators. If the hydro system generates less than total Assured Energy of the system, 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 Assured Energy, 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.
Due to lower than expected hydrology during 2014, from February to April the spot price was at the cap of R$822/MWh and the average spot price of 2014 was R$689/MWh. During October and November 2014, the ANEEL conducted a public hearing to define a new spot price cap, changing it from R$822/MWh to R$388/MWh from January 2015 until December 2015. The lower cap price resulted in a meaningful reduction on the expenses of the agents that were negatively exposed to the spot price in 2015. However, due to improved hydrology in the second half of 2015 spot prices were below the cap with the average price of R$287/MWh. For 2016, ANEEL has already defined the new spot price cap, changing it from R$388/MWh to R$423/MWh from January 2016 forward.
Key Financial Drivers — As the system is highly dependent on hydroelectric generation, Tietê and Uruguaiana (more likely to generate during low hydrology) 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, as well as 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 is a driver forat Uruguaiana.
Through and beyond 2016, Tietê's financial results are likely to be driven by many factors, including, but not limited to, the following:to:
Hydrology,hydrology, impacting quantity of energy generated in MRE;
Demand growthdemand growth;
Re-contracting pricere-contracting price;
Assetasset management and plant availabilityavailability;
Cost managementcost management; and
Abilityability to execute on its growth strategystrategy.
ThroughConstruction and beyond 2016, Uruguaiana's financial results are likely to be driven by many factors including, but not limited to, the following:
Arbitration settlement with YPF (see Item 3.—Legal Proceedings)
Secure long-term gas solution
Brazil Utility Businesses
Business Description Development — Eletropaulo distributes electricity to the greater São Paulo area, Brazil's main economic and financial center. Eletropaulo is the largest electric power distributor in Latin America in terms of both revenues and volume of energy distribution.
AES owns 16%As part of the economic interestinitiative to pursue opportunities in Eletropaulo, our partner, BNDES, owns 19%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 the remaining shares are publicly held or held by government-related entities. AES is the controlling shareholder and manages and consolidates this business. Eletropaulo holds a 30-year concession that expires in 2028.
AES owns 100% of Sul. Sul distributes electricity in the metropolitan region of Porto Alegre up to the frontier with Uruguay and Argentina, respectively, in the municipalities of Santana do Livramento and Uruguaiana/São Borja at the extreme west of the state of Rio Grande do Sul. AES manages Sul under a 30-year concession expiring in 2027.
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 WACC, which is set for all industry participants during each tariff reset cycle. The current Regulatory WACC for Eletropaulo, after tax, is 8.1%. This WACC is effective for three years and as such will be updated again in the next tariff review for Sul in April 2018.
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 by our distribution companies are passed through to customers with adjustments on a yearly basis, working capital will be sensitive to significant increases in energy prices. In order to reduce potential working capital needs, in February 2015, ANEEL opened two public hearings (i) to discuss an Extraordinary Tariff Review ("ETR") requested by distribution companies and ii) to discuss adjustments to a tariff flag mechanism that may change the tariff to customers on a monthly basis depending on energy prices. These items were approved by ANEEL and made effective on March 2, 2015. The ETR represented an average tariff increase of 32% in AES Eletropaulo and 39% at AES Sul. The tariff flag mechanism, a temporary measure in response to higher energy prices due to dry hydrological conditions, was improved by incorporating i) a higher tariff increase depending on the energy purchase costs and (ii) resources collected by the tariff flag being centralized in an account and shared among distribution companies in proportion to their respective involuntary exposure. Most recently, ANEEL approved the Annual Readjustment for AES Sul on April 14, 2015 representing an average tariff increase of 5.46%.
Every four to five years, ANEEL resets each distributor's tariff to incorporate the revised Regulatory WACC and determination of the distributor's net asset base. Eletropaulo's tariff reset occurs every four years and the next tariff reset will be in July 2019. Sul's tariff is reset every five years and the next tariff resetsecond phase, AGV Solar, is expected in April 2018. The 4th Tariff Reset for AES Eletropaulo occurred on July 4, 2015, representing an average tariff increasethe first half of 15.23%.2019.
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 (R$630 million) over a period of up to four tariff processes beginning 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 was completed. On January 28, 2014, ANEEL denied Eletropaulo's request to suspend the effects of the previous decision. On January 29, 2014, Eletropaulo requested and received from the Federal Court of Brazil an injunction for the suspension of the effects of ANEEL's previous decision. As ANEEL had confirmed the original decision and the related refund to customers, the injunction no longer became effective. The Company recognized a regulatory liability of approximately $269 million in the Company's 2013 fourth quarter results of operations since ANEEL had compelled the Company to refund customers. Eletropaulo started reimbursing customers in July 2014.
On December 18, 2014, the effects of the injunction were restored and on January 5, 2015, during a public hearing, ANEEL resolved to follow the legal decision. However, on January 7, 2015 ANEEL requested the suspension of the injunction. While the final legal decision has yet not been taken, ANEEL released a new tariff for Eletropaulo on January 8, 2015, not considering the reimbursement to customers, which is immediately effective. On June 30, 2015, ANEEL included in Eletropaulo's tariff reset the reimbursement of amounts previously refunded to customers from July 2014 through early January 2015. In addition to ANEEL's failure thus far to suspend the injunction through the appeals process in the Brazilian courts, the tariff reset resulted in management's reassessment of the probability of refunding customers these disputed amounts. The Company now 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 the second quarter of 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 — Through and beyond 2016, Eletropaulo's and Sul's financial results are likely to be driven by many factors including, but not limited to, the following:
Hydrology, impacting quantity of energy sold and energy purchasedBrazilian economic growth and tariff increases, impacting energy consumption growth, losses and delinquency (see Item 7.—Key Trends and Uncertainties—Macroeconomics—Brazil for further information)
Ability of both Eletropaulo and Sul to pass through costs via productivity gains
Capital structure optimization to reduce leverage and interest costs
Sul's fourth tariff cycle outcomes in April 2018
July 2012 regulatory asset base resolution
The Eletrobrás case (see Item 3.—Legal Proceedings for further information)
Eletropaulo and Sul are 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.
MCACPuerto 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
Our MCACSouth America SBU has a portfolio of distribution businesses and generation facilities including renewable energy, in fivefour countries with— 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 totalpublicly 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 3,239our South America SBU totals 12,435 MW, of which 33%, 28%, 8%, and distribution networks serving 1.3 million customers as of December 31, 2015. MCAC operations accounted for the following proportions of consolidated AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow,31% are located in Argentina, Chile, Colombia and AES Proportional Free Cash Flow (a non-GAAP measure):
|
| | | | | | | | |
MCAC SBU (1) | 2015 | | 2014 | | 2013 |
| % of AES Operating Margin | 19 | % | | 18 | % | | 17 | % |
| % of AES Adjusted PTC (a non-GAAP measure) | 20 | % | | 19 | % | | 19 | % |
| % of AES Operating Cash Flow | 28 | % | | 16 | % | | 17 | % |
| % of AES Proportional Free Cash Flow (a non-GAAP measure) | 30 | % | | 20 | % | | 23 | % |
(1) Percentages reflect the contributions by our MCAC SBU before deductions for Corporate.
Brazil, respectively. The following table provides highlights of our MCAC SBU operations:
|
| | |
Countries | | Dominican Republic, El Salvador, Mexico, Panama and Puerto Rico |
Generation Capacity | | 3,239 gross MW (2,482 proportional MW) |
Generation Facilities | | 17 (including 1 under construction) |
Key Generation Businesses | | Andres, Panama and TEG TEP |
Utilities Penetration | | 1.3 million customers (3,754 GWh) |
Utility Businesses | | 4 |
Key Utility Businesses | | El Salvador |
The table below lists our MCACSouth America SBU generation facilities:
|
| | | | | | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest (% Rounded) | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| Andres | | Dominican Republic (DR) | | Gas | | 319 |
| | 90 | % | | 2003 | | 2018 | | Ede Este/Non-Regulated Users/Linea Clave |
Itabo(1) | | DR | | Coal/Gas | | 295 |
| | 45 | % | | 2000 | | 2016 | | Ede Este/Ede Sur/Ede Norte/Quitpe |
| DPP (Los Mina) | | DR | | Gas | | 236 |
| | 90 | % | | 1996 | | 2016 | | Ede Este |
| Dominican Republic Subtotal | | | | | | 850 |
| | | | | | | | |
| 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 |
| 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 |
| | | | | | | | |
| 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 de 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 | | | | | | 777 |
| | | | | | | | |
| Puerto Rico | | US-PR | | Coal | | 524 |
| | 100 | % | | 2002 | | 2027 | | Puerto Rico Electric Power Authority |
| Illumina | | US-PR | | Solar | | 24 |
| | 100 | % | | 2012 | | | | |
| Puerto Rico Subtotal | | | | | | 548 |
| | | | | | | | |
| MCAC Total | | | | | | 3,239 |
| | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| 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) | ItaboGener - Chile plants: Itabo complex (twoAlfalfal, 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 steam turbinesunits 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 one gas-fired steam turbine).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 construction — The following table lists our plants under construction in the MCACSouth America SBU:
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| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest (% Rounded) | | Expected Year of Commercial Operations |
| DPP (Los Mina) Conversion | | Dominican Republic | | Gas | | 122 |
| | 90 | % | | 1H 2017 |
| Dominican Republic Subtotal | | | | | | 122 |
| | | | |
| MCAC Total | | | | | | 122 |
| | | | |
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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 |
| | | | |
MCAC Utilities — OurIn June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo, a distribution businesses are locatedbusiness in El SalvadorBrazil. Prior to its sale, Eletropaulo was accounted for as an equity method investment and distribute power to 1.3 million peopleits results of operations and financial position were reported as discontinued operations in the country. These businesses consist of four companies, each of which operates in defined service areas as described below:consolidated financial statements for all periods presented.
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| | | | | | | | | | | | | |
| Business | | Location | | Approximate Number of Customers Served as of 12/31/2015 | | Approximate GWh Sold in 2015 | | AES Equity Interest (% Rounded) | | Year Acquired |
| CAESS | | El Salvador | | 583,000 |
| | 2,174 |
| | 75 | % | | 2000 |
| CLESA | | El Salvador | | 377,000 |
| | 892 |
| | 80 | % | | 1998 |
| DEUSEM | | El Salvador | | 76,000 |
| | 132 |
| | 74 | % | | 2000 |
| EEO | | El Salvador | | 290,000 |
| | 556 |
| | 89 | % | | 2000 |
| | | | | 1,326,000 |
| | 3,754 |
| | | | |
The following map illustrates the location of our MCACSouth America facilities:
MCACSouth America Businesses
Dominican RepublicChile
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:
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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 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 Dominicana consistsGener, we are engaged in the generation and supply of threeelectricity (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 subsidiaries, Itabo, Andres and DPP. AES has 23%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 capacity (850 MW) and suppliesmarginal cost.
AES Gener currently has long-term contracts, with an average remaining term of approximately 42% of energy demand through these generation facilities.
During 2014, AES entered into a strategic partnership11 years, with the Estrella and Linda Groups ("Estrella-Linda"), an investor group based in the Dominican Republic. Under this agreement, Estrella-Linda acquired an 8% non-controlling interest in AES' business in the Dominican Republic for $83 million and, in December 2015, exercised its first call option of additional 2% for$18 million, net of discount and transaction costs. Estrella-Linda has an additional option to increase up to 20% by the end of 2016. 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. Itabo owns and operates two thermal power generation units with a total of 295 MW of installed capacity. Itabo's PPAs are with government-ownedregulated distribution companies and expire in 2016. Sinceunregulated 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 majority of distribution companies' long term PPAs are expiring in Julycapacity 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 CDEEE is sponsoringMinistry 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 bidding process that is expected to be releasednew decontamination plan for the Ventanas and awarded during 2016 in order to secure supply and competitive pricing for actual and future distribution energy requirements. The existing business strategy is to secure approximately 75% to 85%Huasco regions was proposed by the authority under the current administration. Currently, the Environmental Ministry expects approval of the open position through new PPAsdecontamination 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 distributionNCREs. Generation companies are able to meet this requirement by building NCRE generation capacity (wind, solar, biomass, geothermal and large users. Pricesmall 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 PPA structurebiomass 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 subjectequivalent to $5 per ton emitted. PPAs originating from the termsSING 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 the bidding process.these costs.
Andres and DPP are owned 90% by AES and 10% by Estrella-Linda. Andres has a combined cycle gas turbine and generation capacity of 319 MW as well as the only LNG import facility in the country, 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-owned distribution companies and large customers.
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 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.
In 2005, Andres entered into a contract to sell re-gasified LNG for further distribution to industrial users within the Dominican Republic using compression technology to transport it within the country. In January 2010, the first LNG truck
tanker loading terminal started operations. With this investment, AES is capturing demand from industrial and commercial customers.
Market Structure
Electricity Market — The Dominican Republic has one main interconnected system with approximately 3,742 MW of installed capacity, composed primarily of thermal generation (82%), hydroelectric power plants (16%) and wind plants (2%).
Natural Gas Market — The natural gas market in the Dominican Republic started developing in 2001 when AES entered into a long-term contract for LNG and constructed AES Dominicana's LNG regasification terminal.
Regulatory Framework — The regulatory framework in the Dominican Republic consists of a decentralized industry including generation, transmission and distribution, where generation companies can earn revenue through short- and long-term PPAs, ancillary services and a competitive wholesale generation market. All electric companies (generators, transmission and distributors), are subject to and regulated by the GEL.
Two main agencies are responsible for monitoring and ensuring compliance with the GEL, the CNE and the SIE. CNE is in charge of drafting and coordinating the legal framework and regulatory legislation, proposing and adopting policies and procedures to assure best practices, drafting plans to ensure the proper functioning and development of the energy sector and promoting investment. SIE'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.
The electricity tariff applicable to regulated customers is subject to regulation within the concessions of the distribution companies. Clients with demand above 1.0 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 ICM 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:
dry hydrology scenarios;
forced outages;
changes in current regulatory rulings altering the ability to the following:pass through or recover certain costs;
Spot prices are mainly driven by the fluctuations in commodity prices due to the dependency of the Dominican RepublicChilean 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 oil-based thermal generation. Since the fuel component is a pass-through cost under the PPAs, any variation in the oil prices will mainly impact the spot sales for both Andresgeneration assets; and Itabo, which are expected to be net sellers in the upcoming years. Current contracting level for 2016 is close to 90%. Supply shortages in the near term (next 2 to 3 years) may provide opportunities for upside but new generation is expected to come online from 2018.
Additional sales derived from natural gas domestic demand are expected to continue providing an income stream and growth based on the entry of future projects and the fees from the infrastructure service.market price risk when re-contracting.
In addition, the financial weakness of the three state-owned distribution companies due to low collection rates and high levels of non-technical losses has led to delays in payments for the electricity supplied by generators. At times 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.
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 operational in 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 years term beginning on August 1, 2016.
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 25% 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 on 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 on June 2020, reducing the total contracted capacity to 350 MW until December 2030.
Market Structure — Panama's current total installed capacity is 3,068 MW, of which 56% is hydroelectric, 3% wind and the remaining 41% 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 CND implementselectricity sector in Colombia operates under a competitive market framework for the economic dispatchgeneration and sale of electricity, in the wholesale market. The CND's objectives are to minimize the total cost of generation and maintain the reliability and security of the electric power system, taking into account the price of water, which determines the dispatch of hydro plants with reservoirs. Short-term power prices are determined on an hourly basis by the last dispatched generating unit.
In Panama, dry hydrological conditions remained during 2015 affecting the generation output from hydroelectric facilities as in the prior year. AES Panama had to purchase energy on the spot market 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 $90/MWh from $217/MWh in 2014, impacting also the amount recognized through the 2014-2016 Government Compensation Agreement to only $5.8 million out of the $30 milliona regulated framework for 2015. 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 up to $40 million in 2014, $30 million in 2015 and $30 million in 2016.
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 utilitieselectricity. 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 provide such services.demand will be satisfied by the lowest cost combination of available generating units.
Generators can only contract their firm capacity. Physical generationIn 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 determinedscheduled 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 CND regardlessspot market, including ancillary services. Additionally, AES Chivor receives reliability payments for maintaining the plant available during periods of contractual arrangements.power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.
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,to:
forced outages;
fluctuations of the following:Colombian peso; and
Lower hydrology resulting in low generationspot market prices.
Argentina
Regulatory Framework and additional energy purchases to fulfill contracts, partially mitigated by additional generation from Estrella del Mar I, lower spot prices driven byMarket Structure — Argentina has one main power system, the drop in commodities, andSADI, which serves 96% of the compensation amount fromcountry. As of December 31, 2018, the Government Compensation Agreement.
In addition to spot prices being driven by hydrology since Panama is highly dependent on hydro generation (~56%), the fluctuations in commodity prices, mainly oil prices, affect the thermal generation cost impacting the spot prices and the opportunity cost of water. In the event of low hydrology, high commodity prices will increase the business exposure and the cost of replacement power to back up our contractual commitment.
Constraints imposed by theinstalled capacity of the transmission line connectingSADI totaled 38,538 MW. The SADI's installed capacity is composed primarily of thermoelectric generation (64%) and hydroelectric generation (28%).
Thermoelectric generation in the west sideSADI 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 countrysystem'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 load centerenergy 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;
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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 continue untildistribution 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 endnational operator, ONS, and regulated by ANEEL. The ONS dispatches generators based on their marginal cost of 2016 keeping surplus power trapped, particularly duringproduction and on the wet season.
Country demand as GDP growth is expected to remain strong overrisk of system rationing. Key variables for the short and medium term.
Given that most of AES' portfolio is run-of-river,dispatch decision are forecasted hydrological conditions, have an important influence on its profitability. Variationsreservoir 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 actual hydrology can result in excess or a short energy balance relativethe spot market to our contractfulfill their contractual obligations. During
A mechanism known as the low inflow period (JanuaryMRE was created under ONS to May), generation tendsshare hydrological risk across MRE hydro generators. If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may
need to be lower and AES Panama may purchase energy in the short-term market to cover contractual obligations. Duringmarket. When total hydro generation is higher than the remaindertotal 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 (JunePPAs. Through its ownership of Tietê, AES owns a 24% economic interest in those entities. These assets are not subject to December),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 tendscapacity in the state of São Paulo allowed Tietê to be highersign 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 excess of contract volumes is soldMRE;
demand growth;
re-contracting price;
asset management and plant availability;
cost management; and
ability to the short-term market. In addition to hydrological conditions, commodity prices affect short-term electricity prices. See Item 7.—Key Trends and Uncertainties—Operational—Sensitivity to Dry Hydrological Conditions for further information.execute on its growth strategy.
Construction and Development — Continuing with the strategy to reduce reliance on hydrology started with the acquisitionAs part of the initiative to pursue opportunities in renewable generation discussed above, Tietê is currently constructing photovoltaic power barge, Estrella del Mar I, in August 2015 AES executedplants with a partnership agreement with Deeplight Corporation, a minority partner, withtotal projected capacity of 144 MW, subject to 20 year PPAs. Commercial operation of first phase, Boa Hora Solar, and of 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. As of December 31, 2015, amounts capitalized include $7 million recorded in Construction in Progress and the projectsecond phase, AGV Solar, is scheduled to initiate operationsexpected in the first half of 2018.2019.
Mexico
Business Description — AES has 1,055 MW of installed capacity in Mexico, including the 550 MW Termoeléctrica del Golfo ("TEG") and Termoeléctrica Peñoles ("TEP") facilities and Merida III ("Merida"), 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.
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 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 — Mexico has a single national electricity grid, the SEN, covering nearly all of Mexico's territory. Mexico has an installed capacity totaling 65 GW with a generation mix of 74% thermal, 19% hydroelectric and 7% other. Electricity consumption is split between the following end users: industrial (58%), residential (26%) and commercial and service (16%).
Regulatory Framework —Following the constitutional changes approved 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 which foresees:
The energy market liberalization in January 2016 through the implementation of: wholesale electricity market (day ahead and real time market), ancillary services, capacity, Clean Energy Certificates, and Financial Transmission Rights market.
CFE's, former state-owned electric monopoly, vertical and horizontal disintegration into different segments of the value chain: generation, transmission, distribution and commercialization.
CENACE as new ISO is responsible for managing the wholesale electricity market, transmission and distribution infrastructure, planning the network developments, guaranteeing open access to network infrastructure, executing competitive mechanisms to cover regulated demand, and setting transmission charges.
Implementation of annual mid and long term auctions to secure supply for the regulated demand, establishing a PPA with CFE as the Basic Supplier.
According to the new regulatory framework, new assets developed under the new framework or assets transferred to the new regime and in operation after the approval of the Electricity Law (August 2014) are eligible to participate in the new markets. Additionally, projects developed and operated under the Electric Public Service Law (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 — Operational performance is the key business driver as the companies are fully contracted and better performance provides additional financial benefits including performance incentives and/or excess energy sales (in the case of TEG/TEP). The energy prices of TEG/TEP for the sales in excess over its long-term contracts are driven by the average production cost of CFE which is highly dependent on natural gas and oil. If the average production cost of CFE is higher than the cost of generating with pet coke, our businesses in Mexico will benefit provided that they are able to sell energy in excess of their PPAs.
Other 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).
Business Description — AES Puerto Rico owns and operates a coal-fired cogeneration plant and a recently acquired solar plant of 524 MW and 24 MW, respectively, representing approximately 9% of the installed capacity in Puerto Rico. Both plants have long-term PPAs expiring in 2027 and 2032, respectively, with PREPA, a state-owned entity that supplies virtually all of the electric power consumed in Puerto Rico and generates, transmits and distributes electricity to 1.4 million customers. On April 29, 2015, AES completed the acquisition of 100% of the common stock of the solar plant, AES Illumina. Its results of operations have been included in AES' consolidated results of operations from the date of acquisition.PREPA. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for further discussion of the long-term PPA with PREPA. In addition, AES Puerto Rico has ongoing litigation regarding the disposal of ash in the Dominican Republic. See Item 3.—Legal Proceedings.
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. The distribution companies are operated by AES on an integrated basis under a single management team.Salvador (CAESS, CLESA, EEO and DEUSEM). AES El Salvador's territory covers 77%79% of the country. AES El Salvadorcountry and accounted for 3,7304,040 GWh of the wholesale market energy purchases during 2015,2018, or about 64%63% market shareshare.
Construction and Development — As part of the country's total energy purchases.
initiative to pursue opportunities in renewable generation, AES El Salvador also owns AES Nejapa,has entered into a 6 MW power plant generating electricityjoint venture with methane gas fromCorporacion Multi-Inversiones, a landfill, fully contracted with CAESS. During 2015, AES El Salvador began operations ofGuatemalan investment group, to develop, construct and operate Bosforo, a AES Moncagua, a 2.5142 MW solar facility locatedfarm. 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 eastsecond half of the country, which is fully2019. The energy produced by this project will be contracted with EEO.
The sector is governeddirectly by the General Electricity Law and the general and specific orders are issued by Superintendencia General de Electricidad y Telecomunicacions ("SIGET" or "The Regulator"). The Regulator, jointly with the distribution companiesAES' utilities in El Salvador, completed the tariff reset process in December 2012 and defined the tariff calculation to be applicable for the next five years (2013-2017).Salvador.
South America SBU
Our EuropeSouth America SBU has generation facilities in five countries. Our European operations accounted for thefour 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 proportions of consolidated AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow, and AES Proportional Free Cash Flow (a non-GAAP measure):table lists our South America SBU generation facilities:
|
| | | | | | | | |
Europe SBU (1) | 2015 | | 2014 | | 2013 |
| % of AES Operating Margin | 11 | % | | 13 | % | | 13 | % |
| % of AES Adjusted PTC (a non-GAAP measure) | 15 | % | | 19 | % | | 19 | % |
| % of AES Operating Cash Flow | 14 | % | | 13 | % | | 15 | % |
| % of AES Proportional Free Cash Flow (a non-GAAP measure) | 15 | % | | 14 | % | | 18 | % |
|
| | | | | | | | | | | | | | | | |
| 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 |
| | | | | | | | |
(1) Percentages reflect_____________________________
| |
(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. |
| |
(2) | Guacolda is comprised of five coal-fired units under Guacolda Energia S.A., an unconsolidated entity for which the results of operations are reflected in Net equity in earnings of affiliates. The Company's ownership in Guacolda is held through AES Gener, a 67%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 33%. |
| |
(3) | TermoAndes is located in Argentina, but is connected to both the SEN in Chile and the SADI in Argentina. |
| |
(4) | AES operates 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 contributions by our Europe SBU before deductionsSouth 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 Corporate.
The following table provides highlightsmap illustrates the location of our Europe operations: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:
|
| | |
Countries | | Bulgaria, Jordan, Kazakhstan, Netherlands and United Kingdom |
GenerationInstalled Capacity | | 6,781gross MW (5,009 proportional MW) | SEN |
Generation FacilitiesThermoelectric | | 12 | 54% |
Key Generation BusinessesHydroelectric | | Maritza, Kilroot, Ballylumford, and Kazakhstan | 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.
37The 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
Operatingcompanies, 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 Europe SBU totaled 6,781 MW. Presentedportfolio 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 table belowunderlying 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;
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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 (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 list640 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 EuropeMCAC SBU generation facilities:
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| | | | | | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest (% Rounded) | | 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 | | 380 |
| | 37 | % | | 2009 | | 2033-2034 | | National Electric Power Company |
| IPP4 | | Jordan | | Heavy Fuel Oil/Gas | | 247 |
| | 60 | % | | 2014 | | 2039 | | National Electric Power Company |
| Jordan Subtotal | | | | | | 627 |
| | | | | | | | |
| Ust-Kamenogorsk CHP | | Kazakhstan | | Coal | | 1,372 |
| | 100 | % | | 1997 | | Short-term | | Various |
Shulbinsk HPP(1) | | Kazakhstan | | Hydro | | 702 |
| | — | % | | 1997 | | Short-term | | Various |
Ust-Kamenogorsk HPP(1) | | Kazakhstan | | Hydro | | 331 |
| | — | % | | 1997 | | Short-term | | Various |
| Sogrinsk CHP | | Kazakhstan | | Coal | | 345 |
| | 100 | % | | 1997 | | Short-term | | Various |
| Kazakhstan Subtotal | | | | | | 2,750 |
| | | | | | | | |
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 | | 1,246 |
| | 100 | % | | 2010 | | 2023 | | Power NI/Single Electricity Market (SEM) |
Kilroot(3) | | United Kingdom | | Coal/Oil | | 662 |
| | 99 | % | | 1992 | | | | SEM |
| Kilroot ES | | United Kingdom | | Energy Storage | | 10 |
| | 100 | % | | 2015 | | | | |
| United Kingdom Subtotal | | | | | | 1,918 |
| | | | | | | | |
| Europe Total | | | | | | 6,781 |
| | | | | | | | |
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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 |
| | | | | | | | |
_____________________________
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(1) | AES operates these facilities under concession agreements until 2017.Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine). |
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(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:
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| | | | | | | | | | | | |
| 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:
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| | | | | | | | | | | | | | | | |
| 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 |
| | | | | | | | |
_____________________________
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(1) | Unconsolidated entity, the results of operations of which are reflected in Equity in Earnings of Affiliates. |
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(2) | The Ballylumford B Station began the process for a safe shutdown in December 2018. |
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(3) | Includes Kilroot Open Cycle Gas Turbine ("OCGT").Turbine. |
Under construction — The following table lists our plants under construction in the Eurasia SBU:
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| | | | | | | | | | | | |
| 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 |
| | | |
_____________________________
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(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 EuropeanEurasia 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 EU Industrial Emission Directive, which came into force in January 2016.thermal power plant. Maritza's entire power output is contracted with NEK under a 15-year PPA, expiring in 2026, capacityMay 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 energy based,regulatory changes in Bulgaria.
The DG Comp is reviewing NEK’s PPA with a fuel pass-though. The ligniteMaritza pursuant to the European Commission’s state aid rules. Maritza believes that its PPA is legal and limestone are supplied under a 15-year fuel supply contract.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 2015 was approximately 13.6 GW. Thermal generation, which is mostly coal-fired,August 2017 and nuclearapplies to Maritza. Impacted power plants account for 64% ofare required to either meet the installed capacity.
Regulatory Framework — The electricity sector in Bulgaria operates under the Energy Act of 2004 that allows the sale of electricity to take place freely at negotiated prices, at regulated prices between partiesnew standards or on the organized market. In 2015 the government of Bulgaria has 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 BankBulgarian environmental authorities in 2018, and expects to receive a response in 2019. If derogation is expected in May 2016. The Independent Bulgarian Energy Exchange started commercial operation ofnot received Maritza would seek to pass through the power exchange on January 19, 2016 after successful test sessions were held in December 2015.
Our investments in Bulgaria rely on long-term PPAs with NEK, the state-owned electricity public supplier and energy trading company. NEK is facing some liquidity issues and has been delayed in making payments under the PPAs with Maritza and St. Nikola. In May and June 2014, SEWRC issued decisions precluding the ability of NEK to pass-throughcompliance costs to the regulated market certain costs incurred by NEKoff-taker pursuant to the PPA with Maritza, which impacted NEK's liquidity and its ability to make payments under the PPA. SEWRC also instructed NEK and Maritza to begin negotiating amendments
Key Financial Drivers —Financial results are driven by many factors, including, but not limited to:
regulatory changes to the PPA. Maritza has engaged in negotiations with NEK and other Bulgarian state bodies concerning these matters. In August 2015, the ninth amendmentBulgaria power market;
results of Maritza's PPA was executed under which Maritza and NEK would reduce the capacity payment to Maritza under the PPA by 14% through the PPA Term, without impacting the energy price component. In exchange, NEK would pay Maritza its overdue receivables. The amendment will become effective upon full payment of the overdue receivables by NEK, which is expected in 2016. In 2014 SEWRC announced that it has asked the DG Comp to review NEK's respective PPAs with Maritza and a separate generator pursuant to European state aid rules, and to suspend the PPAs pending the completion of that review. DG Comp has not contacted Maritza about the SEWRC's request to date.review;
In March 2015, changes to the Energy Act were enacted. Changes included a limitation on electricity purchases from co-generators at preferential prices, the allocation of the proceeds from the sale of state CO2 allowances to NEK, and an increase in the Regulator's independence through appointment of its members by the Parliament rather than by the Council of Ministers. In July 2015, additional measures were voted by the Parliament to complement the first measures taken in March 2015. An Electricity Security Fund was created to help NEK meet its obligations with energy producers, financed with a 5% contribution from all energy producers on their energy revenues as well as with proceeds from the sale of state CO2 allowances. Maritza is able to pass-through this additional contribution to NEK since it falls under a change in law provision under the PPA. Following the Energy Act amendments on July 31, 2015 the regulator approved new regulated prices that led to 0.11% decrease for household electricity prices and increased the non-household prices between 0% and 20% for the various segments. On November 1, 2015 the regulator decreased the non-household prices 2.5% on average as result of the falling gas prices. All these actions are expected to improve NEK's liquidity. At this time, it is difficult to predict the impact of the political conditions and regulatory changes on our businesses in Bulgaria.
Maritza has experienced ongoing delays in the collection of outstanding receivables from NEK. As of December 31, 2015, Maritza had an outstanding receivables balance of $351 million including $44 million of current receivables, $82 million of receivables overdue by less than 90 days and $225 million of receivables overdue by more than 90 days. See Key Trends and Uncertainties—Macroeconomics and Political—Bulgaria in Item 7.—Management's Discussion and Analysis to this Form 10-K for further information.
NEK has failed to maintain a minimum rating pursuant to the Government Support Letter issued in 2005. As a result, the PPA could be terminated at the discretion of Maritza and the lenders. See Item 1A.—Risk Factors—We may not be able to enter into long-term contracts, which reduce volatility in our results of operations. As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) 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 these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.
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: the availability of the operating units;
the level of wind resourceresources for St. Nikola;
spot market price volatility beyond the level of compensation through the Contract for Premium for St. Nikola; and
NEK's ability to meet the payment terms of the PPA contract.
United Kingdom
Business Description Regulatory Framework and Market Structure — AES' generation businessesAES UK operates in the United Kingdom operate in the IrishIntegrated Single Electricity Market (SEM) for the businesses located("I-SEM") in Northern Ireland (1,918 MW). During 2015, AES sold its interestsIreland. The I-SEM is the wholesale electricity market arrangement operating in wind development pipelines of 115 MW in Scotland.
The Northern Ireland generation facilities consist of two plants within the Greater Belfast region. Our Kilroot plant is a 662 MW coal-fired plant with 10 MW of energy storage facility and our Ballylumford plant is a 1,246 MW gas-fired plant. These plants provide approximately 70% of the Northern Ireland installed capacity and 18% of the combined installed capacity for the island of Ireland.
Kilroot is a merchant plant that bids into the SEM market. Kilroot derives its value from the variable margin when scheduled in merit and the margin from constrained dispatch (when dispatched out of merit to support the system in relation to the wind generation, voltage and transmission constraints) and capacity payments paid through the SEM Capacity Payment Mechanism. In addition to the above, value is also secured from ancillary services.
Ballylumford is partially contracted for 600 MW under a PPA with PPB that expires in 2018, with an extension at the offtaker's option through 2023, with the remaining capacity bid into the SEM market. Ballylumford's key sources of revenue are availability payments received under the PPA and capacity payments offered through the SEM Capacity Payment Mechanism. Additionally, Ballylumford receives revenue from constrained dispatch through which the costs of operation are recovered from the market and also from the ancillary services market.
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 18% of the total generation capacity. The governments of Northern Ireland and the Republic of Ireland plan further increases in renewables.and 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 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 lackthe System Operator for Northern Ireland. The Single Electricity Market Operator is licensed and regulated cooperatively by the Commission for Energy Regulation in the Republic of forward pricing. There are essentially three products (baseload, mid-meritIreland and peaking) which are traded between the generators and suppliers.
Regulatory Framework — Electricity Regulation — 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.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 — The European Commission adopted in 2011 the Industrial Emissions Directive ("IED") that establishes the Emission Limit Values ("ELV") for SO2, NOx and dust emissions to be complied with starting from 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 the IED. The Ballylumford C Station is compliant without the need for investment. Both Ballylumford B Station and Kilroot required investment to be in compliance.
The IED provides for two optionsan additional 10 MW of energy storage, that may be implemented by the EU member states other than compliance with the new ELV's- the Transitional National Plan ("TNP") or Limited Life Time Derogation ("LLTD").
Kilroot has optedbids into the TNP and this allowsI-SEM. Kilroot's coal fired units failed to clear in the plantfirst I-SEM capacity auction process finalized in January 2018. Consequently, AES announced its intent to operate between 2016-2020, being exempt from compliance with ELVs, but observing a ceiling set for maximum annual emissions that is based onshut down the last 10 years average emissions and operating hours. Kilroot has invested approximately $10 million in Umbrella Selective Non Catalytic Reduction ("USNCR") technology, which reducescoal units, pending the plant's NOx emissions enablingresults of an assessment by the plant
regulator to increase its capacity factor withindetermine the ceiling of NOx emissions and earn energy margin. Further technical modifications are being evaluated which could make the plant fully compliant with IED from 2020.
Without investment, the Ballylumford B station of 540 MW would not meet the standardslong term needs of the IED following 2015.Northern Ireland power grid. In 2014, AES competed to secure a Local Reserve ServicesNovember 2018, Kilroot's Unit 1 was awarded the 12 month System Support Service Agreement ("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. These units will also qualify for capacity payments under the SEM.
Key Financial Drivers — For our businesses in the SEM market, the financial results will be driven by, but not limited to, the following, and may change in 2017 due to 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
Kazakhstan
Business Description — Our businesses account for approximately 6% of the total annual generation in Kazakhstan. Of the total capacity of 2,750 MW, 1,033 MW is hydroelectric and operates under a concession agreement until the beginning of October 2017 and 1,717 MW of coal-fired capacity 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 no 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 2015 amendments to the Electricity Law state that a centrally organized capacity market will be established by 2019, but the capacity offtaker still only signs annual contracts.
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 growing 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 20,657 MW, of which 17,421 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 $18 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, previously Ministry of Industry and New Technologies, based on a number of factors including plant type and fuel used.
In July 2012, Kazakhstan enacted various amendmentsOctober 2018 to its Electricity Law. Among the amendments was a requirement to reinvest all profits generated by electricity producers during the years 2013-2015. Accordingly, the business will be unable to pay dividends for the period 2013-2015. Under the amended Electricity Law, electricity producers must, on an annual basis, enter into Investment Obligation Agreements ("IOAs") with the Ministry of Energy. These annual IOAs must equal the sum of the upcoming year's planned depreciation and profit. Selection of investment projects for the IOAs is at the discretion of electricity producers, but the Ministry of Energy has the right to reject submitted IOA proposals. An electricity producer without an IOA executed by the Ministry of Energy may not charge tariffs exceeding its incremental cost of production, excluding depreciation. In December 2014, the Ministry of Energy executed IOAs with all four AES generators in Kazakhstan, which allow revenue at the tariff-cap level, but all generated cash will need to be reinvested.
In November 2015, Kazakhstan enacted amendments to its Electricity Law to extend price cap regulation till the end of
2018 and postpone the introduction of capacity market tillSeptember 2019. In addition, the obligation for power plantsCompany also decided to sign annual IOAs has been eliminated for 2016-2018. During 2013-2015, IOAs required businessestransfer the capacity contract awarded to reinvestBallylumford Unit 4 to Kilroot Unit 2. As a result, the sumdecision to shut down both Kilroot coal units was reversed.
Ballylumford is a 708 MW gas-fired plant, of all profitswhich 592 MW is contracted under a PPA with Power NI Power Procurement Business expiring in 2023. The 116 MW remaining capacity is bid into the I-SEM market. Ballylumford's B station 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 depreciation on an annual basis, limitingongoing work to safely shut down the abilitystation is expected to send dividends. Beginningbe completed in 2016 Kazakhstan no longer has a restriction on sending dividends.early 2019.
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 Regulator (Committee of Natural Monopoly Regulation and Competition Protection). Currently, tariffs are only for multi-year periods, but with some annual adjustments for fuel cost.
Key Financial Drivers — The financialFinancial 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; regulated heat tariff levels; and weather conditions, but may change in 2016 due to
regulatory changes to the market structure and payment mechanism.mechanisms;
Availabilityinvestments to maintain compliance with EU environmental legislation;
weather conditions impacting availability of growing renewables generation;
availability of the operating units and trading strategy;
Regulated commodity and FX prices (gas, coal, CO2) and sufficient market liquidity to hedge prices in the short-term; and
electricity tariff-cap levelsdemand in the I-SEM (including impact of wind generation).
Weather conditionsJordan
CostRegulatory 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 coalrenewable energy installed capacity expected by 2020, 940 MW of which is already connected to the grid.
Kazakhstan currency exchange rate fluctuation
Other Europe Businesses
Business Description — In Jordan, AES has a 37% controlling interest in Amman East, a 380381 MW (gross) oil/gas-fired plant fully contracted with the national utility under a 25-year PPA. We also havePPA expiring in 2033, and a 60%36% controlling interest in the IPP4 plant, in Jordan, a 247250 MW (gross)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.
On July 2, 2014, the Company closedshort-term market, for example, traded on an energy exchange or through competitively bid bilateral contracts. The tariffs are fixed on yearly basis by the sale of its 50% ownership interest in Silver Ridge Power ("SRP") for a purchase price of $179 million, excluding the Company's indirect ownership interests in SRP's solar generation businesses in Italy and Spain ("Solar Italy" and "Solar Spain," respectively). On February 9, 2015, SRP distributed its ownership interest in Solar Spain to a joint venture of AES and a third party. After this date, AES' only remaining economic interest under SRP ownership was in Solar Italy. The previous buyer of our interest in SRP also had an option to purchase the Company's indirect 50% interest in Solar Italy for an additional consideration of $42 million by August 2015. That buyer exercised its option to purchase Solar Italy on August 31, 2015, and the sale was completed on October 1, 2015. At this point, the Company ceased having continuing involvement not only with Solar Italy but also with SRP, its parent, and the Company recognized a gain of $5 million on the overall sale of SRP. On September 24, 2015, the Company completed the sale of Solar Spain, an equity method investment with 31 MW peak capacity. Net proceeds from the sale transaction were $31 million and the Company recognized a pretax gain on sale of less than $1 million.
Asia SBU
Our Asia SBU has generation facilities in four countries. Our Asia operations accountedElectricity Regulatory Commissions Central / State(s) for the following proportionslong-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 consolidated AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow,Orissa. OERC also facilitates intrastate transmission and AES Proportional Free Cash Flow (a non-GAAP measure):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.
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| | | | | | | | |
Asia SBU (1) | 2015 | | 2014 | | 2013 |
| % of AES Operating Margin | 5 | % | | 2 | % | | 5 | % |
| % of AES Adjusted PTC (a non-GAAP measure) | 6 | % | | 2 | % | | 8 | % |
| % of AES Operating Cash Flow | 1 | % | | 5 | % | | 3 | % |
| % of AES Proportional Free Cash Flow (a non-GAAP measure) | 5 | % | | 6 | % | | 5 | % |
(1) Percentages reflect the contributions by our Asia SBU before deductions for Corporate.
The following table provides highlightspower sector in India is composed of our Asia operations: |
| | |
Countries | | India, Philippines and Vietnam |
Generation Capacity | | 2,290 gross MW (1,159 proportional MW) |
Generation Facilities | | 5 (including 2 under construction) |
Key Businesses | | Masinloc, OPGC I and Mong Duong II |
Operatingcoal, gas, hydroelectric, renewable and nuclear energy. Total installed capacity totals 2,290 MW. Presented below inas 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 tabletotal installed capacity. The remaining capacity is a list of our Asia SBU generation facilities:nuclear (2%) and hydro (13%).
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| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest (% Rounded) | | 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 |
| Philippines Subtotal | | | | | | 630 |
| | | | | | | | |
| Mong Duong 2 | | Vietnam | | Coal | | 1,240 |
| | 51 | % | | 2015 | | 2040 | | EVN |
| Vietnam Subtotal | | | | | | 1,240 |
| | | | | | | | |
| Asia Total | | | | | | 2,290 |
| | | | | | | | |
| |
(1)
| Unconsolidated entity for which the results of operations are reflected in Equity in Earnings of Affiliates. |
Under Construction
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| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest (% Rounded) | | Expected Date of Commercial Operation |
| OPGC II | | India | | Coal | | 1,320 |
| | 49 | % | | 1H 2018 |
| India Subtotal | | | | | | 1,320 |
| | | | |
| Masinloc ES | | Philippines | | Energy Storage | | 10 |
| | 100 | % | | 1H 2016 |
| Philippines Subtotal | | | | | | 10 |
| | | | |
| Asia Total | | | | | | 1,330 |
| | | | |
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 EquityNet equity in Earningsearnings of Affiliates inaffiliates on our consolidated resultsConsolidated Statements of operations.Operations.
Construction and Development — As noted above, AES has one 1,320 MW coal-fired project under development with a total capacity of 1,320 MWconstruction, which is an expansion of our existing OPGC business. The project started construction in April 2014 and is currently expected to begin operations in 2018.the first half of 2019. As of December 31, 2015,2018, total capitalized costs at the project level were $336 million (AES share of $165 million), while at the AES level capitalized costs were $13.6 million. Currently, 50%$1.3 billion. Once becoming operational, 75% of the expansion installed capacity is contracted with the state offtaker, GRIDCO for a period of four years through 2023 and 100% for the next 25 years with a normative after-tax ratethrough 2048. A separate trading agreement is being negotiated for the remaining 25% of return of 15.5% with an opportunity to capture additional 0.5% tied to timely completion of the project. The contract is subject to Central Electricity Regulatory Commission ("CERC") approval, which is responsible for publishing tariff determination norms every five years. The rest of the capacity is expected to be sold through competitive bid or regulated Power Purchase Agreements and a small component in the Indian merchant market.
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, basedtrading market by GRIDCO on which the coal blocks have been allocated to a subsidiarybehalf of OPGC Odisha Coal and Power Ltd. ("OCPL"), which is an OPGC joint venture with another company wholly-owned byduring the governmentfirst four years following commencement of Odisha. This new company meets the lower private ownership stipulations for allocation of mines.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 as well as existing thermal power plants viathrough their notification datedissued in December 7, 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 is evaluatinghardware to be installed to meet the options and the cost implications. The required design modification and scheduled implications for the expansion project are currently being evaluated. The impacts of these amendments are still under review, but wetightened emission requirements will require substantial investment by 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.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
operating performance of the facility;
regulatory and environmental policy changes;
tariff determination by the OERC; and
PPA provisions and energy trading.
Vietnam
Regulatory Framework and Market Structure — The Ministry of Power has issued revised Tariff PolicyIndustry and Trade in January 2016 to bring more regulatory certainty, attract private investment, ensure distribution efficiency and promote renewable energy.
Philippines
Business Description — The Masinloc power project in the Philippines is a 630 (gross) MW coal-fired plant located in Zambales, Philippines and is interconnected to the Luzon Grid. AES acquired 92% of Masinloc in 2008 (IFC is an 8% non-controlling shareholder in Masinloc). In July 2014, AES reduced its ownership to 51% through a sale to the EGCO Group, a Thailand-based power company. More than 95% of Masinloc's peak capacity and variable margin are contracted through
medium to long-term bilateral contracts primarily with Meralco, the largest distribution company in the Philippines, several electric cooperatives and industrial customers.
In January 2013, Masinloc entered into a new Power Supply Agreement ("PSA") with its main customer, Meralco, as the previous Transition Supply Contract ("TSA") expired in December 2012. The PSA is for 7 years, with an additional 3-year extension clause dependent on mutual agreement. Payments are primarily capacity-based. The PSAVietnam is primarily priced in U.S. Dollars, aligningresponsible for formulating a program to restructure the revenues withpower industry, developing the majority of variableelectricity market, and fixed costs (fuel, debt, insurance) and minimizing currency exchange risks. Masinloc's remaining contracts expire between 2016 and 2026.
Construction and Development — In December 2015, financial close was achieved for 335 MW (gross) expansion unit adjacent to the existing 630 MW plant.promulgating electricity market regulations. The project, which will employ supercritical technologyfuel supply is expected to be commercially operating in 2019. The additional capacity is targeted for sale to distribution utilities, electric cooperatives, and industrial and commercial customers in the Luzon and Visayas grids. 40% of this additional capacity has already been contracted with an expectation to have 80% capacity contractedowned by the date of commercial operations.government through Vinacomin, a state-owned entity, and Petro Vietnam.
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 16,093 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 the Luzon — Visayas generation, with coal accounting for 37%, natural gas for 17%, hydroelectric for 15%, geothermal generation for 10%,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 the remaining 21% from other generating plants such as oil, wind, biomass, and solar (priority dispatch with feed-in tariff).
The primary customers for electricity are private distribution utilities, electric cooperatives, and large contestable (industrial and commercial) customers. Approximately 90%-94% of the system's total energy requirement is currently being sold/purchased through medium (3-5 years) to long (6-10 years) term bilateral contracts. The remaining 6%-10% of energy is sold through the WESM, which is the real-time, bid-based and hourly market for energy where the sellers and the buyers adjust their differences between their production/demand and their contractual commitments.
Environmental Regulation — The Renewable Energy Act of 2008 was enacted to promote the development, utilization and commercialization of renewable energy resources, such as solar, wind, small hydroelectric and biomass energies. Under Chapter III, Section 6, the Renewable Portfolio Standard (RPS) was introduced mandating all stakeholders in the electric power industry to contribute to the growth of the renewable energy industry of the country. Under the current draft of the RPS, certain customers (e.g. distribution utilities and retail electricity suppliers) will be required to source a certain percentage of their supply from eligible renewable energy sources.implemented over the next five years. The National Renewable Energy Board ("NREB") is currently developing and implementing regulations for the RPS, including mechanisms for compliance by actual purchase of renewable energy or equivalent renewable energy certificates. If the regulations are implemented, our Retail Electricity Supply business in the Philippines could be affected by the RPS requirement.
Regulatory Framework
Electricity Regulation — The Philippines has divided itsretail market will undergo similar reforms after 2022. BOT power sector into generation, transmission, distribution and supply under the EPIRA act. The EPIRA 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 EPIRA, 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. Bilateral contracts with contestable customers do not require ERC approval to be implemented. Masinloc has obtained a retail electricity supplier license from the ERC and currently markets power to contestable customers. On June 16, 2015, ERC released a draft for the rules on mandatory contestability. According to this draft, all contestable customers with an average peak demand of more 750 kW are mandated to enter into power supply contracts by June 2016, at which point contestable customers shall be required to purchase power from licensed generation or retail suppliers instead of their local distribution utility.
Vietnam
Business Description — The Mong Duong II power project is a 1,2401,242 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 ("CSA") 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 unitsKey Financial Drivers — Financial results are driven by many factors, including, but not limited to, the operating performance and availability 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.facility.
Market Structure — The Vietnam Power market is divided into three regions (North, Central and South), with current total installed capacity of 37,604 MW, an 11% increase from 2014 (33,970 MW). The total demand in year 2015 was 141.8 billion kWh with the highest demand of 70 billion kWh in the South and 60 billion kWh in the North.
The fuel mix in Vietnam is comprised of hydropower 35% (priority dispatch with low tariff), coal 35%, gas 20%, diesel and small hydro generation 5%, oil 1% (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, the total targeted installed capacity for 2020 is approximately 75,000 MW, in which coal-fired power will account for 48%, hydropower 23%, pumped storage hydropower 2%, gas-fired thermo-power 17%, renewable energy 6%, nuclear power 1% and imported power 3%.
EVN owns 58% of installed generation capacity followed by Petro Vietnam ("PVN") 12%, Vinacomin 4%, BOT projects 8% and others 18%. 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
Electricity Regulation — The electricity sector is overseen by several key government entities, including the National Assembly, the Prime Minister, the Ministry of Industry & Trade ("MOIT") and the Electricity Regulatory Agency of Vietnam ("ERAV"), which is under the supervision of the MOIT. These entities are responsible for the issuance of laws, guidance, and implementing regulations for the sector. The MOIT, in particular, is responsible for formulating a program to restructure the power industry, develop the electricity market and promulgating electricity market regulations.
Generation, transmission and distribution are currently dominated by the EVN, despite recent inclusion of other players. Transmission and distribution companies are wholly-owned by EVN and it also owns 58% of the total installed capacity as noted above. The fuel supply is owned by the government through Vinacomin and PVN. The government plans to equitize EVN-owned generation companies and separate generation, System and Market Provider ("SMP") and distribution into three different independent operations in order to establish the competitive power market.
Other Regulatory Considerations — According to Decision 63/2013/QÐ-TTG dated November 8, 2013, the roadmap of the power market of Vietnam consists of three phases. The first phase in relation to establishment of a competitive electricity market 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 2013 onward for implementation of competitive retail electricity market. EVN as 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.
The revised Environmental Act was enacted, effective from January 1, 2015 establishing new rules in relation to, discarded materials and hazardous waste management. Additionally, new regulations on the registration of effluent and emission waste will be put into effect from the beginning of 2018 with no material impact to AES.
According to Decision No. 1696/QÐ-TTG dated September 23, 2014 on re-using of ash and gypsum discharged from coal power plants for construction material, the power plants need to propose investment and construction plans (or co-operative investment) to convert ash into construction material before 2020. There is no material impact to AES.
Sri Lanka
Business Description — AES closed the sale of Kelanitissa, a 168 MW oil-fired business with 90% ownership, on January 27, 2016 with proceeds of $18 million, with the potential to receive up to an additional $1.3 million overdue receivable from CEB.
Financial Data by Country
See the table with our consolidated operations for each of the three years ended December 31, 2015, 2014 and 2013, and property, plant and equipment as of December 31, 2015 and 2014, by country, in Note 17—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.
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 started in the 2017 ozone season (May-September 2017). Affected facilities began to receive fewer ozone season NOx allowances in 2017, resulting in the need to purchase additional allowances. While the Company's 20152017 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.
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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The EPA has released a proposed rule that would further reduce the amount of ozone season NOX allowances that would be available under the market-based program, starting in 2017. This proposed rule would not affect annual SO2 and NOX allowances. We cannot predict at this time, the impact that implementation of the revised CSAPR will have on the Company. Certain of the Company's subsidiariesbut it could be requiredmaterial if certain facilities will need to increase their capital expenditures, make operational changes or purchase additional allowances based on the open market resulting in additional compliance costs to fully comply with the CSAPR, which expenditures and costs could be material.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 coal-fired 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. To comply with the rule, many coal-fired power plants may need to install additional control technology to control acid gases, mercury or PM, or they may need to repower with an alternate fuel or retire operations. Most of the Company's U.S. coal-fired plants operated by the Company's subsidiaries comply with MATS as of April 16, 2015 using existing control technologies. However, in some cases additional time for compliance was needed in order to make necessary capital and operational changes, particularly for older facilities lacking advanced control technologies. For a discussion of the deactivation and planned deactivation of certain units owned or partially owned by IPL and DP&L as a result of existing and expected environmental regulations, including MATS, see Unit Retirement and Replacement Generation below.
IPL required additional time for compliance beyond April 16, 2015. In December 2012, IDEM granted an extension to April 16, 2016 covering all coal-fired units at Harding Street and Eagle Valley, in addition to Unit 3 and Unit 4 at Petersburg. In February 2013, IDEM granted a three-month extension on Petersburg Unit 2 to July 16, 2015, and that unit, as well as Petersburg Unit 1, which did not receive an extension, is currently in compliance with MATS.
On August 14, 2013, the IURC approved IPL's MATS plan, which included investing up to $511 million in the installation of new pollution control equipment on IPL's five largest base load generating units. These coal-fired units are located at IPL's Petersburg and Harding Street generating stations. The IURC also approved IPL's request to recover operating and construction costs for this equipment (including a return) through a rate adjustment mechanism, with certain stipulations. IPL plans to spend a total of $454 million for this project as approximately $57 million of costs will largely be avoided as a result of the approval for IPL's plans to refuel Harding Street Station Unit 7 from coal to natural gas.
Several lawsuits challenging the MATS rule were filed by other parties and consolidated into a single proceeding before the United States Court of Appeals for the District of Columbia Circuit (the "D.C Circuit"). On April 15, 2014, the D.C. Circuit denied the challenges. On June 29, 2015, the U.S. Supreme Court reversed the D.C. Circuit's decision, and remanded MATS to the D.C. Circuit for further proceedings. On December 15, 2015, the D.C. Circuit issued an order remanding MATS to the EPA without vacatur while the EPA works to comply with the U.S. Supreme Court's decision. The EPA published its revised appropriate and necessary finding on December 1, 2015 and plans to finalize it by April 15, 2016. Further proceedings are expected; however, in the meantime MATS remains in effect. We currently cannot predict the outcome of this litigation, or its impact, if any, on our MATS compliance planning 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.
DP&L's Stuart Station and Hutchings Station have received NOVs from the EPA alleging that certain activities undertaken in the past are outside the scope of the RMRR exclusion. 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 determinationsrequirements. All of the Company’s facilities that are subject to BART comply by meeting the requirements of CSAPR.
The second phase of the Regional Haze Rule begins in 2019. States must submit regional haze plans for BART-affected electric generating units, reasoning thatthis second implementation period in 2021 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 emissions reductions required bysecond implementation period. We currently cannot predict the CSAPR were "better than BART." Concurrently, EPA also finalized a limited disapprovalimpact of certain states' plans — including Ohio's — that previously reliedthis second implementation period, if any, 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.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 expected compliance date for these requirements is January 1, 2017. No impact is expected for Eagle Valley or Harding Street Generating Stations because these facilities will cease 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 to meet the emission limits imposed by the rule. The IURC approved IPL’s request for NAAQS SO2 compliance at its Petersburg generation station with 80% of qualifying costs recovered through a rate adjustment mechanism and the remainder recorded as a regulatory asset for recovery in ordera subsequent rate case. The approved capital cost of the NAAQS SO2 compliance plan is approximately $29 million. On August 15, 2018, EPA proposed to comply. IPL has engaged an engineering firm to further assess potential compliance measures and associated costs and timing. While costs associated withapprove Indiana’s State Implementation Plan addressing attainment of the proposed rule cannot accurately be predicted at this time, they could be material.2010 SO2 standard for certain locations including those of 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 Prevention of Significant Deterioration ("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, ifPSD. If 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 new source performance standards ("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 new source performance standards ("NSPS")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 Clean Power Plan (the "CPP")) also became effective.CPP). 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 filed petitionschallenged the NSPS for CO2 in the D.C. Circuit challengingCircuit. Pursuant to a court order issued in August 2017, 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 challengeslitigation is being held in indefinite abeyance pending further court order.
In addition, 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.
Because we likely will not knowOn August 31, 2018, the answersEPA 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 proposed ACE Rule would replace the EPA’s 2015 Clean Power Plan and proposes to determine that heat rate improvement measures are the best system of emission reduction for existing coal-fired electric generating units.
Due to the above questions regardingfuture uncertainty of the CPP until 2018 or later, because the first compliance period will not end until 2025, and becausepotential replacement rule, we cannot predict whetherat this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP, will surviveshould it be upheld and implemented in its current or a substantially similar form, could be material. The GHG NSPS remains in effect at this time, and, absent further action from the legal challenges,EPA that rescinds or substantively revises the NSPS, it is too sooncould impact any Company plans to determine the CPP's potentialconstruct and/or modify 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 Best Technology Available ("BTA")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 regulations will seeSWRCB OTC Policy by shutting down and permanently retiring all once-through-cooledexisting 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.stations, and there is currently no plan to replace the OTC generating units at the AES Redondo Beach generating station. The execution of the Implementation Planimplementation plan for compliance with the SWRCB's OTC Policy is entirely dependent on the Company's ability to execute on long-term power purchase agreements to support project financing of the replacement units.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. Powerreliability, 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 are currently under reviewwhich have been approved by the California Public Utilities Commission. Construction of new generating capacity 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 and a hearing has been scheduled for March 2016. 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. IPL received an extension to the compliance deadline through September 29, 2017 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 approved 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), and also to install and operate wastewater treatment technologies at Harding Street Station and Petersburg Generation Station. IPL plans to invest $319 million in these projects to ensure compliance with the wastewater treatment requirements by September 29, 2017. The deadline for Petersburg to commission a portion of the treatment system was subsequently extended to 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. ChallengesOn 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 Petersburg has installed a dry bottom ash handling system in response to thisthe CCR rule described below and wastewater treatment systems in response to the NPDES permits described above in advance of the ELG compliance date. As a result of the decision to retire Stuart and Killen generating stations, we do not expect the ELG rule to have a material impact on these two stations. While we are being consolidated instill evaluating the effects of the rule on our other U.S. Courtbusinesses, we anticipate
that the implementation of Appealsits current requirements could have a material adverse effect on our results of operations, financial condition and cash 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 Fifth Circuit. IPL expectspollutant Selenium in fresh water. NPDES permits may be updated to recover through its environmental rate adjustment mechanisminclude Selenium water quality based effluent limits based on a site-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 operating orchallenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures related to compliance with the effluent limitations requirements. Recoveryare necessary, they could be material. IPL would seek 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;capital expenditures; however, there can beis no assurances that IPL willguarantee it would be successful in thatthis regard. In light of the uncertainties at this time, we cannot predict the impact of these regulations on our consolidated results of operations, cash flows, or financial condition, but it could be material.
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, the Water Infrastructure Improvements for the Nation Act ("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 Company's U.S. subsidiaries are still analyzingEPA 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 and compliance cost associated with this final rule, and there can be no assurance that the Company's businesses,on our business, financial condition or results of operations wouldoperations.
The existing ash ponds at the Petersburg Station did not be materially and adversely affected by such rule.
Senate Bill 251 — In May 2011, Senate Bill 251 became a lawmeet certain structural stability requirements set forth in the stateCCR rule. As such, the Company was ultimately required to cease use of Indiana. Senate Bill 251 is a comprehensive bill that, among other things, provides Indiana utilities, including IPL, with a means for recovering 80% of costs incurred to comply with federal mandates through a periodic retail rate adjustment mechanism. This includes costs to comply with regulations from the EPA, FERC, the North American Electric Reliability Corporation, Department of Energy, etc., including capital intensive requirements and/or proposals described herein, such as cooling water intake regulations, waste management and coal combustion byproducts, wastewater effluent, MISO transmission expansion costs and polychlorinated biphenyls. It does not change existing legislation that allows for 100% recovery of clean coal technology designed to reduce air pollutants.all ash ponds at Petersburg by November 11, 2018.
Some of the most important features of Senate Bill 251 to IPL are as follows. Any energy utility in Indiana seeking to recover federally mandated costs incurred in connection with a compliance project shall apply to the IURC for a CPCN for the compliance project. It presents certain factors that the IURC must consider in determining whether to grant a CPCN. It further specifies that if the IURC approves a proposed compliance project and the projected federally mandated costs associated with the project, the following apply: (i) 80% of the approved costs shall be recovered by the energy utility through a periodic retail rate adjustment mechanism; (ii) 20% of the approved costs shall be deferred and recovered by the energy utility as part of the next general rate case filed with the IURC; and (iii) actual costs exceeding the projected federally mandated costs of the approved compliance project by more than 25% shall require specific justification and approval before being authorized in the energy utility's next general rate case. Senate Bill 251 also requires the IURC to adopt rules to establish a voluntary clean energy portfolio standard program. Such program will provide incentives to participating electricity suppliers to obtain specified percentages of electricity from clean energy sources in accordance with clean portfolio standard goals, including requiring at least 50% of the clean energy to originate from Indiana suppliers. The goals can also be met by purchasing clean energy credits.
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 ("PRPs") 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 PRPpotentially 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 we are 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 April 2017, 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.
As a result of existing and expected environmental regulations, including MATS, DP&L notified PJM of its plan to retire the six coal-fired units aggregating approximately 360 MW at its wholly-owned Hutchings Generation Station. Hutchings Unit 4 was retired in June 2013. In conjunction with administrative agreements reached in 2013 with the EPA and Ohio's Regional
Air Pollution Control Authority that resolved alleged violations of air quality standards, DP&L accelerated its plans with respect to Hutchings Units 1, 2, 3, 5 and 6 and those units were each retired by June 2015. DP&L removed equipment from such units so that combustion of coal was not possible after September 2013. Conversion of the coal-fired units to natural gas was investigated, but the cost of investment exceeded the expected return. In addition, DP&L owned approximately 207 MW of coal-fired generation at Beckjord Unit 6, which was operated by Duke Energy Ohio. Beckjord Unit 6 was retired effective October 1, 2014. At this time, DP&L does not have plans to replace the units that have been or will be retired.
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 20152018 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.
Employees — As of December 31, 2015, we employed approximately 21,000 people.
Executive Officers—
The following individuals are our executive officers:
Michael ChiltonSanjeev Addala, 56 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, 5253 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, AES Chivor & Cia S.C.A. E.S.P. 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, 58 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 Executive Vice President ("EVP") 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 to 2016, Mr. Gluski currently servesserved on President Obama's Export Council, the US-Brazil CEO Forum and the US-India CEO Forum. HeCouncil. Mr. Gluski is a member of the Board of Waste
Management and is Chairman of 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, 55 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 Dayton PowerRetail Operations, and Vice President, Environmental, Health & Light ("DP&L") and its parent company DPL, Inc. AES Cochrane and AES Chivor.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, 4043 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, 50 39 years old, is an EVP ofhas served as Senior Vice President, Corporate Strategy and Investments and Chief Risk Officer since May 2017. Previously Mr. Moreno served as the Company, General Counsel,Chief Financial Officer, Europe SBU from May 2015 to April 2017 and Corporate Secretary.as a Managing Director on AES’ Mergers & Acquisitions team from January 2012 to April 2015. Since joining AES in 2006, Mr. Miller joined the Company in 2001 andMoreno has served in various positions including VP, Deputy General Counsel, Corporate Secretary, General Counsel for North America and Assistant General Counsel.throughout the Company. Mr. Miller served on the Boards of AES Entek, a joint venture between AES and Koc Holdings in Turkey, from 2010 through 2014; and Silver Ridge Power, a joint venture between AES and Riverstone Holdings LLC, from 2008 through July of 2014. Mr. Miller is the chairman of Indianapolis Power and Light Board and DP&L. Mr. Miller alsoMoreno serves as a member of the Board of DPL, Inc.DP&L and AES Chivor.Tiete. Prior to joining AES he was an attorney with 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, 5652 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. ("TDI"), 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 andRubiolo serves as a member ofon 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 is Chairman of the Institute for Sustainability and Energy at Northwestern University. 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 26, 2015.8, 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, 2015,2018, we had approximately $20.8$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 1210.—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, 2015,2018, we had approximately $20.8$19.3 billion of outstanding indebtedness on a consolidated basis, of which approximately $5.0$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 $1.0 billion$351 million as of December 31, 2015.2018. 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. Any number of assumptions could prove to be incorrect,dividends and therefore thereother distributions. There 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 offor 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 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 US 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 United States, including in developing countries, which presents significant risks.
A significant amount of our revenue is generated outside the 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.
Our inability to attract and retain skilled people 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.
62Our businesses will need to continue to adapt to technological change and we may incur significant expenditures to adapt to these changes.
SomeEmerging 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 riskspolicies 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 exacerbatedtargeted 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 current global economic crisis, includingrelease 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 management's increased focus on liquidity, which may also 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 projects we can pursue. Thecustomers 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 downturnand 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 also impacthave 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 assetslargest plans include a significant weighting of investments in these countries andfixed 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 ability to develop these projects. Ifsignificant assumptions underlying the valueestimates of these assets decline, thisour subsidiaries' pension plan obligations, could result in a material impairment or a seriesan 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 impairments which are material inpension plan assets as compared to pension obligations under the aggregate, which wouldpension plan. Satisfying such funding requirements may necessitate additional cash contributions to the pension plans that could adversely affect the Parent Company and our financial statements.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, 2015,2018, the Company had approximately $1.2$1.1 billion of goodwill, which represented approximately 3.1%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 or more frequently if potential impairment indicators are present. Otherwise,basis.
Any of the recoverability assessment of long-lived assets is similar to the potential impairment evaluation of goodwill particularly as it relates to the identification of potential impairment indicators, and making estimates and assumptions to determine fair value, as described above.
Certain 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 United States generationU.S. 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)("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 2015,2018, the Company's subsidiaries operated businesses whichthat had total CO2 emissions of approximately 67.655 million metric tonnes, approximately 27.423 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 7.87 million metric tonnes (ownership adjusted). This overall estimate is based on a number of projections and assumptions whichthat 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. 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 Clean Power Plan ("CPP"), that 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 recently issued orders 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 mandatory GHG reductions from several 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 United States 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 regional auctions of RGGI allowances needed to be acquired 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 2015. Of the approximately 27.4 million metric tonnes of CO2 emitted in the United States by our subsidiaries in 2015 (ownership adjusted), approximately 1.4 million metric tonnes were emitted by our subsidiary in Maryland. The Company estimates that the RGGI compliance costs could be approximately $3.4 million for 2016. 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. Unless the United States Congress acts to preempt such suits as part of comprehensive federal legislation, additionalWhile these lawsuits may be brought against the Company or its subsidiaries in the future. While the litigation mentioned has beenwere 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 U.S. internationalevolve in future periods as further administrative guidance and regulations are issued, which may materially affect our effective tax rulesrate or tax payments. For further details, please see Item 7.—Management's Discussion and corporate tax rates. Analysis of Financial Condition and 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, recently concludedthrough its Base Erosion and Profit Shifting project (“BEPS") withintroduced 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, United StatesU.S. federal, state and local, as well as non-United States,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 |
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, 2015.
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 for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$1.8 billion ($458 million) from Eletropaulo (as estimated by Eletropaulo (or approximately R$2.2 billion ($571 million)) plus legal costs according to Eletrobrás as of June 2015 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 that concluded that Eletropaulo is liable for the debt, without quantifying the debt. Eletropaulo has submitted questions to the expert and reports rebutting the expert's preliminary report. The expert will issue a final report in the near future. Thereafter, a decision will be issued by the FDC, which will be free to reject or adopt in whole or in part the expert's
final 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, after the amount of the alleged debt is determined, Eletropaulo will be required to provide security for its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the FDC grants such request, Eletropaulo's results of operations may be materially adversely affected and, in turn, the Company's results of operations could be materially adversely affected. 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.
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$1.8 million ($461 thousand) as of December 31, 2015, or pay an indemnification amount of approximately R$15 million ($4 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$1.8 million ($461 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$2 million ($512 thousand).2018.
In December 2001, Gridco Ltd. ("Gridco"Grid 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"ODPL”), and Jyoti Structures ("Jyoti"(“Jyoti”) pursuant to the terms of the shareholders agreement between Gridco,GRIDCO, the Company, AES ODPL, Jyoti and the Central Electricity Supply Company of Orissa Ltd. ("CESCO"(“CESCO”), an affiliate of the Company. In the arbitration, GridcoGRIDCO 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. GridcoGRIDCO. 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.GRIDCO. The Company counterclaimed against GridcoGRIDCO for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco'sGRIDCO's claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco.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. GridcoGRIDCO filed challenges of the tribunal's awards with the local Indian court. Gridco'sGRIDCO'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 to the Superior Court of Justice. The lawsuit remains pending before the FCSP, but it will remain suspended until the
interlocutory appeal has been finally decided. 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"(“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 ($158 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 in the ICC 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 in the ICC 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 it was determined that AESU was responsible for the termination of the GSA, AESU was liable for TGM's alleged losses, including losses under the TA. In April 2011, the arbitrations were consolidated into a single proceeding. The hearing on liability issues took place in December 2011. In May 2013, the arbitral tribunal issued a liability award in AESU's favor. YPF thereafter challenged the award in Argentine court. In December 2015, an Argentine court issued a decision purporting to annul the liability award. AESU has sought reconsideration of that decision. The damages hearing in the arbitration took place on November 16-17, 2015. The tribunal has not issued a damages award to date. AESU believes it has meritorious claims and defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.
In April 2009, the Antimonopoly Agency in Kazakhstan initiated an investigation of certain power sales of Ust-Kamenogorsk HPP ("UK HPP") and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the "Hydros"). The Antimonopoly Agency determined that the Hydros had abused their market position and charged monopolistically high prices for power from January-February 2009. Administrative proceedings followed, but were later suspended due to the initiation of related criminal proceedings against officials of the Hydros. Recently, the Antimonopoly Agency terminated its investigation of the Hydros due to the expiration of the relevant statute of limitations.
In October 2009, AES Mérida III, S. de R.L. de C.V. ("AES Mérida"), one of our businesses in Mexico, initiated arbitration against its fuel supplier and electricity offtaker, Comisión Federal de Electricidad ("CFE"), seeking a declaration that CFE breached the parties' PPA by supplying gas that did not comply with the PPA's specifications. Alternatively, AES Mérida requested a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputed the claims. Although it did not assert counterclaims, in its closing brief CFE asserted that it is entitled to a partial refund of the capacity charge payments that it made for power generated with the out-of-specification gas. In July 2012, the arbitral tribunal issued an award in AES Mérida's favor. In December 2012, CFE initiated an action in Mexican court seeking to nullify the award. AES Mérida opposed the request and asserted a counterclaim to confirm the award. In February 2014, the court rejected CFE's claims and granted AES Mérida's request to confirm the award. CFE has appealed the court's decision. The appeal is pending before the Mexican Supreme Court. AES Mérida believes it has meritorious grounds to defeat that action; however, there can be no assurances that it will be successful.
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. Since receiving the letter, IPL management has 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 November 2009, April 2010, December 2010, April 2011, June 2011, August 2011, November 2011, and October 2014, substantially similar personal injury lawsuits were filed by a total of 50 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the state of Delaware. In each lawsuit, the plaintiffs allege that the coal combustion by-products of AES Puerto Rico's power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs' birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The AES defendants moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs' international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. In November 2011, the AES defendants again moved for partial dismissal of those amended complaints, and in both lawsuits, the Superior Court dismissed the plaintiffs' claims for future medical monitoring expenses but declined to dismiss their claims under Dominican Republic Law 64-00. The AES defendants filed an answer to the November 2009 lawsuit in June 2012. The Superior Court has stayed all lawsuits but the November 2009 lawsuit. In that lawsuit, discovery is complete on causation and exposure issues, but is ongoing on other liability issues as well as damages issues. Based on the information they have disclosed during discovery, the plaintiffs in the November 2009 lawsuit appear to be seeking a total of approximately $30 million for life care assistance and lost earnings, additional but unspecified amounts for moral damages, and additional but unspecified damages for loss of consortium and deaths. Also, in the November 2009 lawsuit, trial is scheduled for April 2016. The AES defendants believe they have meritorious defenses and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.
On February 11, 2011, Eletropaulo received a notice of violation from São Paulo State's Environmental Authorities for allegedly destroying 0.32 hectares of native vegetation at the Conservation Park of Serra do Mar ("Park"), without previous authorization or license. The notice of violation asserted a fine of approximately R$1 million ($256 thousand) and the suspension of Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities ("São Paulo EA"), Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the NOV or reduce the fine. In December 2011, the São Paulo EA declined to vacate the NOV but reduced the fine to R$757 thousand ($194 thousand) and recognized the possibility of an additional 40% reduction of the fine if Eletropaulo agrees to recover the affected area with additional vegetation. Eletropaulo did not appeal the decision and discussed the terms of a possible settlement with the São Paulo EA, including a plan to recover the affected area by primarily planting additional trees. In March 2012, the state of São Paulo Prosecutor's Office of São Bernardo do Campo initiated a Civil Proceeding to review the compliance by Eletropaulo with the terms of any possible settlement. The Park Administrator subsequently approved an area for the recovery project different from the affected area, which was no longer available. On January 23, 2015, AES Eletropaulo entered into a Recovery and Compensation Agreement with the Coordenadoria de Fiscalização Ambiental ("CFA") to restore 3.2 hectares during the course of two years, which restoration is currently estimated to cost R$592 thousand ($152 thousand). In June 2015, the state of São Paulo Prosecutor's Office of São Bernardo do Campo decided to close its Civil Proceeding, subject to the approval of the Superior Counsel of the Public Prosecutor's Office. Upon completion of the recovery project as approved and established in the Recovery and Compensation Agreement, AES will be entitled to a 40% reduction (R$303 thousand or $78 thousand) of the fine as legally provided.
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 ground that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$3.3 billion ($843 million) as estimated by Eletropaulo. Eletropaulo thereafter appealed to the Second Instance Administrative Court ("SIAC"). In January 2016, the Tax Authority reduced the total amount of the ISS assessments to approximately R$228 million ($58 million). The reduced amount of ISS remains under consideration by the SIAC. No tax is due while the appeal is pending. 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 groundgrounds that the tax rate was set in the applicable legislation. In April 2013, the First Instance Administrative CourtFIAC 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$910 million1.21 billion ($233312 million) as estimated by AES Tietê. AES Tietê appealed to the SIAC. In January 2015, the Second Instance Administrative Court (“SIAC”("SIAC"). In January 2015, the 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 (“Special Appeal”), which was rejected as untimely in October 2016. The Tax Authority thereafter filed an interlocutory appeal 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 remains pending.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 August 2012, Fondo Patrimonial de las Empresas Reformadas (“FONPER”) (the Dominican instrumentality that holdsJanuary 2015, DPL received NOVs from the Dominican Republic's sharesEPA alleging violations of opacity at Stuart and Killen Stations, and in Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”)) filed a criminal complaint against certain current and former employees of AES. The criminal proceedings include a related civil component initiated against, among others, Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NC”) (the AES affiliate that manages Itabo). FONPER asserts claims relating to the alleged mismanagement of Itabo and seeks approximately $270 million in damages. The Dominican District Attorney (“DA”) thereafter admitted the criminal complaint and requested that the Dominican Republic's Cámara de Cuentas (“Cámara”) perform an audit of the allegations in the criminal complaint. In October 2015, IPL received a similar NOV alleging violations at Petersburg Station. In February 2017, the CámaraEPA issued its final report, determining thata second NOV for DPL Stuart Station, alleging violations of opacity in 2016. Moreover, in February 2016, IPL received an NOV from the contested actionsEPA alleging violations of NSR and other CAA regulations, the AES employees were in accordance with Dominican law. Further, in August 2012, Coastal and NC initiated an international arbitration proceeding against FONPERIndiana SIP, and the Dominican Republic (“Respondents”), seekingTitle V operating permit at Petersburg Station. It is too early to determine whether the NOVs could have a declaration that Coastal and NC have acted both lawfully and in accordance with the relevant contracts with the Respondents in relationmaterial 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 the management of Itabo. Coastal and NC also seek a declaration that the criminal complaint is a breach of the relevant contracts between the parties, including the obligationair pollution control technology to arbitrate disputes. Coastal and NC further seek damages from the Respondents resulting from their breach of contract. The Respondents have denied the claims and challenged the jurisdiction of the arbitral tribunal. In February 2015, the Respondents made an application requesting that the tribunal rule on their jurisdictional objections prior to giving any consideration to the merits of the claims of Coastal and NC. In August 2015, the tribunal rejected the application. The tribunal has established the procedural schedule for the arbitration, but has not yet scheduled dates for the final evidentiary hearing. At the parties' request, the Tribunal has suspended the arbitration until July 30, 2016. The AES parties believe they have meritorious claims and defenses, which they will assert vigorously;reduce regulated air emissions; however, there can be no assurances that they willwe would be successful in their efforts.
In July 2015, BTG Pactual (“BTG”) initiated arbitration against AES Tietê under the parties' PPA. BTG claims that AES Tietê breached the PPA by purchasing more power than it was entitled to take under the PPA. BTG seeks to recover the payments that AES Tietê received from its spot-market sales of BTG's power, totaling approximately R$30 million ($8 million). BTG also seeks to terminate the PPA and to collect a termination payment of approximately R$560 million ($143 million). AES Tietê has placed R$30 million ($8 million) into escrow, with a full reservation of rights. AES Tietê has responded to the arbitration demand, contesting the claims against it. AES Tietê believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in this proceeding; however, there can be no assurances that it will be successful in its efforts.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 firstinitially by GG and latercurrently by CT, and that AES Panama must pay compensation for its use of the land. The damages sought from AES Panama are approximately $680$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. GG has 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 to theand claims asserted against it and will defend itself vigorously in the lawsuits;assert them vigorously; however, there can be no assurances that it will be successful in its efforts.
In January 2015, DPL received NOVs2017, 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 EPA alleging violationsEnvironmental Evaluation Service (“SEA”) an acceptable interpretation of opacity at Stuartthe 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 Killen Stations, and in October 2015, IPL received a similar NOV alleging violations at Petersburg Station. In February 2016, IPL received an NOVtreatment of Infiltration Water. Alto Maipo continues to seek the relevant final approvals from the EPA alleging violationsSEA. Furthermore,
in May 2018, three lawsuits were filed with the Environmental Court of NSRSantiago (“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 other CAA regulations,if the Indiana SIP,above-referenced lawsuits are dismissed, the Formulation of Charges will be discharged without penalty. Otherwise, Alto Maipo could be subject to penalties, and the Title V operating permit at Petersburg Station. It is too early to determine whetherconstruction of the NOVsproject could have a material impact on our business, financial
condition or results of our operations. We would seek recovery of any operating or capital expenditures for IPL, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions;be negatively impacted. Alto Maipo will pursue its interests vigorously in these matters; however, there can be no assurances that we wouldit 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 regard.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 |
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
In October 2015, the Company's Board of Directors approved an increase of $400 million to the stock repurchase program (the "Program") under which the Company can repurchase AES common stock.— 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, 2015, the Company repurchased 39.7 million shares of its common stock at a total cost of $482 million under the existing stock repurchase program. The cumulative repurchase from the commencement of the Stock Repurchase Program in July 2010 through December 31, 20152018 is 145.6154.3 million shares at a total cost of $1.8$1.9 billion, at an average price per share of $12.31$12.12 (including a nominal amount of commissions).
The following table presents information regarding As of December 31, 2018, $264 million remained available for repurchase under the Stock Repurchase Program. No repurchases were made by The AES Corporation of its common stock in the fourth quarter2018 and 2017, respectively. The Parent Company repurchased 8,686,983 shares of 2015.its common stock in 2016.
|
| | | | | | | | | | | | | | |
| Repurchase Period | | Total Number of Shares Purchased | | Average Price Paid Per Share | | Total Number of Shares Repurchased as Part of a Publicly Announced Purchase Plan | | Dollar Value of Maximum Number of Shares to be Purchased Under the Plan |
| 10/1/2015 - 10/31/15 | | 1,598,910 |
| | $ | 10.03 |
| | 1,598,910 |
| | $ | 400,312,942 |
|
| 11/1/2015 - 11/30/15 | | 1,584,932 |
| (1) | 10.02 |
| | 1,564,682 |
| | 385,040,330 |
|
| 12/1/2015 - 12/31/15 | | 4,495,268 |
| | 9.35 |
| | 4,495,268 |
| | 343,035,214 |
|
| Total | | 7,679,110 |
| | | | 7,658,860 |
| | |
(1)Includes 20,250 shares purchased by an executive of the Company in November 2015 that were not under the publicly announced stock repurchase program.
Market Information
Our common stock is currently 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 18, 2016, was $9.70 per share. The Company repurchased 39,684,131, 21,900,246, and 25,297,042 shares of its common stock in 2015, 2014 and 2013, respectively. The following tables present the high and low intraday sale prices of our common stock and cash dividends declared for the periods indicated:
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| | | | | | | | | | | | | | | | | | | | | | | |
| | 2015 | | 2014 |
| | Sales Price | | Cash Dividends | | Sales Price | | Cash Dividends |
| | High | | Low | | Declared | | High | | Low | | Declared |
| First Quarter | $ | 13.87 |
| | $ | 11.53 |
| | $ | — |
| | $ | 14.94 |
| | $ | 13.42 |
| | $ | — |
|
| Second Quarter | 14.02 |
| | 12.64 |
| | 0.10 |
| | 15.65 |
| | 13.42 |
| | 0.05 |
|
| Third Quarter | 13.40 |
| | 9.42 |
| | 0.10 |
| | 15.64 |
| | 14.01 |
| | 0.05 |
|
| Fourth Quarter | 11.21 |
| | 8.76 |
| | 0.21 |
| | 14.49 |
| | 12.38 |
| | 0.15 |
|
Dividends
The Parent Company commenced a quarterly cash dividend of $0.04 per share beginning in the fourth quarter of 2012, which2012. The Parent Company has increased to $0.05 per share beginning inthis dividend annually and the quarterly cash dividend for the last three years are displayed below.
|
| | | | | | |
| Commencing the fourth quarter of | | 2018 | | 2017 | | 2016 |
| Cash dividend | | $0.1365 | | $0.13 | | $0.12 |
The fourth quarter of 2013, and increased2018 cash dividend is to $0.10 per share in the fourth quarter of 2014. During the fourth quarter of 2015, the Board of Directors voted to increase the quarterly dividend to $0.11 per share, beginningbe paid in the first quarter of 20162019. 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 18, 2016,21, 2019, there were approximately 4,7023,875 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 3127 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, 20152018 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 27—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
| | | | 2015 | | 2014 | | 2013 | | 2012 | | 2011(1) | 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 | $ | 14,963 |
| | $ | 17,146 |
| | $ | 15,891 |
| | $ | 17,164 |
| | $ | 16,098 |
| $ | 10,736 |
| | $ | 10,530 |
| | $ | 10,281 |
| | $ | 11,260 |
| | $ | 12,604 |
|
Income (loss) from continuing operations(2)(1) | 762 |
| | 1,176 |
| | 730 |
| | (420 | ) | | 1,602 |
| 1,349 |
| | (148 | ) | | 191 |
| | 682 |
| | 941 |
|
| Income (loss) from continuing operations attributable to The AES Corporation, net of tax | 306 |
| | 789 |
| | 284 |
| | (960 | ) | | 506 |
| 985 |
| | (507 | ) | | (20 | ) | | 318 |
| | 678 |
|
| Discontinued operations, net of tax | — |
| | (20 | ) | | (170 | ) | | 48 |
| | (448 | ) | |
Income (loss) from discontinued operations attributable to The AES Corporation, net of tax (2) | | 218 |
| | (654 | ) | | (1,110 | ) | | (12 | ) | | 91 |
|
| Net income (loss) attributable to The AES Corporation | $ | 306 |
| | $ | 769 |
| | $ | 114 |
| | $ | (912 | ) | | $ | 58 |
| $ | 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 | $ | 0.45 |
| | $ | 1.10 |
| | $ | 0.38 |
| | $ | (1.27 | ) | | $ | 0.65 |
| |
| Discontinued operations, net of tax | — |
| | (0.03 | ) | | (0.23 | ) | | 0.06 |
| | (0.58 | ) | |
| Basic earnings (loss) per share | $ | 0.45 |
| | $ | 1.07 |
| | $ | 0.15 |
| | $ | (1.21 | ) | | $ | 0.07 |
| |
| 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 | $ | 0.44 |
| | $ | 1.09 |
| | $ | 0.38 |
| | $ | (1.27 | ) | | $ | 0.65 |
| |
| Discontinued operations, net of tax | — |
| | (0.03 | ) | | (0.23 | ) | | 0.06 |
| | (0.58 | ) | |
| Diluted earnings (loss) per share | $ | 0.44 |
| | $ | 1.06 |
| | $ | 0.15 |
| | $ | (1.21 | ) | | $ | 0.07 |
| |
| 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 | $ | 0.41 |
| | 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 | $ | 2,134 |
| | $ | 1,791 |
| | $ | 2,715 |
| | $ | 2,901 |
| | $ | 2,884 |
| $ | 2,343 |
| | $ | 2,504 |
| | $ | 2,897 |
| | $ | 2,136 |
| | $ | 1,800 |
|
| Net cash used in investing activities | (2,366 | ) | | (656 | ) | | (1,774 | ) | | (895 | ) | | (4,906 | ) | (505 | ) | | (2,599 | ) | | (2,136 | ) | | (2,128 | ) | | (1,075 | ) |
| Net cash provided by (used in) financing activities | 28 |
| | (1,262 | ) | | (1,136 | ) | | (1,867 | ) | | 1,412 |
| (1,643 | ) | | 43 |
| | (747 | ) | | 28 |
| | (1,262 | ) |
| Total (decrease) increase in cash and cash equivalents | (277 | ) | | (103 | ) | | (258 | ) | | 276 |
| | (736 | ) | |
| Cash and cash equivalents, ending | 1,262 |
| | 1,539 |
| | 1,642 |
| | 1,900 |
| | 1,624 |
| |
| 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 | $ | 36,850 |
| | $ | 38,966 |
| | $ | 40,411 |
| | $ | 41,830 |
| | $ | 45,346 |
| $ | 32,521 |
| | $ | 33,112 |
| | $ | 36,124 |
| | $ | 36,545 |
| | $ | 38,676 |
|
| Non-recourse debt (noncurrent) | 13,263 |
| | 13,618 |
| | 13,318 |
| | 12,265 |
| | 13,261 |
| 13,986 |
| | 13,176 |
| | 13,731 |
| | 12,184 |
| | 12,077 |
|
| Non-recourse debt (noncurrent)—Discontinued operations | — |
| | — |
| | 124 |
| | 322 |
| | 1,369 |
| — |
| | — |
| | 758 |
| | 772 |
| | 1,226 |
|
| Recourse debt (noncurrent) | 5,015 |
| | 5,107 |
| | 5,551 |
| | 5,951 |
| | 6,180 |
| 3,650 |
| | 4,625 |
| | 4,671 |
| | 4,966 |
| | 5,047 |
|
| Redeemable stock of subsidiaries | 538 |
| | 78 |
| | 78 |
| | 78 |
| | 78 |
| 879 |
| | 837 |
| | 782 |
| | 538 |
| | 78 |
|
| Retained earnings (accumulated deficit) | 143 |
| | 512 |
| | (150 | ) | | (264 | ) | | 678 |
| (1,005 | ) | | (2,276 | ) | | (1,146 | ) | | 143 |
| | 512 |
|
| The AES Corporation stockholders' equity | 3,149 |
| | 4,272 |
| | 4,330 |
| | 4,569 |
| | 5,946 |
| 3,208 |
| | 2,465 |
| | 2,794 |
| | 3,149 |
| | 4,272 |
|
_____________________________
| |
(1) | On November 28, 2011, AES completed the acquisition of 100% of the common stock of DPL Inc. Its results of operations have been included in AES's consolidated results of operations from the date of acquisition. |
| |
(2)
| Includes pretax impairment expensepre-tax gains on sales of $602business interests of $984 million, $383$29 million, $596$29 million $1.9 billion, and $272$358 million for the years ended December 31, 2018, 2016, 2015 and 2014, 2013, 2012respectively, and 2011,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 9—Other Non-Operating Expense23—Held-for-Sale and Dispositions, Note 10—8—Goodwill and Other Intangible Assets and, Note 21—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 Topics in Management's DiscussionExecutive Summary
In 2018, AES delivered strong financial results and Analysis
Our discussion coversachieved significant milestones on its strategic goals, including continuing to enhance the following:
Strategic Performanceresilience 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 2015our Strategy included in Item 1.—Business of this Form 10-K for further information.
During 2018, the Company saw increased margins at its South America, MCAC and US 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.
Overview of 2018 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 Electrica 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.
SBU Performance Analysis
Key Trends and Uncertainties
Capital Resources and Liquidity
Overview of 2015 Results and Strategic Performance
In 2015, we faced tough macroeconomic headwinds, including up to 30% devaluation in some of our key currencies, including the Brazilian Real, Colombian Peso and Euro. We also saw more than 40% declines in oil and natural gas prices, which have an impact on our businesses in the Dominican Republic, Ohio and Northern Ireland. Additionally, Brazil's GDP continued to contract. Despite these continuing challenging conditions, we did what we are good at — adapted to the changes in circumstances and took actions to mitigate their impact on our businesses and on our financial results. We successfully executed on our strategy and achieved the majority of our objectives by: delivering Proportional Free Cash Flow of $1,241 million, up 39% compared to 2014, and Adjusted EPS of $1.22; prudently allocating our capital; and advancing select platform expansion projects across our portfolio.
Management's Strategic Priorities
Management is focused on the following priorities:
Reducing complexity: By exiting businesses and markets where we do not have a competitive advantage, we are simplifying our portfolio and reducing risk. During 2015, we announced or closed $787 million in equity proceeds from the sales or sell-downs of seven businesses.
Leveraging our platforms: We are focusing our growth on platform expansions in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns. We currently have 5,620 MW under construction, representing $7 billion in total capital expenditures, with 85% of AES' $1.2 billion in equity already funded. We expect the majority of these projects to come on-line through 2018. Beyond the projects we currently have under construction, we will continue to advance select projects from our development pipeline.
Performance excellence: We strive to be the low-cost manager of a portfolio of assets and to derive synergies and scale from our businesses. In November, we launched a $150 million cost reduction and revenue enhancement initiative. This initiative will include overhead reductions, procurement efficiencies and operational improvements. We expect to achieve at least $50 million in savings in 2016, ramping up to $150 million, including modest revenue enhancements, in 2018.
Expanding access to capital: We are building strategic partnerships at the project and business level. Through these partnerships, we aim to optimize our risk-adjusted returns in our existing businesses and growth projects. By selling down portions of certain businesses, we can adjust our global exposure to commodity, fuel, country and other macroeconomic risks. Partial sell-downs of our assets can also serve to highlight or enhance the value of businesses in our portfolio.
Allocating capital in a disciplined manner: Our top priority is to maximize risk-adjusted returns to our shareholders, which we achieve by investing our discretionary cash and recycling the capital we receive from asset sales and strategic partnerships. In 2015, we generated substantial cash by executing on our strategy, which we allocated in line with our capital allocation framework:
| |
◦ | Used $345 million to prepay and refinance Parent debt; |
| |
◦ | returned $757 million to shareholders through share repurchases and quarterly dividends; |
| |
▪ | increased our quarterly dividend by 10%, to $0.11 per share, beginning in the first quarter of 2016; |
| |
◦ | invested $114 million in our subsidiaries, largely for projects that are currently under construction. |
2015 Strategic Performance
Earnings Per Share and Proportional Free Cash Flow Results in 2015 (in millions, except per share amounts)
|
| | | | | | | | | | | |
| Years Ended December 31, | 2015 | | 2014 | | 2013 |
| Diluted earnings per share from continuing operations | $ | 0.44 |
| | $ | 1.09 |
| | $ | 0.38 |
|
Adjusted earnings per share (a non-GAAP measure)(1) | 1.22 |
| | 1.30 |
| | 1.29 |
|
| Net cash provided by operating activities | 2,134 |
| | 1,791 |
| | 2,715 |
|
Proportional Free Cash Flow (a non-GAAP measure)(1) | 1,241 |
| | 891 |
| | 1,271 |
|
_____________________________
| |
(1)
| See reconciliation and definition under Non-GAAP Measures.
|
Diluted earnings per share from continuing operations decreased by 60% to $0.44 primarily due to higher impairment expense and lower gains from sales of businesses, partially offset by lower debt extinguishment expense.
Adjusted EPS, a non-GAAP measure, decreased by 6% to $1.22 primarily due to the devaluation of foreign currencies in Latin America and Europe, the impact of lower commodity prices in certain markets, and lower demand in Brazil. These negative impacts were partially offset by a 5% reduction in shares outstanding, lower Parent interest expense, improved hydrological conditions in Panama, and contributions from new businesses, including Mong Duong in Vietnam.
Net cash provided by operating activities increased by 19% to $2.1 billion primarily due to the timing of collections in the Dominican Republic as well as increases at the Parent Company primarily driven by lower interest payments and lower payments for capital expenditures, partially offset by collections on lower margins resulting from economic slowdown, timing of energy purchases and higher interest payments in Brazil.
Proportional free cash flow increased by 39% to $1.2 billion primarily due to the timing of collections in the Dominican Republic as well as increases at the Parent Company primarily driven by lower interest payments and lower payments for maintenance capital expenditures.
Safe Operations
Safety is our first value and a top priority. We consistently analyze and evaluate our safety performance in order to capture lessons learned and strengthen mitigation plans that improve our safety performance.
Review of Consolidated Results of Operations
|
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, | 2015 | | 2014 | | 2013 | | % Change 2015 vs. 2014 | | % Change 2014 vs. 2013 |
| Results of operations | (in millions, except per share amounts) | | | | |
| Revenue: | | | |
| US SBU | $ | 3,593 |
| | $ | 3,826 |
| | $ | 3,630 |
| | -6 | % | | 5 | % |
| Andes SBU | 2,489 |
| | 2,642 |
| | 2,639 |
| | -6 | % | | — | % |
| Brazil SBU | 4,666 |
| | 6,009 |
| | 5,015 |
| | -22 | % | | 20 | % |
| MCAC SBU | 2,353 |
| | 2,682 |
| | 2,713 |
| | -12 | % | | -1 | % |
| Europe SBU | 1,191 |
| | 1,439 |
| | 1,347 |
| | -17 | % | | 7 | % |
| Asia SBU | 684 |
| | 558 |
| | 550 |
| | 23 | % | | 1 | % |
| Corporate and Other | 31 |
| | 15 |
| | 7 |
| | 107 | % | | 114 | % |
| Intersegment eliminations | (44 | ) | | (25 | ) | | (10 | ) | | -76 | % | | -150 | % |
| Total Revenue | 14,963 |
| | 17,146 |
| | 15,891 |
| | -13 | % | | 8 | % |
| Operating Margin: | | | | | | | | | |
| US SBU | 621 |
| | 699 |
| | 668 |
| | -11 | % | | 5 | % |
| Andes SBU | 618 |
| | 587 |
| | 533 |
| | 5 | % | | 10 | % |
| Brazil SBU | 600 |
| | 742 |
| | 871 |
| | -19 | % | | -15 | % |
| MCAC SBU | 543 |
| | 541 |
| | 543 |
| | — | % | | — | % |
| Europe SBU | 303 |
| | 403 |
| | 415 |
| | -25 | % | | -3 | % |
| Asia SBU | 149 |
| | 76 |
| | 169 |
| | 96 | % | | -55 | % |
| Corporate and Other | 33 |
| | 53 |
| | 25 |
| | -38 | % | | 112 | % |
| Intersegment eliminations | (1 | ) | | (13 | ) | | 23 |
| | 92 | % | | -157 | % |
| Total Operating Margin | 2,866 |
| | 3,088 |
| | 3,247 |
| | -7 | % | | -5 | % |
| General and administrative expenses | (196 | ) | | (187 | ) | | (220 | ) | | 5 | % | | -15 | % |
| Interest expense | (1,436 | ) | | (1,471 | ) | | (1,482 | ) | | -2 | % | | -1 | % |
| Interest income | 524 |
| | 365 |
| | 275 |
| | 44 | % | | 33 | % |
| Loss on extinguishment of debt | (186 | ) | | (261 | ) | | (229 | ) | | -29 | % | | 14 | % |
| Other expense | (65 | ) | | (68 | ) | | (76 | ) | | -4 | % | | -11 | % |
| Other income | 83 |
| | 124 |
| | 125 |
| | -33 | % | | -1 | % |
| Gain on sale of businesses | 29 |
| | 358 |
| | 26 |
| | -92 | % | | NM |
|
| Goodwill impairment expense | (317 | ) | | (164 | ) | | (372 | ) | | 93 | % | | -56 | % |
| Asset impairment expense | (285 | ) | | (91 | ) | | (95 | ) | | 213 | % | | -4 | % |
| Foreign currency transaction gains (losses) | 105 |
| | 11 |
| | (22 | ) | | 855 | % | | 150 | % |
| Other non-operating expense | — |
| | (128 | ) | | (129 | ) | | -100 | % | | -1 | % |
| Income tax expense | (465 | ) | | (419 | ) | | (343 | ) | | 11 | % | | 22 | % |
| Net equity in earnings of affiliates | 105 |
| | 19 |
| | 25 |
| | 453 | % | | -24 | % |
| INCOME FROM CONTINUING OPERATIONS | 762 |
| | 1,176 |
| | 730 |
| | -35 | % | | 61 | % |
| Income (loss) from operations of discontinued businesses | — |
| | 27 |
| | (27 | ) | | -100 | % | | 200 | % |
| Net loss from disposal and impairments of discontinued operations | — |
| | (56 | ) | | (152 | ) | | -100 | % | | -63 | % |
| NET INCOME | 762 |
| | 1,147 |
| | 551 |
| | -34 | % | | 108 | % |
| Noncontrolling interests: | | | | | | | | | |
| (Income) from continuing operations attributable to noncontrolling interests | (456 | ) | | (387 | ) | | (446 | ) | | 18 | % | | -13 | % |
| Loss from discontinued operations attributable to noncontrolling interests | — |
| | 9 |
| | 9 |
| | -100 | % | | — | % |
| NET INCOME ATTRIBUTABLE TO THE AES CORPORATION | $ | 306 |
| | $ | 769 |
| | $ | 114 |
| | -60 | % | | 575 | % |
| AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS: | | | | | | |
| |
|
| Income from continuing operations, net of tax | $ | 306 |
| | $ | 789 |
| | $ | 284 |
| | -61 | % | | 178 | % |
| Loss from discontinued operations, net of tax | — |
| | (20 | ) | | (170 | ) | | -100 | % | | -88 | % |
| Net income | $ | 306 |
| | $ | 769 |
| | $ | 114 |
| | -60 | % | | 575 | % |
| Net cash provided by operating activities | $ | 2,134 |
| | $ | 1,791 |
| | $ | 2,715 |
| | 19 | % | | -34 | % |
| DIVIDENDS DECLARED PER COMMON SHARE | $ | 0.41 |
| | $ | 0.25 |
| | $ | 0.17 |
| | 64 | % | | 47 | % |
_____________________________
NM — Not meaningful
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 on the Consolidated Statements of Operations, respectively. 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, O&M costs, depreciation and amortization expense, bad debt expense and recoveries, 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 — Executive Summary
(in millions)
Year Ended December 31, 2015
Consolidated Revenue— Revenue decreased $2.2 billion, or 13%, to $15.0 billion in 2015 compared to $17.1 billion in 2014. This decrease was primarily driven by unfavorable FX impacts of $2.5 billion, primarily in Brazil ($2.2 billion) and Colombia ($179 million). Additionally, there were lower volumes at the US Utilities, primarily at DPL, and outages, milder weather, and lower demand at IPL. Finally, there were lower prices in the Dominican Republic and El Salvador (primarily resulting from lower pass-through costs). These decreases were partially offset by higher tariffs at Eletropaulo and Sul (including higher pass-through costs), the reversal of a contingent regulatory liability at Eletropaulo, higher capacity prices at DPL, and the commencement of principal operations at Mong Duong in April 2015.
Consolidated Operating margin— Operating margin decreased $222 million, or 7%, to $2.9 billion in 2015 compared to $3.1 billion in 2014. This decrease was driven by unfavorable FX impacts of $368 million, primarily in Brazil ($235 million) and Colombia ($83 million). In addition, Brazil was impacted by lower demand, lower hydrology, and higher fixed costs and the Dominican Republic was impacted by lower commodities and lower availability. These decreases were partially offset by the impact of higher tariffs in Brazil as discussed above, 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, and higher availability at Gener and Masinloc.
Year Ended December 31, 2014
Consolidated Revenue— Revenue increased $1.3 billion, or 8%, to $17.1 billion in 2014 compared to $15.9 billion in 2013. This increase was driven by higher tariffs (primarily pass-through costs) at the Brazil Utilities and at IPL, higher spot prices at Tietê, and regulatory retail rate increases at DPL. These increases were partially offset by unfavorable FX impacts of $752 million, primarily in Brazil ($630 million), Argentina ($69 million) and Colombia ($30 million).
Consolidated Operating Margin— Operating margin decreased $159 million, or 5%, to $3.1 billion in 2014 compared to $3.2 billion in 2013. This decrease was driven by unfavorable FX impacts of $124 million, primarily in Brazil ($97 million). In addition, margins were negatively impacted by higher fixed costs at Eletropaulo, lower hydrology and higher spot purchase prices Tietê, and lower availability at Kilroot, Maritza, and Masinloc. These decreases were partially offset by higher tariffs and a non-recurring 2013 charge related to the recognition of a contingent regulatory liability at Eletropaulo, and higher generation volumes and prices at Chivor.
See Item 7.—SBU Performance Analysis of this Form 10-K for additional discussion and analysis of operating results for each SBU.
Consolidated Results of Operations — Other
General and administrative expenses
General and administrative expenses include expenses related to corporate staff functions and/or initiatives, executive management, finance, legal, human resources and information systems, as well as global development costs.
General and administrative expenses increased $9 million, or 5%, to $196 million in 2015 from 2014 primarily due to increased business development costs and employee-related costs partially offset by decreased professional fees.
General and administrative expenses decreased $33 million, or 15%, to $187 million in 2014 from 2013 primarily due to lower employee-related costs and business development costs.
Interest expense
Interest expense decreased $35 million, or 2%, to $1.4 billion in 2015 from $1.5 billion in 2014. The decrease was primarily attributable 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 the first half of 2015 and ceased capitalizing interest, as well as the impact of the 2014 contingent interest reversal at Sul discussed below.
Interest expense decreased $11 million, or 1%, to $1.5 billion in 2014 from $1.5 billion in 2013. This decrease was primarily attributable to lower interest expense of $53 million at the Parent Company due to a reduction in debt principal, and a $48 million reversal of contingent interest accruals associated with disputed purchased energy obligations at Sul for which it was determined, based on developments during the second quarter of 2014, that the likelihood of an unfavorable outcome for the payment of interest on the disputed obligation was no longer probable. These decreases were partially offset by income of $34 million in the prior year resulting from the ineffectiveness on derivative interest rate swaps accounted for as cash flow hedges at Puerto Rico, and higher interest expense of $24 million at Gener due to an increase in debt principal.
Interest income
Interest income increased $159 million, or 44%, to $524 million in 2015 from $365 million in 2014. The increase was 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 $54 million at Eletropaulo and Sul resulting from higher interest rates and an increase in regulatory assets.
Interest income increased $90 million, or 33%, to $365 million in 2014 from $275 million in 2013. The increase was primarily due to interest income of $59 million recognized on FONINVEMEM III receivables in Argentina, which satisfied the criteria for revenue recognition in the fourth quarter of 2014, as well as an increase of $23 million at Eletropaulo resulting from higher interest rates and an increase in regulatory assets. See Note 7—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Loss on extinguishment of debt
Loss on extinguishment of debt was $186 million for the year ended December 31, 2015. This loss was primarily related to expense of $105 million, $22 million, and $19 million recognized on debt extinguishments at the Parent Company, IPL, and the Dominican Republic, respectively.
Loss on extinguishment of debt was $261 million for the year ended December 31, 2014. This loss was primarily related to expense of $193 million, $31 million, and $20 million recognized on debt extinguishments at the Parent Company, DPL, and Gener, respectively.
Loss on extinguishment of debt was $229 million for the year ended December 31, 2013. This was primarily related to debt extinguishments at the Parent Company and at Masinloc. See Note 12—Debt included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Other income and expense
Other income was $83 million, $124 million, and $125 million for the years ended December 31, 2015, 2014, and 2013, respectively. Other expense was $65 million, $68 million, and $76 million for the years ended December 31, 2015, 2014, and 2013, respectively. See Note 20—Other Income and Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Gain on sale of businesses
Gain on sale of businesses was $29 million for the year ended December 31, 2015, which was primarily related to the sale of Armenia Mountain.
Gain on sale of businesses was $358 million for the year ended December 31, 2014, 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).
Gain on disposal and sale of investments for the year ended December 31, 2013 was $26 million, which was primarily related to the sale of our remaining 20% interest in Cartagena as well as the sale of our 10% equity interest in Trinidad Generation Unlimited. See Note8—Investments in and Advances to Affiliates, Note 16—Equity, andNote 24—Dispositions and Held-For-Sale Businesses included in Item 8.—Financial Statements and Supplemental Data of this Form 10-K for further information.
Goodwill impairment expense
The Company recognized goodwill impairment expense of $317 million, $164 million, and $372 million for the years
ended December 31, 2015, 2014, and 2013, respectively. See Note 10—Goodwill and Other Intangible Assets included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Asset impairment expense
The Company recognized asset impairment expense of $285 million, $91 million and $95 million for the years ended December 31, 2015, 2014, and 2013, respectively. See Note 21—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 increased $46 million, or 11%, to $465 million in 2015. The Company's effective tax rates were 41% and 27% 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 current year nondeductible impairment of goodwill at our U.S. utility, DPL 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 items described below.
Income tax expense increased $76 million, or 22%, to $419 million in 2014. The Company's effective tax rates were 27% and 33% for the years ended December 31, 2014 and 2013, respectively.
The net decrease in the 2014 effective tax rate was due, in part, to the 2014 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. Further, the 2014 effective tax rate benefited from the release of valuation allowance against U.S. capital loss carryforwards and a change in tax status at a subsidiary operating in the Dominican Republic. Offsetting these items is the unfavorable impact of Chilean income tax law reform enacted in the third quarter of 2014. See Note 16—Equity for additional information regarding the sale of approximately 45% of the Company's interest in Masin-AES Pte Ltd. See Note 24—Dispositions and Held-for-Sale Businesses for additional information regarding the sale of the Company's interests in four U.K wind operating projects.
Our effective tax rate reflects the tax effect of significant operations outside the U.S., which are generally taxed at rates lower than the U.S. statutory rate of 35%. 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 22—Income Taxes 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, | 2015 | | 2014 | | 2013 |
| Argentina | $ | 124 |
| | $ | 66 |
| | $ | 2 |
|
| Colombia | 29 |
| | 17 |
| | 6 |
|
| United Kingdom | 11 |
| | 12 |
| | 2 |
|
| Philippines | 8 |
| | 11 |
| | (10 | ) |
| Brazil | (6 | ) | | (4 | ) | | (12 | ) |
| Mexico | (6 | ) | | (14 | ) | | — |
|
| Chile | (18 | ) | | (30 | ) | | (20 | ) |
| AES Corporation | (31 | ) | | (34 | ) | | 5 |
|
| Other | (6 | ) | | (13 | ) | | 5 |
|
Total (1) | $ | 105 |
| | $ | 11 |
| | $ | (22 | ) |
(1) Includes gains of $247 million, $172 million and $60 million on foreign currency derivative contracts for the years ended December 31, 2015, 2014 and 2013, respectively.
The Company recognized a net foreign currency transaction gain of $105 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, primarily due to the depreciation of the Colombian Peso, positively impacting Chivor (a U.S. Dollar functional currency subsidiary) due to liabilities denominated in Colombian Pesos,
$11 million in the United Kingdom, primarily due to the depreciation of the Pound Sterling, resulting in gains at Ballylumford Holdings (a U.S. Dollar functional currency subsidiary) associated with intercompany notes payable
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 gain 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, primarily due to a 23% depreciation of the Colombian Peso, positively impacting Chivor (a U.S. Dollar functional currency subsidiary) due to liabilities denominated in Colombian Pesos, primarily income tax payable and accounts payable,
$12 million in the United Kingdom, primarily due to a 6% depreciation of the Pound Sterling, resulting in gains at Ballylumford Holdings (a U.S. Dollar functional currency subsidiary) associated with intercompany notes payable denominated in Pound Sterling, and gains related to foreign currency derivatives, and
$11 million in the Philippines, primarily due to amortization of frozen embedded derivatives and a 4% appreciation of the Philippine Peso against the U.S. Dollar, resulting in a revaluation of cash accounts, customer receivables, and deferred tax asset.
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).
The Company recognized a net foreign currency transaction loss of $22 million for the year ended December 31, 2013 primarily due to losses of:
$20 million in Chile, primarily due to a 9% weakening of the Chilean Peso, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with net working capital denominated in Chilean Pesos, mainly cash, accounts receivables and tax receivables, partially offset by gains related to foreign currency derivatives,
$12 million in Brazil, primarily due to a 15% weakening of the Brazilian Real resulting in losses mainly associated with U.S. Dollar denominated liabilities, and
$10 million in the Philippines (a U.S. Dollar functional currency subsidiary beginning in 2013), primarily due to the 8% weakening of the Philippine Peso, resulting in revaluation of cash accounts, customer receivables and deferred tax assets.
Other non-operating expense
Other non-operating expense was zero, $128 million and $129 million for the years ended December 31, 2015, 2014 and 2013, respectively. See Note 9—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 increased $86 million, or 453%, to $105 million in 2015 from $19 million in 2014. The increase was primarily due to the 2015 restructuring of Guacolda in Chile, which increased the Company's equity investment and resulted in additional equity earnings, as well as the 2014 impairment at Elsta discussed below.
Net equity in earnings of affiliates decreased $6 million to $19 million in 2014 from $25 million in 2013. The decrease was primarily a result of an asset impairment charge at Elsta due to long lived assets that were determined to not be recoverable of which our share was $41 million. These items were partially offset by a $22 million lower loss recognized at Entek on an embedded foreign currency derivative and a $19 million increase as a result of the sale of equity interests in SRP. See Note 8—Investments in and Advances to Affiliates included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Income from continuing operations attributable to noncontrolling interests
Income from continuing operations attributable to noncontrolling interests increased $69 million, or 18%, to $456 million in 2015 from $387 million in 2014 as a result of:
an increase at Mong Duong due to commencement of operations in the current year,
an increase at Gener primarily due to the restructuring of Guacolda,
an increase at Masinloc due to increased earnings and the 2014 sale of a noncontrolling interest in that business
Partially offset by
a decrease at Buffalo Gap III resulting from the asset impairment expense allocation to the tax equity partner, and
a decease at Eletropaulo resulting from unfavorable foreign exchange and lower demand.
Income from continuing operations attributable to noncontrolling interests decreased $59 million, or 13%, to $387 million in 2014 from $446 million in 2013 as a result of:
a decrease at Tietê due to lower earnings resulting from poor hydrology and increased prices for purchased energy,
a decrease at Uruguaiana due to a favorable arbitration settlement in 2013, and
a decrease at Panama related to poor hydrology.
Loss from discontinued operations
Total loss from discontinued operations was zero, $29 million, and $179 million for the years ended December 31, 2015, 2014 and 2013, respectively. See Note 23—Discontinued Operations included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Net income attributable to The AES Corporation
Net income attributable to The AES Corporation decreased $463 million to $306 million in 2015 from $769 million in 2014. The key drivers of the decrease included:
Higher impairment expense
Lower gains from the sale of businesses
These increases were partially offset by:
Lower debt extinguishment expense
Net income attributable to The AES Corporation increased $655 million to $769 million in 2014 from $114 million in 2013. The key drivers of the increase included:
Higher gains from the sale of businesses
Lower impairment expense
Lower general and administrative expenses
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— Operating Margin is defined as revenue less cost of sales. Cost of sales includes costs incurred directly by the businesses in the ordinary course of business, such as Electricity and fuel purchases; O&M costs; Depreciation and amortization expense; Bad debt expense & recoveries; General administrative & support costs at the businesses; and Gains or losses on derivatives associated with the purchase and sale of electricity or fuel.
We define Adjusted Operating Margin as Operating Margin, adjusted for the impact of noncontrolling interests,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 noncontrolling interests,NCI, where AES consolidates the results of a subsidiary that is not wholly-ownedwholly 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, |
| | 2018 | | 2017 | | 2016 |
| Operating Margin | $ | 2,573 |
| | $ | 2,465 |
| | $ | 2,383 |
|
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 | $ | 1,928 |
| | $ | 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 and Adjusted EPS —
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 noncontrolling interestsNCI 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 Generalgeneral and administrative expenseexpenses in the corporateCorporate segment, as well as business development costs; Interestcosts, interest expense and interest income; Otherincome,other expense and other income; Realizedincome,realized foreign currency transaction gains and losses;losses, and Netnet equity in earnings of affiliates.affiliates.
We define Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt.
The GAAP measure most comparable to Adjusted PTC is income from continuing operations attributable to The AES Corporation. The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations.Corporation. We believe that Adjusted PTC and Adjusted EPS better reflectreflects the underlying business performance of the Company and areis 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, for Adjusted PTC, 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 and is a more transparent measure that better assists investors in determining which businesses have the greatest impact on the Company's results.
Adjusted EPSPTC should not be construed as alternativesan 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, |
| | 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; (c) gains, losses, benefits 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; (e) gains, losses and costs due to the early retirement of 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, 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 areis determined in accordance with GAAP.
Proportional Free Cash Flow — Refer to Item 7—Management's DiscussionThe Company reported a loss from continuing operations of $0.77 and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Proportional Free Cash Flow (A non-GAAP Measure) $0.04 per share for the discussionyears ended December 31, 2017 and reconciliation2016, respectively. For purposes of Proportional Free Cash Flowmeasuring 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 its nearest GAAP measure.
Reconciliations of Non-GAAP Measures
|
| | | | | | | | | | | | |
| Adjusted Operating Margin (in millions) | | Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 |
| US | | $ | 598 |
| | $ | 711 |
| | $ | 684 |
|
| Andes | | 466 |
| | 444 |
| | 402 |
|
| Brazil | | 136 |
| | 235 |
| | 271 |
|
| MCAC | | 438 |
| | 482 |
| | 472 |
|
| Europe | | 276 |
| | 373 |
| | 392 |
|
| Asia | | 70 |
| | 51 |
| | 159 |
|
| Corp/Other | | 33 |
| | 53 |
| | 25 |
|
| Intersegment eliminations | | (1 | ) | | (13 | ) | | 23 |
|
| Total Adjusted Operating Margin | | 2,016 |
| | 2,336 |
| | 2,428 |
|
| Noncontrolling interests adjustment | | 869 |
| | 760 |
| | 833 |
|
| Derivatives adjustment | | (19 | ) | | (8 | ) | | (14 | ) |
| Operating Margin | | $ | 2,866 |
| | $ | 3,088 |
| | $ | 3,247 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Adjusted PTC (in millions) Year Ended December 31, | | Total Adjusted PTC | | Intersegment | | External Adjusted PTC |
| 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 |
| US SBU | | $ | 360 |
| | $ | 445 |
| | 440 |
| | $ | 12 |
| | $ | 10 |
| | 11 |
| | $ | 372 |
| | $ | 455 |
| | $ | 451 |
|
| Andes SBU | | 482 |
| | 421 |
| | 353 |
| | 17 |
| | 6 |
| | 19 |
| | 499 |
| | 427 |
| | 372 |
|
| Brazil SBU | | 91 |
| | 242 |
| | 212 |
| | 2 |
| | 3 |
| | 3 |
| | 93 |
| | 245 |
| | 215 |
|
| MCAC SBU | | 327 |
| | 352 |
| | 339 |
| | 18 |
| | 26 |
| | 12 |
| | 345 |
| | 378 |
| | 351 |
|
| Europe SBU | | 235 |
| | 348 |
| | 345 |
| | 5 |
| | 5 |
| | 7 |
| | 240 |
| | 353 |
| | 352 |
|
| Asia SBU | | 96 |
| | 46 |
| | 142 |
| | 3 |
| | 2 |
| | 2 |
| | 99 |
| | 48 |
| | 144 |
|
| Corporate and Other | | (441 | ) | | (533 | ) | | (624 | ) | | (57 | ) | | (52 | ) | | (54 | ) | | (498 | ) | | (585 | ) | | (678 | ) |
| Total Adjusted Pretax Contribution | | 1,150 |
| | 1,321 |
| | 1,207 |
| | — |
| | — |
| | — |
| | 1,150 |
| | 1,321 |
| | 1,207 |
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| 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 | ) |
|
| | | | | | | | | | | |
| Reconciliation to income from continuing operations, net of tax, attributable to The AES Corporation: | | |
| Non-GAAP Adjustments: | | | | | |
| Unrealized derivative gains | 166 |
| | 135 |
| | 57 |
|
| Unrealized foreign currency losses | (96 | ) | | (110 | ) | | (41 | ) |
| Disposition/acquisition gains | 42 |
| | 361 |
| | 30 |
|
| Impairment losses | (504 | ) | | (416 | ) | | (588 | ) |
| Loss on extinguishment of debt | (183 | ) | | (274 | ) | | (225 | ) |
| Pre-tax contribution | 575 |
| | 1,017 |
| | 440 |
|
| Income tax expense attributable to The AES Corporation | 269 |
| | 228 |
| | 156 |
|
| Income from continuing operations, net of tax, attributable to The AES Corporation | $ | 306 |
| | $ | 789 |
| | $ | 284 |
|
|
| | | | | | | | | | | | |
| 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 |
| |
|
| | | | | | | | | | | | |
| Adjusted EPS | Years Ended December 31, | |
| | 2015 | | 2014 | | 2013 | |
| Diluted earnings per share from continuing operations | $ | 0.44 |
| | $ | 1.09 |
| | $ | 0.38 |
| |
Unrealized derivative (gains) (1) | (0.16 | ) | | (0.12 | ) | | (0.05 | ) | |
Unrealized foreign currency transaction losses(2) | 0.12 |
| | 0.14 |
| | 0.02 |
| |
| Disposition/acquisition (gains) | (0.03 | ) | (3) | (0.59 | ) | (4) | (0.03 | ) | (5) |
| Impairment losses | 0.67 |
| (6) | 0.53 |
| (7) | 0.75 |
| (8) |
| Loss on extinguishment of debt | 0.18 |
| (9) | 0.25 |
| (10) | 0.22 |
| (11) |
| Adjusted EPS | $ | 1.22 |
| | $ | 1.30 |
| | $ | 1.29 |
| |
_____________________________
| |
(1) | Unrealized derivatives were netAmount primarily relates to unrealized FX losses of income tax expense$22 million, or $0.03 per share, associated with the devaluation of $(0.08), $(0.07)long-term receivables denominated in Argentine pesos, and $(0.02)unrealized FX losses of $14 million, or $0.02 per share, on intercompany receivables denominated in 2015, 2014,Euros and 2013, respectively.British pounds at the Parent Company. |
| |
(2) | Unrealized foreign currency transaction losses were netAmount primarily relates to gain on sale of income tax benefitMasinloc 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 $0.02per share and $0.02 in 2015, 2014,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 2013, respectively.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 $38 million, or $0.06 per share, loss on sale of Kazakhstan HPPs of $33 million, or $0.05 per share, and costs associated with early plant closures at DPL of $24 million, or $0.04 per share; partially offset by gain on Masinloc contingent consideration of $23 million, or $0.03 per share and gain on sale of Miami Fort and Zimmer of $13 million, or $0.02 per share. |
| |
(4) | Amount primarily relates to the gain from the saleasset impairments at Shady Point of Solar Spain and Solar Italy of $7 million ($20$157 million, or $0.03$0.24 per share, including income tax benefitand Nejapa of $37 million, or $0.06 per share, and other-than-temporary impairment of $0.02), the gain from the saleGuacolda of Armenia Mountain of $22 million ($14$96 million, or $0.02 per share, net of income tax expense per share of $0.01), and the loss from the tax consequences associated with the sale of a noncontrolling interest in Gener of $25 million, or $0.04$0.14 per share. |
| |
(4)(5)
| Amount primarily relates to the gain from the saleasset impairments at Kazakhstan CHPs of a noncontrolling interest in Masinloc of $283$94 million, ($0.39or $0.14 per share, netat Kazakhstan HPPs of income tax$92 million, or $0.14 per share, at Laurel Mountain of $0.00), the gain from the sale of the U.K. wind projects of $78$121 million, ($0.11or $0.18 per share, netat DPL of income tax$175 million, or $0.27 per share and at Kilroot of $0.00), the loss from the liquidation of AgCert International of $1 million (net benefit of $18$37 million, or $0.03$0.05 per share, including income tax benefit per share of $0.03), the tax benefit of $24 million ($0.03 per share) related to the Silver Ridge Power transaction, and the tax benefit of $18 million ($0.02 per share) associated with the agreement executed in December 2014 to sell a noncontrolling interest in IPALCO.share. |
| |
(5)(6)
| Amount primarily relates to the gain from the saleasset impairments at DPL of Cartagena of $20 million ($15$859 million, or $0.02$1.30 per share, at Buffalo Gap II of $159 million ($49 million, or $0.07 per share, net of income tax benefit per share of $0.01). |
| |
(6)
| Amount primarily relates to the goodwill impairment at DPL of $317 million ($0.46 per share, net of income tax per share of $0.00) and asset impairments at Kilroot of $121 million ($95 million, or $0.14 per share, net of income tax benefit per share of $0.03), at U.K. Wind (Development Projects) of $38 million ($24 million, or $0.04 per share, net of income tax benefit per share of $0.01),NCI) and at Buffalo Gap IIII of $116$77 million ($1823 million, or $0.03 per share, net of income tax benefit per share of $0.01)NCI). |
| |
(7) | Amount primarily relates to loss on early retirement of debt at the goodwill impairments at DPLERParent Company of $136 million ($0.19 per share, net of income tax per share of $0.00), and at Buffalo Gap of $28 million ($0.04 per share, net of income tax per share of $0.00), and asset impairments at Ebute of $67 million ($64$171 million, or $0.09$0.26 per share, net of income tax benefit per share of $0.00), and at Elsta of $41 million ($31 million, or $0.04 per share, net of income tax benefit per share of $0.01), and the other-than-temporary impairments at Silver Ridge Power of $42 million ($27 million, or $0.04 per share, net of income tax benefit per share of $0.02), and at Entek of $86 million ($0.12 per share, net of income tax benefit per share of $0.00).share. |
| |
(8) | Amount primarily relates to losses on early retirement of debt at the goodwill impairments at DPLParent Company of $307$92 million, ($0.41or $0.14 per share, netat AES Gener of income tax per share of $0.00) and at Ebute of $58 million ($0.08 per share, net of income tax per share of $0.00), the other-than-temporary impairment at Elsta of $129 million ($128 million, or $0.17 per share, net of income tax benefit per share of $0.00) and the asset impairments at Beaver Valley of $46 million ($30 million, or $0.04 per share, net of income tax benefit per share of $0.02), and at DPL of $26 million ($17$20 million, or $0.02 per share, netand at IPALCO of income tax benefit$9 million or $0.01 per shareshare; partially offset by a gain on early retirement of $0.01).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 $116 million ($75$19 million, or $0.11$0.03 per share, net of income tax benefit per share of $0.06) and at IPL of $22 million ($11 million, or $0.02 per share, net of income tax benefit per share of $0.01).share. |
| |
(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 $200 million ($130$36 million, or $0.18$0.05 per share, net ofand income tax benefit per sharebenefits associated with the impairment at Shady Point of $0.10), at DPL of $31 million ($20$33 million, or $0.03$0.05 per share, net of income tax benefit per share of $0.02), at Electrica Angamos of $20 million ($11 million, or $0.02 per share, net of income tax benefit per share of $0.00), at U.K. wind projects of $18 million ($15 million, or $0.02 per share, net of income tax benefit per share of $0.00).share. |
| |
(11)(13)
| Amount primarily relates to the loss on early retirement of debt at Parent Company of $165 million ($107 million, or $0.14 per share, net of income tax benefit per shareassociated with asset impairments of $0.08), at Masinloc of $43 million ($39$148 million, or $0.05$0.22 per share, net of income tax per share of $0.00) and at Changuinola of $14 million ($10 million, or $0.01 per share, net ofshare. |
| |
(14) | Amount primarily relates to the income tax benefit associated with asset impairments of $332 million, or $0.50 per share of $0.01).share. |
US AND UTILITIES SBU
A summary ofThe following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC and Proportional Free Cash Flow ($ in(in millions) is as follows:for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2015 | | 2014 | | 2013 | | $ Change 2015 vs. 2014 | | $ Change 2014 vs. 2013 | | % Change 2015 vs. 2014 | | % Change 2014 vs. 2013 |
| Operating Margin | | $ | 621 |
| | $ | 699 |
| | $ | 668 |
| | $ | (78 | ) | | $ | 31 |
| | -11 | % | | 5 | % |
| Noncontrolling Interests Adjustment | | (38 | ) | | — |
| | — |
| | | | | | | | |
| Derivatives Adjustment | | 15 |
| | $ | 12 |
| | 16 |
| | | | | | | | |
| Adjusted Operating Margin | | $ | 598 |
| | $ | 711 |
| | $ | 684 |
| | $ | (113 | ) | | $ | 27 |
| | -16 | % | | 4 | % |
| Adjusted PTC | | $ | 360 |
| | $ | 445 |
| | $ | 440 |
| | $ | (85 | ) | | $ | 5 |
| | -19 | % |
| 1 | % |
| Proportional Free Cash Flow | | $ | 591 |
| | $ | 646 |
| | $ | 689 |
| | $ | (55 | ) | | $ | (43 | ) | | -9 | % | | -6 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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) | 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 margin decreased $78Margin increased $40 million, or 11%6%, which was driven primarily by the following:following (in millions):
|
| | | |
| 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 | ) |
| IPL | |
| Lower wholesale margin due to lower market prices of electricity and outages | (26 | ) |
| Higher retail margins | 20 |
|
| Higher fixed costs primarily due to higher maintenance expense attributed to plant outages and higher depreciation expense due to MATS assets | (18 | ) |
| Other | (1 | ) |
| Total IPL Decrease | (25 | ) |
| 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 | ) |
| Total US SBU Operating Margin Decrease | $ | (78 | ) |
|
| | | |
| 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 $113increased $55 million for the US SBUprimarily due to the drivers above, excluding the impact ofadjusted for a $24 million unrealized derivative gains and losses and proportional share adjustments. AES owns 100% of its businessesloss on coal derivatives in the US with the exception of IPL with ownership of 85% beginning in February 2015 and 75% beginning in April 2015. AES owned 100% of IPL prior to February 2015.
Adjusted PTC decreased $85 million driven by the decrease of $113 million in Adjusted Operating Margin described above and a decrease in the Company's share of earnings under the HLBV allocation of noncontrolling interest at Buffalo Gap,Hawaii partially offset by IPL due to lower interest expense related to the impact of the sell down and increased AFUDC, and DPL due to lower interest expense.
Proportional Free Cash Flow decreased $55 million, which includes the $113 million decrease in Adjusted Operating Margin as described above as well as a $22 million increase in maintenance and non-recoverable capital expenditures, partially offset by the collection of previously deferred storm costs, a one-time payment in 2014 to terminate an unfavorable coal contract, higher collections and the timing of inventory payments at DPL. Cash was also favorably impacted by the timing of collections and payments for energy at IPL as well as a reduction in interest payments.
Fiscal year 2014 versus 2013
Operating margin increased by $31 million, or 5%, which was driven primarily by the following:
|
| | | |
| U.S. Generation | |
| Increased availability at Hawaii | $ | 11 |
|
| Increased market prices at Laurel Mountain | 8 |
|
| Completion of the Tait energy storage project in September 2013 | 8 |
|
| Other | (1 | ) |
| Total US Generation Increase | 26 |
|
| IPL | |
| Higher wholesale margin | 14 |
|
| Lower fixed costs, primarily due to lower pension expense | 11 |
|
| Other | (1 | ) |
| Total IPL Increase | 24 |
|
| DPL | |
| Impact from the timing of outages, resulting in higher purchased power and related costs, lower gas availability and higher demand during the peak of cold weather in Q1 2014, as well as increased customer switching to third party CRES providers | (71 | ) |
| Higher rates resulting from increased retail prices, lower fuel costs, and higher capacity prices | 57 |
|
| Other | (5 | ) |
| Total DPL Decrease | (19 | ) |
| Total US SBU Operating Margin Increase | $ | 31 |
|
Adjusted Operating Margin increased $27 million due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owned 100% of its businessesrestructuring charges in the US in 2014, so there is no adjustment for noncontrolling interests.prior year.
Adjusted PTC increased $5$87 million, primarily driven by net gains of $53 million recognized resulting from the early termination of the PPA and coal supply contract at Beaver Valley during the first quarter of 2013, largely offset by an increase of $27 million in Adjusted Operating Margin described above, as well as an 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 lower 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 the drivers above, excluding unrealized gains and Armenia Wind of $13 millionlosses on derivatives, restructuring charges and settlements at Laurel Mountain of $6 million.costs associated with early plant closures.
Proportional Free Cash Flow decreased $43Adjusted PTC increased $32 million, driven by earnings from equity affiliates due to the one-time cash receipt2017 acquisition of sPower, the Company's share of earnings at Distributed Energy due to new solar project growth and an increase in 2013 upon the early termination of the PPAinsurance recoveries at Beaver Valley as well as the timing of legal settlements at Laurel Mountain as described above. Additionally, cashDPL. The increase in Adjusted PTC was unfavorably impacted by the timing of payments at IPL for energy, maintenance and inventory and a one-time payment at DPL in the fourth quarter of 2014 to terminate an unfavorable coal contract. These unfavorable impacts were partially offset by the $27decrease of $14 million in Adjusted Operating Margin described above and a 2016 gain on contract termination at DP&L.
SOUTH AMERICA 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 | | $ | 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 businesses. |
Fiscal year 2018 versus 2017
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 as described above and lower interest in Chile, partially offset by a $51$28 million reductiondecrease associated with a gain recognized in maintenance capital expenditures, primarilythe prior year from the settlement of a legal dispute with YPF at our Utility businesses, as well as the timing of fuel paymentsUruguaiana, higher interest expense in Brazil, lower equity earnings in Chile and a reductionhigher realized foreign currency losses in interest payments at DPL.
ANDES SBUArgentina.
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow ($ in millions) is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2015 | | 2014 | | 2013 | | $ Change 2015 vs. 2014 | | $ Change 2014 vs. 2013 | | % Change 2015 vs. 2014 | | % Change 2014 vs. 2013 |
| Operating Margin | | $ | 618 |
| | $ | 587 |
| | $ | 533 |
| | $ | 31 |
| | $ | 54 |
| | 5 | % | | 10 | % |
| Noncontrolling Interests Adjustment | | (152 | ) | | (143 | ) | | (131 | ) | | | | | | | | |
| Adjusted Operating Margin | | $ | 466 |
| | $ | 444 |
| | $ | 402 |
| | $ | 22 |
| | $ | 42 |
| | 5 | % | | 10 | % |
| Adjusted PTC | | $ | 482 |
| | $ | 421 |
| | $ | 353 |
| | $ | 61 |
| | $ | 68 |
| | 14 | % | | 19 | % |
| Proportional Free Cash Flow | | $ | 224 |
| | $ | 176 |
| | $ | 188 |
| | $ | 48 |
| | $ | (12 | ) | | 27 | % | | -6 | % |
Fiscal year 20152017 versus 20142016
Including the unfavorablefavorable impact of foreign currency translation and remeasurement of $87$38 million, operating marginOperating 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. AES owned 71% of Gener and Chivor prior to sell down effective December 2015 which resulted in ownership of 67%. AES Argentina is owned 100%. The Alto Maipo and Cochrane plants under construction are owned 40%.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 in earnings of $46 million, realized FX gains, lower interest expense at Chivor2017 and the $14 million increase of $22 million in Adjusted Operating Margin described above. This wasabove, as well as foreign currency gains in Argentina associated with the collection of financing receivables, prepayment of financial debt denominated in U.S. dollars in 2017 and lower foreign currency losses associated with the sale of Argentina’s sovereign bonds at Termoandes. These positive impacts were partially offset by higher interest expense, mainly due to the acquisition of Alto Sertão II debt, issuance of debt at Argentina and 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 higher VAT refunds atinterest capitalization in Cochrane and Alto Maipo,Chivor, and the timingwrite-off of non-recurring maintenance collectionswater rights at Alicura, a decrease in interest payments as well as a $17 million net reduction in maintenance and non-recoverable environmental capital expenditures. Excluding the $22 million collection delayGener resulting from the various resolutions passed by the Argentine government (as discussed in Note 7—Financing Receivables),a business development project that is no longer pursued.
MCAC SBU
The following table summarizes Operating Margin, Adjusted Operating Margin decreased by $4 million due toand Adjusted PTC (in millions) for the drivers discussed above. Additionally, cash flow was negatively impacted by higher tax payments and lower collections from contract customers at Chivor as well as a one-time swap termination payment at Ventanas.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 20142018 versus 20132017
Including the unfavorable impact of foreign currency translation and remeasurement of $14 million, operating margin for 2013Operating Margin increased $54$69 million, or 10%15%, which was driven primarily by the following:following (in millions):
|
| | | |
| Chivor | |
| Higher generation, higher spot and contract prices, and higher ancillary services | $ | 72 |
|
| Higher maintenance costs | (12 | ) |
| Unfavorable FX impacts | (9 | ) |
| Other | 4 |
|
| Total Chivor Increase | 55 |
|
| Argentina | |
| Higher rates as a result of the impact of Resolution 529 | 30 |
|
| Higher generation and availability | 13 |
|
| Higher fixed costs driven by higher inflation | (27 | ) |
| Unfavorable FX impacts | (5 | ) |
| Other | (3 | ) |
| Total Argentina Increase | 8 |
|
| Gener | |
| Lower contract prices, spot prices in the SADI, and lower Energy Plus margin | (32 | ) |
| Lower availability | (9 | ) |
| Contributions from Ventanas IV, which commenced operations in March 2013 | 10 |
|
| Lower fixed costs, primarily lower maintenance and salaries | 19 |
|
| Other | 3 |
|
| Total Gener Decrease | (9 | ) |
| Total Andes SBU Operating Margin Increase | $ | 54 |
|
|
| | | |
| 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 $42$33 million for the yearprimarily due to the drivers above, adjusted for the impact of noncontrolling interests. AES owned 71% of Gener and Chivor and 100% of AES Argentina.NCI.
Adjusted PTC increased $68$23 million, mainly driven by the increase of $42 million in Adjusted Operating Margin described above, and a net benefit of $45 million related to FONINVEMEM interest income on receivables in 2014 and 2013, partially offset by realized FX losses at Gener as well as non-recurring equity tax reversal of $8 million at Chivor in 2013.
Proportional Free Cash Flow decreased $12 million driven by an increase in interest payments, higher payments for VAT at our Cochrane plant, a one-time swap termination payment at Angamos as well as a $3 million net increase in maintenance and non-recoverable environmental capital expenditures. These unfavorable impacts were partially offset by the $42 million increase in Adjusted Operating Margin as described above, as well a reductionpartially offset by lower capitalized interest due to project completions in tax payments at ChivorPanama and Gener.
BRAZIL SBUDominican Republic and lower foreign currency gains in Mexico.
A summary of Fiscal year 2017 versus 2016
Operating Margin Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow ($ in millions) is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2015 | | 2014 | | 2013 | | $ Change 2015 vs. 2014 | | $ Change 2014 vs. 2013 | | % Change 2015 vs. 2014 | | % Change 2014 vs. 2013 |
| Operating Margin | | $ | 600 |
| | $ | 742 |
| | $ | 871 |
| | $ | (142 | ) | | $ | (129 | ) | | -19 | % | | -15 | % |
| Noncontrolling Interests Adjustment | | (464 | ) | | (507 | ) | | (600 | ) | | | | | | | | |
| Adjusted Operating Margin | | $ | 136 |
| | $ | 235 |
| | $ | 271 |
| | $ | (99 | ) | | $ | (36 | ) | | -42 | % | | -13 | % |
| Adjusted PTC | | $ | 91 |
| | $ | 242 |
| | $ | 212 |
| | $ | (151 | ) | | $ | 30 |
| | -62 | % | | 14 | % |
| Proportional Free Cash Flow | | $ | (29 | ) | | $ | 13 |
| | $ | 116 |
| | $ | (42 | ) | | $ | (103 | ) | | -323 | % | | -89 | % |
Fiscal year 2015 versus 2014
Including the unfavorable impact of foreign currency translation of $235 million, operating margin decreased $142increased $75 million, or 19%, which was driven primarily by the following:following (in millions):
|
| | | |
| Sul | |
| Lower volumes due to economic decline and higher technical and non-technical losses | $ | (68 | ) |
| Higher fixed costs, primarily due to higher bad debt and regulatory penalties due to storms as well as higher depreciation expenses | (44 | ) |
| Higher tariffs | 19 |
|
| Other | (6 | ) |
| Total Sul Decrease | (99 | ) |
| 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 | ) |
| 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 |
|
| Other Business Drivers | 1 |
|
| Total Brazil SBU Operating Margin Decrease | $ | (142 | ) |
|
| | | |
| 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 decreased $99increased $66 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.
Adjusted PTC decreased $151 million, driven by the decrease of $99 million in Adjusted Operating Margin described above, a reversal of $47 million in contingent interest accruals in 2014 as well as higher debt and interest rates in 2015 at Sul. These results were partially offset by favorable net interest income recognized on receivables at Eletropaulo and Sul.
Proportional Free Cash Flow decreased $42 million, which includes the $99 million decrease in Adjusted Operating Margin as described above as well as an increase in interest payments, partially offset by the timing of energy purchases and regulatory charges, lower tax payments as well as a $25 million reduction in maintenance capital expenditures.
Fiscal year 2014 versus 2013
Including the unfavorable impact of foreign currency translation of $97 million, operating margin decreased $129 million, or 15%, which was driven primarily by the following:
|
| | | |
| Tietê | |
| Net impact of lower hydrology, which led to lower generation and an increase in energy purchases at higher prices, partially offset by higher spot sales in the first half of 2014 due to lower contracted volumes of energy sold | $ | (252 | ) |
| Unfavorable FX impacts | (58 | ) |
| Other | (5 | ) |
| Total Tietê Decrease | (315 | ) |
| Uruguaiana | |
| Extinguishment of a liability based on a favorable arbitration decision in the second quarter of 2013, partially offset by higher generation in 2014 during the period of temporary restart of operations | (53 | ) |
| Other | 2 |
|
| Total Uruguaiana Decrease | (51 | ) |
| Eletropaulo | |
| Non-recurring 2013 charge related to the recognition of a contingent regulatory liability related to potential customer refunds | 198 |
|
| Higher rates driven by a higher tariff | 124 |
|
| Higher volumes | 46 |
|
| Higher fixed costs and depreciation, primarily related to personnel and pension costs | (133 | ) |
| Unfavorable FX impacts | (28 | ) |
| Total Eletropaulo Increase | 207 |
|
| Sul | |
| Higher volumes and rates | 52 |
|
| Higher fixed costs and depreciation | (11 | ) |
| Unfavorable FX impacts | (10 | ) |
| Total Sul Increase | 31 |
|
| Other Business Drivers | (1 | ) |
| Total Brazil SBU Operating Margin Decrease | $ | (129 | ) |
Adjusted Operating Margin decreased $36 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.
Adjusted PTC increased $30 million, driven by the reversal of a loss contingency resulting from a change in estimate related to interest expense of $47 million and 2014 municipalities settlement interest of $12 million at Sul, partially offset by the decrease of $36 million in Adjusted Operating Margin described above, and higher interest rates and debt.
Proportional Free Cash Flow decreased $103 million, which includes the $36 million decrease in Adjusted Operating Margin as described above with the exception of the non-recurring 2013 charge related to potential customer refunds as that balance was not fully paid. The Brazil SBU was also unfavorably impacted by an increase in tax payments at Sul and Eletropaulo, the timing of collections of regulatory assets and settlement of regulatory liabilities at Eletropaulo and an increase in interest payments at Sul as noted above. These decreases were partially offset by a $19 million reduction in maintenance capital expenditures as well as the timing of energy purchases at Tietê.
MCAC SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow ($ in millions) is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2015 | | 2014 | | 2013 | | $ Change 2015 vs. 2014 | | $ Change 2014 vs. 2013 | | % Change 2015 vs. 2014 | | % Change 2014 vs. 2013 |
| Operating Margin | | $ | 543 |
| | $ | 541 |
| | $ | 543 |
| | $ | 2 |
| | $ | (2 | ) | | — | % | | — | % |
| Noncontrolling Interests Adjustment | | (106 | ) | | (59 | ) | | (69 | ) | | | | | | | | |
| Derivatives Adjustment | | 1 |
| | — |
| | (2 | ) | | | | | | | | |
| Adjusted Operating Margin | | $ | 438 |
| | $ | 482 |
| | $ | 472 |
| | $ | (44 | ) | | $ | 10 |
| | -9 | % | | 2 | % |
| Adjusted PTC | | $ | 327 |
| | $ | 352 |
| | $ | 339 |
| | $ | (25 | ) | | $ | 13 |
| | -7 | % | | 4 | % |
| Proportional Free Cash Flow | | $ | 498 |
| | $ | 281 |
| | $ | 433 |
| | $ | 217 |
| | $ | (152 | ) | | 77 | % | | -35 | % |
Fiscal year 2015 versus 2014
Operating margin increased $2 million, or 0.4%, which was driven primarily by the following:
|
| | | |
| 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 | ) |
| Mexico | |
| Higher fuel costs, lower spot sales and lower availability | (29 | ) |
| Total Mexico Decrease | (29 | ) |
| Puerto Rico | |
| One-time reversal of bad debt in 2014 and higher maintenance expense | (11 | ) |
| Total Puerto Rico Decrease | (11 | ) |
| 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 |
|
| 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. AES owns 90% of Changuinola and 49% of its other generation facilities in Panama, 92% of Andres and Los Mina (compared to 100% in 2014) and 46% of Itabo (compared to 50% in 2014) in the Dominican Republic, 99% of TEG/TEP and 55% of Merida in Mexico, and a weighted average of 77% of its businesses in El Salvador (compared to 75% in 2014). In December 2015, there was an additional sell down in the Dominican Republic resulting in ownership of 90% at Andres and Los Mina and 45% at Itabo.
Adjusted PTC decreased $25 million, driven by the decrease in Adjusted Operating Margin of $44 million as 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 timing of collections in the Dominican Republic, Puerto Rico and Panama. These favorable impacts were partially offset by the $44 million decrease in Adjusted Operating Margin as described above as well as a $2 million increase in maintenance and non-recoverable environmental capital expenditures.
Fiscal year 2014 versus 2013
Including the unfavorable impact of foreign currency translation of $3 million, operating margin decreased $2 million, or 0.4%, which was driven primarily by the following:
|
| | | |
| El Salvador | |
| One-time unfavorable adjustment to unbilled revenue | $ | (12 | ) |
| Higher energy losses and other fixed costs | (9 | ) |
| Other | (1 | ) |
| Total El Salvador Decrease | (22 | ) |
| Panama | |
| Lower generation and higher energy purchases due to dry hydrological conditions | (38 | ) |
| Esti tunnel settlement agreement in 2013 | (31 | ) |
| Compensation from the government of Panama related to spot purchases from dry hydrological conditions | 40 |
|
| Lower fixed and other costs | 22 |
|
| Other | (1 | ) |
| Total Panama Decrease | (8 | ) |
| Dominican Republic | |
| Higher spot sales | 58 |
|
| Higher availability | 20 |
|
| Lower gas sales to third parties | (27 | ) |
| Lower frequency regulation revenues | (26 | ) |
| Lower PPA margins | (14 | ) |
| Other | 8 |
|
| Total Dominican Republic Increase | 19 |
|
| Puerto Rico | |
| Favorable bad debt reversal | 6 |
|
| Total Puerto Rico Increase | 6 |
|
| Other business drivers | 3 |
|
| Total MCAC SBU Operating Margin Decrease | $ | (2 | ) |
Adjusted Operating Margin increased $10 million due to the drivers above adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 90% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina and 50% of Itabo in the Dominican Republic, 99% of TEG/TEP and 55% of Merida in Mexico, and a weighted average of 75% of its businesses in El Salvador.NCI.
Adjusted PTC increased $13$55 million, driven by the increase in Adjusted Operating Margin of $10$66 million as described above.
Proportional Free Cash Flow decreased $152 million primarily due to a one-time settlement received in 2013 at the Dominican Republic resulting from a fuel contract amendment, an increase in tax payments, as well as the timing of energy purchases at Panama, partially offset by the $10 million increase in Adjusted Operating Margin as described above.
EUROPEEURASIA SBU
A summary ofThe following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC and Proportional Free Cash Flow ($ in(in millions) is as follows:for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2015 | | 2014 | | 2013 | | $ Change 2015 vs. 2014 | | $ Change 2014 vs. 2013 | | % Change 2015 vs. 2014 | | % Change 2014 vs. 2013 |
| Operating Margin | | $ | 303 |
| | $ | 403 |
| | $ | 415 |
| | $ | (100 | ) | | $ | (12 | ) | | -25 | % | | -3 | % |
| Noncontrolling Interests Adjustment | | (30 | ) | | (26 | ) | | (23 | ) | | | | | | | | |
| Derivatives Adjustment | | 3 |
| | (4 | ) | | — |
| | | | | | | | |
| Adjusted Operating Margin | | $ | 276 |
| | $ | 373 |
| | $ | 392 |
| | $ | (97 | ) | | $ | (19 | ) | | -26 | % | | -5 | % |
| Adjusted PTC | | $ | 235 |
| | $ | 348 |
| | $ | 345 |
| | $ | (113 | ) | | $ | 3 |
| | -32 | % |
| 1 | % |
| Proportional Free Cash Flow | | $ | 238 |
| | $ | 197 |
| | $ | 345 |
| | $ | 41 |
| | $ | (148 | ) | | 21 | % | | -43 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 20152018 versus 20142017
Including the unfavorable impactfavorable FX impacts of foreign currency translation of $47$8 million, operating marginOperating Margin decreased $100$195 million, or 25%46%, which was driven primarily by the following:following (in millions):
|
| | | |
| 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 Europe SBU Operating Margin Decrease | $ | (100 | ) |
|
| | | |
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 $97$112 million, or 37%, primarily due to the drivers above, adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89% of St. Nikola in Bulgaria, and 37% and 60%, respectively, of the Amman East and IPP4 projects in Jordan.NCI.
Adjusted PTC decreased $113$68 million, driven primarily 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, which is primarily driven by higher collections at Maritza and Kavarna in Bulgaria, IPP4 in Jordan and at Ballylumford, partially offset by the $97 million 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 contract consideration as described above.a result of adoption of the new revenue recognition standard in 2018. See Note 1—General and Summary of Significant Accounting Policies—New Accounting Standards Adopted included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Fiscal year 20142017 versus 20132016
Including the unfavorable impact of foreign currency translation of $10 million, operating marginOperating Margin decreased $12$5 million, or 3%1%, which was driven primarily by the following:
|
| | | |
| Kilroot | |
| Lower dispatch and higher outages and related maintenance costs | $ | (46 | ) |
| Higher rates, including income from energy price hedges and favorable FX rates | 13 |
|
| Other | 2 |
|
| Total Kilroot Decrease | (31 | ) |
| Maritza | |
| Higher outages and related maintenance costs | (32 | ) |
| Impact of higher rates | 10 |
|
| Other | 5 |
|
| Total Maritza Decrease | (17 | ) |
| Jordan | |
| Commencement of operations at the IPP4 plant in July 2014 | 17 |
|
| Total Jordan Increase | 17 |
|
| Kazakhstan | |
| Higher volumes and rates | 29 |
|
| Unfavorable FX impacts | (13 | ) |
| Other | (5 | ) |
| Total Kazakhstan Increase | 11 |
|
| Other Business Drivers | 8 |
|
| Total Europe SBU Operating Margin Decrease | $ | (12 | ) |
and Adjusted Operating Margin decreased $19increased $3 million, due toor 1%, with no material drivers.
Adjusted PTC increased $7 million, primarily driven by the drivers aboveincrease in Adjusted Operating Margin, adjusted for noncontrolling interests, primarily Jordan with Amman East at 36% and IPP4 at 60%,NCI and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $3 million, driven by the decrease of $19 million in Adjusted Operating Margin described above, offset by the reversal of a liability of $18 million in Kazakhstan from the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES.
Proportional Free Cash Flow decreased $148 million, which includes the $19 million decrease in Adjusted Operating Margin as described above as well as the loss of cash flow resulting from the sale of our businesses in Cameroon and the Ukraine. Cash was also unfavorably impacted by the timing of collections at Maritza, Ballylumford and Jordan as well as pension plan contributions at Kilroot. These drivers were partially offset by an increase in dividends received at Elsta, our equity method investment in the Netherlands.
ASIA SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow ($ in millions) is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2015 | | 2014 | | 2013 | | $ Change 2015 vs. 2014 | | $ Change 2014 vs. 2013 | | % Change 2015 vs. 2014 | | % Change 2014 vs. 2013 |
| Operating Margin | | $ | 149 |
| | $ | 76 |
| | $ | 169 |
| | $ | 73 |
| | $ | (93 | ) | | 96 | % | | -55 | % |
| Noncontrolling Interests Adjustment | | (79 | ) | | (25 | ) | | (10 | ) | | | | | | | | |
| Adjusted Operating Margin | | $ | 70 |
| | $ | 51 |
| | $ | 159 |
| | $ | 19 |
| | $ | (108 | ) | | 37 | % | | -68 | % |
| Adjusted PTC | | $ | 96 |
| | $ | 46 |
| | $ | 142 |
| | $ | 50 |
| | $ | (96 | ) | | 109 | % |
| -68 | % |
| Proportional Free Cash Flow | | $ | 87 |
| | $ | 82 |
| | $ | 101 |
| | $ | 5 |
| | $ | (19 | ) | | 6 | % | | -19 | % |
Fiscal year 2015 versus 2014
Operating margin increased $73 million, or 96%, which was driven primarily by the following:
|
| | | |
| 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 | (3 | ) |
| Total Asia SBU Operating Margin Increase | $ | 73 |
|
Adjusted Operating Margin increased $19 million due to the drivers above adjusted for the impact of noncontrolling interests resulting primarily from the sell-down of our ownership in Masinloc from 92% to 51% in mid-July 2014. AES also owns 90% of Kelanitissa and 51% of Mong Duong.
Adjusted PTC increased $50 million, driven by the increase of $19 million in Adjusted Operating Margin described above, and the additional net impact of $28 million at Mong Duong due to a component of service concession revenue recognized as interest income, net of higher interest expense as interest is no longer capitalized. See Note 1—General and Summary of Significant Accounting Policies in Part II.—Item 8.—Financial Statements and Supplementary Data for further information regarding the accounting for service concession arrangements.
Proportional Free Cash Flow increased $5 million, driven by the collection of service concession revenue at Mong Duong noted above (which is not included in operating margin) as well as the $19 million increase in Adjusted Operating Margin, but excluding the retrospective adjustment to energy prices as described above. These favorable drivers were partially offset by the timing of collections at Masinloc which were negatively impacted by our sell-down of ownership interest in 2014.
Fiscal year 2014 versus 2013
Operating margin decreased $93 million, or 55%, which was driven primarily by the following:
|
| | | |
| Masinloc | |
| Lower plant availability | $ | (33 | ) |
| Net decrease from lower spot sales, partially offset by higher volumes | (21 | ) |
| Philippine market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013 | (15 | ) |
| Higher maintenance costs | (4 | ) |
| Other | (6 | ) |
| Total Masinloc Decrease | (79 | ) |
| Kelanitissa | |
| Impact of the step-down in the contracted PPA price | (17 | ) |
| Total Kelanitissa Decrease | (17 | ) |
| Other Business Drivers | 3 |
|
| Total Asia SBU Operating Margin Decrease | $ | (93 | ) |
Adjusted Operating Margin decreased $108 million due to the drivers above adjusted for the impact of noncontrolling interests and excluding unrealized gains on derivatives. AES owned 92% of Masinloc until July 2014 when AES reduced its ownership to 51%.
Adjusted PTC decreased $96 million, driven by the decrease of $108 million in Adjusted Operating Margin described above, partially offset by the impact of lower proportional interest expense at Masinloc and gains on foreign currency.
Proportional Free Cash Flow decreased $19 million, which includes the $108 million decrease in Adjusted Operating Margin as described above, excluding the retrospective adjustment to energy prices, partially offset by the timing of collections and payments for coal at Masinloc as well as a decrease in payments for interest and taxes.
Key Trends and Uncertainties
During 20162019 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. Operational
Sensitivity to Dry Hydrological Conditions — Our hydroelectric generation facilities are sensitive to changes in the weather, particularly the level of water inflows into generation facilities. Since 2013, dry hydrological conditions in Panama, Brazil, Colombia and Chile have presented challenges for our businesses in these markets. Low rainfall and water inflows have caused reservoir levels to be below historical levels, reduced generation output, and increased prices for electricity. If hydrological conditions do not improve and our hydroelectric generation facilities cannot generate sufficient energy to meet contractual arrangements, we may need to purchase energy to fulfill our obligations, which could have a material adverse impact on our results of operations.
According to the National Oceanic and Atmospheric Administration ("NOAA") a strong El Niño has been declared and is forecasted through the spring of 2016. According to local hydrological forecasts in Panama, below historical average inflows are expected to persist through the dry season of 2016 (ending in April). The effects of the El Niño phenomena could potentially intensify the dry hydrology conditions during this period. AES Panama has to purchase energy on the spot market to fulfill its contract obligations when its generation output is below contract levels. However, with declines in oil prices the cost of purchasing replacement power is reduced. In addition, lower hydrology results in less energy available to sell in the spot market after fulfilling contract obligations. We expect this trend to continue through the dry season of 2016, which will continue to impact our results of operations.
The El Niño brought some relief to the dry conditions in Brazil as it brought rain to the South and Southeast regions. The Southeast region has a significant portion of the country's reservoir capacity. At the beginning of 2016, we expect the system operator in Brazil to continue to pursue a more conservative reservoir management strategy to recover the reservoirs. Higher inflows are expected along with an impact on reservoir level recovery and lower spot prices. AES Sul, which is in the South of Brazil, could be negatively impacted by higher hydrology causing floods and other damage which could disrupt service and require emergency repairs. Additionally, higher hydrology could reduce the need for demand to provide irrigation services during the warm season.
Impacts in Colombia are uncertain since it will depend strongly upon the behavior pattern of the El Niño and can lead to better hydrology for just the area where our plant, Chivor, is located or the country as a whole. More extreme behavior can have an opposite impact and leave the Chivor basin dryer but the remainder of the country with better hydrology.
In the case of Chile, the hydrological year starts in April, and given that the El Niño phenomenon is not highly correlated with hydrological conditions in Chile, projection are made considering the average of all hydrological conditions. For the first quarter 2016, projections are made considering 2015 snowpack information which shows hydrological condition lower than average.
The exact behavior pattern and strength of El Niño cannot be definitively known at this time and therefore the impacts could vary from those described above. Even if rainfall and water inflows return to historical averages, in some cases high market prices and low generation could persist until reservoir levels are fully recovered.
Macroeconomic and Political
During the past few years, economic conditionsThe macroeconomic and political environments in some countries where our subsidiaries conduct business have deteriorated. Global economic conditions remain volatilechanged during 2018. This could result in significant impacts to tax laws and could haveenvironmental 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.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 adverseallowable 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 on our businesseseffective 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 event these
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.
recent trends continue.
Brazil Transition Tax— 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 the guidance of SAB 118. Our revised estimates took into account interpretative guidance issued in 2018 by the U.S. Treasury in proposed regulations. In Brazil, economic conditions remain unfavorable, as indicated by such factors as a negative GDP growth for 2015 and expectation for the same in 2016 and flat for 2017, higher interest rates and inflation, and increasing unemployment. As a consequence, our distribution businessesfirst quarter of 2019, the U.S. Treasury issued final regulations related to the one-time transition tax which further amended the guidance of the proposed regulations. We are still evaluating the final regulations which may have experienced a decline in demand. If these economic conditions persist or worsen, there could be a material impact on our businesses and AES's resultsfinancial statements. The impacts of operations, particularlythe final regulations will be reflected in our distribution businessesfinancial 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 Brazil, 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 AES Eletropaulo.are 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 foreign subsidiaries to current U.S. taxation to the extent 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 our foreign earnings to current U.S. taxation. In 2018, the caseGILTI provision materially, negatively impacted our effective tax rate and we expect this to continue in future years. Prospectively, the consequences of AES Sul, at December 31, 2015, debtthe new GILTI provision may be partially mitigated by foreign tax credits. Proposed regulations
were issued in 2018 by the U.S. Treasury which provided 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 yet enacted final legislation. As we expect higher taxable income in the amount of $333 million is classified as current due to a failure to meet required debt covenants related to earnings for two consecutive quarters. This default is primarilyfuture due to the economic conditions noted above, an increasefederal 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 re-assessed in regulatory assets due to sector chargesthe future as state tax law evolves and higher pricedmay result in material changes in position.
Tax Equity Structures — Our U.S. renewable energy purchases, increase in delinquency rates, and higher costs due to unfavorable hydrology in Brazil and severe weather conditions, particularly in AES Sul's service area. AES Sul is in negotiations with its creditors and has obtained a waiver for a period of two months, that ends in February 2016, when the Company expects to close the renegotiationportfolio operates primarily through tax equity partnerships. We cannot be certain of the whole debt, involving extending the debt maturities and additional equity contributions of approximately $75 million. Following the debt renegotiations, the Company will assess all strategic alternatives for AES Sul. If the negotiation is unsuccessful, we may face a loss of earnings and/or cash flows from Sul andimpacts 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 provide loans orour partners in our existing tax equity to support the business, and/or restructure the business, any of which could have a material impact on the Company. In addition, AES Sul has recorded net deferred tax assets ("DTA") of $133 million relating primarily to net operating loss carryforwards, which are not subject to expiration. Realization is dependent on generating sufficient taxable income. Although realization is not assured, management believes it is more likely than not that all of the DTA will be realized. The amount of DTA that is considered realizable, however, could be reduced in the near term if estimates of future taxable income are reduced. structures.
Argentina — In November 2015, Argentina held presidential elections in which centrist candidate Mauricio Macri was elected president. During his campaign, Mauricio Macri emphasized that energy would be a key factor in the government's agenda and that a long-term state policy would be required to address the country's energy crisis. Also, the elected President signed, together with the opposition candidates, a statement of commitment addressed to the previous administration, that included several guidelines to reactivate the sector including the implementation of a strategic long-term energy plan, that a fair and reasonable customer tariffs be set for generation, transport and distribution costs, as well as reductions in subsidies and the introduction of a social tariff.
In line with these statements, the Energy and Mining Minister published Resolution 6/2016 and 7/2016 in January 2016 that outlines planned increases to the end consumers of energy that will be effective starting on February 1, 2016. These resolutions contemplate an increase in tariffs of up to 300% for energy pass-through, grant Distribution Value Added ("DVA") increases for Distribution Companies, provide a regulatory framework for an Integral Tariff Review and introduce subsidies for low income consumers. These increases are intended to lessen the burden on the government to subsidize the energy industry.
In 2001, Argentina defaulted on its public debt, when it stopped making payments of approximately $100 billion of debt amid a deep economic crisis. In 2005 and 2010, Argentina restructured its defaulted bonds into new securities valued at about 33 cents on the dollar. Between the two transactions, 93% of the bondholders agreed to exchange their defaulted bonds for new bonds. The remaining 7% did not accept the restructured deal. Since then, a certain group of the "hold-out" bondholders have been in judicial proceedings with Argentina regarding payment and the U.S. District Court ruled that Argentina would need to make payments to such hold-out bondholders according to the original applicable terms. Despite intense negotiations with the hold-out bondholders through the U.S. District Court appointed Special Master, on July 30, 2014 the parties failed to reach a settlement agreement and consequently (as referred by S&P and Fitch ratings) Argentina fell into a selective default resulting from failure to make interest payments on its Discount Bonds maturing in December 2033. The new administration started conversations to negotiate a solution with the bondholders which could resolve this situation and let Argentina return to the credit markets in the near future. Although this situation remains unresolved, it has not caused any significant changes that impact our current exposures, and the long-term receivables in Argentina for the plants that commenced commercial operations in 2010 are being actively collected. For further information, see Note 7—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of the 2015 Form 10-K.
Bulgaria — Our investments in Bulgaria rely on long-term PPAs with NEK, the state-owned electricity public supplier and energy trading company. NEK is facing some liquidity issues and has been delayed in making payments under the PPAs with Maritza and St. Nikola. In August 2015, the ninth amendment of Maritza's PPA was executed under which Maritza and NEK would reduce the capacity payment to Maritza under the PPA by 14% through the PPA Term, without impacting the energy price component. In exchange, NEK would pay Maritza its overdue receivables. The amendment will become effective upon full payment of the overdue receivables by NEK, which is expected in 2016. For the period October through December 2015, NEK paid a total of $64 million, which is $16 million more than payments received in the previous year. As of December 31, 2015, Maritza's total outstanding receivables were $351 million, of which $44 million were current and $307 million were overdue. Total receivables increased by $89 million from $262 million in December 31, 2014. See additional background within Part I.—Item 1—Business—Our Organization and Segments—Europe—Bulgaria—Regulatory Framework.
As of June 30, 2015, we concluded that the HTA signed with NEK in April is considered an indicator of an impairment of the long-lived assets in Bulgaria for Maritza. Therefore, a test of recoverability was performed and management believes the carrying amount of the asset groups was recoverable as of June 30, 2015. Management does not believe that an indicator of an impairment existed as of December 31, 2015. As of December 31, 2015, Maritza had long-lived assets of $1.2 billion and total debt of $559 million. Long-lived assets for St. Nikola were $210 million and total debt of $140 million.
Unless and until a complete and binding resolution is in place, there remains a risk that we may still face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) 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 these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.
Puerto Rico — Our subsidiaries in Puerto Rico have long term PPAsa long-term PPA with state-owned PREPA, which has been facing economic challenges that could result in a state-owned entity. Duematerial 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 ongoing economic situation in the country, PREPA faces significant financial challenges.
On June 28, 2014,fiscal affairs of U.S. territories and created procedures for adjusting debt accumulated by the Puerto Rico Public Corporation Debt Enforcementgovernment and, Recovery Act (the "Recovery Act"potentially, other territories (“Title III”) was signed into law, which allows public corporations, including. 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 to adjust their debts.under Title III in July 2017. As a result of this event, on July 6, 2014, PREPA entered into a Forbearance Agreement with its lenders in order to permit an opportunity for negotiation of a possible financial restructuring of PREPA. In February 2015, the negotiating position of PREPA was weakened when the federal court deemed the Recovery Act unconstitutional. Despite this setback, PREPA managed to extend the expiration of the Forbearance Agreement several times, achieving in December of 2015 certain preliminary restructuring agreements, called Restructuring Support Agreements ("RSAs"), with most of the bondholders and bank lenders, which involved reductions of capital and interest rates and options to either convert existing credits to term loans or to exchange their principal for new securitized bonds. The RSA is conditional to a series of future related milestones, the more important being the passing of a bill that would allow an increase in tariffs.
There has been no adverse impacts tobankruptcy filing, AES Puerto Rico dueand AES Ilumina’s non-recourse debt of $317 million and $34 million, respectively, continue to PREPA's financial challenges. AES Puerto Rico's receivables balancebe in default and are classified as current as of December 31, 20152018. The Company is $65in 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 $21$18 million was overdue. SubsequentDespite 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, 2015,2027. 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 — In June 2016, the UK held a referendum in which voters approved an exit from the EU, commonly referred to as “Brexit.” In January 2019, the UK parliament rejected a proposed withdrawal agreement that the EU had supported. The UK is expected to exit the EU on March 29, 2019. While the full overdue amountimpact of the Brexit remains uncertain, these changes are not expected to have a material adverse effect on our operations and consolidated financial results.
LIBOR Phase Out — In 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 full impact of the 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 review whether Maritza’s PPA with NEK is compliant with the European Commission’s state aid rules. Although no formal investigation has been collected. Iflaunched by DG Comp to date, Maritza has engaged in discussions with the situation declines,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 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.
Macroeconomic and Political — Conclusion If economic conditions deteriorate further, it could affectConsidering the prices we receive forinformation available as of the electricity we generate or transmit. Utility regulators or parties to our generation contracts may seek to lower our prices based on prevailing market conditions pursuant to PPAs, concession agreements or other contracts as they come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual price or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline infiling date, Management believes the carrying value of our long-lived assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses.Maritza of approximately $1.1 billion is recoverable as of 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 2015, there were more than 40% declines in oil and natural gas prices, which have an impact on our businesses in the Dominican Republic, Ohio and Northern Ireland. Since weWe operate in multiple countries and 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 2015, we had2018, there was a significant devaluationsdevaluation in the Argentine Peso, Brazilian Real, Colombian Peso, and Kazakhstan Tenge,peso against the USD, which had a significantan impact on our 20152018 results. In 2016,Continued material devaluation of the Argentine peso against the USD could have an impact on our results could be materially impacted if the U.S. Dollar continues to appreciate.future results. For additional information, refer to Item 7A.—Quantitative and Qualitative Disclosures About Market Risk.
Alto Maipo
Alto Maipo has experienced cost overruns which have resulted in increased projected costs over the original $2 billion budget. Construction 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 funding 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 material impact to the financing and value of the project which could have a material impact on the Company. The carrying value of long-lived assets and deferred tax assets of Alto Maipo as of December 31, 2018 was approximately $2 billion and $60 million, respectively. Management believes the carrying value of the long-lived asset group is recoverable as of December 31, 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 installed 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 assessment, 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 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, 2015,2018, the Company recognized asset impairmentsand other-than-temporary impairment expense of $285$355 million. See Note 21—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. Additionally, in After recognizing this impairment expense, the third quartercarrying value of 2015, the Company testedequity affiliates and the recoverability of itsasset groups, including long-lived assets, at Ballylumford in Northern Ireland and Buffalo Gap I and II. Impairment indicators were identified at Ballylumford, primarily based on an unfavorable capacity reduction proposed by the Utility regulator in Northern Ireland, and at Buffalo Gap, based on a decline in forward power curves coupled with the near term expiration of favorable contracted cash flows. As of September 30, 2015, the Company determined that the carrying amount of the long-livedthose asset groups that were assessed and not impaired, totaled $661 million at Ballylumford and Buffalo Gap I and II, which totaled $92 million and $371 million, respectively, were recoverable, and no impairment expense was recognized. Buffalo Gap
I and II have PPAs that will expire at the end of 2021 and 2017, respectively. 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. No impairment indicators were identified in the fourth quarter of 2015.December 31, 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— During 2015, the The Company recognized total goodwill impairment expense of $317 million, which resulted from the annual goodwill impairment test performed in the fourth quarter of 2015 at its DP&Lconsiders a reporting unit ("DP&L"). Asat risk of December 31, 2015, there was no remaining goodwill balance at DP&L. See Note 10—Goodwill and Other Intangible Assets in Item 8.—Financial Statements and Supplementary Data for further information.
The Company currently has no reporting units considered to be "at risk."A reporting unit is considered "at risk"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.periods.
Capital Resources and Liquidity
Overview — As of December 31, 2015,2018, the Company had unrestricted cash and cash equivalents of $1.3$1.2 billion, of which $400$24 million was held at the Parent Company and qualified holding companies. The Company also had $484$313 million in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $860$837 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.8$15.6 billion and $5.0$3.7 billion, respectively. Of the approximately $2.5$1.7 billion of our current non-recourse debt, $1.5 billion$825 million was presented as such because it is due in the next twelve months, and $1.0 billion$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 senior$366 million outstanding secured credit facility and floating rate senior unsecured notesterm loan due 2019.2022. On a consolidated basis, of the Company's $15.8$19.7 billion of total non-recoursegross debt outstanding as of December 31, 2015,2018, approximately $3.8$3.2 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate. Brazil holds $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, 2015,2018, 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 $396$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, 2015,2018, we had $62$78 million in letters of credit outstanding, provided under our senior secured credit facility, and $32$368 million in cash collateralized letters of credit outstanding, outside of
provided under our unsecured 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, 2015,2018, 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, 2015,2018, the Company had approximately $296$116 million and $63 million of accounts receivable classified as Noncurrent assets—other and Current assets—Accounts receivable, respectively,Other noncurrent assets primarily related to certain of its generation businesses in Argentina and the U.S. and its utility businesses 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, 2016, 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 7—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
For the years ended December 31, 2015 and 2014 cash and cash equivalents decreased$277 million and $103 million, respectively. The following table below reflects the changes in operating, investing, and financing cash flows for the comparative twelve month periods (in millions).
|
| | | | | | | | | | | | | | | | | | | | |
| | | December 31, | | $ Change |
| Cash flows provided by (used in): | | 2015 | | 2014 | | 2013 | | 2015 vs. 2014 | | 2014 vs. 2013 |
| Operating activities | | $ | 2,134 |
| | $ | 1,791 |
| | $ | 2,715 |
| | $ | 343 |
| | $ | (924 | ) |
| Investing activities | | (2,366 | ) | | (656 | ) | | (1,774 | ) | | (1,710 | ) | | 1,118 |
|
| Financing activities | | 28 |
| | (1,262 | ) | | (1,136 | ) | | 1,290 |
| | (126 | ) |
| Effect of exchange rate changes on cash | | (52 | ) | | (51 | ) | | (59 | ) | | (1 | ) | | 8 |
|
| Decrease (increase) in cash of discontinued businesses | | — |
| | 75 |
| | (4 | ) | | (75 | ) | | 79 |
|
| Cash at held-for-sale businesses | | (21 | ) | | — |
| | — |
| | (21 | ) | | — |
|
| Net (decrease) increase in cash and cash equivalents | | (277 | ) | | (103 | ) | | (258 | ) | | (174 | ) | | 155 |
|
| Cash and cash equivalents at beginning of period | | 1,539 |
| | 1,642 |
| | 1,900 |
| | (103 | ) | | (258 | ) |
| Cash and cash equivalents at end of period | | 1,262 |
| | 1,539 |
| | 1,642 |
| | (277 | ) | | (103 | ) |
Operating Activities
Net cash provided by operating activities for the periods indicated was driven by (in millions):
|
| | | | | | | | | | | | | | | | | | | | |
| | | December 31, | | $ Change |
| | | 2015 | | 2014 | | 2013 | | 2015 vs. 2014 | | 2014 vs. 2013 |
| Net Income | | $ | 762 |
| | $ | 1,147 |
| | $ | 551 |
| | $ | (385 | ) | | $ | 596 |
|
| Depreciation and amortization | | 1,144 |
| | 1,245 |
| | 1,294 |
| | (101 | ) | | (49 | ) |
| Impairment expenses | | 602 |
| | 383 |
| | 661 |
| | 219 |
| | (278 | ) |
| Loss on the extinguishment of debt | | 186 |
| | 261 |
| | 229 |
| | (75 | ) | | 32 |
|
| Other adjustments to net income | | (123 | ) | | (223 | ) | | 324 |
| | 100 |
| | (547 | ) |
| Adjusted net income | | $ | 2,571 |
| | $ | 2,813 |
| | $ | 3,059 |
| | $ | (242 | ) | | $ | (246 | ) |
Net change in operating assets and liabilities (1) | | $ | (437 | ) | | $ | (1,022 | ) | | $ | (344 | ) | | $ | 585 |
| | $ | (678 | ) |
Net cash provided by operating activities (2) | | $ | 2,134 |
| | $ | 1,791 |
| | $ | 2,715 |
| | $ | 343 |
| | $ | (924 | ) |
|
| | | | | | | | | | | | | | | | | | | | |
| | | December 31, | | $ Change |
| Cash flows provided by (used in): | | 2018 | | 2017 | | 2016 | | 2018 vs. 2017 | | 2017 vs. 2016 |
| Operating activities | | $ | 2,343 |
| | $ | 2,504 |
| | $ | 2,897 |
| | $ | (161 | ) | | $ | (393 | ) |
| Investing activities | | (505 | ) | | (2,599 | ) | | (2,136 | ) | | 2,094 |
| | (463 | ) |
| Financing activities | | (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 |
| | | 2018 | | 2017 | | 2016 | | 2018 vs. 2017 | | 2017 vs. 2016 |
| Net income (loss) | | $ | 1,565 |
| | $ | (777 | ) | | $ | (777 | ) | | $ | 2,342 |
| | $ | — |
|
| Depreciation and amortization | | 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 | | 355 |
| | 537 |
| | 1,098 |
| | (182 | ) | | (561 | ) |
| 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 | | 358 |
| | 237 |
| | 266 |
| | 121 |
| | (29 | ) |
| Non-cash adjustments to net income (loss) | | 964 |
| | 3,346 |
| | 3,121 |
| | (2,382 | ) | | 225 |
|
| Net income, adjusted for non-cash items | | $ | 2,529 |
| | $ | 2,569 |
| | $ | 2,344 |
| | $ | (40 | ) | | $ | 225 |
|
Changes in working capital (1) | | (186 | ) | | (65 | ) | | 553 |
| | (121 | ) | | (618 | ) |
Net cash provided by operating activities (2) | | $ | 2,343 |
| | $ | 2,504 |
| | $ | 2,897 |
| | $ | (161 | ) | | $ | (393 | ) |
_____________________________
| |
(1) | Refer to tablesthe table below for driver explanations byof the variance in operating assets and liabilities. |
| |
(2) | Refer to below operating cash flow discussion by SBU for further information aboutAmounts included in the key drivers.table above include the results of discontinued operations, where applicable. |
Fiscal Year 20152018 versus 20142017
The net change inCash provided by operating assets and liabilitiesactivities decreased $161 million for the year ended December 31, 20152018, compared to December 31, 2017, primarily driven by a decrease in net income, adjusted for non-cash items of $40 million, and a $121 million increase in working capital requirements.
The increase in working capital requirements of $121 million for the year ended December 31, 20142018, compared to December 31, 2017, was primarily driven by (in millions):
|
| | | |
| | $ Change |
| Decrease in prepaid expenses and other current assets primarily at Eletropaulo, Gener and DPL | $ | 728 |
|
| Decrease in accounts receivable primarily in the Dominican Republic, DPL and Puerto Rico, partially offset by increases at Mong Duong and Chivor | 142 |
|
| Increase in income tax payables, net and other tax payables primarily in Brazil and at Gener | 142 |
|
| Increase in accounts payable and other current liabilities primarily at Eletropaulo, Sul and Mong Duong, partially offset by decreases at Tietê and Gener | 116 |
|
| Increase in other assets primarily regulatory assets at Eletropaulo and Sul as well as service concession assets at Mong Duong | (582 | ) |
| Other operating assets and liabilities | 39 |
|
| | $ | 585 |
|
|
| | | |
| Decreases in operating cash flow resulting from changes in: | |
| Prepaid expenses and other current assets, primarily due to an insurance recovery receivable at Andres, advance payments to gas suppliers at Colon, and prior year collections of net regulatory assets at Eletropaulo, which was deconsolidated in Q4 2017; partially offset by the impact of the sales of Miami Fort and Zimmer and the retirement of the Stuart facility at DPL | $ | (129 | ) |
| Accounts payable and other current liabilities, primarily due to the deconsolidation of Eletropaulo in Q4 2017 and the timing of payments on coal purchases at Gener; partially offset by the timing of payments on coal purchases at Puerto Rico | (101 | ) |
| Other liabilities, primarily due to the deconsolidation of Eletropaulo in Q4 2017; partially offset by a prior year decrease in deferred tax and derivative liabilities at the Parent Company | (57 | ) |
| Accounts receivable, primarily due to lower collections at Los Mina and Itabo, and higher sales at Colon and Chivor; partially offset by the deconsolidation of Eletropaulo in Q4 2017 and higher CAMMESA collections at Alicura | (29 | ) |
| Increases in operating cash flow resulting from changes in: | |
| Other assets, primarily related to the deconsolidation of Eletropaulo in Q4 2017 and collections on the construction performance obligation from the offtaker at Vietnam | 263 |
|
| Other | (68 | ) |
| Total decrease in operating cash flow from higher working capital requirements | $ | (121 | ) |
Fiscal Year 20142017 versus 20132016
The net change inCash provided by operating assets and liabilitiesactivities decreased $393 million for the year ended December 31, 20142017, compared to December 31, 2016, primarily driven by an increase in net income, adjusted for non-cash items of $225 million and a $618 million increase in working capital requirements.
The increase in working capital requirements of $618 million for the year ended December 31, 20132017, compared to December 31, 2016, was primarily driven by (in millions):
|
| | | |
| | $ Change |
| Increase in accounts receivable primarily at Eletropaulo, Sul and Maritza, partially offset by a decrease at Masinloc | $ | (666 | ) |
| Increase in other assets primarily regulatory assets at Eletropaulo, IPL, DPL and Sul | (620 | ) |
| Increase in prepaid expenses and other current assets primarily regulatory assets at Eletropaulo as well as increases at the Dominican Republic, Gener and Kilroot | (431 | ) |
| Decrease in income tax payables, net and other tax payables primarily in Brazil and the U.S. as well as our sold businesses in Africa and the Ukraine, partially offset by an increase at Chivor | (184 | ) |
| Increase in accounts payable and other current liabilities primarily at Eletropaulo, Tietê, Sul and Uruguaiana | 673 |
|
| Increase in other liabilities primarily regulatory liabilities at Eletropaulo and pension liabilities at IPL | 614 |
|
| Other operating assets and liabilities | (64 | ) |
| | $ | (678 | ) |
|
| | | |
| Decreases in operating cash flow resulting from changes in: | |
| Prepaid expenses and other current assets, primarily short-term regulatory assets at Eletropaulo and Sul | $ | (763 | ) |
| Accounts receivable, primarily at Maritza and Eletropaulo | (414 | ) |
| Other liabilities, primarily due to higher deferrals into regulatory liabilities related to energy costs in 2016 compared to 2017 at Eletropaulo | (361 | ) |
| Increases in operating cash flow resulting from changes in: | |
| Accounts payable and other current liabilities, primarily at Eletropaulo, Tietê, Gener and Maritza; partially offset at the Parent Company | 782 |
|
| Income taxes payable, net, and other taxes payable, primarily at Gener, Tietê and Eletropaulo | 252 |
|
| Other | (114 | ) |
| Total decrease in operating cash flow from higher working capital requirements | $ | (618 | ) |
Investing Activities
Fiscal Year 20152018 versus 20142017
Changes to netNet cash used in investing activities decreased $2,094 million for the year ended December 31, 20152018 compared to December 31, 2014 were2017, which was primarily driven by (in millions):
|
| | | |
| | $ Change |
Increase in capital expenditures primarily due to Andes SBU generation growth projects (1) | $ | (292 | ) |
| Decrease in cash paid for acquisitions primarily related to Guacolda for $728 million in Andes SBU in 2014 | 711 |
|
| Decrease in proceeds from sales of business primarily related to $730 million for Guacolda and $436 million for Masinloc in Andes and Asia SBUs, respectively in 2014. | (1,669 | ) |
| Increase in restricted cash, debt service and other assets | (578 | ) |
| Other | 118 |
|
| | $ | (1,710 | ) |
|
| | | |
| Increases in: | |
| Proceeds from the sales of business interests, net of cash and restricted cash sold, primarily due to the current year sales of Masinloc, Electrica Santiago, Eletropaulo, CTNG and the DPL Peaker assets, partially offset by the sale of the Kazakhstan CHPs in 2017 and transaction costs incurred for the Beckjord sale | $ | 1,912 |
|
| Decreases in: | |
| Payments for the acquisitions of business interests, net of cash and restricted cash acquired, primarily due to the acquisitions of sPower and Alto Sertão II in 2017 | 543 |
|
Capital expenditures (1) | 56 |
|
| Cash resulting from net purchases of short-term investments | (339 | ) |
| Other investing activities | (78 | ) |
| Total decrease in net cash used in investing activities | $ | 2,094 |
|
(1) _____________________________
| |
(1) | Refer to the tables below for a breakout of capital expenditure by type and by primary business driver. |
The following table summarizes the Company's capital expenditures for growth investments, maintenance, and environmental reported in investing cash activities for the periods indicated (in millions):
|
| | | | | | | | | | | | |
| | | December 31, |
| | | 2018 | | 2017 | | $ Change |
| Growth Investments | | $ | 1,663 |
| | $ | 1,549 |
| | $ | 114 |
|
| Maintenance | | 423 |
| | 552 |
| | (129 | ) |
| Environmental | | 35 |
| | 76 |
| | (41 | ) |
| Total capital expenditures | | $ | 2,121 |
| | $ | 2,177 |
| | $ | (56 | ) |
Cash used for capital expenditure types and other business drivers.expenditures decreased $56 million for the year ended December 31, 2018 compared to December 31, 2017, which was primarily driven by (in millions):
|
| | | |
| Decreases in: | |
| Growth expenditures at the MCAC SBU, primarily related to the completion of the Colon project, and lower spending at Los Mina due to the completion of the Combined Cycle project | $ | (242 | ) |
| Maintenance and environmental expenditures at the South America SBU, primarily due to the deconsolidation of Eletropaulo in Q4 2017 | (183 | ) |
| Increases in: |
|
|
| Growth expenditures at the US and Utilities SBU, primarily due to increased spending for the Southland re-powering project | 373 |
|
| Other capital expenditures | (4 | ) |
| Total decrease in capital expenditures | $ | (56 | ) |
Fiscal Year 2017 versus 2016
Net cash used in investing activities increased $463 million for the year ended December 31, 2017 compared to December 31, 2016, which was primarily driven by (in millions):
|
| | | |
| Increases in: | |
| Payments for the acquisitions of businesses, net of cash and restricted cash acquired, and equity method investees (related to the acquisitions of sPower and Alto Sertão II in 2017, partially offset by reduced acquisitions of Distributed Energy projects in 2016) | $ | (557 | ) |
| Contributions to equity investments at OPGC and sPower | (83 | ) |
| Cash resulting from net sales of short-term investments | 477 |
|
| Decreases in: | |
| Proceeds from the sale of business, net of cash and restricted cash sold, related to the sale of Sul in 2016, partially offset by the sale of Zimmer and Miami Fort | (430 | ) |
Capital expenditures (1) | 168 |
|
| Other investing activities | (38 | ) |
| Total increase in net cash used in investing activities | $ | (463 | ) |
_____________________________
| |
(1) | Refer to the tables below for a breakout of capital expenditures by type and by primary business driver. |
The following table summarizes the Company's capital expenditures for growth investments, maintenance and environmental for the periods indicated ($ in(in millions):
| | | | December 31, | | | | | | December 31, |
| | 2015 | | 2014 | | $ Change | | % Change | | 2017 | | 2016 | | $ Change |
| Growth Investments | $ | (1,401 | ) | | $ | (1,151 | ) | | $ | (250 | ) | | 22 | % | | $ | 1,549 |
| | $ | 1,510 |
| | $ | 39 |
|
| Maintenance | (606 | ) | | (645 | ) | | 39 |
| | -6 | % | | 552 |
| | 617 |
| | (65 | ) |
Environmental (2)(1) | (301 | ) | | (220 | ) | | (81 | ) | | 37 | % | | 76 |
| | 218 |
| | (142 | ) |
| Total capital expenditures | $ | (2,308 | ) | | $ | (2,016 | ) | | $ | (292 | ) | | 14 | % | | $ | 2,177 |
| | $ | 2,345 |
| | $ | (168 | ) |
_____________________________
| |
(2)(1)
| Includes both recoverable and non-recoverable environmental capital expenditures. See Non GAAP Proportional Free Cash Flow for more information. |
Changes to cash
Cash used for capital expenditures for growth investments, maintenance, and environmentaldecreased by $168 million for the year ended December 31, 20152017 compared to December 31, 2014 were2016, which was primarily driven by (in millions):
|
| | | |
| | $ Change |
| Increase primarily due to growth expenditures at Gener, IPALCO and Los Mina in Andes, US and MCAC SBUs, respectively | $ | (601 | ) |
| Decrease in growth expenditures at Mong Duong in Asia SBU due to service concession accounting adoption in 2015, and at Jordan in Europe SBU due to completion of IPP4 plant construction | 344 |
|
| Increase in maintenance and environmental expenditures at IPALCO and DPL businesses in US SBU | (41 | ) |
| Other business drivers | 6 |
|
| | $ | (292 | ) |
|
| | | |
| Decreases in: | |
| Growth expenditures at the South America SBU, primarily due to the completion of the Cochrane project and slower than anticipated productivity by construction contractors at Alto Maipo | $ | (114 | ) |
| Growth expenditures at the Eurasia SBU, primarily due to timing of payments resulting in more financed capex | (73 | ) |
| Maintenance and environmental expenditures at the US and Utilities SBU, primarily due to lower spending at IPALCO on the NPDES and MATS compliance and Harding Street refueling projects, decreased spending on CCR compliance, and decreased spending at DPL on Stuart and Killen facilities due to planned plant closures | (180 | ) |
| Increases in: | |
| Growth expenditures at the US and Utilities SBU, primarily due to increased spending for the Southland re-powering project and various Distributed Energy projects; partially offset by lower spending related to Eagle Valley at IPALCO | 233 |
|
| Other capital expenditures | (34 | ) |
| Total decrease in capital expenditures | $ | (168 | ) |
Fiscal Year 2014 versus 2013Changes to net cash used in investing activities for the year ended December 31, 2014 compared to December 31, 2013 were driven by (in millions):
|
| | | |
| | $ Change |
Increase in capital expenditures primarily due to US SBU generation growth projects (1) | $ | (28 | ) |
| Increase in cash paid for acquisitions primarily related to Guacolda for $728 million in Andes SBU | (721 | ) |
| Increase in proceeds from sales of business primarily related to $730 million for Guacolda and $436 million for Masinloc in Andes and Asia SBUs, respectively | 1,637 |
|
| Decrease in restricted cash, debt service and other assets | 375 |
|
| Other | (145 | ) |
| | $ | 1,118 |
|
(1) Refer to tables below for capital expenditure types and other business drivers.
The following table summarizes the Company's capital expenditures for growth investments, maintenance and environmental for the periods indicated ($ in millions):
|
| | | | | | | | | | | | | | |
| | December 31, | | | | |
| | 2014 | | 2013 | | $ Change | | % Change |
| Growth Investments | $ | (1,151 | ) | | $ | (1,054 | ) | | $ | (97 | ) | | 9 | % |
| Maintenance | (645 | ) | | (751 | ) | | 106 |
| | -14 | % |
Environmental (2) | (220 | ) | | (183 | ) | | (37 | ) | | 20 | % |
| Total capital expenditures | $ | (2,016 | ) | | $ | (1,988 | ) | | $ | (28 | ) | | 1 | % |
| |
(2)
| Includes both recoverable and non-recoverable environmental capital expenditures. See Non-GAAP Proportional Free Cash Flow for more information. |
Changes to cash used for capital expenditures for growth investments, maintenance, and environmental for the year ended December 31, 2014 compared to December 31, 2013 were driven by (in millions):
|
| | | |
| | $ Change |
| Increase primarily due to growth expenditures at IPALCO, Gener, and Mong Duong in US, Andes and Asia SBUs, respectively | $ | (287 | ) |
| Decrease in growth expenditures at Jordan and Eletropaulo in Europe and Brazil SBUs, respectively | 205 |
|
| Decrease in maintenance and environmental expenditures at Eletropaulo in Brazil SBU | 48 |
|
| Other business drivers | 6 |
|
| | $ | (28 | ) |
Financing Activities
Net cash used in financing activities were driven by ($ in millions):
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, | | $ Change |
| | 2015 | | 2014 | | 2013 | | 2015 vs. 2014 | | 2014 vs. 2013 |
| Issuances and repayments of recourse debt: | | | | | | | | | |
Corporate — Parent Company issuances | $ | 575 |
| | $ | 1,525 |
| | $ | 750 |
| | $ | (950 | ) | | $ | 775 |
|
Corporate — Parent Company repayments | (915 | ) | | (2,117 | ) | | (1,210 | ) | | 1,202 |
| | (907 | ) |
| Net repayments of recourse debt | $ | (340 | ) | | $ | (592 | ) | | $ | (460 | ) | | $ | 252 |
| | $ | (132 | ) |
| Issuances and repayments of non-recourse debt: | | | | | | | | | |
US — IPALCO issuances | $ | 847 |
| | $ | 130 |
| | $ | 170 |
| | $ | 717 |
| | $ | (40 | ) |
US — IPALCO repayments | (602 | ) | | — |
| | (110 | ) | | (602 | ) | | 110 |
|
US — DPL issuances | 325 |
| | 200 |
| | 645 |
| | 125 |
| | (445 | ) |
US — DPL repayments | (475 | ) | | (364 | ) | | (948 | ) | | (111 | ) | | 584 |
|
US — Generation Holdings, Shady Point, Warrior Run and Hawaii issuances | — |
| | 337 |
| | 86 |
| | (337 | ) | | 251 |
|
US — Hawaii, Southland, Warrior Run, Shady Point repayments | (33 | ) | | (417 | ) | | (190 | ) | | 384 |
| | (227 | ) |
| Other business drivers | (11 | ) | | (12 | ) | | (13 | ) | | 1 |
| | 1 |
|
| US SBU net subtotal | 51 |
| | (126 | ) | | (360 | ) | | 177 |
| | 234 |
|
Andes — Gener issuances | 1,131 |
| | 1,934 |
| | 707 |
| | (803 | ) | | 1,227 |
|
Andes — Gener repayments | (423 | ) | | (1,714 | ) | | (67 | ) | | 1,291 |
| | (1,647 | ) |
Andes — Chivor repayments | — |
| | (165 | ) | | — |
| | 165 |
| | (165 | ) |
| Other business drivers | 22 |
| | 5 |
| | (21 | ) | | 17 |
| | 26 |
|
| Andes SBU net subtotal | 730 |
| | 60 |
| | 619 |
| | 670 |
| | (559 | ) |
Brazil — Sul issuances | 513 |
| | 185 |
| | 153 |
| | 328 |
| | 32 |
|
Brazil — Sul repayments | (486 | ) | | (58 | ) | | (44 | ) | | (428 | ) | | (14 | ) |
Brazil — Eletropaulo issuances | 354 |
| | 253 |
| | 8 |
| | 101 |
| | 245 |
|
Brazil — Eletropaulo repayments | (211 | ) | | (110 | ) | | (26 | ) | | (101 | ) | | (84 | ) |
Brazil — Tietê issuances | 153 |
| | 318 |
| | 496 |
| | (165 | ) | | (178 | ) |
Brazil — Tietê repayments | (226 | ) | | (132 | ) | | (396 | ) | | (94 | ) | | 264 |
|
| Other business drivers | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
|
| Brazil SBU net subtotal | 96 |
| | 456 |
| | 191 |
| | (360 | ) | | 265 |
|
MCAC — Panama issuances | 300 |
| | 137 |
| | — |
| | 163 |
| | 137 |
|
MCAC — Panama repayments | (287 | ) | | (35 | ) | | — |
| | (252 | ) | | (35 | ) |
| MCAC — Andres Issuances | 180 |
| | — |
| | — |
| | 180 |
| | — |
|
| MCAC — Andres Repayments | (176 | ) | | — |
| | — |
| | (176 | ) | | — |
|
| MCAC — Changuinola and Caess - EEO issuances | — |
| | — |
| | 730 |
| | — |
| | (730 | ) |
| MCAC — Changuinola and Caess - EEO repayments | (10 | ) | | (10 | ) | | (713 | ) | | — |
| | 703 |
|
| Other business drivers | (35 | ) | | (26 | ) | | (99 | ) | | (9 | ) | | 73 |
|
| MCAC SBU net subtotal | (28 | ) | | 66 |
| | (82 | ) | | (94 | ) | | 148 |
|
| Asia — Mong Duong issuances | 203 |
| | 363 |
| | 472 |
| | (160 | ) | | (109 | ) |
| Asia — Masinloc issuances | 31 |
| | 26 |
| | 500 |
| | 5 |
| | (474 | ) |
| Asia — Masinloc repayments | (32 | ) | | (31 | ) | | (560 | ) | | (1 | ) | | 529 |
|
| Other business drivers | (21 | ) | | 1 |
| | (3 | ) | | (22 | ) | | 4 |
|
| Asia SBU net subtotal | 181 |
| | 359 |
| | 409 |
| | (178 | ) | | (50 | ) |
Europe — UK Wind issuances | — |
| | 132 |
| | 18 |
| | (132 | ) | | 114 |
|
| Europe —UK Wind repayments | — |
| | (139 | ) | | (26 | ) | | 139 |
| | (113 | ) |
Europe — Maritza repayments | (62 | ) | | (65 | ) | | (57 | ) | | 3 |
| | (8 | ) |
Europe — Jordan Levant issuances | — |
| | — |
| | 180 |
| | — |
| | (180 | ) |
| Other business drivers | (35 | ) | | (45 | ) | | (5 | ) | | 10 |
| | (40 | ) |
| Europe SBU net subtotal | (97 | ) | | (117 | ) | | 110 |
| | 20 |
| | (227 | ) |
| Corporate SBU net subtotal | 3 |
| | — |
| | — |
| | 3 |
| | — |
|
| Net issuances of non-recourse debt | $ | 936 |
| | $ | 698 |
| | $ | 887 |
| | $ | 238 |
| | $ | (189 | ) |
| Proceeds from the sale of redeemable stock of subsidiaries: | | | | | | | | | |
Corporate and US — IPALCO | $ | 461 |
| | $ | — |
| | $ | — |
| | $ | 461 |
| | $ | — |
|
| Total proceeds from the sale of redeemable stock of subsidiaries | $ | 461 |
| | $ | — |
| | $ | — |
| | $ | 461 |
| | $ | — |
|
| Dividends paid on The AES Corporation common stock | | | | | | | | | |
Corporate — Parent Company | $ | (276 | ) | | $ | (144 | ) | | $ | (119 | ) | | $ | (132 | ) | | $ | (25 | ) |
| Total dividends paid on The AES Corporation common stock | $ | (276 | ) | | $ | (144 | ) | | $ | (119 | ) | | $ | (132 | ) | | $ | (25 | ) |
| Payments for financed capital expenditures: | | | | | | | | | |
Andes — Gener | $ | (131 | ) | | $ | (178 | ) | | $ | (34 | ) | | $ | 47 |
| | $ | (144 | ) |
Asia — Mong Duong | — |
| | (310 | ) | | (519 | ) | | $ | 310 |
| | $ | 209 |
|
| Other business drivers | (19 | ) | | (40 | ) | | (38 | ) | | $ | 21 |
| | $ | (2 | ) |
| Total payments for financed capital expenditures | $ | (150 | ) | | $ | (528 | ) | | $ | (591 | ) | | $ | 378 |
| | $ | 63 |
|
| Purchase of treasury stock | | | | | | | | | |
Corporate — Parent Company | $ | (482 | ) | | $ | (308 | ) | | $ | (322 | ) | | $ | (174 | ) | | $ | 14 |
|
| Total purchase of treasury stock | $ | (482 | ) | | $ | (308 | ) | | $ | (322 | ) | | $ | (174 | ) | | $ | 14 |
|
| Proceeds from sales to noncontrolling interest, net of transaction costs | | | | | | | | | |
| Andes - Gener | $ | 145 |
| | $ | — |
| | $ | 109 |
| | $ | 145 |
| | $ | (109 | ) |
| MCAC - Dominican Republic | 18 |
| | 83 |
| | — |
| | (65 | ) | | 83 |
|
| US - IPALCO | (9 | ) | | — |
| | — |
| | (9 | ) | | — |
|
| Total proceeds from sales to noncontrolling interest, net of transaction costs | $ | 154 |
| | $ | 83 |
| | $ | 109 |
| | $ | 71 |
| | $ | (26 | ) |
| Other cash uses for financing activities | $ | (275 | ) | | $ | (471 | ) | | $ | (640 | ) | | $ | 196 |
| | $ | 169 |
|
| Net cash provided by (used in) financing activities | $ | 28 |
| | $ | (1,262 | ) | | $ | (1,136 | ) | | $ | 1,290 |
| | $ | (126 | ) |
Proportional Free Cash Flow (a non-GAAP measure)
We define proportional free cash flow as cash flows from operating activities less maintenance capital expenditures (including non-recoverable environmental capital expenditures), adjusted 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 or repaying debt or other purposes. 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.
|
| | | | | | | | | | | | | | | | | | | | |
| Calculation of Proportional Free Cash Flow (in millions) | | 2015 | | 2014 | | 2013 | | 2015/2014 Change | | 2014/2013 Change |
| Net Cash Provided by Operating Activities | | $ | 2,134 |
| | $ | 1,791 |
| | $ | 2,715 |
| | $ | 343 |
| | $ | (924 | ) |
Add: capital expenditures related to service concession assets (1) | | 165 |
| | — |
| | — |
| | 165 |
| | — |
|
| Adjusted Operating Cash Flow | | 2,299 |
| | 1,791 |
| | 2,715 |
| | 508 |
| | (924 | ) |
Less: proportional adjustment factor on operating cash activities (2) (3) | | (558 | ) | | (359 | ) | | (834 | ) | | (199 | ) | | 475 |
|
| Proportional Adjusted Operating Cash Flow | | 1,741 |
| | 1,432 |
| | 1,881 |
| | 309 |
| | (449 | ) |
Less: proportional maintenance capital expenditures, net of reinsurance proceeds(2) | | (449 | ) | | (485 | ) | | (535 | ) | | 36 |
| | 50 |
|
Less: proportional non-recoverable environmental capital expenditures (2) (4) | | (51 | ) | | (56 | ) | | (75 | ) | | 5 |
| | 19 |
|
| Proportional Free Cash Flow | | $ | 1,241 |
| | $ | 891 |
| | $ | 1,271 |
| | $ | 350 |
| | $ | (380 | ) |
| |
(1)
| Service concession asset expenditures excluded from proportional free cash flow non-GAAP metric. |
| |
(2)
| The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds) and proportional non-recoverable environmental capital expenditures are calculated by multiplying the percentage owned by noncontrolling interests for each entity by its corresponding consolidated cash flow metric and are totaled to the resulting figures. For example, Parent Company A owns 20% of Subsidiary Company B, a consolidated subsidiary. Thus, Subsidiary Company B has an 80% noncontrolling interest. Assuming a consolidated net cash flow from operating activities of $100 from Subsidiary B, the proportional adjustment factor for Subsidiary B would equal $80 (or $100 x 80%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then sums these amounts to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to noncontrolling interests as a result of (a) non-cash items which impact income but not cash and (b) AES' ownership interest in the subsidiary where such items occur. |
| |
(3)
| Includes proportional adjustment amount for service concession asset expenditures of $84increased $1,686 million for the year ended December 31, 2015 . The Company adopted service concession accounting effective January 1, 2015. |
| |
(4)
| Excludes IPL's proportional recoverable environmental capital expenditures of $205 million, $163 million and $110 million for the years December 31, 2015, 2014 and 2013, respectively. |
Operating Cash Flow and Proportional Free Cash Flow Analysis (1)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Cash Flow by SBU | | Proportional Free Cash Flow by SBU
|
| | 2015 | | 2014 | | 2013 | | 2015/2014 Change | | 2014/2013 Change | | 2015 | | 2014 | | 2013 | | 2015/2014 Change | | 2014/2013 Change |
| US | $ | 845 |
| | $ | 830 |
| | $ | 924 |
| | $ | 15 |
| | $ | (94 | ) | | $ | 591 |
| | $ | 646 |
| | $ | 689 |
| | $ | (55 | ) | | $ | (43 | ) |
| Andes | 462 |
| | 359 |
| | 373 |
| | 103 |
| | (14 | ) | | 224 |
| | 176 |
| | 188 |
| | 48 |
| | (12 | ) |
| Brazil | 136 |
| | 316 |
| | 866 |
| | (180 | ) | | (550 | ) | | (29 | ) | | 13 |
| | 116 |
| | (42 | ) | | (103 | ) |
| MCAC | 705 |
| | 370 |
| | 550 |
| | 335 |
| | (180 | ) | | 498 |
| | 281 |
| | 433 |
| | 217 |
| | (152 | ) |
| Europe | 339 |
| | 292 |
| | 486 |
| | 47 |
| | (194 | ) | | 238 |
| | 197 |
| | 345 |
| | 41 |
| | (148 | ) |
| Asia | 15 |
| | 105 |
| | 111 |
| | (90 | ) | | (6 | ) | | 87 |
| | 82 |
| | 101 |
| | 5 |
| | (19 | ) |
| Corporate | (368 | ) | | (481 | ) | | (595 | ) | | 113 |
| | 114 |
| | (368 | ) | | (504 | ) | | (601 | ) | | 136 |
| | 97 |
|
| Total SBUs | $ | 2,134 |
| | $ | 1,791 |
| | $ | 2,715 |
| | $ | 343 |
| | $ | (924 | ) | | $ | 1,241 |
| | $ | 891 |
| | $ | 1,271 |
| | $ | 350 |
| | $ | (380 | ) |
| |
(1)
| Operating cash flow and proportional free cash flow as presented above include the effect of intercompany transactions with other segments except for interest, tax sharing, charges for management fees and transfer pricing. |
US SBU
The following table summarizes Operating Cash Flow and Proportional Free Cash Flow (in millions) for our US SBU for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | |
| Calculation of Proportional Free Cash Flow (in millions) | 2015 | | 2014 | | 2013 | | 2015/2014 Change | | 2014/2013 Change |
| Net Cash Provided by Operating Activities | $ | 845 |
| | $ | 830 |
| | $ | 924 |
| | $ | 15 |
| | $ | (94 | ) |
| Less: proportional adjustment factor on operating cash activities | (48 | ) | | — |
| | — |
| | (48 | ) | | — |
|
| Proportional Adjusted Operating Cash Flow | 797 |
| | 830 |
| | 924 |
| | (33 | ) | | (94 | ) |
| Less: proportional maintenance capital expenditures, net of reinsurance proceeds | (199 | ) | | (180 | ) | | (231 | ) | | (19 | ) | | 51 |
|
Less: proportional non-recoverable environmental capital expenditures (1) | (7 | ) | | (4 | ) | | (4 | ) | | (3 | ) | | — |
|
| Proportional Free Cash Flow | $ | 591 |
| | $ | 646 |
| | $ | 689 |
| | $ | (55 | ) | | $ | (43 | ) |
| |
(1)
| Excludes IPL's proportional recoverable environmental capital expenditures of $205 million, $163 million and $110 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Fiscal Year 2015 versus 2014
Operating Cash Flow for the year ended December 31, 20152018 compared to the year ended December 31, 2014 increased $15 million,2017, which was primarily driven primarily by the following businesses(in(in millions):
|
| | | | |
| US SBU | | Amount |
| While operating margin decreased at DPL, operating cash flow increased primarily due to the collection of previously deferred storm costs, a one-time payment in 2014 to terminate an unfavorable coal contract, higher collections and the timing of inventory payments | | $ | 65 |
|
| Decrease at U.S. Wind primarily due to a decrease in operating margin as well as the timing of collections | | (38 | ) |
| Other business drivers | | (12 | ) |
| Total | | $ | 15 |
|
|
| | | |
| Increases in: | |
Net repayments of recourse debt at the Parent Company (1) | $ | (605 | ) |
| Net repayments of non-recourse debt at Angamos, DPL, Chivor, and Maritza | (372 | ) |
| Net repayments on revolving credit facilities at IPALCO and Gener | (370 | ) |
| Net issuance of non-recourse debt at Southland | 199 |
|
| Decreases in: | |
| Net issuance of non-recourse debt at AES Argentina, Tietê, Colon, Alto Maipo, US Generation, and Los Mina | (614 | ) |
| Net borrowing on revolving credit facilities at the Parent Company | (413 | ) |
| Net repayments of non-recourse debt at IPALCO and Gener | 518 |
|
| Other financing activities | (29 | ) |
| Total increase in net cash used in financing activities | $ | (1,686 | ) |
Proportional Free Cash Flow_____________________________
| |
(1) | See Note 10—Debtin Item 8.—Financial Statements and Supplementary Data of this Form 10-K for more information regarding significant recourse debt transactions. |
Net cash provided by financing activities increased $790 million for the year ended December 31, 20152017 compared to the year ended December 31, 2014 decreased $55 million, due to the drivers above, as well as a $22 million increase in maintenance and non-recoverable capital expenditures and adjusted for the impact of noncontrolling interest as a result of the sell-down of IPL in 2015.
Fiscal Year 2014 versus 2013
Operating Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $94 million,2016, which was primarily driven primarily by the following businesses (in millions):
|
| | | | |
| US SBU | | Amount |
| Decrease at DPL primarily due to a decrease in operating margin, the timing of fuel payments as well as a one-time payment in the fourth quarter of 2014 to terminate an unfavorable coal contract, partially offset by a reduction in interest payments | | $ | (74 | ) |
| Decrease at Beaver Valley primarily due to one-time contract termination proceeds received in 2013 | | (54 | ) |
| Increase at Hawaii primarily due to an increase in operating margin | | 13 |
|
| Increase at Southland primarily due to an increase in operating margin as well as the timing of collections | | 12 |
|
| Other business drivers | | 9 |
|
| Total | | $ | (94 | ) |
|
| | | |
| Increases in: | |
| Net issuance of non-recourse debt at Southland, Tiete, Eletropaulo, AES Argentina, and Colon | $ | 1,396 |
|
| Net repayments of non-recourse debt at Gener and IPALCO | (628 | ) |
| Net borrowing on revolving credit facilities at the Parent Company and Gener | 297 |
|
| Decreases in: | |
| Net repayments on revolving credit facilities at IPALCO | 123 |
|
| Net issuance of non-recourse debt at Cochrane | (170 | ) |
| Proceeds from the sale of redeemable stock of subsidiaries at IPALCO | (134 | ) |
| Contributions from noncontrolling interests and redeemable security holders at Colon, IPALCO, and Distributed Energy | (117 | ) |
| Other financing activities | 23 |
|
| Total Increase in net cash provided by financing activities | $ | 790 |
|
Proportional Free Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $43 million, due to the drivers above, partially offset by a $51 million reduction in maintenance capital expenditures, primarily at our Utility businesses.ANDES SBU
The following table summarizes Operating Cash Flow and Proportional Free Cash Flow (in millions) for our Andes SBU for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | |
| Calculation of Proportional Free Cash Flow ($ in millions) | 2015 | | 2014 | | 2013 | | 2015/2014 Change | | 2014/2013 Change |
| Net Cash Provided by Operating Activities | $ | 462 |
| | $ | 359 |
| | $ | 373 |
| | $ | 103 |
| | $ | (14 | ) |
| Less: proportional adjustment factor on operating cash activities | (145 | ) | | (73 | ) | | (78 | ) | | (72 | ) | | 5 |
|
| Proportional Adjusted Operating Cash Flow | 317 |
| | 286 |
| | 295 |
| | 31 |
| | (9 | ) |
| Less: proportional maintenance capital expenditures, net of reinsurance proceeds | (70 | ) | | (63 | ) | | (45 | ) | | (7 | ) | | (18 | ) |
| Less: proportional non-recoverable environmental capital expenditures | (23 | ) | | (47 | ) | | (62 | ) | | 24 |
| | 15 |
|
| Proportional Free Cash Flow | $ | 224 |
| | $ | 176 |
| | $ | 188 |
| | $ | 48 |
| | $ | (12 | ) |
Fiscal Year 2015 versus 2014
Operating Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 increased $103 million, driven primarily by the following businesses (in millions):
|
| | | | |
| Andes SBU | | Amount |
| Increase at Gener primarily due to an increase in VAT refunds related to the construction of our Cochrane and Alto Maipo plants as well as an increase in operating margin, partially offset by a swap termination payment at Ventanas | | $ | 178 |
|
| Decrease at Chivor primarily due to an increase in tax payments, lower collections on contract sales and a decrease in operating margin, partially offset by a decrease in interest payments | | (73 | ) |
| Other business drivers | | (2 | ) |
| Total | | $ | 103 |
|
Proportional Free Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 increased $48 million, due to the drivers above, as well as a $17 million net reduction in maintenance and non-recoverable environmental capital expenditures and adjusted for the impact of noncontrolling interest.
Fiscal Year 2014 versus 2013
Operating Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $14 million, driven primarily by the following businesses (in millions):
|
| | | | |
| Andes SBU | | Amount |
| Decrease at Gener primarily due to higher payments for interest, higher payments for VAT at our Cochrane plant, a one-time swap termination payment as well as a reduction in operating margin, partially offset by a reduction in tax payments | | $ | (82 | ) |
| Decrease at Argentina Generation primarily due to an increase in interest and tax payments as well as the negative impact of exchange rates on collections, partially offset by an increase in operating margin | | (27 | ) |
| Increase at Chivor primarily due to higher operating margin as well as a reduction in tax payments | | 95 |
|
| Total | | $ | (14 | ) |
Proportional Free Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $12 million, due to the drivers above as well as a $3 million net increase in maintenance and non-recoverable environmental capital expenditures and adjusted for the impact of noncontrolling interest.
BRAZIL SBU
The following table summarizes Operating Cash Flow and Proportional Free Cash Flow (in millions) for our Brazil SBU for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | |
| Calculation of Proportional Free Cash Flow | 2015 | | 2014 | | 2013 | | 2015/2014 Change | | 2014/2013 Change |
| Net Cash Provided by Operating Activities | $ | 136 |
| | $ | 316 |
| | $ | 866 |
| | $ | (180 | ) | | $ | (550 | ) |
| Less: proportional adjustment factor on operating cash activities | (102 | ) | | (215 | ) | | (643 | ) | | 113 |
| | 428 |
|
| Proportional Adjusted Operating Cash Flow | 34 |
| | 101 |
| | 223 |
| | (67 | ) | | (122 | ) |
| Less: proportional maintenance capital expenditures, net of reinsurance proceeds | (63 | ) | | (88 | ) | | (107 | ) | | 25 |
| | 19 |
|
| Less: proportional non-recoverable environmental capital expenditures | — |
| | — |
| | — |
| | — |
| | — |
|
| Proportional Free Cash Flow | $ | (29 | ) | | $ | 13 |
| | $ | 116 |
| | $ | (42 | ) | | $ | (103 | ) |
Fiscal Year 2015 versus 2014
Operating Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 decreased $180 million, driven primarily by the following businesses (in millions):
|
| | | | |
| Brazil SBU | | Amount |
| Decrease at Eletropaulo primarily due to the timing of collections, higher payments for interest and taxes as well as a decrease in operating margin, partially offset by the timing of payments for energy and regulatory charges as well as the favorable impact of exchange rates on cash payments | | $ | (90 | ) |
| Decrease at Tietê primarily due to the timing of energy purchases and higher interest payments, partially offset by lower income tax payments and an increase in operating margin | | (62 | ) |
| Decrease at Sul primarily driven by a decrease in operating margin and an increase in interest payments, partially offset by the timing energy purchases and regulatory charges | | (30 | ) |
| Other business drivers | | 2 |
|
| Total | | $ | (180 | ) |
Proportional Free Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 decreased $42 million, due to the drivers above, partially offset by a $25 million reduction in maintenance capital expenditures and adjusted for the impact of noncontrolling interest.
Fiscal Year 2014 versus 2013
Operating Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $550 million, driven primarily by the following businesses (in millions):
|
| | | | |
| Brazil SBU | | Amount |
| Decrease at Eletropaulo primarily due to the timing of collections on regulatory assets and settlement of regulatory liabilities as well as higher interest and tax payments in 2014, partially offset by an increase in operating margin | | $ | (397 | ) |
| Decrease at Tietê primarily due to a decrease in operating margin, partially offset by the timing of payments for energy purchased in the spot market as well as lower tax payments | | (133 | ) |
| Decrease at Sul primarily due to higher payments for taxes and interest, partially offset by an increase in operating margin | | (44 | ) |
| Other business drivers | | 24 |
|
| Total | | $ | (550 | ) |
Proportional Free Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $103 million, due to the drivers above, partially offset by a $19 million reduction in maintenance capital expenditures and adjusted for the impact of noncontrolling interest.
MCAC SBU
The following table summarizes Operating Cash Flow and Proportional Free Cash Flow (in millions) for our MCAC SBU for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | |
| Calculation of Proportional Free Cash Flow | 2015 | | 2014 | | 2013 | | 2015/2014 Change | | 2014/2013 Change |
| Net Cash Provided by Operating Activities | $ | 705 |
| | $ | 370 |
| | $ | 550 |
| | $ | 335 |
| | $ | (180 | ) |
| Less: proportional adjustment factor on operating cash activities | (143 | ) | | (27 | ) | | (44 | ) | | (116 | ) | | 17 |
|
| Proportional Adjusted Operating Cash Flow | 562 |
| | 343 |
| | 506 |
| | 219 |
| | (163 | ) |
| Less: proportional maintenance capital expenditures, net of reinsurance proceeds | (61 | ) | | (60 | ) | | (71 | ) | | (1 | ) | | 11 |
|
| Less: proportional non-recoverable environmental capital expenditures | (3 | ) | | (2 | ) | | (2 | ) | | (1 | ) | | — |
|
| Proportional Free Cash Flow | $ | 498 |
| | $ | 281 |
| | $ | 433 |
| | $ | 217 |
| | $ | (152 | ) |
Fiscal Year 2015 versus 2014
Operating Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 increased $335 million, driven primarily by the following business drivers (in millions):
|
| | | | |
| MCAC SBU | | Amount |
| Increase in Panama primarily due to an increase in operating margin as well as higher collections on contract sales | | $ | 137 |
|
| Increase in the Dominican Republic primarily due to the timing of collections of outstanding accounts receivable and lower tax payments, partially offset by a decrease in operating margin | | 119 |
|
| Increase in El Salvador primarily due to the timing of energy purchases as well as an increase in operating margin, excluding an unbilled revenue adjustment, which did not impact operating cash flow | | 45 |
|
| Excluding the impact of the 2014 non-cash bad debt reversal, operating margin in Puerto Rico remained flat, however operating cash flow increased primarily due to the timing of collections from the off-taker | | 34 |
|
| Total | | $ | 335 |
|
Proportional Free Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 increased $217 million, due to the drivers above, partially offset by a $2 million increase in maintenance and non-recoverable environmental capital expenditures and adjusted for the impact of noncontrolling interest.
Fiscal Year 2014 versus 2013
Operating Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $180 million, driven primarily by the following SBUs and key operating drivers (in millions):
|
| | | | |
| MCAC SBU | | Amount |
| Decrease in the Dominican Republic primarily due to a one-time settlement received in 2013 related to a fuel contract amendment as well as an increase in tax payments, partially offset by an increase in operating margin | | $ | (99 | ) |
| Decrease in Panama primarily due to the timing of energy purchases as well as a decrease in operating margin | | (55 | ) |
| Decrease in El Salvador primarily due to a decrease in operating margin | | (26 | ) |
| Total | | $ | (180 | ) |
Proportional Free Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $152 million, due to the drivers above, partially offset by an $11 million reduction in maintenance capital expenditures and adjusted for the impact of noncontrolling interest.
EUROPE SBU
The following table summarizes Operating Cash Flow and Proportional Free Cash Flow (in millions) for our Europe SBU for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | |
| Calculation of Proportional Free Cash Flow | 2015 | | 2014 | | 2013 | | 2015/2014 Change | | 2014/2013 Change |
| Net Cash Provided by Operating Activities | $ | 339 |
| | $ | 292 |
| | $ | 486 |
| | $ | 47 |
| | $ | (194 | ) |
| Less: proportional adjustment factor on operating cash activities | (32 | ) | | (27 | ) | | (66 | ) | | (5 | ) | | 39 |
|
| Proportional Adjusted Operating Cash Flow | 307 |
| | 265 |
| | 420 |
| | 42 |
| | (155 | ) |
| Less: proportional maintenance capital expenditures, net of reinsurance proceeds | (51 | ) | | (65 | ) | | (68 | ) | | 14 |
| | 3 |
|
| Less: proportional non-recoverable environmental capital expenditures | (18 | ) | | (3 | ) | | (7 | ) | | (15 | ) | | 4 |
|
| Proportional Free Cash Flow | $ | 238 |
| | $ | 197 |
| | $ | 345 |
| | $ | 41 |
| | $ | (148 | ) |
Fiscal Year 2015 versus 2014
Operating Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 increased $47 million, driven primarily by the following business drivers (in millions):
|
| | | | |
| Europe SBU | | Amount |
| While operating margin decreased at Maritza, operating cash flow increased primarily due to higher collections from the off-taker. (Refer to the Key Trends and Uncertainties discussion for further information regarding the collection of outstanding receivables) | | $ | 69 |
|
| Increase at IPP4 in Jordan primarily due to the commencement of operations in July 2014 as well as the timing of customer collections | | 38 |
|
| Decrease in operating cash as a result of the sale of our Africa businesses and U.K. Wind (Operating Projects) in 2014 | | (52 | ) |
| Other business drivers | | (8 | ) |
| Total | | $ | 47 |
|
Proportional Free Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 increased $41 million, due to the drivers above, partially offset by a $1 million net increase in maintenance and non-recoverable environmental capital expenditures and adjusted for the impact of noncontrolling interest.
Fiscal Year 2014 versus 2013
Operating Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $194 million, driven primarily by the following business drivers (in millions):
|
| | | | |
| Europe SBU | | Amount |
| Decrease in operating cash as a result of the sale of our businesses in Africa and the Ukraine as well as our U.K. Wind (Operating Projects) | | $ | (100 | ) |
| Decrease at Maritza primarily due to a decrease in operating margin as well as timing of collections from the off-taker | | (58 | ) |
| Decrease at Kilroot primarily due to a decrease in operating margin as well as an increase in pension contributions | | (45 | ) |
| Increase at Elsta in the Netherlands primarily driven by the timing of dividends received from our equity method investment | | 29 |
|
| Other business drivers | | (20 | ) |
| Total | | $ | (194 | ) |
Proportional Free Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $148 million, due to the drivers above, partially offset by a $7 million reduction in maintenance and non-recoverable environmental capital expenditures and adjusted for the impact of noncontrolling interest.
ASIA SBU
The following table summarizes Operating Cash Flow and Proportional Free Cash Flow (in millions) for our Asia SBU for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | |
| Calculation of Proportional Free Cash Flow | 2015 | | 2014 | | 2013 | | 2015/2014 Change | | 2014/2013 Change |
| Net Cash Provided by Operating Activities | $ | 15 |
| | $ | 105 |
| | $ | 111 |
| | $ | (90 | ) | | $ | (6 | ) |
Add: capital expenditures related to service concession assets (1) | 165 |
| | — |
| | — |
| | 165 |
| | — |
|
| Adjusted Operating Cash Flow | 180 |
| | 105 |
| | 111 |
| | 75 |
| | (6 | ) |
Less: proportional adjustment factor on operating cash activities (2) | (88 | ) | | (17 | ) | | (3 | ) | | (71 | ) | | (14 | ) |
| Proportional Adjusted Operating Cash Flow | 92 |
| | 88 |
| | 108 |
| | 4 |
| | (20 | ) |
| Less: proportional maintenance capital expenditures, net of reinsurance proceeds | (5 | ) | | (6 | ) | | (7 | ) | | 1 |
| | 1 |
|
| Less: proportional non-recoverable environmental capital expenditures | — |
| | — |
| | — |
| | — |
| | — |
|
| Proportional Free Cash Flow | $ | 87 |
| | $ | 82 |
| | $ | 101 |
| | $ | 5 |
| | $ | (19 | ) |
| |
(1)
| Service concession asset expenditures excluded from proportional free cash flow non-GAAP metric. |
| |
(2)
| Includes proportional adjustment amount for service concession asset expenditures of $84 million for the year ended December 31, 2015. The Company adopted service concession accounting effective January 1, 2015. |
Fiscal Year 2015 versus 2014
Operating Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 decreased $90 million, driven primarily by the following business drivers (in millions):
|
| | | | |
| Asia SBU | | Amount |
| Decrease at Mong Duong in Vietnam primarily driven by payment for service concession assets, partially offset by an increase in operating cash due to commencement of operations in April 2015 | | $ | (85 | ) |
| Other business drivers | | (5 | ) |
| Total | | $ | (90 | ) |
Proportional Free Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 increased $5 million, due to the drivers above and adjusted for the impact of noncontrolling interest as well as $84 million of proportional service concession assets, which are excluded from the calculation of proportional free cash flow.
Fiscal Year 2014 versus 2013
Operating Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $6 million, driven primarily by the following business drivers (in millions):
|
| | | | |
| Asia SBU | | Amount |
| Decrease at Kelanitissa primarily due to lower operating margin and collections as a result of the step-down in the contracted PPA price | | $ | (21 | ) |
| Increase at Masinloc primarily due to the timing of collections (despite the market operator's price adjustment) and payments for coal purchases as well as decreases in cash paid for interest and taxes, partially offset by a decrease in operating margin | | 16 |
|
| Other business drivers | | (1 | ) |
| Total | | $ | (6 | ) |
Proportional Free Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $19 million, due to the drivers above, partially offset by a $1 million reduction in maintenance capital expenditures and adjusted for the impact of noncontrolling interest.
CORPORATE
The following table summarizes Operating Cash Flow and Proportional Free Cash Flow (in millions) for Corporate for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | |
| Calculation of Proportional Free Cash Flow | 2015 | | 2014 | | 2013 | | 2015/2014 Change | | 2014/2013 Change |
| Net Cash Provided by Operating Activities | $ | (368 | ) | | $ | (481 | ) | | $ | (595 | ) | | $ | 113 |
| | $ | 114 |
|
| Proportional Adjusted Operating Cash Flow | (368 | ) | | (481 | ) | | (595 | ) | | 113 |
| | 114 |
|
| Less: proportional maintenance capital expenditures, net of reinsurance proceeds | — |
| | (23 | ) | | (6 | ) | | 23 |
| | (17 | ) |
| Proportional Free Cash Flow | $ | (368 | ) | | $ | (504 | ) | | $ | (601 | ) | | $ | 136 |
| | $ | 97 |
|
Fiscal Year 2015 versus 2014
Operating Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 increased $113 million, driven primarily by the following business drivers (in millions):
|
| | | | |
| Corporate | | Amount |
| Increase primarily at the Parent Company driven by lower interest payments, prior year swap termination payments upon refinance of debt, a reduction in incentive payments and the collection of realized gains resulting from the Company's corporate hedging program | | $ | 113 |
|
| Total | | $ | 113 |
|
Proportional Free Cash Flow for the year ended December 31, 2015 compared to the year ended December 31, 2014 increased $136 million, due to the drivers above as well as an $23 million reduction in maintenance capital expenditures.
Fiscal Year 2014 versus 2013
Operating Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 increased $114 million, driven primarily by the following business drivers (in millions):
|
| | | | |
| Corporate | | Amount |
| Increase primarily at the Parent Company driven by lower interest payments | | $ | 114 |
|
| Total | | $ | 114 |
|
Proportional Free Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 increased $97 million, due to the drivers above, partially offset by a $17 million increase in maintenance capital expenditures.
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.
Parent Company Liquidity
The following discussion of Parent Company Liquidity has beenis included because we believe it isas a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company Liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to cash and cash equivalents which areis determined in accordance with GAAP, as a measure of liquidity. Cash and cash equivalents are disclosed in the consolidated statements of cash flows.GAAP. Parent Company Liquidity may differ from similarly titled measures used by other companies. The principal sources of liquidity at the Parent Company level are dividends and other distributions from our subsidiaries, including refinancing proceeds;proceeds, proceeds from debt and equity financings at the Parent Company level, including availability under our credit facility;facilities, and proceeds from asset sales. Cash requirements at the Parent Company level are primarily to fund interest; principal repayments of debt; construction commitments; other equity commitments; common stock repurchases; acquisitions; taxes; Parent Company overhead and development costs; and dividends on common stock.
The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facility.facilities plus cash at qualified holding companies. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S..U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company
Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, Cash and cash equivalents, at December 31, 20152018 and 20142017 as follows:
| | | Parent Company Liquidity (in millions) | | 2015 | | 2014 | | 2018 | | 2017 |
| Consolidated cash and cash equivalents | | $ | 1,262 |
| | $ | 1,539 |
| | $ | 1,166 |
| | $ | 949 |
|
| Less: Cash and cash equivalents at subsidiaries | | 862 |
| | 1,032 |
| | (1,142 | ) | | (938 | ) |
| Parent and qualified holding companies' cash and cash equivalents | | 400 |
| | 507 |
| | 24 |
| | 11 |
|
| Commitments under Parent credit facility | | 800 |
| | 800 |
| |
| Commitments under Parent Company credit facilities | | | 1,100 |
| | 1,100 |
|
| Less: Letters of credit under the credit facilities | | (62 | ) | | (61 | ) | | (78 | ) | | (35 | ) |
| Borrowings available under Parent credit facilities | | 738 |
| | 739 |
| |
| Less: Borrowings under the credit facilities | | | — |
| | (207 | ) |
| Borrowings available under Parent Company credit facilities | | | 1,022 |
| | 858 |
|
| Total Parent Company Liquidity | | $ | 1,138 |
| | $ | 1,246 |
| | $ | 1,046 |
| | $ | 869 |
|
The Parent Company paid dividends of $0.40$0.52 per share to its common stockholders during the year ended December 31, 2015.2018. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance that we will continue to pay dividends, or if continued, the amount of such dividends.
Recourse Debt—
Our total recourse debt at year-end was approximately $5.0$3.7 billion and $5.3$4.6 billion in 2015at December 31, 2018 and 2014,2017, respectively. See Note 12—10—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional detail. While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets, (see Key Trends and Uncertainties—Global Economic Conditions), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries' ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. See Item 1A.—Risk Factors—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, of this Form 10-K. Various debt instruments at the Parent Company level, including our senior secured credit facility,facilities, contain certain restrictive covenants. The covenants provide for, — among other items, — limitations on other indebtedness,indebtedness; liens, investments and guarantees; limitations on dividends, stock repurchases and other equity transactions; restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements; maintenance of certain financial ratios; and financial and other reporting requirements.
As of December 31, 2015,2018, we were in compliance with these covenants at the Parent Company level.
Non-Recourse Debt—
While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:
reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default;
triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;
causing us to record a loss in the event the lender forecloses on the assets; and
triggering defaults in our outstanding debt at the Parent Company.
For example, our senior secured credit facilityfacilities and outstanding debt securities at the Parent Company include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.
Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying Consolidated Balance Sheets amounts to $2.5$1.7 billion. The portionAs of December 31, 2018, $351 million of non-recourse debt was current debt related to such defaults was $1.0 billion at December 31, 2015, alltwo subsidiaries, AES Puerto Rico and AES Ilumina, 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. The Company expects to modify the Colon loan agreement in 2019 to amend the requirements of this technical covenant, after which was non-recoursethe debt related to four subsidiaries — Maritza, Sul, Kavarna, and Sogrinsk.will be re-classified as noncurrent. See Note 12—10—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional detail. None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES' corporate debt agreements as of December 31, 20152018 in order for such defaults to trigger an event of default or permit acceleration under AES' indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a "material subsidiary" and thereby upon an acceleration, trigger an event of default and possible acceleration of the indebtedness under the Parent Company's outstanding debt securities. A material subsidiary is defined in the Company's senior secured revolving credit facilityfacilities as any business that contributed 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of December 31, 2015,2018, none of the defaults listed above individually or in the aggregate results in or is at risk of triggering a cross-default under the recourse debt of the Company.
Contractual Obligations and Parent Company Contingent Contractual Obligations
A summary of our contractual obligations, commitments and other liabilities as of December 31, 20152018 is presented in the table below whichand excludes any businesses classified as discontinued operations or held-for-sale (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Contractual Obligations | Total | | Less than 1 year | | 1-3 years | | 3-5 years | | More than 5 years | | Other | | Footnote Reference(5) |
Debt Obligations(1) | $ | 20,807 |
| | $ | 2,529 |
| | $ | 2,562 |
| | $ | 3,624 |
| | $ | 12,092 |
| | $ | — |
| | 12 |
|
Interest Payments on Long-Term Debt(2) | 7,897 |
| | 1,233 |
| | 2,131 |
| | 1,552 |
| | 2,981 |
| | — |
| | n/a |
|
Capital Lease Obligations(3) | 147 |
| | 14 |
| | 23 |
| | 20 |
| | 90 |
| | — |
| | 13 |
|
Operating Lease Obligations(3) | 1,291 |
| | 77 |
| | 157 |
| | 159 |
| | 898 |
| | — |
| | 13 |
|
Electricity Obligations(3) | 37,594 |
| | 2,623 |
| | 5,078 |
| | 5,717 |
| | 24,176 |
| | — |
| | 13 |
|
Fuel Obligations(3) | 5,253 |
| | 1,120 |
| | 1,367 |
| | 625 |
| | 2,141 |
| | — |
| | 13 |
|
Other Purchase Obligations(3) | 9,383 |
| | 1,332 |
| | 2,128 |
| | 1,528 |
| | 4,395 |
| | — |
| | 13 |
|
| Other Long-Term Liabilities |
| | | | | | | | | | | | |
Reflected on AES' Consolidated Balance Sheet under GAAP(4) | 696 |
| | — |
| | 220 |
| | 35 |
| | 406 |
| | 35 |
| | n/a |
|
| Total | $ | 83,068 |
| | $ | 8,928 |
| | $ | 13,666 |
| | $ | 13,260 |
| | $ | 47,179 |
| | $ | 35 |
| | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Contractual Obligations | Total | | Less than 1 year | | 1-3 years | | 3-5 years | | More than 5 years | | Other | | Footnote Reference(4) |
Debt obligations (1) | $ | 19,687 |
| — |
| $ | 1,701 |
| — |
| $ | 3,567 |
| — |
| $ | 4,407 |
| — |
| $ | 10,012 |
| | $ | — |
| | 10 |
|
Interest payments on long-term debt (2) | 6,967 |
| | 846 |
| | 1,625 |
| | 1,194 |
| | 3,302 |
| | — |
| | n/a |
|
| Capital lease obligations | 12 |
| | 1 |
| | 2 |
| | 2 |
| | 7 |
| | — |
| | 11 |
|
| Operating lease obligations | 643 |
| | 74 |
| | 63 |
| | 51 |
| | 455 |
| | — |
| | 11 |
|
| Electricity obligations | 7,573 |
| | 786 |
| | 973 |
| | 627 |
| | 5,187 |
| | — |
| | 11 |
|
| Fuel obligations | 6,175 |
| | 1,494 |
| | 1,909 |
| | 1,038 |
| | 1,734 |
| | — |
| | 11 |
|
| Other purchase obligations | 3,944 |
| | 1,375 |
| | 1,017 |
| | 774 |
| | 778 |
| | — |
| | 11 |
|
Other long-term liabilities reflected on AES' consolidated balance sheet under GAAP (3) | 809 |
| | — |
| | 263 |
| | 207 |
| | 326 |
| | 13 |
| | n/a |
|
| Total | $ | 45,810 |
| | $ | 6,277 |
| | $ | 9,419 |
| | $ | 8,300 |
| | $ | 21,801 |
| | $ | 13 |
| | |
_____________________________
| |
(1) | Includes recourse and non-recourse debt presented on the Consolidated Balance Sheet. See Note 12—Debt to the Consolidated Financial Statements included in Item 8—Financial Statements and Supplementary Data of this Form 10-K which provides additional disclosure regarding these obligations. These amounts exclude capital lease obligations which are included in the capital lease category, see (3) below. category. |
| |
(2) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 20152018 and do not reflect anticipated future refinancing, early redemptions or new debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2015.2018. |
| |
(3) | See Note 13—Commitments to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further information.
|
| |
(4)
| These amounts do not include current liabilities on the Consolidated Balance Sheet except for the current portion of uncertain tax obligations. Noncurrent uncertain tax obligations are reflected in the "Other" column of the table above as the Company is not able to reasonably estimate the timing of the future payments. In addition, thethese amounts do not include: (1) regulatory liabilities (See Note 11—9—Regulatory Assets and Liabilities), (2) contingencies (See Note 14—12—Contingencies), (3) pension and other post retirementpostretirement employee benefit liabilities (see Note 15—13—Benefit Plans), (4) derivatives and incentive compensation (See Note 5—Derivative Instruments and Hedging Activities) or (4)(5) any taxes (See Note 22—21—Income Taxes) except for uncertain tax obligations, as the Company is not able to reasonably estimate the timing of future payments. See the indicated notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on the items excluded. Derivatives (See Note 6—Derivative Instruments and Hedging Activities) and incentive compensation are excluded as the Company is not able to reasonably estimate the timing or amount of the future payments. |
| |
(5)(4)
| For further information see the note referenced below in Item 8.—Financial Statements and Supplementary Data of this Form 10-K. |
The following table presents our Parent Company's contingent contractual obligations as of December 31, 2015:2018:
| | | Contingent contractual obligations ($ in millions) | | Amount | | Number of Agreements | | Maximum Exposure Range for Each Agreement | |
| Contingent contractual obligations | | | Amount (in millions) | | Number of Agreements | | Maximum Exposure Range for Each Agreement (in millions) |
| Guarantees and commitments | | $ | 369 |
| | 14 | | $1 - 53 | | $ | 685 |
| | 33 | | $0 — 157 |
| Letters of credit under the unsecured credit facility | | | 368 |
| | 10 | | $1 — 247 |
| Letters of credit under the senior secured credit facility | | | 78 |
| | 23 | | $0 — 49 |
Asset sale related indemnities(1) | | 27 |
| | 1 | | 27 | | 27 |
| | 1 | | $27 |
| Cash collateralized letters of credit | | 32 |
| | 4 | | $1 - 15 | |
| Letters of credit under the senior secured credit facility | | 62 |
| | 7 | | <$1 - 29 | |
| Total | | $ | 490 |
| | 26 | | | $ | 1,158 |
| | 67 | |
(1) Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal._____________________________
As of December 31, 2015, the Company had no commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit disclosed above. | |
(1) | Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal. |
We have a diverse portfolio of performance-related contingent contractual obligations. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, subsidiary default, political risk, tax indemnities, spot market power prices, sponsor support and liquidated damages under power sales agreements for projects in development, in operation and under construction. In addition, we have an
asset sale program through which we may have customary indemnity obligations under certain assets sale agreements. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations beyond 2015,2018, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.
Critical Accounting Policies and Estimates
The Consolidated Financial Statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. AES' significant accounting policies are described in Note 1—General and Summary of Significant Accounting Policies to the Consolidated Financial Statements included in Item 8 of this Form 10-K. An accounting estimate is considered critical if the estimate requires management to make assumptions about matters that were highly uncertain at the time the estimate was made;made, different estimates reasonably could have been used;used, or the impact of the estimates and assumptions on financial condition or operating performance is material.
Management believes that the accounting estimates employed are appropriate and the resulting balances are reasonable; however, actual results could materially differ from the original estimates, requiring adjustments to these balances in future periods. Management has discussed these critical accounting policies with the Audit Committee, as appropriate. Listed below are the Company's most significant critical accounting estimates and assumptions used in the preparation of the Consolidated Financial Statements.
Income Taxes — We are subject to income taxes in both the U.S. and numerous foreign jurisdictions. Our worldwide income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the Internal Revenue Service and other taxing authorities. The Company and certainCertain of itsthe Company's subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each tax jurisdiction when determining the adequacy of the provision for income taxes. Accounting guidance for uncertainty in income taxes prescribes a more likely than not recognition threshold. Tax reserves have been established, which the Company believes to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While the Company believes that the amounts of the tax estimates are reasonable, it is possible that the ultimate outcome of current or future examinations may be materially different than the reserve amounts.
Because we have a wide range of statutory tax rates in the multiple jurisdictions in which we operate, any changes in our geographical earnings mix could materially impact our effective tax rate. Furthermore, our tax position could be adversely impacted by changes in tax laws, tax treaties or tax regulations or the interpretation or enforcement thereof and such changes may be more likely or become more likely in view of recent economic trends in certain of the jurisdictions in which we operate. As an example, new tax laws were enacted in February 2016December 2017 in Chilethe U.S. which will increasedecreased the statutory income tax rate for mostfrom 35% to 21%, required a one-time transition tax, and introduced numerous other changes. As further outlined in Key Trends and Uncertainties, the Company anticipates that the GILTI provisions of our Chilean businesses from 25% to 25.5%U.S. tax reform could materially impact the effective tax rate in 2017 and to 27% for 2018 and future years. Accordingly, in 2016 our net Chilean deferred tax liabilities will be remeasured periods. See Note 21—Income Taxesto the new rates. The remeasurement amountConsolidated Financial Statements included in Item 8 of this Form 10-K for additional information. In accordance with SAB 118, the Company made reasonable estimates of the impacts of U.S. tax reform on its 2017 financial results, and other potential futurerecorded adjustments to those estimates in 2018 as analysis was completed. As of December 31, 2018, our analysis of the one-time impacts of the changesTCJA is complete under SAB 118. However, in tax law may be material to continuing operations.
The Company's provision for income taxes could be adversely impacted by changes tothe first quarter of 2019, the U.S. taxation of earnings of our foreign subsidiaries. Since 2006,Treasury Department issued final regulations on the Company has benefitedone-time transition tax. The final regulations include changes from the Controlled Foreign Corporation look-through rule, originally enactedproposed regulations issued in 2018 and we expect to record the impacts of the final regulations in the TIPRAfirst quarter of 2005, subject to five temporary extensions, including2019. We are still evaluating the most recent five year retroactive extension enactedfinal regulations which may have a material impact on December 18, 2015 in the H.R.2029 - Consolidated Appropriations Act, 2016. There can be no assurance that this provision will continue to be extended beyond December 31, 2019. Further, the U.S. is considering corporate tax reform that may significantly change the U.S. international tax rules and corporate tax rates. Our expected effective tax rate could increase by amounts that may be material to the Company should such reforms be enacted.our financial statements.
In addition, U.S. income taxes and foreign withholdingno taxes have not been providedrecorded on undistributed earnings for certain of our non-U.S. subsidiaries to the extent such earnings are considered to be indefinitely reinvested in the operations of those subsidiaries. Should the earnings be remitted as dividends, the Company may be subject to additional foreign withholding and state income taxes.
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income
tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company has elected to treat GILTI as an expense in the period in which the tax is accrued. Accordingly, no deferred tax assets or liabilities are recorded related to GILTI.
Sales of Noncontrolling Interests — TheSales of noncontrolling interests are recognized within stockholders' equity. Effective January 1, 2018, the Company adopted ASU No. 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets, which clarified the accounting for the sale of business interests as either the sale of nonfinancial assets or the sale of businesses. Among other things, under the newly adopted guidance fewer transactions are expected to meet the definition of a business under the scope of ASC 810 and will fall under the scope of the sale of nonfinancial assets.
Prior to January 1, 2018, the accounting for a sale of noncontrolling interests under the accounting standards dependswas dependent on whether the sale iswas considered to be a sale of in-substance real estate, (as opposed to an equity transaction), where the gain (loss) on sale would be recognized in earnings rather than within stockholders' equity. If management's estimation process determines that there is no significant value beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest is recognized in earnings. However, if it is determined that significant value likely exists beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest would be recognized within stockholders' equity. In-substance real estate is comprisedcomposed of land plus improvements and integral equipment. The determination of whether property, plant and equipment is integral equipment is based on the significance of the costs to remove the equipment from its existing location (including the cost of repairing damage resulting from the removal), combined with the decrease in the fair
value of the equipment as a result of those removal activities. When the combined total of removal costs and the decrease in fair value of the equipment exceeds 10% of the fair value of the equipment, the equipment is considered integral equipment. The accounting standards specifically identify power plants as an example of in-substance real estate. Where the consolidated entity in which noncontrolling interests have been sold contains in-substance real estate, management estimates the extent to which the total fair value of the assets of the entity is represented by the in-substance real estate and whether significant value exists beyond the in-substance real estate. This estimation considers all qualitative and quantitative factors relevant for each sale and, where appropriate, includes making quantitative estimates about the fair value of the entity and its identifiable assets and liabilities (including any favorable or unfavorable contracts) by analogy to the accounting standards on business combinations. As such, these estimates may require significant judgment and assumptions, similar to the critical accounting estimates discussed below for impairments and fair value.
Impairments — Our accounting policies on goodwill and long-lived assets are described in detail in Note 1—General and Summary of Significant Accounting Policies, included in Item 8 of this Form 10-K. The Company makes considerable judgments in its impairment evaluations of goodwill and long-lived assets; however,assets, starting with determining if an impairment indicator exists. Events that may result in an impairment analysis being performed include, but are not limited to: adverse changes in the regulatory environment, unfavorable changes in power prices or fuel costs, increased competition due to additional capacity in the grid, technological advancements, declining trends in demand, or an expectation it is more likely than not that the asset will be disposed of before the end of its previously estimated useful life. The Company exercises judgment in determining if these events represent an impairment indicator requiring the computation of the fair value of goodwill and/or the recoverability of long-lived assets. The fair value determination is typically the most judgmental part in an impairment evaluation. Please see Fair Value below for further detail. The Company determines the fair value of a reporting unit or a long-lived asset (asset group) by applying the approaches prescribed under the fair value measurement accounting framework. Generally, the market approach and income approach are most relevant in the fair value measurement of our reporting units and long-lived assets; however, due to the lack of available relevant observable market information in many circumstances, the Company often relies on the income approach. The Company may engage an independent valuation firm to assist management with the valuation. The decision to engage an independent valuation firm considers all relevant facts and circumstances, including a cost-benefit analysis and the Company's internal valuation knowledge of the long-lived asset (asset group) or business. The Company develops the underlying assumptions consistent with its internal budgets and forecasts for such valuations. Additionally, the Company uses an internal discounted cash flow valuation model (the "DCF model"), based on the principles of present value techniques, to estimate the fair value of its reporting units or long-lived assets under the income approach. The DCF model estimates fair value by discounting our internal budgets and cash flow forecasts, adjusted to reflect market participant assumptions, to the extent necessary, at an appropriate discount rate.
Management applies considerable judgment in selecting several input assumptions during the development of our internal budgets and cash flow forecasts. Examples of the input assumptions that our budgets and forecasts are sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power prices and commodity prices. Whenever appropriate, management obtains these input assumptions from observable market data sources (e.g., Economic Intelligence Unit) and extrapolates the market information if an input assumption is not observable for the entire forecast period. Many of these input assumptions are dependent on other economic assumptions, which are often derived from statistical economic models with inherent limitations such as estimation differences. Further, several input assumptions are based on historical trends which often do not recur. The input assumptions most significant to our budgets and cash flows are based on expectations of macroeconomic factors which have been volatile recently. It is not uncommon that different market data sources have different views of the macroeconomic factor expectations and related assumptions. As a result, macroeconomic factors and related assumptions are often available in a narrow range; however, in some situations these ranges become wide and the use of a different set of input assumptions could produce significantly different budgets and cash flow forecasts.
A considerable amount of judgment is also applied in the estimation of the discount rate used in the DCF model. To the extent practical, inputs to the discount rate are obtained from market data sources (e.g., Bloomberg, Capital IQ, etc.). The Company selects and uses a set of publicly traded companies from the relevant industry to estimate the discount rate inputs. Management applies judgment in the selection of such companies based on its view of the most likely market participants. It is reasonably possible that the selection of a different set of likely market participants could produce different input assumptions and result in the use of a different discount rate.
Fair value of a reporting unit or a long-lived asset (asset group) is sensitive to both input assumptions to our budgets and cash flow forecasts and the discount rate. Further, estimates of long-term growth and terminal value are often critical to the fair value determination. As part of the impairment evaluation process, management analyzes the sensitivity of fair value to various underlying assumptions. The level of scrutiny increases as the gap between fair value and carrying amount decreases. Changes in any of these assumptions could result in management reaching a different conclusion regarding the potential impairment, which could be material. Our impairment evaluations inherently involve uncertainties from uncontrollable events that could positively or negatively impact the anticipated future economic and operating conditions.
Fair Value
Fair Value Hierarchy — The Company uses valuation techniques and methodologies that maximize the use of observable inputs and minimize the use of unobservable inputs. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices are not available, valuation models are applied to estimate the fair value using the available observable inputs. The valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments' complexity.
To increase consistency and enhance disclosure of the fair value of financial instruments, the fair value measurement standard includes a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability's level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. For more information regarding the fair value hierarchy, see Note 1—General and Summary of Significant Accounting Policies included in Item 8 of this Form 10-K.Fair Value of Financial Instruments — A significant number of the Company's financial instruments are carried at fair value with changes in fair value recognized in earnings or other comprehensive income each period. The Company makes estimates regarding the valuation of assets and liabilities measured at fair value in preparing the Consolidated Financial Statements. These assets and liabilities include short and long-term investments in debt and equity securities, included in the balance sheet line items Short-term investments and Other assets (Noncurrent), derivative assets, included in Other current assets and Other assets (Noncurrent) and derivative liabilities, included in Accrued and other liabilities (current) and Other long-term liabilities. Investments are generally fair valued based on quoted market prices or other observable market data such as interest rate indices. The Company's investments are primarily certificates of deposit government debt securities and money marketmutual funds. Derivatives are valued using observable data as inputs into internal valuation models. The Company's derivatives primarily consist of interest rate swaps, foreign currency instruments, and commodity and embedded derivatives. Additional
discussion regarding the nature of these financial instruments and valuation techniques can be found in Note 4—Fair Value included in Item 8 of this Form 10-K. Fair Value of Nonfinancial Assets and Liabilities — Significant estimates are made in determining the fair value of long-lived tangible and intangible assets (i.e., property, plant and equipment, intangible assets and goodwill) during the impairment evaluation process. In addition, the majority of assets acquired and liabilities assumed in a business combination and asset acquisitions by VIEs are required to be recognized at fair value under the relevant accounting guidance. In determining
The Company may engage an independent valuation firm to assist management with the valuation. The Company generally utilizes the income approach to value nonfinancial assets and liabilities, specifically a Discounted Cash Flow ("DCF") model to estimate fair value by discounting cash flow forecasts, adjusted to reflect market participant assumptions, to the extent necessary, at an appropriate discount rate.
Management applies considerable judgment in selecting several input assumptions during the development of our cash flow forecasts. Examples of the input assumptions that our forecasts are sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power prices and commodity prices. Whenever appropriate, management obtains these input assumptions from observable market data sources (e.g., Economic Intelligence Unit) and extrapolates the market information if an input assumption is not observable for the entire forecast period. Many of these items, management makesinput assumptions are dependent on other economic assumptions, which are often derived from statistical economic models with inherent limitations such as estimation differences. Further, several input assumptions as discussedare based on historical trends which often do not recur. It is not uncommon that different market data sources have different views of the macroeconomic factor expectations and related assumptions. As a result, macroeconomic factors and related assumptions are often available in a narrow range; however, in some situations these ranges become wide and the use of a different set of input assumptions could produce significantly different budgets and cash flow forecasts.
A considerable amount of judgment is also applied in the Impairments section above.estimation of the discount rate used in the DCF model. To the extent practical, inputs to the discount rate are obtained from market data sources (e.g., Bloomberg). The Company selects and uses a set of publicly traded companies from the relevant industry to estimate the discount rate inputs. Management applies judgment in the selection of such companies based on its view of the most likely market participants. It is reasonably possible that the selection of a different set of likely market participants could produce different input assumptions and result in the use of a different discount rate.
Accounting for Derivative Instruments and Hedging Activities — We enter into various derivative transactions in order to hedge our exposure to certain market risks. We primarily use derivative instruments to manage our interest rate, commodity and foreign currency exposures. We do not enter into derivative transactions for trading purposes.
In accordance with the accounting standards for derivatives and hedging, we recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value except where derivatives qualify and are designated as "normal purchase/normal sale" transactions. Changes in fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Income and expense related to derivative instruments are recognized in the same category as that generated by the underlying asset or liability. See Note 6—5—Derivative Instruments and Hedging Activitiesincluded in Item 8 of this Form 10-K for further information on the classification.The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective and is designated and qualifies as a fair value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. The Company has no fair value hedges at this time. Changes in the fair value of a derivative that is highly effective and is designated as and qualifies as a cash flow hedge, are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. For all hedge contracts, the Company provides formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging.
The fair value measurement accounting standard provides additional guidance on the definition of fair value and defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. The fair value measurement standard requires the Company to consider and reflect the assumptions of market participants in the fair value calculation. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk, both of the reporting entity (for liabilities) and of the counterparty (for assets). Due to the nature of the Company's interest rate swaps, which are typically associated with non-recourse debt, credit risk for AES is evaluated at the subsidiary level rather than at the Parent Company level. Nonperformance
risk on the Company's derivative instruments is an adjustment to the initial asset/liability fair value position that is derived from internally developed valuation models that utilize observable market inputs.
As a result of uncertainty, complexity and judgment, accounting estimates related to derivative accounting could result in material changes to our financial statements under different conditions or utilizing different assumptions. As a part of accounting for these derivatives, we make estimates concerning nonperformance, volatilities, market liquidity, future commodity prices, interest rates, credit ratings (both ours and our counterparty's), and future exchange rates. Refer to Note 4—Fair Value included in Item 8 of this Form 10-K for additional details. The fair value of our derivative portfolio is generally determined using internal and third party valuation models, most of which are based on observable market inputs, including interest rate curves and forward and spot prices for currencies and commodities. The Company derives most of its financial instrument market assumptions from market efficient data sources (e.g., Bloomberg, Reuters and Platt's). In some cases, where market data is not readily available, management uses comparable market sources and empirical evidence to derive market assumptions to determine a financial instrument's fair value. In certain instances, the published curve may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve. Specifically, where there is limited forward curve data with respect to foreign exchange contracts, beyond the traded points the Company utilizes the purchasing power parityinterest rate differential approach to construct the remaining portion of the
forward curve using relative inflation rates.curve. Additionally, in the absence of quoted prices, we may rely on "indicative pricing" quotes from financial institutions to input into our valuation model for certain of our foreign currency swaps. These indicative pricing quotes do not constitute either a bid or ask price and therefore are not considered observable market data. For individual contracts, the use of different valuation models or assumptions could have a material effect on the calculated fair value.
Regulatory Assets — Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, any asset write-offs would be required to be recognized in operating income.
Consolidation — The Company has recently enteredenters into several transactions wherebyimpacting the Company sells an interestCompany's equity interests in its controlled subsidiaries and/or equity method investments.affiliates. In connection with each transaction, the Company must determine whether the sale of the interesttransaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, the Company is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights.
If the entity is determined to be a variable interest entity, the most significant judgment in determining whether the Company must consolidate the entity is whether the subsidiary,Company, including its related parties and de facto agents, collectively have power and benefits. If AES is determined to have power and benefits, the entity will be consolidated by AES.
Alternatively, if the entity is determined to be a voting model entity, the most significant judgments involve determining whether the non-AES shareholders have substantive participating rights. The assessment of shareholder rights and whether they are substantive participating rights requires significant judgment since the rights provided under shareholders' agreements may include selecting, terminating, and setting the compensation of management responsible for implementing the subsidiary's policies and procedures, and establishing operating and capital decisions of the entity, including budgets, in the ordinary course of business. On the other hand, if shareholder rights are only protective in nature (referred to as protective rights) then such rights would not overcome the presumption that the owner of a majority voting interest shall consolidate its investee. Significant judgment is required to determine whether minority rights represent substantive participating rights or protective rights that do not affect the evaluation of control. While both represent an approval or veto right, a distinguishing factor is the underlying activity or action to which the right relates.
Pension and Other Postretirement Plans — Effective January 1, 2016The Company recognizes a net asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in actuarial gains or losses recognized in AOCL, except for those plans at certain of the Company's regulated utilities that can recover portions of their pension and postretirement obligations through future rates. The valuation of the Company's benefit obligation, fair value of plan assets, and net periodic benefit costs requires various estimates and assumptions, the most significant of which include the discount rate and expected return on plan assets. These assumptions are reviewed by the Company will apply a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans in the U.S. and U.K.on an annual basis. Refer to Note 1—General and Summary of Significant Accounting Policiesincluded in Item 8 of this Form 10-K for further information. New Accounting Pronouncements Revenue Recognition—See The Company recognizes revenue to depict the transfer of energy, capacity and other services to customers in an amount that reflects the consideration to which we expect to be entitled. In applying the revenue model, we determine whether the sale of energy, capacity and other services represent a single performance obligation based on the individual market and terms of the contract. Generally, the promise to transfer energy and capacity represent a performance obligation that is satisfied over time and meets the criteria to be accounted for as a series of distinct goods or services. Progress toward satisfaction of a performance obligation is measured using output methods, such as MWhs delivered or MWs made available, and when we are entitled to consideration in an amount that corresponds directly to the value of our performance completed to date, we recognize revenue in the amount to which we have the right to invoice. For further information regarding the nature of our revenue streams and our critical accounting policies affecting revenue recognition, see Note 1—General and Summary of Significant Accounting Policiesincluded in Item 8 of this Form 10-K.New Accounting Pronouncements — See Note 1—General and Summary of Significant Accounting Policies included in Item 8 of this Form 10-K for further information about new accounting pronouncements adopted during 20152018 and accounting pronouncements issued, but not yet effective.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview Regarding Market Risks — 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 addition, our businesses are also exposed to lower electricity prices due to increased competition, including from renewable sources such as wind and solar, as a result of lower costs of entry and lower variable costs. We
operate in multiple countries and 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,dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments.
The disclosures presented in this Item 7A are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 7A. For further information regarding market risk, see Item 1A.—Risk Factors, Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations, Our businesses may incur substantial costsWholesale power prices are declining in many markets and liabilities and be exposed to price volatility as a result of risks associated with the electricity markets, whichthis could have a material adverse effect on our financial performance,operations and opportunities for future growth, and We may not be adequately hedged against our exposure to changes in commodity prices or interest rates of this 20152018 Form 10-K. Commodity Price Risk — Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term sales or under contract sales that leave an unhedged exposure on some of our capacity or through imperfect fuel pass-throughs. In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations and sharing or pass-through mechanisms. These businesses subject our operational results to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options. At our generation businesses for 2016-2018, 80% to 85% of our variable margin is hedged against changes in commodity prices. At our utility businesses for 2016-2018, 85% to 90% of our variable margin is insulated from changes in commodity prices.
The portion of our sales and purchases that are not subject to such agreements or contracted businesses where indexation is not perfectly matched to business drivers will be exposed to commodity price risk. When hedging the output of our generation assets, we utilize contract sales that lock in the spread per MWh between variable costs and the price at which the electricity can be sold.
AES businesses will see changes in variable margin performance as global commodity prices shift. For 2016,2019, we project pretaxpre-tax earnings exposure on a 10% move in commodity prices would be approximately $25 million for U.S. power (DPL), less than $5 million for U.S. power, $(10) million for natural gas, $5less than $(5) million for oil and $10$(5) million for coal.Our estimates exclude correlation of oil with coal or natural gas. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company's downside exposure occurs with lower power, higher oil, lowerhigher natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some of our businesses.
Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Spot power prices, contract indexation provisions and generation costs can be directly or indirectly affected by movements in the price of natural gas, oil and coal. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. Exposures are not perfectly linear or symmetric. The sensitivities are affected by a number of local or indirect market factors. Examples of these factors include hydrology, local energy market supply/demand balances, regional fuel supply issues, regional competition, bidding strategies and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, certain power plants may limit downside exposure by reducing dispatch in low market environments. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices.
In the US and Utilities SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Additionally, at DPL, open access allows our retail customersprimarily generates energy to switch to alternative suppliers; falling energy prices may increase the rate of switching; DPL sells generation in excess ofmeet its retail demand under short-term sales. Given that natural gas-fired generators set power prices for manycustomer demand; however, it opportunistically sells surplus economic energy into wholesale markets higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set theat market price only during peak periods.prices.
In the AndesSouth America SBU, our business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. In the central region, the contract sales generally cover the efficient generation from our coal-fired and hydroelectric assets. Any residual spot price risk will primarily be driven by the amount of hydrological inflows. In the case of low hydroelectric generation, spot price exposure is capped by the ability to dispatch our natural gas/diesel assets, the price of which depends on fuel pricing at the time required. There is a small amount of coal generation in the northern region that is not covered by the portfolio of contract sales and therefore subject to spot price risk. In both regions, generators with oilunder normal hydrology conditions, coal-firing generation sets the price. However, when there are spikes in price due to lower hydrology and higher demand, gas or oil-
linked fueloil-linked fuels generally set power prices. In Colombia, we operate under a short-term sales strategy and have commodity exposure to unhedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel.
In the Additionally, in Brazil, SBU, the hydroelectric generating facility is covered by contract sales. Under normal hydrological volatility, spot price risk is mitigated through a regulated sharing mechanism across all hydroelectric generators in the country. Under drier conditions, the sharing mechanism may not be sufficient to cover the business' contract position, and therefore it may have to purchase power at spot prices driven by the cost of thermal generation.
In the MCAC SBU, our businesses have commodity exposure on unhedged volumes. Panama is highly contracted under a portfolio of fixed volume contract sales. To the extent hydrological inflows are greater than or less than the contract sales volume, the business will be sensitive to changes in spot power prices which may be driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices. Additionally, the contract levels do not always match our generation availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot market to satisfy contract obligations.
In the EuropeEurasia SBU, our Kilroot facility operates on a short-term sales strategy. To the extent that sales arevariable energy margin is unhedged, the commodity risk at our Kilroot business is to the clean dark spread, which is the difference between electricity price and our coal-based variable dispatch cost, including emissions. Natural gas-fired generators set power prices for many periods, so higher natural gas prices generally expand margins and higher coal or emissions prices reduce them. Similarly, increased wind generators displacesdisplace higher cost generation, potentially reducing Kilroot's margins, and vice versa.
In Two steam gas generating units at Ballylumford were shut down at the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a portfolioend of contract sales that are indexed2018 having reached the end of their economic lives. The open cycle gas turbines at both Ballylumford and Kilroot will continue to fuel prices, with generation in excessoperate as peaking units at times of contract volume or shortfalls of generation relative to contract volumes settled in the spot market. Low oil prices may be a driver of margin compression since oil affects spot power sale prices sold in the spot market. Low oil prices may be a driver of margin compression since oil affects spot power sale prices.high demand. Our Mong Duong business has minimal exposure to commodity price risk as it has no merchant exposure and fuel is subject to a pass-through mechanism.
Foreign Exchange Rate Risk — In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar ("USD").USD. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in the USD or currencies other than their own functional currencies. We have varying degrees of exposure to changes in the exchange rate between the USD and the following currencies: Argentine Peso,peso, British Pound,pound, Brazilian Real,real, Chilean Peso,peso, Colombian Peso,peso, Dominican Peso,peso, Euro, Indian Rupee, Kazakhstan Tenge,rupee, and Mexican Peso and Philippine Peso.peso. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.
We have enteredAES enters into foreign currency hedges to partially mitigateprotect economic value of the exposurebusiness and minimize impact of earnings translated into the USD to foreign exchange rate fluctuations to AES' portfolio. While protecting cash flows, the hedging strategy is also designed to reduce forward-looking earnings foreign exchange volatility. Due to variation of timing and amount between cash distribution and earnings exposure, the hedge impact may not fully cover the earnings exposure on a realized basis, which could result in greater volatility in earnings. The largest foreign exchange risks over a 12-month forward-looking period stem from the following currencies: Argentine Peso,peso, Brazilian real, Colombian peso, Euro, British Pound, Brazilian Real, Colombian Peso, Europound, and Kazakhstan Tenge.Indian Rupee. As of December 31, 2015,2018, assuming a 10% USD appreciation, adjusted pretax earningscash distributions attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine Peso, Brazilian Real, Colombian Peso,peso and Euro and Kazakhstan Tenge relative to the USDeach are projected to be reduced by approximately $5 million, and the Colombian peso, Brazilian real, British Pound —pound and Indian Rupee each are projected to be impacted by less than $5 million for 2016.million. These numbers have been produced by applying a one-time 10% USD appreciation to forecasted exposed pretax earningscash distributions for 20162019 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally,
updates to the forecasted pretax earningscash distributions exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility.
Interest Rate Risks — We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt, as well as interest rate swap, cap, floor and option agreements.
Decisions on the fixed-floating debt mix are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant's capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Most of our interest rate risk is related to non-recourse financings at our businesses.
As of December 31, 2015,2018, the portfolio's pretaxpre-tax earnings exposure for 20162019 to a one-time 100-basis-point increase in interest rates
for our Argentine Peso,peso, Brazilian Real,real, Chilean peso, Colombian Peso,peso, Euro Kazakhstani Tenge and USD denominated debt would be approximately $30$20 million based on the impact of a one time,100-basis-point upward shift in interest rates on interest expense for the debt denominated in these currencies. These amounts do not take into account the historical correlation between these interest rates.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
| |
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TheTo the Stockholders and the Board of Directors and Stockholders of The AES Corporation:
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of The AES Corporation (the Company) as of December 31, 20152018 and 2014,2017, and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included2018, and the related notes and the financial statement schedulesschedule listed in the indexIndex at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 26, 2019, expressed an unqualified opinion thereon.
Adoption of New Accounting Standards
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for revenue as a result of the adoption of Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606), and the amendments in ASUs 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10 and 2017-13 effective January 1, 2018.
Basis for Opinion
These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesethe Company’s financial statements and schedules based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includesmisstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The AES Corporation at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company changed its requirements for reporting discontinued operations as a result of the adoption of the amendments to the FASB Accounting Standards Codification resulting from Accounting Standards Update No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity,” effective July 1, 2014. Also, the Company changed its accounting for service concession arrangements as a result of the adoption of the amendments to the FASB Accounting Standards Codification resulting from Accounting Standards Update No. 2014-05, “Service Concession Arrangements,” effective January 1, 2015. Lastly, the Company changed its classification of all deferred tax assets and liabilities as a result of the adoption of the amendments to the FASB Accounting Standards Codification resulting from Accounting Standards Update No. 2015-17, “Income Taxes,” effective December 31, 2015.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The AES Corporation’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 23, 2016 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
We have served as the Company's auditor since 2008.
McLean,
Tysons, Virginia
February 23, 201626, 2019
THE AES CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 20152018 AND 20142017 | | | | 2015 | | 2014 | 2018 | | 2017 |
| | (in millions, except share and per share data) | (in millions, except share and per share data) |
| ASSETS | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents | $ | 1,262 |
| | $ | 1,539 |
| $ | 1,166 |
| | $ | 949 |
|
| Restricted cash | 295 |
| | 283 |
| 370 |
| | 274 |
|
| Short-term investments | 484 |
| | 709 |
| 313 |
| | 424 |
|
| Accounts receivable, net of allowance for doubtful accounts of $95 and $96, respectively | 2,473 |
| | 2,709 |
| |
| Accounts receivable, net of allowance for doubtful accounts of $23 and $10, respectively | | 1,595 |
| | 1,463 |
|
| Inventory | 675 |
| | 702 |
| 577 |
| | 562 |
|
| Deferred income taxes | — |
| | 275 |
| |
| Prepaid expenses | 108 |
| | 175 |
| 130 |
| | 62 |
|
| Other current assets | 1,473 |
| | 1,434 |
| 807 |
| | 630 |
|
| Assets of held-for-sale businesses | 96 |
| | — |
| |
| Current assets of discontinued operations and held-for-sale businesses | | 57 |
| | 2,034 |
|
| Total current assets | 6,866 |
| | 7,826 |
| 5,015 |
| | 6,398 |
|
| NONCURRENT ASSETS | | | | | | |
| Property, Plant and Equipment: | | | | | | |
| Land | 711 |
| | 870 |
| 449 |
| | 502 |
|
| Electric generation, distribution assets and other | 28,491 |
| | 30,459 |
| 25,242 |
| | 24,119 |
|
| Accumulated depreciation | (9,449 | ) | | (9,962 | ) | (8,227 | ) | | (7,942 | ) |
| Construction in progress | 3,063 |
| | 3,784 |
| 3,932 |
| | 3,617 |
|
| Property, plant and equipment, net | 22,816 |
| | 25,151 |
| 21,396 |
| | 20,296 |
|
| Other Assets: | | | | | | |
| Investments in and advances to affiliates | 610 |
| | 537 |
| 1,114 |
| | 1,197 |
|
| Debt service reserves and other deposits | 565 |
| | 411 |
| 467 |
| | 565 |
|
| Goodwill | 1,157 |
| | 1,458 |
| 1,059 |
| | 1,059 |
|
| Other intangible assets, net of accumulated amortization of $97 and $158, respectively | 214 |
| | 281 |
| |
| Other intangible assets, net of accumulated amortization of $457 and $441, respectively | | 436 |
| | 366 |
|
| Deferred income taxes | 543 |
| | 662 |
| 97 |
| | 130 |
|
| Service concession assets, net of accumulated amortization of $34 | 1,543 |
| | — |
| |
| Service concession assets, net of accumulated amortization of $0 and $206, respectively | | — |
| | 1,360 |
|
| Loan receivable | | 1,423 |
| | — |
|
| Other noncurrent assets | 2,536 |
| | 2,640 |
| 1,514 |
| | 1,741 |
|
| Total other assets | 7,168 |
| | 5,989 |
| 6,110 |
| | 6,418 |
|
| TOTAL ASSETS | $ | 36,850 |
| | $ | 38,966 |
| $ | 32,521 |
| | $ | 33,112 |
|
| LIABILITIES AND EQUITY | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Accounts payable | $ | 1,721 |
| | $ | 2,278 |
| $ | 1,329 |
| | $ | 1,371 |
|
| Accrued interest | 251 |
| | 260 |
| 191 |
| | 228 |
|
| Accrued non-income taxes | | 250 |
|
| 252 |
|
| Accrued and other liabilities | 2,436 |
| | 2,326 |
| 962 |
| | 980 |
|
| Recourse debt | — |
| | 151 |
| |
| Non-recourse debt, including $163 and $240, respectively, related to variable interest entities | 2,529 |
| | 1,982 |
| |
| Liabilities of held-for-sale businesses | 13 |
| | — |
| |
| Non-recourse debt, including $479 and $1,012, respectively, related to variable interest entities | | 1,659 |
| | 2,164 |
|
| Current liabilities of discontinued operations and held-for-sale businesses | | 8 |
| | 1,033 |
|
| Total current liabilities | 6,950 |
| | 6,997 |
| 4,399 |
| | 6,028 |
|
| NONCURRENT LIABILITIES | | | | | | |
| Recourse debt | 5,015 |
| | 5,107 |
| 3,650 |
| | 4,625 |
|
| Non-recourse debt, including $760 and $1,030, respectively, related to variable interest entities | 13,263 |
| | 13,618 |
| |
| Non-recourse debt, including $2,922 and $1,358 respectively, related to variable interest entities | | 13,986 |
| | 13,176 |
|
| Deferred income taxes | 1,090 |
| | 1,277 |
| 1,280 |
| | 1,006 |
|
| Pension and other post-retirement liabilities | 927 |
| | 1,342 |
| |
| Other noncurrent liabilities | 2,896 |
| | 3,222 |
| 2,723 |
| | 2,595 |
|
| Total noncurrent liabilities | 23,191 |
| | 24,566 |
| 21,639 |
| | 21,402 |
|
| Commitments and Contingencies (see Notes 13 and 14) |
| |
| |
| Commitments and Contingencies (see Notes 11 and 12) | |
| |
|
| Redeemable stock of subsidiaries | 538 |
| | 78 |
| 879 |
| | 837 |
|
| EQUITY | | | | | | |
| THE AES CORPORATION STOCKHOLDERS’ EQUITY | | | | | | |
| Common stock ($0.01 par value, 1,200,000,000 shares authorized; 815,846,621 issued and 666,808,790 outstanding at December 31, 2015 and 814,539,146 issued and 703,851,297 outstanding at December 31, 2014) | 8 |
| | 8 |
| |
| Common stock ($0.01 par value, 1,200,000,000 shares authorized; 817,203,691 issued and 662,298,096 outstanding at December 31, 2018 and 816,312,913 issued and 660,388,128 outstanding at December 31, 2017) | | 8 |
| | 8 |
|
| Additional paid-in capital | 8,718 |
| | 8,409 |
| 8,154 |
| | 8,501 |
|
| Retained earnings | 143 |
| | 512 |
| |
| Accumulated deficit | | (1,005 | ) | | (2,276 | ) |
| Accumulated other comprehensive loss | (3,883 | ) | | (3,286 | ) | (2,071 | ) | | (1,876 | ) |
| Treasury stock, at cost (149,037,831 shares at December 31, 2015 and 110,687,849 shares at December 31, 2014) | (1,837 | ) | | (1,371 | ) | |
| Treasury stock, at cost (154,905,595 and 155,924,785 shares at December 31, 2018 and 2017, respectively) | | (1,878 | ) | | (1,892 | ) |
| Total AES Corporation stockholders’ equity | 3,149 |
| | 4,272 |
| 3,208 |
| | 2,465 |
|
| NONCONTROLLING INTERESTS | 3,022 |
| | 3,053 |
| 2,396 |
| | 2,380 |
|
| Total equity | 6,171 |
| | 7,325 |
| 5,604 |
| | 4,845 |
|
| TOTAL LIABILITIES AND EQUITY | $ | 36,850 |
| | $ | 38,966 |
| $ | 32,521 |
| | $ | 33,112 |
|
See Accompanying Notes to Consolidated Financial Statements.
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
| | | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 |
| | (in millions, except per share amounts) | (in millions, except per share amounts) |
| Revenue: | | | | | | | | | | |
| Regulated | $ | 7,660 |
| | $ | 8,874 |
| | $ | 8,056 |
| $ | 2,939 |
| | $ | 3,109 |
| | $ | 3,310 |
|
| Non-regulated | 7,303 |
| | 8,272 |
| | 7,835 |
| |
| Non-Regulated | | 7,797 |
| | 7,421 |
| | 6,971 |
|
| Total revenue | 14,963 |
| | 17,146 |
| | 15,891 |
| 10,736 |
| | 10,530 |
| | 10,281 |
|
| Cost of sales: | | | | | | |
| Cost of Sales: | | | | | | |
| Regulated | (6,564 | ) | | (7,530 | ) | | (6,837 | ) | (2,473 | ) | | (2,650 | ) | | (2,839 | ) |
| Non-regulated | (5,533 | ) | | (6,528 | ) | | (5,807 | ) | |
| Non-Regulated | | (5,690 | ) | | (5,415 | ) | | (5,059 | ) |
| Total cost of sales | (12,097 | ) | | (14,058 | ) | | (12,644 | ) | (8,163 | ) | | (8,065 | ) | | (7,898 | ) |
| Operating margin | 2,866 |
| | 3,088 |
| | 3,247 |
| 2,573 |
| | 2,465 |
| | 2,383 |
|
| General and administrative expenses | (196 | ) | | (187 | ) | | (220 | ) | (192 | ) | | (215 | ) | | (194 | ) |
| Interest expense | (1,436 | ) | | (1,471 | ) | | (1,482 | ) | (1,056 | ) | | (1,170 | ) | | (1,134 | ) |
| Interest income | 524 |
| | 365 |
| | 275 |
| 310 |
| | 244 |
| | 245 |
|
| Loss on extinguishment of debt | (186 | ) | | (261 | ) | | (229 | ) | (188 | ) | | (68 | ) | | (13 | ) |
| Other expense | (65 | ) | | (68 | ) | | (76 | ) | (58 | ) | | (58 | ) | | (80 | ) |
| Other income | 83 |
| | 124 |
| | 125 |
| 72 |
| | 120 |
| | 64 |
|
| Gain on sale of businesses | 29 |
| | 358 |
| | 26 |
| |
| Goodwill impairment expense | (317 | ) | | (164 | ) | | (372 | ) | |
| Gain (loss) on disposal and sale of business interests | | 984 |
| | (52 | ) | | 29 |
|
| Asset impairment expense | (285 | ) | | (91 | ) | | (95 | ) | (208 | ) | | (537 | ) | | (1,096 | ) |
| Foreign currency transaction gains (losses) | 105 |
| | 11 |
| | (22 | ) | (72 | ) | | 42 |
| | (15 | ) |
| Other non-operating expense | — |
| | (128 | ) | | (129 | ) | (147 | ) | | — |
| | (2 | ) |
| INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES | 1,122 |
| | 1,576 |
| | 1,048 |
| 2,018 |
| | 771 |
| | 187 |
|
| Income tax expense | (465 | ) | | (419 | ) | | (343 | ) | (708 | ) | | (990 | ) | | (32 | ) |
| Net equity in earnings of affiliates | 105 |
| | 19 |
| | 25 |
| 39 |
| | 71 |
| | 36 |
|
| INCOME FROM CONTINUING OPERATIONS | 762 |
| | 1,176 |
| | 730 |
| |
| Income (loss) from operations of discontinued businesses, net of income tax expense of $0, $23, and $24, respectively | — |
| | 27 |
| | (27 | ) | |
| Net loss from disposal and impairments of discontinued operations, net of income tax expense (benefit) of $0, $4, and $(15), respectively | — |
| | (56 | ) | | (152 | ) | |
| NET INCOME | 762 |
| | 1,147 |
| | 551 |
| |
| INCOME (LOSS) FROM CONTINUING OPERATIONS | | 1,349 |
| | (148 | ) | | 191 |
|
| Income (loss) from operations of discontinued businesses, net of income tax benefit (expense) of $(2), $(21), and $229, respectively | | (9 | ) | | (18 | ) | | 151 |
|
| 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 | ) |
| NET INCOME (LOSS) | | 1,565 |
| | (777 | ) | | (777 | ) |
| Noncontrolling interests: | | | | | | | | | | |
| Less: (Income) from continuing operations attributable to noncontrolling interests | (456 | ) | | (387 | ) | | (446 | ) | |
| Plus: Loss from discontinued operations attributable to noncontrolling interests | — |
| | 9 |
| | 9 |
| |
| Total net income attributable to noncontrolling interests | (456 | ) | | (378 | ) | | (437 | ) | |
| NET INCOME ATTRIBUTABLE TO THE AES CORPORATION | $ | 306 |
| | $ | 769 |
| | $ | 114 |
| |
| Less: Income from continuing operations attributable to noncontrolling interests and redeemable stock of subsidiaries | | (364 | ) | | (359 | ) | | (211 | ) |
| Less: Loss (income) from discontinued operations attributable to noncontrolling interests | | 2 |
| | (25 | ) | | (142 | ) |
| NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION | | $ | 1,203 |
| | $ | (1,161 | ) | | $ | (1,130 | ) |
| AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS: | | | | | | | | | | |
| Income from continuing operations, net of tax | $ | 306 |
| | $ | 789 |
| | $ | 284 |
| |
| Loss from discontinued operations, net of tax | — |
| | (20 | ) | | (170 | ) | |
| Net income | $ | 306 |
| | $ | 769 |
| | $ | 114 |
| |
| Income (loss) from continuing operations, net of tax | | $ | 985 |
| | $ | (507 | ) | | $ | (20 | ) |
| Income (loss) from discontinued operations, net of tax | | 218 |
| | (654 | ) | | (1,110 | ) |
| NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION | | $ | 1,203 |
| | $ | (1,161 | ) | | $ | (1,130 | ) |
| BASIC EARNINGS PER SHARE: | | | | | | | | | | |
| Income from continuing operations attributable to The AES Corporation common stockholders, net of tax | $ | 0.45 |
| | $ | 1.10 |
| | $ | 0.38 |
| |
| Loss from discontinued operations attributable to The AES Corporation common stockholders, net of tax | — |
| | (0.03 | ) | | (0.23 | ) | |
| NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS | $ | 0.45 |
| | $ | 1.07 |
| | $ | 0.15 |
| |
| Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax | | $ | 1.49 |
| | $ | (0.77 | ) | | $ | (0.04 | ) |
| Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax | | 0.33 |
| | (0.99 | ) | | (1.68 | ) |
| NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS | | $ | 1.82 |
| | $ | (1.76 | ) | | $ | (1.72 | ) |
| DILUTED EARNINGS PER SHARE: | | | | | | | | | | |
| Income from continuing operations attributable to The AES Corporation common stockholders, net of tax | $ | 0.44 |
| | $ | 1.09 |
| | $ | 0.38 |
| |
| Loss from discontinued operations attributable to The AES Corporation common stockholders, net of tax | — |
| | (0.03 | ) | | (0.23 | ) | |
| NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS | $ | 0.44 |
| | $ | 1.06 |
| | $ | 0.15 |
| |
| Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax | | $ | 1.48 |
| | $ | (0.77 | ) | | $ | (0.04 | ) |
| Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax | | 0.33 |
| | (0.99 | ) | | (1.68 | ) |
| NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS | | $ | 1.81 |
| | $ | (1.76 | ) | | $ | (1.72 | ) |
| DIVIDENDS DECLARED PER COMMON SHARE | $ | 0.41 |
| | $ | 0.25 |
| | $ | 0.17 |
| $ | 0.53 |
| | $ | 0.49 |
| | $ | 0.45 |
|
See Accompanying Notes to Consolidated Financial Statements.
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) INCOME
YEARS ENDED DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| | (in millions) |
| NET INCOME | $ | 762 |
| | $ | 1,147 |
| | $ | 551 |
|
| Foreign currency translation activity: | | | | | |
| Foreign currency translation adjustments, net of income tax benefit (expense) of $1, $(7), and $10, respectively | (1,019 | ) | | (491 | ) | | (375 | ) |
| Reclassification to earnings, net of $0 income tax for all periods | — |
| | (3 | ) | | 41 |
|
| Total foreign currency translation adjustments | (1,019 | ) | | (494 | ) | | (334 | ) |
| Derivative activity: | | | | | |
| Change in derivative fair value, net of income tax benefit (expense) of $16, $72 and $(31), respectively | (57 | ) | | (358 | ) | | 108 |
|
| Reclassification to earnings, net of income tax (expense) of $(11), $(26) and $(41), respectively | 66 |
| | 99 |
| | 139 |
|
| Total change in fair value of derivatives | 9 |
| | (259 | ) | | 247 |
|
| Pension activity: | | | | | |
| Change in pension adjustments due to prior service cost, net of $0 income tax for all periods | 1 |
| | — |
| | — |
|
| Change in pension adjustments due to net actuarial gain (loss) for the period, net of income tax (expense) benefit of $(29), $27, and $(198), respectively | 60 |
| | (49 | ) | | 379 |
|
| Reclassification to earnings due to amortization of net actuarial loss, net of income tax (expense) of $(9), $(7), and $(26), respectively | 16 |
| | 29 |
| | 52 |
|
| Total pension adjustments | 77 |
| | (20 | ) | | 431 |
|
| OTHER COMPREHENSIVE (LOSS) INCOME | (933 | ) | | (773 | ) | | 344 |
|
| COMPREHENSIVE (LOSS) INCOME | (171 | ) | | 374 |
| | 895 |
|
| Less: Comprehensive (income) attributable to noncontrolling interests | (133 | ) | | (49 | ) | | (743 | ) |
| COMPREHENSIVE (LOSS) INCOME ATTRIBUTABLE TO THE AES CORPORATION | $ | (304 | ) | | $ | 325 |
| | $ | 152 |
|
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| | (in millions) |
| NET INCOME (LOSS) | $ | 1,565 |
| | $ | (777 | ) | | $ | (777 | ) |
| Foreign currency translation activity: | | | | | |
| Foreign currency translation adjustments, net of income tax benefit of $2, $17, and $1, respectively | (161 | ) | | (9 | ) | | 189 |
|
| Reclassification to earnings, net of $0 income tax for all periods | (21 | ) | | 643 |
| | 992 |
|
| Total foreign currency translation adjustments | (182 | ) | | 634 |
| | 1,181 |
|
| Derivative activity: | | | | | |
| Change in derivative fair value, net of income tax benefit (expense) of $27, $10 and $(7), respectively | (67 | ) | | (12 | ) | | 5 |
|
| Reclassification to earnings, net of income tax expense of $24, $1 and $8, respectively | 93 |
| | 50 |
| | 37 |
|
| Total change in fair value of derivatives | 26 |
| | 38 |
| | 42 |
|
| Pension activity: | | | | | |
| Change in pension adjustments due to prior service cost, net of income tax benefit (expense) of $1, $(1), and $(6) respectively | (2 | ) | | 2 |
| | 11 |
|
| Change in pension adjustments due to net actuarial gain (loss) for the period, net of income tax benefit of $1, $6, and $106, respectively | (1 | ) | | (21 | ) | | (208 | ) |
| Reclassification to earnings, net of income tax expense of $2, $135, and $3 respectively | 8 |
| | 266 |
| | 10 |
|
| Total pension adjustments | 5 |
| | 247 |
| | (187 | ) |
| OTHER COMPREHENSIVE INCOME (LOSS) | (151 | ) | | 919 |
| | 1,036 |
|
| COMPREHENSIVE INCOME | 1,414 |
| | 142 |
| | 259 |
|
| Less: Comprehensive income attributable to noncontrolling interests | (425 | ) | | (390 | ) | | (262 | ) |
| COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION | $ | 989 |
| | $ | (248 | ) | | $ | (3 | ) |
See Accompanying Notes to Consolidated Financial Statements.
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
YEARS ENDED DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | THE AES CORPORATION STOCKHOLDERS | | |
| | Common Stock | | Treasury Stock | | Additional Paid-In Capital | | Retained Earnings (Accumulated Deficit) | | Accumulated Other Comprehensive Loss | | Noncontrolling Interests |
| (in millions) | Shares | | Amount | | Shares | | Amount | |
| Balance at December 31, 2015 | 815.8 |
| | $ | 8 |
| | 149.0 |
| | $ | (1,837 | ) | | $ | 8,718 |
| | $ | 143 |
| | $ | (3,883 | ) | | $ | 3,022 |
|
| Net income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | (1,130 | ) | | — |
| | 353 |
|
| Total foreign currency translation adjustment, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,109 |
| | 72 |
|
| Total change in derivative fair value, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 30 |
| | 12 |
|
| Total pension adjustments, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (12 | ) | | (175 | ) |
| Total other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,127 |
| | (91 | ) |
Fair value adjustment (1) | — |
| | — |
| | — |
| | — |
| | 17 |
| | (4 | ) | | — |
| | (17 | ) |
Disposition of business interests (2) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) |
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (10 | ) | | — |
| | — |
| | (430 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 60 |
|
| Dividends declared on common stock | — |
| | — |
| | — |
| | — |
| | (226 | ) | | (71 | ) | | — |
| | — |
|
| Purchase of treasury stock | — |
| | — |
| | 8.7 |
| | (79 | ) | | — |
| | — |
| | — |
| | — |
|
| Issuance and exercise of stock-based compensation benefit plans, net of income tax | 0.3 |
| | — |
| | (0.8 | ) | | 12 |
| | 11 |
| | — |
| | — |
| | — |
|
| Sale of subsidiary shares to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 84 |
| | (84 | ) | | — |
| | 17 |
|
| Acquisition of subsidiary shares from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (17 | ) |
| Less: Net loss attributable to redeemable stock of subsidiaries | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Balance at December 31, 2016 | 816.1 |
| | $ | 8 |
| | 156.9 |
| | $ | (1,904 | ) | | $ | 8,592 |
| | $ | (1,146 | ) | | $ | (2,756 | ) | | $ | 2,906 |
|
| Net income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | (1,161 | ) | | — |
| | 384 |
|
| Total foreign currency translation adjustment, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 661 |
| | (27 | ) |
| Total change in derivative fair value, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 23 |
| | 15 |
|
| Total pension adjustments, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 229 |
| | 18 |
|
| Total other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 913 |
| | 6 |
|
Cumulative effect of a change in accounting principle (3) | — |
| | — |
| | — |
| | — |
| | — |
| | 31 |
| | — |
| | — |
|
Fair value adjustment (1) | — |
| | — |
| | — |
| | — |
| | (25 | ) | | — |
| | — |
| | — |
|
Disposition of business interests (2) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (666 | ) |
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (426 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Dividends declared on common stock | — |
| | — |
| | — |
| | — |
| | (324 | ) | | — |
| | — |
| | — |
|
| Issuance and exercise of stock-based compensation benefit plans, net of income tax | 0.2 |
| | — |
| | (1.0 | ) | | 12 |
| | 5 |
| | — |
| | — |
| | — |
|
| Sale of subsidiary shares to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 13 |
| | — |
| | 7 |
| | 83 |
|
| Acquisition of subsidiary shares from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 240 |
| | — |
| | (40 | ) | | 68 |
|
| Less: Net loss attributable to redeemable stock of subsidiaries | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 14 |
|
| Balance at December 31, 2017 | 816.3 |
| | $ | 8 |
| | 155.9 |
| | $ | (1,892 | ) | | $ | 8,501 |
| | $ | (2,276 | ) | | $ | (1,876 | ) | | $ | 2,380 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 1,203 |
| | — |
| | 360 |
|
| Total foreign currency translation adjustment, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (235 | ) | | 53 |
|
| Total change in derivative fair value, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 14 |
| | 10 |
|
| Total pension adjustments, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 7 |
| | (2 | ) |
| Total other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (214 | ) | | 61 |
|
Cumulative effect of a change in accounting principle (3) | — |
| | — |
| | — |
| | — |
| | — |
| | 68 |
| | 19 |
| | 81 |
|
Fair value adjustment (1) | — |
| | — |
| | — |
| | — |
| | (4 | ) | | — |
| | — |
| | — |
|
Disposition of business interests (2) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (250 | ) |
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (343 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 9 |
|
| Dividends declared on common stock | — |
| | — |
| | — |
| | — |
| | (348 | ) | | — |
| | — |
| | — |
|
| Issuance and exercise of stock-based compensation benefit plans, net of income tax | 0.9 |
| | — |
| | (1.0 | ) | | 14 |
| | 8 |
| | — |
| | — |
| | — |
|
| Sale of subsidiary shares to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (3 | ) | | — |
| | — |
| | 98 |
|
| Balance at December 31, 2018 | 817.2 |
| | $ | 8 |
| | 154.9 |
| | $ | (1,878 | ) | | $ | 8,154 |
| | $ | (1,005 | ) | | $ | (2,071 | ) | | $ | 2,396 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | THE AES CORPORATION STOCKHOLDERS | | |
| | Common Stock | | Treasury Stock | | Additional Paid-In Capital | | Retained Earnings (Accumulated Deficit) | | Accumulated Other Comprehensive Loss | | Noncontrolling Interests |
| (in millions) | Shares | | Amount | | Shares | | Amount | |
| Balance at January 1, 2013 | 810.7 |
| | $ | 8 |
| | 66.4 |
| | $ | (780 | ) | | $ | 8,525 |
| | $ | (264 | ) | | $ | (2,920 | ) | | $ | 2,945 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| | — |
| | 437 |
|
| Total foreign currency translation adjustment, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (227 | ) | | (107 | ) |
| Total change in derivative fair value, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 174 |
| | 73 |
|
| Total pension adjustments, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 91 |
| | 340 |
|
| Total other comprehensive income |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| | 38 |
| | 306 |
|
| Disposition of businesses | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (13 | ) |
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (553 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 109 |
|
| Dividends declared on common stock | — |
| | — |
| | — |
| | — |
| | (125 | ) | | — |
| | — |
| | — |
|
| Purchase of treasury stock | — |
| | — |
| | 25.3 |
| | (322 | ) | | — |
| | — |
| | — |
| | — |
|
| Issuance and exercise of stock-based compensation benefit plans, net of income tax | 2.6 |
| | — |
| | (0.9 | ) | | 13 |
| | 33 |
| | — |
| | — |
| | — |
|
| Sale of subsidiary shares to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 16 |
| | — |
| | — |
| | 91 |
|
| Acquisition of subsidiary shares from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (6 | ) | | — |
| | — |
| | (1 | ) |
| Balance at December 31, 2013 | 813.3 |
| | $ | 8 |
| | 90.8 |
| | $ | (1,089 | ) | | $ | 8,443 |
| | $ | (150 | ) | | $ | (2,882 | ) | | $ | 3,321 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 769 |
| | — |
| | 378 |
|
| Total foreign currency translation adjustment, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (332 | ) | | (162 | ) |
| Total change in derivative fair value, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (108 | ) | | (151 | ) |
| Total pension adjustments, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | (16 | ) |
| Total other comprehensive loss |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| | (444 | ) | | (329 | ) |
Balance Sheet reclassification related to an equity method investment (1) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 40 |
| | — |
|
| Disposition of businesses | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (153 | ) |
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (466 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 147 |
|
| Dividends declared on common stock | — |
| | — |
| | — |
| | — |
| | (73 | ) | | (107 | ) | | — |
| | — |
|
| Purchase of treasury stock | — |
| | — |
| | 21.9 |
| | (308 | ) | | — |
| | — |
| | — |
| | — |
|
| Issuance and exercise of stock-based compensation benefit plans, net of income tax | 1.2 |
| | — |
| | (2.0 | ) | | 26 |
| | 3 |
| | — |
| | — |
| | — |
|
| Sale of subsidiary shares to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 29 |
| | — |
| | — |
| | 173 |
|
| Acquisition of subsidiary shares from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 7 |
| | — |
| | — |
| | (18 | ) |
| Balance at December 31, 2014 | 814.5 |
| | $ | 8 |
| | 110.7 |
| | $ | (1,371 | ) | | $ | 8,409 |
| | $ | 512 |
| | $ | (3,286 | ) | | $ | 3,053 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 306 |
| | — |
| | 456 |
|
| Total foreign currency translation adjustment, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (674 | ) | | (345 | ) |
| Total change in derivative fair value, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 43 |
| | (34 | ) |
| Total pension adjustments, net of income tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 21 |
| | 56 |
|
| Total other comprehensive loss |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| | (610 | ) | | (323 | ) |
| Cumulative effect of a change in accounting principle | — |
| | — |
| | — |
| | — |
| | — |
| | (18 | ) | | 13 |
| | — |
|
Acquisition of business (2) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 15 |
|
| Disposition of businesses | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (41 | ) |
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (27 | ) | | — |
| | — |
| | (383 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 126 |
|
| Dividends declared on common stock | — |
| | — |
| | — |
| | — |
| | — |
| | (280 | ) | | — |
| | — |
|
| Purchase of treasury stock | — |
| | — |
| | 39.7 |
| | (482 | ) | | — |
| | — |
| | — |
| | — |
|
| Issuance and exercise of stock-based compensation benefit plans, net of income tax | 1.3 |
| | — |
| | (1.4 | ) | | 16 |
| | 13 |
| | — |
| | — |
| | — |
|
| Sale of subsidiary shares to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 323 |
| | (377 | ) | | — |
| | 119 |
|
| Balance at December 31, 2015 | 815.8 |
| | $ | 8 |
| | 149.0 |
| | $ | (1,837 | ) | | $ | 8,718 |
| | $ | 143 |
| | $ | (3,883 | ) | | $ | 3,022 |
|
(1) Reclassification resulting from SRP transaction duringAdjustment to the third quartercarrying amount of 2014. noncontrolling interest and redeemable stock of subsidiaries to fair value.
(2) See Note 8—Investments In23—Held-for-Sale and Advances to AffiliatesDispositions for further information.
(2)(3) Fair valueSee Note 1—General and Summary of a tax equity partner's right to preferential returns recognized as a result of the acquisition of Solar Power PR, LLC, which was previously accountedSignificant Accounting Policies for as an equity method investment.further information.
See Accompanying Notes to Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016 |
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| OPERATING ACTIVITIES: | (in millions) |
| Net income (loss) | $ | 1,565 |
| | $ | (777 | ) | | $ | (777 | ) |
| Adjustments to net income (loss): | | | | | |
| Depreciation and amortization | 1,003 |
| | 1,169 |
| | 1,176 |
|
| Loss (gain) on disposal and sale of business interests | (984 | ) | | 52 |
| | (29 | ) |
| Impairment expenses | 355 |
| | 537 |
| | 1,098 |
|
| Deferred income taxes | 313 |
| | 672 |
| | (793 | ) |
| Provisions for contingencies | 14 |
| | 34 |
| | 48 |
|
| Loss on extinguishment of debt | 188 |
| | 68 |
| | 20 |
|
| Loss on sale and disposal of assets | 27 |
| | 43 |
| | 38 |
|
| Net loss (gain) from disposal and impairments of discontinued businesses | (269 | ) | | 611 |
| | 1,383 |
|
| Other | 317 |
| | 160 |
| | 180 |
|
| Changes in operating assets and liabilities: | | | | | |
| (Increase) decrease in accounts receivable | (206 | ) | | (177 | ) | | 237 |
|
| (Increase) decrease in inventory | (36 | ) | | (28 | ) | | 42 |
|
| (Increase) decrease in prepaid expenses and other current assets | (22 | ) | | 107 |
| | 870 |
|
| (Increase) decrease in other assets | (32 | ) | | (295 | ) | | (251 | ) |
| Increase (decrease) in accounts payable and other current liabilities | 62 |
| | 163 |
| | (619 | ) |
| Increase (decrease) in income tax payables, net and other tax payables | (7 | ) | | 53 |
| | (199 | ) |
| Increase (decrease) in other liabilities | 55 |
| | 112 |
| | 473 |
|
| Net cash provided by operating activities | 2,343 |
| | 2,504 |
| | 2,897 |
|
| INVESTING ACTIVITIES: | | | | | |
| Capital expenditures | (2,121 | ) | | (2,177 | ) | | (2,345 | ) |
| Acquisitions of business interests, net of cash and restricted cash acquired | (66 | ) | | (609 | ) | | (52 | ) |
| Proceeds from the sale of business interests, net of cash and restricted cash sold | 2,020 |
| | 108 |
| | 538 |
|
| Sale of short-term investments | 1,302 |
| | 3,540 |
| | 4,904 |
|
| Purchase of short-term investments | (1,411 | ) | | (3,310 | ) | | (5,151 | ) |
| Contributions to equity investments | (145 | ) | | (89 | ) | | (6 | ) |
| Other investing | (84 | ) | | (62 | ) | | (24 | ) |
| Net cash used in investing activities | (505 | ) | | (2,599 | ) | | (2,136 | ) |
| FINANCING ACTIVITIES: | | | | | |
| Borrowings under the revolving credit facilities | 1,865 |
| | 2,156 |
| | 1,465 |
|
| Repayments under the revolving credit facilities | (2,238 | ) | | (1,742 | ) | | (1,433 | ) |
| Issuance of recourse debt | 1,000 |
| | 1,025 |
| | 500 |
|
| Repayments of recourse debt | (1,933 | ) | | (1,353 | ) | | (808 | ) |
| Issuance of non-recourse debt | 1,928 |
| | 3,222 |
| | 2,978 |
|
| Repayments of non-recourse debt | (1,411 | ) | | (2,360 | ) | | (2,666 | ) |
| Payments for financing fees | (39 | ) | | (100 | ) | | (105 | ) |
| Distributions to noncontrolling interests | (340 | ) | | (424 | ) | | (476 | ) |
| Contributions from noncontrolling interests and redeemable security holders | 43 |
| | 73 |
| | 190 |
|
| Proceeds from the sale of redeemable stock of subsidiaries | — |
| | — |
| | 134 |
|
| Dividends paid on AES common stock | (344 | ) | | (317 | ) | | (290 | ) |
| Payments for financed capital expenditures | (275 | ) | | (179 | ) | | (113 | ) |
| Purchase of treasury stock | — |
| | — |
| | (79 | ) |
| Proceeds from sales to noncontrolling interests, net of transaction costs | — |
| | 94 |
| | — |
|
| Other financing | 101 |
| | (52 | ) | | (44 | ) |
| Net cash provided by (used in) financing activities | (1,643 | ) | | 43 |
| | (747 | ) |
| Effect of exchange rate changes on cash, cash equivalents and restricted cash | (54 | ) | | 8 |
| | 37 |
|
| (Increase) decrease in cash, cash equivalents and restricted cash of discontinued operations and held-for-sale businesses | 74 |
| | (128 | ) | | (42 | ) |
| Total increase (decrease) in cash, cash equivalents and restricted cash | 215 |
| | (172 | ) | | 9 |
|
| Cash, cash equivalents and restricted cash, beginning | 1,788 |
| | 1,960 |
| | 1,951 |
|
| Cash, cash equivalents and restricted cash, ending | $ | 2,003 |
| | $ | 1,788 |
| | $ | 1,960 |
|
| SUPPLEMENTAL DISCLOSURES: | | | | | |
| Cash payments for interest, net of amounts capitalized | $ | 1,003 |
| | $ | 1,196 |
| | $ | 1,273 |
|
| Cash payments for income taxes, net of refunds | 370 |
| | 377 |
| | 487 |
|
| SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES: | | | | | |
| Non-cash acquisition of intangible assets | 16 |
| | — |
| | — |
|
| Non-cash contributions of assets and liabilities for the Fluence transaction (see Note 7) | 20 |
| | — |
| | — |
|
| Non-cash exchange of debentures for the acquisition of the Guaimbê Solar Complex (see Note 24) | 119 |
| | — |
| | — |
|
| Non-cash acquisition of the remaining interest in a Distributed Energy equity affiliate (see Note 24) | 23 |
| | — |
| | — |
|
| Dividends declared but not yet paid | 90 |
| | 86 |
| | 174 |
|
| Conversion of Alto Maipo loans and accounts payable into equity (see Note 14) | — |
| | 279 |
| | — |
|
| Return Share Transfer Payment due (see Note 23) | — |
| | 75 |
| | — |
|
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| | (in millions) |
| OPERATING ACTIVITIES: | | | | | |
| Net income | $ | 762 |
| | $ | 1,147 |
| | $ | 551 |
|
| Adjustments to net income: | | | | | |
| Depreciation and amortization | 1,144 |
| | 1,245 |
| | 1,294 |
|
| Gain on sale of businesses | (29 | ) | | (358 | ) | | (26 | ) |
| Impairment expenses | 602 |
| | 383 |
| | 661 |
|
| Deferred income taxes | (50 | ) | | 47 |
| | (158 | ) |
| (Reversals of) provisions for contingencies | (72 | ) | | (34 | ) | | 312 |
|
| Loss on extinguishment of debt | 186 |
| | 261 |
| | 229 |
|
| Loss on disposals and impairments - discontinued operations | — |
| | 50 |
| | 163 |
|
| Other | 28 |
| | 72 |
| | 33 |
|
| Changes in operating assets and liabilities: | | | | | |
| (Increase) decrease in accounts receivable | (378 | ) | | (520 | ) | | 146 |
|
| (Increase) decrease in inventory | (26 | ) | | (48 | ) | | 16 |
|
| (Increase) decrease in prepaid expenses and other current assets | 655 |
| | (73 | ) | | 358 |
|
| (Increase) decrease in other assets | (1,305 | ) | | (723 | ) | | (103 | ) |
| Increase (decrease) in accounts payable and other current liabilities | 31 |
| | (85 | ) | | (758 | ) |
| Increase (decrease) in income tax payables, net and other tax payables | 53 |
| | (89 | ) | | 95 |
|
| Increase (decrease) in other liabilities | 533 |
| | 516 |
| | (98 | ) |
| Net cash provided by operating activities | 2,134 |
| | 1,791 |
| | 2,715 |
|
| INVESTING ACTIVITIES: | | | | | |
| Capital expenditures | (2,308 | ) | | (2,016 | ) | | (1,988 | ) |
| Acquisitions, net of cash acquired | (17 | ) | | (728 | ) | | (7 | ) |
| Proceeds from the sale of businesses, net of cash sold | 138 |
| | 1,807 |
| | 170 |
|
| Sale of short-term investments | 4,851 |
| | 4,503 |
| | 4,361 |
|
| Purchase of short-term investments | (4,801 | ) | | (4,623 | ) | | (4,443 | ) |
| (Increase) decrease in restricted cash, debt service reserves and other assets | (159 | ) | | 419 |
| | 44 |
|
| Other investing | (70 | ) | | (18 | ) | | 89 |
|
| Net cash used in investing activities | (2,366 | ) | | (656 | ) | | (1,774 | ) |
| FINANCING ACTIVITIES: | | | | | |
| Borrowings under revolving credit facilities | 959 |
| | 836 |
| | 1,139 |
|
| Repayments under revolving credit facilities | (937 | ) | | (834 | ) | | (1,161 | ) |
| Issuance of recourse debt | 575 |
| | 1,525 |
| | 750 |
|
| Repayments of recourse debt | (915 | ) | | (2,117 | ) | | (1,210 | ) |
| Issuance of non-recourse debt | 4,248 |
| | 4,179 |
| | 4,277 |
|
| Repayments of non-recourse debt | (3,312 | ) | | (3,481 | ) | | (3,390 | ) |
| Payments for financing fees | (90 | ) | | (158 | ) | | (176 | ) |
| Distributions to noncontrolling interests | (326 | ) | | (485 | ) | | (557 | ) |
| Contributions from noncontrolling interests | 126 |
| | 143 |
| | 101 |
|
| Proceeds from the sale of redeemable stock of subsidiaries | 461 |
| | — |
| | — |
|
| Dividends paid on AES common stock | (276 | ) | | (144 | ) | | (119 | ) |
| Payments for financed capital expenditures | (150 | ) | | (528 | ) | | (591 | ) |
| Purchase of treasury stock | (482 | ) | | (308 | ) | | (322 | ) |
| Proceeds from sales to noncontrolling interests, net of transaction costs | 154 |
| | 83 |
| | 109 |
|
| Other financing | (7 | ) | | 27 |
| | 14 |
|
| Net cash provided by (used in) financing activities | 28 |
| | (1,262 | ) | | (1,136 | ) |
| Effect of exchange rate changes on cash | (52 | ) | | (51 | ) | | (59 | ) |
| Decrease (increase) in cash of discontinued businesses | — |
| | 75 |
| | (4 | ) |
| Cash at held-for-sale businesses | (21 | ) | | — |
| | — |
|
| Total decrease in cash and cash equivalents | (277 | ) | | (103 | ) | | (258 | ) |
| Cash and cash equivalents, beginning | 1,539 |
| | 1,642 |
| | 1,900 |
|
| Cash and cash equivalents, ending | $ | 1,262 |
| | $ | 1,539 |
| | $ | 1,642 |
|
| SUPPLEMENTAL DISCLOSURES: | | | | | |
| Cash payments for interest, net of amounts capitalized | $ | 1,265 |
| | $ | 1,351 |
| | $ | 1,398 |
|
| Cash payments for income taxes, net of refunds | $ | 388 |
| | $ | 480 |
| | $ | 570 |
|
| SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES: | | | | | |
| Assets received upon sale of subsidiaries | $ | — |
| | $ | 44 |
| | $ | — |
|
| Assets acquired through capital lease and other liabilities | $ | 18 |
| | $ | 49 |
| | $ | 34 |
|
| Dividends declared but not yet paid | $ | 135 |
| | $ | 72 |
| | $ | 54 |
|
See Accompanying Notes to Consolidated Financial Statements.Statements
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The AES Corporation is a holding company (the "Parent Company") that, through its subsidiaries and affiliates, (collectively, "AES" or "the Company") operates a geographically diversified portfolio of electricity generation and distribution businesses. Generally, given this holding company structure, the liabilities of the individual operating entities are non-recourse to the parentParent Company and are isolated to the operating entities. Most of our operating entities are structured as limited liability entities, which limit the liability of shareholders. The structure is generally the same regardless of whether a subsidiary is consolidated under a voting or variable interest model. The preparation of these consolidated financial statements is in conformity with accounting principles generally accepted in the United States of America ("US GAAP").
PRINCIPLES OF CONSOLIDATION — The Consolidated Financial Statementsconsolidated financial statements of the Company include the accounts of The AES Corporation and its subsidiaries, which are the entities that it controls.controlled subsidiaries. Furthermore, variable interest entities ("VIEs")VIEs in which the Company has a variablean ownership interest have been consolidated when the Companyand is the primary beneficiary, and thus controlscontrolling the VIE.VIE, have been consolidated. Intercompany transactions and balances are eliminated in consolidation. Investments in entities where the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting.
DP&L, our utilityNONCONTROLLING INTERESTS — Noncontrolling interests are classified as a separate component of equity in Ohio,the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income and comprehensive income attributable to noncontrolling interests are reflected separately from consolidated net income and comprehensive income on the Consolidated Statements of Operations and Consolidated Statements of Changes in Equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests (unless the transaction qualified as a sale of in-substance real estate). Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has undivided interestsbeen reduced to zero.
Equity securities with redemption features that are not solely within the control of the issuer are classified outside of permanent equity. Generally, initial measurement will be at fair value. Subsequent measurement and classification vary depending on whether the instrument is probable of becoming redeemable. When the equity instrument is not probable of becoming redeemable, subsequent allocation of income and dividends is classified in five generation facilitiespermanent equity. For those securities where it is probable that the instrument will become redeemable or that are currently redeemable, AES recognizes changes in the fair value at each accounting period against retained earnings or additional paid-in-capital in the absence of retained earnings, subject to the floor of the initial fair value. Further, the allocation of income and numerous transmission facilities. These undivided interestsdividends, as well as the adjustment to fair value, is classified outside permanent equity. Instruments that are mandatorily redeemable are classified as a liability.
EQUITY METHOD INVESTMENTS — Investments in jointly-owned facilitiesentities over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting and reported in Investments in and advances to affiliates on the Consolidated Balance Sheets. The Company’s proportionate share of the net income or loss of these companies is included in our results of operations.
The Company utilizes the cumulative earning approach to determine whether distributions received from equity method investees are returns on investment or returns of investment. The Company discontinues the application of the equity method when an investment is reduced to zero and the Company is not otherwise committed to provide further financial support to the investee. The Company resumes the application of the equity method accounting to the extent that net income is greater than the share of net losses not previously recorded.
Upon acquiring the investment, we determine the fair value of the identifiable assets and assumed liabilities and the basis difference between each fair value and the carrying amount of the corresponding asset or liability in the financial statements of the investee. The AES share of the amortization of the basis difference is recognized in Net equity in earnings of affiliates in the Consolidated Statements of Operations over the life of the asset or liability.
The Company periodically assesses if impairment indicators exist at our equity method investments. When an impairment is observed, any excess of the carrying amount over its estimated fair value is recognized as impairment expense when the loss in value is deemed other-than-temporary and included in Other non-operating expense in the Consolidated Statements of Operations.
BUSINESS INTERESTS — Acquisitions and disposals of business interests are generally transactions pertaining to legal entities, which may be accounted for as a consolidated business, an asset, or an equity method
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
investment. Losses on sales of business interests are limited to the impairment of long-lived assets as of the date of execution of the sales agreement. Any additional gains/(losses) on sales are recognized in Gain (loss) on disposal and sale of business interests in the Consolidated Statement of Operations upon completion of the sale.
ALLOCATION OF EARNINGS — Certain of the Company's businesses are subject to profit-sharing arrangements where the allocation of cash distributions and the sharing of tax benefits are not based on fixed ownership percentages. These arrangements exist for certain U.S. renewable generation partnerships to designate different allocations of value among investors, where the allocations change in form or percentage over the life of the partnership. For these businesses, the Company uses the hypothetical liquidation at book value (“HLBV”) method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a pro-rata basis in our consolidated financial statements. Certain expenses, primarily fuel costshypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions.
The HLBV method is used both to allocate the equity earnings attributable to AES when the Company accounts for the generating units, are allocatedrenewable business as an equity method investment and to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES. Where, prior to the joint owners based on theircommencement of operating activities for a respective renewable energy usage. The remaining expenses, investmentsfacility, HLBV results in fuel inventory, plant materials and operating supplies and capital additions are allocatedan immediate decrease in the hypothetical liquidation proceeds attributable to the joint ownerstax equity investor due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in accordance with their respective ownership interests. See Note 3—Property, Plant and Equipment for additional details.the same period.
USE OF ESTIMATES — The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP")US GAAP requires the Company to make estimates and assumptions that affect the asset and liability balances reported amountsas of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of revenuerevenues and expenses recognized during the reporting period. Actual results could differ from those estimates. Items subject to such estimates and assumptions include: the carrying amount and estimated useful lives of long-lived assets; asset retirement obligations; impairment of goodwill, long-lived assets and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of regulatory assets; the estimation of regulatory liabilities; the fair value of financial instruments; the fair value of assets and liabilities acquired in aas business combination;combinations or as asset acquisitions by variable interest entities; the measurement of equity method investments or noncontrolling interest using the hypothetical liquidation at book value ("HLBV")HLBV method for certain renewable generation partnerships; the determination of whether a sale of noncontrolling interests is considered to be a sale of in-substance real estate (as opposed to an equity transaction); pension liabilities; environmental liabilities; the impact of U.S. tax reform; and potential litigation claims and settlements.
HELD-FOR-SALE DISPOSAL GROUPS— A disposal group classified as held-for-sale is reflected on the balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the carrying amount of the disposal group exceeds its estimated fair value less cost to sell. This loss is limited to the carrying value of long-lived assets until the completion of the sale, at which point, any additional loss is recognized. If the fair value of the disposal group subsequently exceeds the carrying amount while the disposal group is still held-for-sale, any impairment expense previously recognized will be reversed up to the lesser of the previously recognized expense or the subsequent excess.
Assets and liabilities related to a disposal group classified as held-for-sale are segregated in the current balance sheet in the period in which the disposal group is classified as held-for-sale. Assets and liabilities of held-for-sale disposal groups are classified as current when they are expected to be disposed of within twelve months. Transactions between the held-for-sale disposal group and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See Note 23—Held-for-Sale and Dispositionsfor further information. DISCONTINUED OPERATIONS AND HELD-FOR-SALE BUSINESSES — Effective July 1, 2014,Discontinued operations reporting occurs only when the Company prospectively adopted Accounting Standards Update ("ASU") No. 2014-08, Presentationdisposal of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting discontinued Operations and Disclosuresa business or a group of Disposals of Components of an Entity, which significantly changed the prior accounting guidance on discontinued operations. Under ASU No. 2014-08, only those disposals of components of an entity that representbusinesses represents a strategic shift that has (or will have) a major effect on an entity'sthe Company's operations and financial results. The Company reports financial results are reported as discontinued operations. Amongst other changes: equity method investments that were previously scoped-out of thefor discontinued operations accounting guidance are now includedseparately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the scope; a business can meet the criteria to be classified as held-for-sale upon acquisitionConsolidated Statements of Operations and be reported in discontinued operations; and components where an entity retains significant continuing involvement or where operations and cash flows will not be eliminated from ongoing operations as a result of a disposal transaction can meet the definition of discontinued operations. Additionally, where summarized amountsConsolidated Balance Sheets are presented on the face of the financial statements, reconciliations of those amounts to major classes of line items are also required. ASU No. 2014-08 requires additional disclosures for individually material components that do not meet the definition of discontinued operations. Under the previous accounting guidance, DPLER and Kelanitissa (which both met the Held-for-Sale criteria in 2015) and the Armenia Mountain, U.K. Wind (Operating Projects), and Ebute disposals would have met the discontinued operations criteria and would have been reclassified accordingly. See Note 24—Dispositions and Held-for-Sale Businesses for further information.
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 from or significant continuing involvement with the component as of one year after its disposal or sale. A component was comprised of operations and cash flows that could be clearly distinguished, operationally and for financial reporting purposes, from the rest of the Company. Before the Company's adoption of ASU No. 2014-08, prior period amounts were retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
businesses that are determined to be discontinued operations. For components that had been determined to be discontinued operations and held for sale businesses under the old standard, the related cash flows are included within the relevant categories within operating, investing and financing activities. The aggregate amountactivities on the face of cash flows is offset by the net increase or decrease in cash of discontinued and held for sale businesses, which is presented as a separate line item in the Consolidated Statements of Cash Flows.
When an operation is classified as held for sale,Transactions between the Company recognizes impairment expense, if any, atbusinesses determined to be discontinued operations and businesses that are expected to continue to exist after the consolidated financial statement level which also includes noncontrolling interests. However,disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value less cost to sell, including gains or losses associated with noncontrolling interests upon completion of athe disposal transaction is recognized only for the Company's ownership interest. Upon adoption of ASU No. 2014-08 on July 1, 2014, the Company no longer recasts prior period resultstransaction. Adjustments related to components previously reported as discontinued operations classifiedunder prior accounting guidance are presented as held for sale. All assets and liabilities of held-for-sale businesses are classified as current as they are expected to be disposed of within twelve months.
RECLASSIFICATIONS — Certain prior period amountsdiscontinued operations in the consolidated financial statements have been reclassifiedcurrent period even if the disposed-of component to conform towhich the adjustments are related would not meet the criteria for presentation as a discontinued operation under current presentation. Non-cash impacts related to a regulatory liability at Eletropaulo were reclassified from the Increase (decrease) in accounts payable and other current liabilities and Increase (decrease) in other liabilities lines to the (Reversals of) provisions guidance. See Note 22—Discontinued Operationsfor contingencies line on the Consolidated Statement of Cash Flows for the year ended December 31, 2013. Additionally, amounts related to certain transactions pertaining to noncontrolling interests were reclassified from the Contributions from noncontrolling interest line to the Proceeds from sales to noncontrolling interests, net of transaction costs line on the Consolidated Statement of Cash flows for the years ended December 31, 2014 and 2013.further information.FAIR VALUE — Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly, hypothetical transaction between market participants at the measurement date, or exit price. The Company applies the fair value measurement accounting guidance to financial assets and liabilities in determining the fair value of investments in marketable debt and equity securities, included in the Consolidated Balance Sheet line items Short-term investments and Other noncurrent assets (noncurrent); derivative assets, included in Other current assets and Other noncurrent assets (noncurrent); and, derivative liabilities, included in Accrued and other liabilities (current) and Other long-termnoncurrent liabilities. The Company applies the fair value measurement guidance to nonfinancial assets and liabilities upon the acquisition of a business or an asset acquisition by a variable interest entity, or in conjunction with the measurement of an asset retirement obligation or a potential impairment loss on an asset group or goodwill undergoodwill.
When determining the accounting guidancefair value measurements for assets and liabilities required to be reflected at their fair values, the impairment of long-lived assetsCompany considers the principal or goodwill.
The Company makesmost advantageous market in which it would transact and considers assumptions about whatthat market participants would assume in valuing an assetuse when pricing the assets or liability based on the best information available. These factors include nonperformanceliabilities, such as inherent risk, (the risk that the obligation will not be fulfilled)transfer restrictions and credit risk of the subsidiary (for liabilities) and of the counterparty (for assets).nonperformance. The Company is prohibited from including transaction costs and any adjustments for blockage factors in determining fair value. The principal or most advantageous market is considered from
In determining fair value measurements, the perspective of the subsidiary owning the asset or with the liability.
Fair value is based on observable market prices where available. Where they are not available, specific valuation models and techniques are applied depending on what is being fair valued. These models and techniques maximizeCompany maximizes the use of observable inputs and minimizeminimizes the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on price transparencyAssets and complexity. An asset's or liability's levelliabilities are categorized within thea fair value hierarchy is based onupon the lowest level of input that is significant to the fair value measurement, wheremeasurement:
Level 1: Quoted prices in active markets for identical assets or liabilities;
Level 2: Inputs other than Level 1 is the highest and Level 3 is the lowest. The three levelsthat are definedobservable, either directly or indirectly, such as follows:
Level 1 — unadjusted quoted prices in active markets accessible by the Companyfor similar assets or liabilities, quoted prices for identical or similar assets or liabilities. Activeliabilities in markets that are those in which transactions for the assetnot active or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 — pricingother inputs other than quoted market prices included in Level 1 whichthat are based onobservable or can be corroborated by observable market data that are directly or indirectly observable for substantially the full term of the asset or liability. These include quoted market prices for similar assets or liabilities, quoted market prices for identicalliabilities; or similar assets in markets that are not active, adjusted quoted market prices, inputs from observable data such as interest rate and yield curves, volatilities or default rates observable at commonly quoted intervals or inputs derived from observable market data by correlation or other means.
Level 3 — pricing3: Unobservable inputs that are unobservable from objective sources. Unobservable inputssupported by little or no market activity and that are only usedsignificant to the extent observable inputs aren't available. These inputs maintain the concept of an exit price from the perspective of a market participant and reflect assumptions of other market participants. The Company considers all market participant assumptions that are available without unreasonable cost and effort. These are given the lowest priority and are generally used in internally developed methodologies to generate management's best estimatefair values of the fair value when no observable market data is available.assets or liabilities.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
Any transfers between all levels within the fair value hierarchy levels are recognized at the end of the reporting period.
CASH AND CASH EQUIVALENTS — The Company considers unrestricted cash on hand, cash balances not restricted as to withdrawal or usage, deposits in banks, certificates of deposit and short-term marketable securities with original maturities of three months or less to be cash and cash equivalents. The carrying amounts of such balances approximate fair value.
RESTRICTED CASH AND DEBT SERVICE RESERVES — These include cashCash balances which are restricted as to withdrawal or usage, byprimarily via contract, are considered restricted cash.
The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the subsidiaryConsolidated Balance Sheets that owns the cash. The nature of restrictions includes restrictions imposed by financing agreements such as security deposits kept as collateral, debt service reserves, maintenance reserves, contractual terms and others, as well as restrictions imposed by agreements relatedreconcile to the salestotal of businesses or long-term PPAs.such amounts as shown on the Consolidated Statements of Cash Flows (in millions): |
| | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| Cash and cash equivalents | $ | 1,166 |
| | $ | 949 |
|
| Restricted cash | 370 |
| | 274 |
|
| Debt service reserves and other deposits | 467 |
| | 565 |
|
| Cash, Cash Equivalents and Restricted Cash | $ | 2,003 |
| | $ | 1,788 |
|
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
INVESTMENTS IN MARKETABLE SECURITIES — The Company's marketable investments are primarily unsecured debentures, certificates of deposit, government debt securities and money market funds.
Short-term investments consist of marketable equity securities and debt securities with original maturities in excess of three months with remaining maturities of less than one year.
Marketable debt securities thatwhere the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at amortized cost. OtherRemaining marketable debt securities that the Company does not intend to hold to maturity are classified as available-for-sale or trading and are carried at fair value. Available-for-sale investments are fair valued at the end of each reporting period where the unrealized
Unrealized gains or losses on available-for-sale debt securities are reflected in accumulated other comprehensive loss ("AOCL"),AOCL, a separate component of equity.
Investments classified as trading are fair valued at the end of each reporting period throughequity, and the Consolidated Statements of Operations.Operations, respectively. Unrealized gains or losses on equity investments are reported in Other income. Interest and dividends on investments are reported in interestInterest income and otherOther income, respectively. Gains and losses on sales of investments are determined using the specific identification method.
ACCOUNTS AND NOTES RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS — Accounts and notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable, considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other currently available evidence of thesupporting collectability, and records an allowance for doubtful accounts for the estimated uncollectible amount as appropriate. Certain of our businesses charge interest on accounts receivable either under contractual terms or where charging interest is a customary business practice. In such cases, interestreceivable. Interest income is recognized on an accrual basis. When the collection of such interest is not reasonably assured, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectible.
INVENTORY — Inventory primarily consists of fuel and other raw materials used to generate power, and operational spare parts and supplies used to maintain power generation and distribution facilities. Inventory is carried at lower of cost or market.net realizable value. Cost is the sum of the purchase price and incidental expenditures and charges incurred to bring the inventory to its existing condition or location. Costs of inventory areInventory is primarily valued primarily using the average cost method. Generally, cost is reduced to market value if the market value of inventory has declined and it is probable that the utility ofexpected fuel inventory in its disposal in the ordinary course of business, will not be recovered through revenue earned from power generation, an impairment is recognized to reflect the generationfuel at market value. The carrying amount of power.spare parts and supplies is typically reduced only in instances where the items are considered obsolete.
LONG-LIVED ASSETS — Long-lived assets include property, plant and equipment, assets under capital leases and intangible assets subject to amortization (i.e., finite-lived intangible assets).
Property, plant and equipment — Property, plant and equipment are stated at cost, net of accumulated depreciation. The cost of renewals and improvements that extend the useful life of property, plant and equipment are capitalized.
Construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction in progress are capitalized during the construction period, provided the completion of the construction project is deemed probable, or expensed at the time the Company determines that development of a particular projectconstruction completion is determined to no longer be probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. Construction-in-progress balances are transferred to electric generation and distribution assets when an asset group is ready for its intended use. Government subsidies, liquidated damages recovered for construction delays, and income tax credits are recorded as a reduction to property, plant and equipment and reflected in cash flows from investing activities. Maintenance and repairs are charged to expense as incurred.
Depreciation, after consideration of salvage value and asset retirement obligations, is computed primarily using the straight-line method over the estimated useful lives of the assets, which are determined on a composite or component basis. Maintenance and repairs are charged to expense as incurred. Capital spare parts, including rotable spare parts, are included in electric generation and distribution assets. If the spare part is considered a component, it is depreciated over its useful life after
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
the part is placed in service. If the spare part is deemed part of a composite asset, the part is depreciated over the composite useful life even when being held as a spare part.
TheCertain of the Company's Brazilian subsidiaries which include both generation and distribution companies, operate under concession contracts. Certain estimates are utilized to determine depreciation expense for the Brazilian subsidiaries, including the useful lives of the property, plant and equipment and the amounts to be recovered at the end of the concession contract. The amounts to be recovered under these concession contracts are based on estimates that are inherently uncertain and actual amounts recovered may differ
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
from those estimates. These concession contracts are not within the scope of ASC 853—Service Concession Arrangements.
Intangible Assets Subject to Amortization — Finite-lived intangible assets are amortized over their useful lives which range from 1 – 50 years. years and are included in the Consolidated Balance Sheet line item Other intangible assets. The Company accounts for purchased emission allowances as intangible assets and records an expense when they are utilized or sold. Granted emission allowances are valued at zero.
Impairment of Long-lived Assets — When circumstances indicate that the carrying amount of long-lived assets (asset group)in a held-for-use asset group may not be recoverable, the Company evaluates the assets for potential impairment using internal projections of undiscounted cash flows expected to resultresulting from the use and eventual disposal of the assets. Events or changes in circumstances that may necessitate a recoverability evaluation 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. If the carrying amount of the assets exceeds the undiscounted cash flows, and exceeds any fair value of the assets, an impairment expense is recognized for the excess up toamount by which the carrying amount of the long-lived assets (but upasset group exceeds its fair value (subject to anythe carrying amount not being reduced below fair value for any individual long-lived asset that is determinable without undue cost and effort). For regulated assets where recovery through approved rates is probable, anAn impairment expense couldfor certain assets may be reduced by the establishment of a regulatory asset. For other regulated assets and for non-regulated assets, impairmentasset if recovery through approved rates is recognized as an expense. When long-lived assets meet the criteria to be classified as held-for-sale and the carrying amount of the disposal group exceeds its fair value less costs to sell, an impairment expense is recognized for the excess up to the carrying amount of the long-lived assets; if the fair value of the disposal group subsequently exceeds the carrying amount while the disposal group is still held-for-sale, any impairment expense previously recognized will be reversed up to the lower of the prior expense or the subsequent excess.probable.
SERVICE CONCESSION ASSETS — Service concession assets are stated at cost, net of accumulated amortization, in accordance with ASC 853. Service concession assets represent the cost of all infrastructure to be transferred to the public-sector entity grantors at the end of the concession. These costs primarily represent construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction of the service concession infrastructure. Government subsidies, liquidated damages recovered for construction delays and income tax credits are recorded as a reduction to Service Concession Assets. Service concession assets are amortized and recognized in earnings as a cost of goods sold. Amortization is recorded ratablysold as buildinfrastructure construction revenue is recognized.
For additional details regarding Services provided under concession arrangements are recognized on a straight line basis. Effective January 1, 2018, the impact ofCompany derecognized the service concession assets and recognized a loan receivable under ASC 606. See further detail in the new accounting on certain of the Company's businesses, see New Accounting Pronouncements Adopted—ASU No. 2014-05, Service Concession Arrangements (Topic 853) pronouncements discussion below.
DEFERRED FINANCINGDEBT ISSUANCE COSTS — Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows used in financing activities.
EQUITY METHOD INVESTMENTS — Investments in entities over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting and reported in Investments in and advances to affiliates on the Consolidated Balance Sheets. The Company periodically assesses if there is an indication that the fair value of an equity method investment is less than its carrying amount. When an indicator exists, any excess of the carrying amount over its estimated fair value is recognized as impairment when the loss in value is deemed other-than-temporary and included in Other non-operating expense in the Consolidated Statements of Operations. The difference between the carrying amount and our underlying equity in the net assets of the investee are accounted for as if the investee were a consolidated subsidiary, except that the portion that represents equity method goodwill is not reviewed for impairment like consolidated goodwill. Upon acquiring the investment, we determine the fair value of the identifiable assets and assumed liabilities and the basis difference between each fair value and the carrying amount of the corresponding asset or liability in the financial statements of the investee are recognized in our net equity in earnings of affiliates over the life of the asset or liability.
The Company discontinues the application of the equity method when an investment is reduced to zero and the Company is not otherwise committed to provide further financial support to the investee. The Company resumes the application of the
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
equity method if the investee subsequently reports net income to the extent that the Company's share of such net income equals the share of net losses not recognized during the period in which the equity method of accounting was suspended.
GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS — The Company evaluates goodwill and indefinite-lived intangible assets for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. The Company's annual impairment testing date is October 1.
Goodwill — The Company evaluates goodwill impairment atGoodwill represents the reporting unit level, which is an SBU (i.e. an operating segment as defined in the segment reporting accounting guidance), or a component (i.e., one level below an operating segment). In determining its reporting units, the Company starts with its management reporting structure. Operating segments are identified and then analyzed to identify components which make up these operating segments. Two or more components are combined into a single reporting unit if they are economically similar. Assets and liabilities are allocated to a reporting unit if the assets will be employed by or a liability relates to the operationsexcess of the reporting unit or would be considered by a market participant in determining itspurchase price of the business acquisition over the fair value.value of identifiable net assets acquired. Goodwill resulting from an acquisition is assigned to the reporting units that are expected to benefit from the synergies of the acquisition. Generally, each AES business with a goodwill balance constitutes a reporting unit as they are not similar to other businesses in a segment nor are they reported to segment management together with other businesses and are not similar to other businesses in a segment.businesses.
Goodwill is evaluated for impairment either under the qualitative assessment option or the two-stepquantitative test approach depending on facts and circumstances of a reporting unit, including the excess of fair value over carrying amount in the last valuation or changes in business environment. If the Company qualitatively determines it is more likely than not thatoption to determine the fair value of athe reporting unitunit. If goodwill is greater than itsdetermined to be impaired, an impairment loss measured at the amount by which the reporting unit’s carrying amount the two-step impairment test is unnecessary. Otherwise, goodwill is evaluated for impairment using the two-step test, where the carrying amount of a reporting unit is compared toexceeds its fair value, in Step 1; if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit's fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is requirednot to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations (which in some cases may be based in part on third party valuation reports) or other observable sources of fair value, as appropriate. Ifexceed the carrying amount of goodwill, exceeds its implied fair value, the excess is recognized as an impairment loss up to the carrying amount of the goodwill.recorded.
Most of the Company's reporting units are not publicly traded. Therefore, the Company estimates the fair value of its reporting units using internal budgets and forecasts, adjusted for any market participants' assumptions and discounted at the rate of return required by a market participant. The Company considers both market and income-based approaches to determine a range of fair value, but typically concludes that the value derived using an income-based approach is more representative of fair value due to the lack of direct market comparables. The Company utilizes market data, when available, to corroborate and determine the reasonableness of the fair value derived from the income-based discounted cash flow analysis.
Indefinite-Lived Intangible Assets — The Company's indefinite-lived intangible assets primarily include land-use rights and water rights. TheseIndefinite-lived intangible assets are testedevaluated for impairment on an annual basiseither under the qualitative assessment option or whenever events or changes in circumstances necessitate an evaluation for impairment.the two-step quantitative test. If the carrying amount of an intangible asset being tested for impairment exceeds its fair value, the excess is recognized as impairment expense. When deemed appropriate, the Company uses the qualitative assessment option under the accounting guidance on goodwill and intangible assets to determine whether the existence of events or circumstances indicate that it is more likely than not that an intangible asset is impaired. If, after assessing the totality of events and circumstances, the Company determines that it is not more likely than not that an intangible asset is impaired, no further action is taken. The accounting guidance provides the option to bypass the qualitative assessment for any intangible asset in any period and proceed directly to performing the quantitative impairment test.
ACCOUNTS PAYABLE AND OTHER ACCRUED LIABILITIES — Accounts payable consists of amounts due to trade creditors related to the Company's core business operations. These payables include amounts owed to
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
vendors and suppliers for items such as energy purchased for resale, fuel, maintenance, inventory and other raw materials. Other accrued liabilities include items such as income taxes, regulatory liabilities, legal contingencies and employee-related costs, including payroll, benefits and related taxes.benefits.
REGULATORY ASSETS AND LIABILITIES — The Company recordsrecognizes assets and liabilities that result from the regulated ratemaking process that are not recognized under GAAP for non-regulated entities.processes. Regulatory assets generally represent incurred costs thatwhich have been deferred due to the probable future recovery invia customer rates being probable.rates. Generally, returns earned on regulatory assets are reflected onin the Consolidated Statement of Operations within Interest Income. Regulatory liabilities generally represent obligations to make refunds torefund customers. Management continually assesses whether the regulatory assets are probable of future recovery and regulatory of liabilities are probable of future payment by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities, and the status of any
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
pending or potential deregulation legislation. If future recovery of costs previously deferred ceases to be probable, the related regulatory assets are written off and recognized in income from continuing operations.
PENSION AND OTHER POSTRETIREMENT PLANS — The Company recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in actuarial gains or losses recognized in AOCL, except for those plans at certain of the Company's regulated utilities that can recover portions of their pension and postretirement obligations through future rates. All plan assets are recorded at fair value. AES follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
Effective January 1, 2016, the Company will apply a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans in the U.S. and U.K. This approach is consistent with the requirements of ASC 715—Compensation—Retirement Benefits and is considered to be more precise compared to the aggregated single rate discount approach, which has historically been used in the U.S. and U.K., because it is more consistent with the philosophy of a full yield curve valuation. The disaggregated rate approach can be applied only in countries with a sufficiently robust yield curve. For countries other than the U.S. and U.K., the Company will continue to apply a local government bond yield approach.
The change in discount rate approach in the U.S. and U.K. did not have an impact on the measurement of the benefit obligations as at December 31, 2015, nor will it impact future remeasurements. This change in estimate will impact the service cost and interest cost recorded in 2016 and future years. It will also impact the actuarial gains and losses recorded in future years, as well as the amortization thereof.
The expected 2016 service costs and interest costs included in Note 15—Benefit Plans reflect the change in estimate described above. The impact of the change in approach on expected service costs for the U.S. and U.K. plans in 2016 is shown below (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Expected 2016 Service Cost | | Expected 2016 Interest Cost |
| | Disaggregated rate approach | | Aggregate rate approach | | Impact of change | | Disaggregated rate approach | | Aggregate rate approach | | Impact of change |
| U.S. | $ | 13 |
| | $ | 14 |
| | $ | (1 | ) | | $ | 42 |
| | $ | 51 |
| | $ | (9 | ) |
| U.K. | 3 |
| | 4 |
| | (1 | ) | | 7 |
| | 9 |
| | (2 | ) |
| Total | $ | 16 |
| | $ | 18 |
| | $ | (2 | ) | | $ | 49 |
| | $ | 60 |
| | $ | (11 | ) |
INCOME TAXES — Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases.basis. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company's tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.
Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company's policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
The Company has elected to treat GILTI as an expense in the period in which the tax is accrued. Accordingly, no deferred tax assets or liabilities are recorded related to GILTI.
ASSET RETIREMENT OBLIGATIONS — The Company records the fair value of thea liability for a legal obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.
NONCONTROLLING INTERESTS — Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income and comprehensive income attributable to noncontrolling interests are reflected separately from consolidated net income and comprehensive income on the Consolidated Statements of Operations and Consolidated Statements of Changes in Equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests (unless the transaction qualifies as a sale of in-substance real estate). Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.
Although, in general, the noncontrolling ownership interest in earnings is calculated based on ownership percentage, certain of the Company's businesses are subject to certain profit-sharing arrangements. These agreements exist for certain renewable generation partnerships to designate different allocations of value among investors, where the allocations change in form or percentage over the life of the partnership. For these businesses, the Company uses the HLBV method when it is a
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
reasonable approximation of the profit-sharing arrangement. HLBV uses a balance sheet approach, which measures the Company's equity in income or loss by calculating the change in the amount of net worth the partners are legally able to claim based on a hypothetical liquidation of the entity at the beginning of a reporting period compared to the end of that period.
FOREIGN CURRENCY TRANSLATION — A business's functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is a currency other than the U.S. Dollardollar translate their assets and liabilities into U.S. Dollarsdollars at the current exchange rates in effect at the end of the fiscal period. Adjustments arising from the translation of the balance sheet of such subsidiaries are included in AOCL. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. Dollarsdollars at the average exchange rates that prevailed duringfor the period. Translation adjustments are included in AOCL. Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in AOCL. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency are included in determining net income. Accumulated foreign currency translation adjustments are reclassified from AOCL to net income only when realized upon sale or upon complete or substantially complete liquidation of the investment in a foreign entity. The accumulated adjustments are included in carrying amounts in impairment assessments where the Company has committed to a plan that will cause the accumulated adjustments to be reclassified to earnings.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
REVENUE RECOGNITION — Revenue is earned from the sale of electricity from our utilities and the production and sale of electricity and capacity from our generation facilities. Revenue is recognized upon the transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
Utilities— Our utilities sell electricity directly to end-users, such as homes and businesses, and bill customers directly. The majority of our utility contracts have a single performance obligation, as the promises to transfer energy, capacity, and other distribution and/or transmission services are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. Utility revenue is classified as regulated inon the Consolidated Statements of Operations.
In exchange for the right to sell or distribute electricity in a service territory, our utility businesses are subject to government regulation. This regulation sets the framework for the prices (“tariffs”) that our utilities are allowed to charge customers for electricity. Since tariffs are determined by the regulator, the price that our utilities have the right to bill corresponds directly with the value to the customer of the utility's performance completed in each period. The Company also has some month-to-month contracts. Revenue from the sale of energyunder these contracts is recognized inusing an output method measured by the period duringMWh delivered each month, which best depicts the sale occurs. The calculationtransfer of revenue earned but not yet billed is based ongoods or services to the number of days not billed incustomer, at the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are usually immaterial. approved tariff.
The Company has businesses where it sells and purchases power to and from Independent System Operators ("ISOs")ISOs and Regional Transmission Organizations ("RTOs").RTOs. Our utility businesses generally purchase power to satisfy the demand of customers that is not contracted through separate PPAs. In thosethese instances, the Company accounts for these transactions on a net hourly basis because the transactions are settled on a net hourly basis. In limited situations, a utility customer may choose to receive generation services from a third-party provider, in which case the Company may serve as a billing agent for the provider and recognize revenue on a net basis.
Generation — Most of our generation fleet sells electricity under contracts to customers such as utilities, industrial users, and other intermediaries. Our generation contracts, based on specific facts and circumstances, can have one or more performance obligations as the promise to transfer energy, capacity, and other services may or may not be distinct depending on the nature of the market and terms of the contract. As the performance obligations are generally satisfied over time and use the same method to measure progress, the performance obligations meet the criteria to be considered a series. In measuring progress toward satisfaction of a performance obligation, the Company applies the "right to invoice" practical expedient when available, and recognizes revenue in the amount to which the Company has a right to consideration from a customer that corresponds directly with the value of the performance completed to date. Revenue from generation businesses is classified as non-regulated on the Consolidated Statements of Operations.
For contracts determined to have multiple performance obligations, we allocate revenue to each performance obligation based on its relative standalone selling price using a market or expected cost plus margin approach. Additionally, the Company allocates variable consideration to one or more, but not all, distinct goods or services that form part of a single performance obligation when (1) the variable consideration relates specifically to the efforts to transfer the distinct good or service and (2) the variable consideration depicts the amount to which the Company expects to be entitled in exchange for transferring the promised good or service to the customer.
Revenue from generation contracts is recognized based uponusing an output deliveredmethod, as energy and capacity provided, at ratesdelivered best depicts the transfer of goods or services to the customer. Performance obligations including energy or ancillary services (such as specified under contract termsoperations and maintenance and dispatch services) are generally measured by the MWh delivered. Capacity, which is a stand-ready obligation to deliver energy when required by the customer, is measured using MWs. In certain contracts, if plant availability exceeds a contractual target, the Company may receive a performance bonus payment, or prevailing market rates. Certainif the plant availability falls below a guaranteed minimum target, we may incur a non-availability penalty. Such bonuses or penalties represent a form of variable consideration and are estimated and recognized when it is probable that there will not be a significant reversal.
In assessing whether variable quantities are considered variable consideration or an option to acquire additional goods and services, the Company evaluates the nature of the promise and the legally enforceable rights in the contract. In some contracts, such as requirement contracts, the legally enforceable rights merely give the customer a right to purchase additional goods and services which are distinct. In these contracts, the customer's action results in a new obligation, and the variable quantities are considered an option.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
When energy or capacity is sold or purchased in the spot market or to ISOs, the Company PPAs meetassesses the definitionfacts and circumstances to determine gross versus net presentation of spot revenues and purchases. Generally, the nature of the performance obligation is to sell surplus energy or capacity above contractual commitments, or to purchase energy or capacity to satisfy deficits. Generally, on an hourly basis, a generator is either a net seller or a net buyer in terms of the amount of energy or capacity transacted with the ISO. In these situations, the Company recognizes revenue for the hours where the generator is a net seller and cost of sales for the hours where the generator is a net buyer.
Certain generation contracts contain operating leases where capacity payments are generally considered lease or contain similar arrangements. Typically, minimumelements. In such cases, the allocation between the lease and non-lease elements is made at the inception of the lease following the guidance in ASC 840. Minimum lease payments from such PPAscontracts are recognized as revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned. Revenue
The transaction price allocated to a construction performance obligation is recorded netrecognized as revenue over time as construction activity occurs, with revenue being fully recognized upon completion of any taxes assessedconstruction. These contracts may include a difference in timing between revenue recognition and the collection of cash receipts, which may be collected over the term of the entire arrangement. The timing difference could result in a significant financing component for the construction performance obligation if determined to be a material component of the transaction price. The Company accounts for a significant financing component under the effective interest rate method, recognizing a long-term receivable for the expected future payments related to the construction performance obligation in the Loan Receivable line item on andthe Consolidated Balance Sheets. As payments are collected from customers, which are remittedthe customer over the term of the contract, consideration related to the governmental authorities.construction performance obligation is bifurcated between the principal repayment of the long-term receivable and the related interest income, recognized in the Consolidated Statements of Operations.
SHARE-BASED COMPENSATION — The Company grants share-based compensation in the form of stock options, restricted stock units, performance stock units, and performance stockcash units. The expense is based on the grant-date fair value of the equity or liability instrument issued and is recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. The Company uses a Black-Scholes option pricing model to estimate the fair value of stock options granted to its employees.
GENERAL AND ADMINISTRATIVE EXPENSES — General and administrative expenses include corporate and other expenses related to corporate staff functions and initiatives, primarily executive management, finance, legal, human resources and information systems, which are not directly allocable to our business segments. Additionally, all costs associated with corporate business development efforts are classified as general and administrative expenses.
DERIVATIVES AND HEDGING ACTIVITIES — Under the accounting standards for derivatives and hedging, the Company recognizes all contracts that meet the definition of a derivative, except those designated as normal purchase or normal sale at inception, as either assets or liabilities in the Consolidated Balance Sheets and measures those instruments at fair value. See the Company's fair value policy and Note 4—Fair Value and Fair value in this section for additional discussion regarding the determination of the fair value. The PPAs and fuel supply agreements entered into by the Company are evaluated to determineassess if they meet the definition ofcontain either a derivative or containan embedded derivatives, either of which requirederivative requiring separate valuation and accounting. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Generally, these agreements do not meet the definition of a derivative, often due to the inability to be net settled. On a quarterly basis, we evaluate the markets for the commodities to be delivered under these agreements to determine if facts and circumstances have changed such that the agreements could then be net settled and meet the definition of a derivative.
The Company typically designates its derivative instruments as cash flow hedges if they meet the criteria specified in ASC 815, Derivatives primarily consist of interest rate swaps, cross-currency swaps, foreign currency instruments, and commodity derivatives.Hedging. The Company enters into various derivative transactionsinterest rate swap agreements in order to hedge its exposurethe variability of expected future cash interest payments. Foreign currency contracts are used to certain marketreduce risks primarily interest rate,arising from the change in fair value of certain foreign currency denominated assets and commodity price risks. Regarding interest rate risk, the Company and our subsidiaries generally utilize variable rate debt financing for construction projects and operations so interest rate swap, lock, cap, and floor agreements are entered intoliabilities. The objective of these practices is to manage interest rate risk by effectively fixing or limiting the interest rate exposure on the underlying financing and are typically designated as cash flow hedges. Regarding foreign currency risk, we are exposed to it as a result of our investments in foreign subsidiaries and affiliates that may be impacted by significant fluctuations in
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
foreign currency exchange rates so foreign currency options and forwards are utilized, where deemed appropriate, to manage the risk related to these fluctuations. Cross-currency swaps are utilized in certain instances to manage the risk related to certain foreign currencies and the associated impact on interest and loan principal payments. In addition, certain of our subsidiaries have entered into contracts which contain embedded derivatives as a portion of the contracts primarily that are denominated in a currency other than the functional or local currency of that subsidiary or the currency of the item. Regarding commodity price risk, we are exposed tominimize the impact of marketforeign currency fluctuations in the price of electricity, fuel and environmental credits. Although we primarily consist of businesses with long-term contracts or retail sales concessions (which provide our distribution businesses with a franchise to serve a specific geographic region), a portion of our current and expected future revenues are derived from businesses without significant long-term purchase or sales contracts. We use an overall hedging strategy, not just derivatives, to hedge our financial performance against the effects of fluctuations in commodity prices.
The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged.operating results. The Company only has cash flowalso enters into commodity contracts to economically hedge price variability inherent in electricity sales arrangements. The objectives of the commodity contracts are to minimize the impact of variability in spot electricity prices and stabilize estimated revenue streams. The Company does not use derivative instruments for speculative purposes.
For our hedges, at this time. Changeschanges in the fair value of a derivative that isare considered highly effective designated and qualifies as a cash flow hedge are deferred in AOCL and are recognized into earnings as the hedged transactions affect earnings. Any ineffectiveness is recognized in earnings
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
immediately. For all designated and qualifying hedges, the Company maintains formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If AES determines that thea derivative is no longer highly effective, as a hedge, hedge accounting will be discontinued prospectively. For cash flow hedges of forecasted transactions, AES estimates the future cash flows of the forecasted transactions and evaluates the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from AOCL into earnings.
While derivative transactions are not entered into for trading purposes, some contracts are not eligible for hedge accounting. Changes in the fair value of derivatives not designated and qualifying as cash flow hedges are immediately recognized in earnings. Regardless of when gains or losses on derivatives (including all those where the fair value measurement is classified as Level 3) are recognized in earnings, they are generally classified as follows: interest expense for interest rate and cross-currency derivatives, foreign currency transaction gains or losses for foreign currency derivatives, and non-regulated revenue or non-regulated cost of sales for commodity and other derivatives. However, gains and losses on interest rate and cross-currency derivatives are classified as foreign currency transaction gains and losses if they offset the remeasurement of the foreign currency-denominated debt being hedged by the cross-currency swaps and the amount reclassified from AOCL to cost of sales to offset depreciation where the variable-rate interest capitalized as part of the asset was hedged during its construction. Cash flows arising from derivatives are included in the Consolidated Statements of Cash Flows as an operating activity given the nature of the underlying risk being economically hedged and the lack of significant financing elements, except that cash flows on designated and qualifying hedges of variable-rate interest during construction are classified as an investing activity.
The Company has elected not to offset net derivative positions in the financial statements. Accordingly, the Company does not offset such derivative positions against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.
NEW ACCOUNTING PRONOUNCEMENTS ADOPTED
ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification— The following table provides a brief description of Deferred Taxes
Effective December 31, 2015, the Company prospectively adopted ASU No. 2015-17, which requiresrecent accounting pronouncements that
all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrenthad an impact on the
balance sheet. AsCompany’s consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a
result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. The guidance does not changematerial impact on the
existing requirement that only permits offsetting within a jurisdiction; that is, companies will remain prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. Additionally, the current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the update. As the Company elected to apply this ASU prospectively, prior periods were not adjusted.Company’s consolidated financial statements.ASU No. 2015-13, Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets |
| | | |
| New Accounting Standards Adopted |
| ASU Number and Name | Description | Date of Adoption | Effect on the financial statements upon adoption |
| 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract | This standard aligns the accounting for implementation costs incurred for a cloud computing arrangement that is a service with the requirement for capitalizing implementation costs associated with developing or obtaining internal-use software.
Transition method: retrospective or prospective. | October 1, 2018
| The Company elected to early-adopt this standard on a prospective basis, effective for fiscal year 2018. The adoption of this standard did not have a material impact on the financial statements. |
| 2018-14, Compensation— Retirement Benefits — Defined Benefit Plans — General (Subtopic 715-20): Disclosure Framework | This standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans.
Transition method: retrospective. | Early adoption elected, January 1, 2018 | Impact limited to changes in financial statement disclosures. |
| 2017-07, Compensation — Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost | This standard changes the presentation of non-service costs associated with defined benefit and other postretirement plans and updates the guidance so that only the service cost component will be eligible for capitalization.
Transition method: retrospective for presentation of non-service cost and prospective for the change in capitalization. | January 1, 2018 | For the year ended December 31, 2017 and 2016, $1 million and $3 million of non-service costs associated with defined benefit and other postretirement plans were reclassified from Costs of Sales to Other Expense, respectively. |
| 2017-05, Other Income — Gains and Losses from the Derecognition of Nonfinancial Assets (Topic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets | This standard clarifies the scope and application of ASC 610-20 on the sale, transfer, and derecognition of nonfinancial assets and in substance nonfinancial assets to non-customers, including partial sales. It also provides guidance on how gains and losses on transfers of nonfinancial assets and in substance nonfinancial assets to non-customers are recognized. The standard also clarifies that the derecognition of businesses is under the scope of ASC 810. The standard must be adopted concurrently with ASC 606, however an entity will not have to apply the same transition method as ASC 606.
Transition method: modified retrospective. | January 1, 2018 | Following adoption of ASU 2017-01, fewer transactions are expected to meet the definition of a business under the scope of ASC 810 and will fall under the scope under this standard.
|
In August 2015, the FASB issued ASU No. 2015-13, which resolves the diversity in practice resulting from determining whether certain contracts qualify for the normal purchases and normal sales scope exception under ASC Topic 815—Derivatives and Hedging. This standard clarifies that entities would not be precluded from applying the normal purchases and normal sales exception to certain forward contracts that necessitate the transmission of electricity through, or delivery to a
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
location within, a nodal energy market. The standard is effective upon issuance and should be applied prospectively. As the Company had designated qualifying contracts as normal purchase or normal sales, there was no impact on the Company's consolidated financial statements upon adoption of this standard.
ASU No. 2014-05, Service Concession Arrangements (Topic 853)Effective |
| | | |
| 2017-04, Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment | This standard simplifies the accounting for goodwill impairments by removing the requirement to calculate the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if it had been acquired in a business combination. Instead, it requires that an entity record an impairment charge based on the amount by which a reporting unit's carrying amount exceeds its fair value, not to exceed the total amount of goodwill allocated to that reporting unit.
Transition method: prospective. | October 1, 2018 | In anticipation of our annual goodwill process, the Company early-adopted this standard to ease the administrative burden for the measurement of any potential goodwill impairment losses. There was no impact to the financial statements upon adoption of the standard. |
| 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business | The standard requires an entity to first evaluate whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, and if that threshold is met, the set is not a business. As a second step, at least one substantive process should exist to be considered a business.
Transition method: prospective. | January 1, 2018 | Some acquisitions and dispositions are expected to now fall under a different accounting model. This will reduce the number of transactions that are accounted for as business combinations and therefore future acquired goodwill.
|
| 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) | This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.
Transition method: retrospective. | January 1, 2018 | For the years ended December 31, 2017 and 2016, cash provided by operating activities increased by $15 million and $13 million, respectively, cash used in investing activities decreased by $150 million and increased by $28 million, respectively, and cash provided by financing activities was unchanged. |
| 2016-01, Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities | The standard significantly revises an entity’s accounting related to (1) classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosures of financial instruments.
Transition method: modified retrospective. Prospective for equity investments without readily determinable fair value. | January 1, 2018 | No material impact upon adoption of the standard. |
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606)
| See discussion of the ASU below. | January 1, 2018 | See impact upon adoption of the standard below. |
On January 1, 2015,2018, the Company adopted ASU No. 2014-05,2014-09, "Revenue from Contracts with Customers," and its subsequent corresponding updates ("ASC 606"). Under this standard, an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which states that certain service concession arrangements with public-sectorthe entity grantors are notexpects to be entitled in scope of ASC 840—Leases, and that entities should not recognize the related infrastructure as property, plant and equipment, but should apply other GAAP.exchange for those goods or services. The Company has a small numberapplied the modified retrospective method of entities that fall within the scope of this guidance, with the Company's Mong Duong generation facility in Vietnam being the most significant.
Mong Duong is based on a build, operate and transfer agreement with the Vietnamese government. Management concluded there were two deliverables included within the arrangement, as well as a financing element. Dueadoption to the contingent nature of the revenue stream, no amounts of revenue could be recognized during the build phase of the contract. All amounts billed during the operate phase are recognized as revenue when billed, with amounts allocated between the financing element and build and operate deliverables. The financing element is recognized as interest income using the effective interest method as payments for construction of the plant are received over the life of the contract. Costs are expensed as incurred. As the related infrastructure is no longer considered property, plant and equipment, there are no longer any capitalizable expenses beyond those related to the initial build, and accordingly these will be expensed as incurred. All cash flows for these arrangements, excluding those related to the debt incurred by AES, will be reflected in cash flows from operating activities on the Company's Consolidated Statements of Cash Flows prospectively.
The guidance was applied on a modified retrospective basis to service concession arrangements in existence at January 1, 2015. Upon adoption of this standard, the impact to the Company's Consolidated Balance Sheetcontracts that were not completed as of January 1, 2015 resulted in a reclassification of $1.5 billion from property, plant2018. Results for reporting periods beginning January 1, 2018 are presented under ASC 606, while prior period amounts were not adjusted and equipment to service concession assets, as well as a cumulative adjustment to retained earnings and cumulative translation adjustment of $(18) million, net of tax, and $13 million, respectively.
ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET EFFECTIVE — The following accounting standards have been issued, but are not yet effective for, and have not been adopted in these financial statements by AES.
ASU No. 2016-01, Financial Instruments — Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU 2016-01, which was designed to improve the recognition and measurement of financial instruments through targeted changes to existing GAAP. The guidance requires equity investments (except those that are accounted for under the equity method of accounting or result in consolidation of the investee)continue to be measured at fair value with changes in fair value recognized in net income; that entities use the exit price notion when measuring financial instrument fair values; that an entity separate presentation of financial assets and liabilities by measurement category and form of financial asset on the Balance Sheets or Notes to the financial statements; that an entity present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk (or "own credit") when the entity has elected to measure the liability at fair valuereported in accordance with the fair value option for financial instruments. Also, the standard eliminates the requirement for public entities to disclose the methods and significant assumptions used to estimate the fair value required to be disclosed for financial instruments measured at amortized cost on the Balance Sheets. The standard is effective beginning with interim periods starting after December 31, 2017 and cannot be applied early. The Company is currently evaluating the applicability and materiality of the standard, but does not anticipate a material impact on the Company's consolidated financial statements.
ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments
In September 2015, the FASB issued ASU 2015-16, which simplifies the measurement-period adjustments in business combinations. It eliminates the requirementprevious revenue recognition standard. For contracts that an acquirer in a business combination account for measurement-period adjustments retrospectively. An acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. The standard is effective for public entities for annual reporting periods beginning after December 15, 2015, and interim periods therein. Early adoption is permitted for financial statements that have not been issued. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this standard. The Company will adopt this standard onwere modified before January 1, 2016, which is not expected2018, the Company reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price.
The cumulative effect to have a material impact onour January 1, 2018 Consolidated Balance Sheet resulting from the Company's consolidated financial statements.adoption of ASC 606 was as follows (in millions):
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
ASU No. 2015-15, Interest — Imputation
|
| | | | | | | | | | | |
| Consolidated Balance Sheet | Balance at December 31, 2017 | | Adjustments Due to ASC 606 | | Balance at January 1, 2018 |
| Assets | | | | | |
| Other current assets | $ | 630 |
| | $ | 61 |
| | $ | 691 |
|
| Deferred income taxes | 130 |
| | (24 | ) | | 106 |
|
| Service concession assets, net | 1,360 |
| | (1,360 | ) | | — |
|
| Loan receivable | — |
| | 1,490 |
| | 1,490 |
|
| Equity | | | | | |
| Accumulated deficit | (2,276 | ) | | 67 |
| | (2,209 | ) |
| Accumulated other comprehensive loss | (1,876 | ) | | 19 |
| | (1,857 | ) |
| Noncontrolling interest | 2,380 |
| | 81 |
| | 2,461 |
|
The Mong Duong II power plant in Vietnam is the primary driver of Interest (Subtopic 835-30): Presentationchanges in revenue recognition under the new standard. This plant is operated under a build, operate, and Subsequent Measurementtransfer contract and will be transferred to the Vietnamese government after the completion of Debt Issuance Costs Associated with Line-of-Credit Arrangements
In August 2015,a 25-year PPA. Under the FASB issued ASU No. 2015-15,previous revenue recognition standard, construction costs were deferred to a service concession asset, which clarifies thatwas expensed in proportion to revenue recognized for the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratablyconstruction element over the term of the line-of-credit arrangement, regardlessPPA. Under ASC 606, construction revenue and associated costs are recognized as construction activity occurs. As construction of whether there are any outstanding borrowingsthe plant was substantially completed in 2015, revenues and costs associated with the construction were recognized through retained earnings, and the service concession asset was derecognized. A loan receivable was recognized for the future expected payments for the construction performance obligation. As the payments for the construction performance obligation occur over a 25-year term, a significant financing element was determined to exist which is accounted for under the effective interest rate method. The other performance obligation to operate and maintain the facility is measured based on the line-of-credit arrangement. This standard should be adopted concurrent with adoption of ASU 2015-03 (see below). Ascapacity made available.
The impact to our Consolidated Balance Sheet as of December 31, 2015,2018 resulting from the Company had deferred financing costs related to lines-of-credit of approximately $2 million recorded within other current assets and $24 million recorded within other noncurrent assets that would not be reclassified upon adoption of this standard.
ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory
In July 2015, the FASB issued ASU No. 2015-11, which simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with a lower of cost or net realizable value test. The standard is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted. The new guidance must be applied prospectively. The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
ASU No. 2015-05, Intangibles — Goodwill and Other — Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement
In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizingASC 606 as compared to the accounting guidance on leases. previous revenue recognition standard was as follows (in millions):
|
| | | | | | | | | | | |
| | December 31, 2018 |
| Consolidated Balance Sheet | As Reported | | Balances Without Adoption of ASC 606 | | Adoption Impact |
| Assets | | | | | |
| Other current assets | $ | 807 |
| | $ | 741 |
| | $ | 66 |
|
| Deferred income taxes | 97 |
| | 122 |
| | (25 | ) |
| Service concession assets, net | — |
| | 1,261 |
| | (1,261 | ) |
| Loan receivable | 1,423 |
| | — |
| | 1,423 |
|
| TOTAL ASSETS | 32,521 |
| | 32,318 |
| | 203 |
|
| Equity | | | | | |
| Accumulated deficit | (1,005 | ) | | (1,112 | ) | | 107 |
|
| Accumulated other comprehensive loss | (2,071 | ) | | (2,088 | ) | | 17 |
|
| Noncontrolling interest | 2,396 |
| | 2,317 |
| | 79 |
|
| TOTAL LIABILITIES AND EQUITY | 32,521 |
| | 32,318 |
| | 203 |
|
The standard is effectiveimpact to our Consolidated Statement of Operations for annual reporting periods beginning afterthe year ended December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits31, 2018 resulting from the use of a prospective or retrospective approach. The Company expects to utilize the prospective approach upon adoption of thisASC 606 as compared to the previous revenue recognition standard which is not expected towas as follows (in millions):
|
| | | | | | | | | | | |
| | Year Ended December 31, 2018 |
| Consolidated Statement of Operations | As Reported | | Balances Without Adoption of ASC 606 | | Adoption Impact |
| Total revenue | $ | 10,736 |
| | $ | 10,800 |
| | $ | (64 | ) |
| Total cost of sales | (8,163 | ) | | (8,207 | ) | | 44 |
|
| Operating margin | 2,573 |
| | 2,593 |
| | (20 | ) |
| Interest income | 310 |
| | 252 |
| | 58 |
|
| Other Income | 72 |
| | 70 |
| | 2 |
|
| Income from continuing operations before taxes and equity in earnings of affiliates | 2,018 |
| | 1,978 |
| | 40 |
|
| INCOME FROM CONTINUING OPERATIONS | 1,349 |
| | 1,309 |
| | 40 |
|
| NET INCOME | 1,565 |
| | 1,525 |
| | 40 |
|
| NET INCOME ATTRIBUTABLE TO THE AES CORPORATION | 1,203 |
| | 1,163 |
| | 40 |
|
New Accounting Pronouncements Issued But Not Yet Effective — The following table provides a brief description of recent accounting pronouncements that could have a material impact on itsthe Company’s consolidated financial statements.statements once adopted. Accounting pronouncements not listed below were assessed and determined to
ASU No. 2015-03, Interest — Imputation of Interest (Subtopic 835-30)
In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015, the Company had deferred financing costs of approximately $24 million classified within other current assets and $356 million classified within other noncurrent assets that would be reclassified to reduce the related debt liabilities upon adoption of this standard.
ASU No. 2015-02, Consolidation — Amendments to the Consolidation Analysis (Topic 810)
In February 2015, the FASB issued ASU 2015-02, which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. Based on the Company's preliminary analysis, no change in consolidation is expected although additional disclosures may be required.
ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)
In May 2014, the FASB issued ASU No. 2014-09, which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, whichdeferred the effective date of ASU 2014-09 by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). The standard permits the use of
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
be either not applicable or are expected to have no material impact on the Company’s consolidated financial statements.
|
| | | |
| New Accounting Standards Issued But Not Yet Effective |
| ASU Number and Name | Description | Date of Adoption | Effect on the financial statements upon adoption |
| 2018-02, Income Statement — Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from AOCI | This amendment allows a reclassification of the stranded tax effects resulting from the implementation of the Tax Cuts and Jobs Act from AOCI to retained earnings. Because this amendment only relates to the reclassification of the income tax effects of the Tax Cuts and Jobs Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. | January 1, 2019. Early adoption is permitted.
| The Company does not expect any impact on its consolidated financial statements upon adoption of the standard on January 1, 2019. |
| 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities | The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.
Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures. | January 1, 2019. Early adoption is permitted.
| The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
|
| 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments | The standard updates the impairment model for financial assets measured at amortized cost. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses as it is done today, except that the losses will be recognized as an allowance rather than a reduction in the amortized cost of the securities.
Transition method: various. | January 1, 2020. Early adoption is permitted only as of January 1, 2019. | The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements. |
| 2016-02, 2018-01, 2018-10, 2018-11, 2018-20 Leases (Topic 842) | See discussion of the ASU below. | January 1, 2019. Early adoption is permitted. | The Company will adopt the standard on January 1, 2019; see below for the evaluation of the impact of its adoption on the consolidated financial statements. |
ASU 2016-02 and its subsequent corresponding updates require lessees to recognize assets and liabilities for most leases, and recognize expenses in a full retrospective ormanner similar to the current accounting method. For lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates current real estate-specific provisions.
The standard must be adopted using a modified retrospective approach. The FASB has provided an optional transition method, which the Company has not yet selected aelected, that allows entities to continue to apply the guidance in ASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, the Company will apply the transition provisions starting on January 1, 2019.
The Company has elected to apply a package of practical expedients that allow lessees and lessors not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under ASC 842. These three practical expedients must be elected as a package and must be consistently applied to all leases. The Company has also elected to apply an optional transition practical expedient for land easements that allows an entity to continue applying its current accounting policy for all land easements that exist before the standard’s effective date that were not previously accounted for under ASC 840.
The Company established a task force focused on the identification of contracts that are under the scope of the new standard and the assessment and measurement of their corresponding right-of-use assets and related liabilities. Additionally, the implementation team has been working on the configuration of a lease accounting tool that will support the implementation and the subsequent accounting. The implementation team has also evaluated
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
changes to our business processes, systems and controls to support recognition and disclosure under the new standard.
Under ASC 842, it is currently evaluatingexpected that fewer contracts will contain a lease. However, due to the elimination of the real estate-specific guidance and changes to certain lessor classification criteria, more leases will qualify as sales-type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will recognize a lease receivable. According to ASC 842, the lease receivable includes the fair value of the plant after the contract period but does not include any variable payments such as margin on the sale of energy. Therefore, the lease receivable could be significantly different than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized lease receivable and the carrying amount of the underlying asset is recognized as a gain/loss at lease commencement.
The primary expected impact as of adopting the standardeffective date is the recognition of approximately $300 million of lease liabilities and the corresponding right of use assets for all contracts that contain an operating lease and for which the Company is the lessee. In addition, the Company expects to reclassify various account balances to different line items on its consolidated financial statements.the Consolidated Balance Sheet to reflect the new presentation requirements. Consolidated Statement of Operations presentation and the expense recognition pattern are not expected to change for lessees.
2. INVENTORY
Inventory is valued primarily using the average-cost method. The following table summarizes the Company's inventory balances (in millions) as of the dates indicated:indicated (in millions):
|
| | | | | | | | |
| December 31, | | 2018 | | 2017 |
| Fuel and other raw materials | | $ | 300 |
| | $ | 284 |
|
| Spare parts and supplies | | 277 |
| | 278 |
|
| Total | | $ | 577 |
| | $ | 562 |
|
|
| | | | | | | | |
| December 31, | | 2015 | | 2014 |
| Fuel and other raw materials | | $ | 343 |
| | $ | 357 |
|
| Spare parts and supplies | | 332 |
| | 345 |
|
| Total | | $ | 675 |
| | $ | 702 |
|
3. PROPERTY, PLANT AND EQUIPMENT
The following table summarizes the components of the electric generation and distribution assets and other property, plant and equipment (in millions) with their estimated useful lives (in years). The amounts are stated net of all prior asset impairment losses recognized.
|
| | | | | | | | | |
| | | | December 31, |
| | Estimated Useful Life | 2018 | | 2017 |
| Electric generation and distribution facilities | 7-40 | | $ | 22,875 |
| | $ | 21,529 |
|
| Other buildings | 5-72 | | 1,651 |
| | 1,971 |
|
| Furniture, fixtures and equipment | 3-25 | | 310 |
| | 284 |
|
| Other | 5-44 | | 406 |
| | 335 |
|
| Total electric generation and distribution assets and other | | | 25,242 |
| | 24,119 |
|
| Accumulated depreciation | | | (8,227 | ) | | (7,942 | ) |
| Net electric generation and distribution assets and other | | | $ | 17,015 |
| | $ | 16,177 |
|
|
| | | | | | | | | |
| | | | December 31, |
| | Estimated Useful Life | 2015 | | 2014 |
| Electric generation and distribution facilities | 5 - 68 | | $ | 25,427 |
| | $ | 27,488 |
|
| Other buildings | 3 - 53 | | 1,868 |
| | 1,694 |
|
| Furniture, fixtures and equipment | 2 - 31 | | 305 |
| | 307 |
|
| Other | 1 - 50 | | 891 |
| | 970 |
|
| Total electric generation and distribution assets and other | | | 28,491 |
| | 30,459 |
|
| Accumulated depreciation | | | (9,449 | ) | | (9,962 | ) |
Net electric generation and distribution assets and other (1) | | | $ | 19,042 |
| | $ | 20,497 |
|
| |
(1)
| Net electric generation and distribution assets and other include unamortized internal-use software costs of $83 million and $115 million as of December 31, 2015 and 2014, respectively. |
The following table summarizes depreciation expense (including the amortization of assets recorded under capital leases),leases and the amortization of internal-use softwareasset retirement obligations) and interest capitalized during development and construction on qualifying assets for the periods indicated (in millions):
|
| | | | | | | | | | | | |
| Year Ended December 31, | | 2015 | | 2014 | | 2013 |
| Depreciation expense (including amortization of assets recorded under capital leases) | | $ | 1,104 |
| | $ | 1,204 |
| | $ | 1,193 |
|
| Amortization of internal-use software | | 29 |
| | 33 |
| | 36 |
|
| Interest capitalized during development and construction | | 90 |
| | 120 |
| | 84 |
|
|
| | | | | | | | | | | | |
| Years Ended December 31, | | 2018 | | 2017 | | 2016 |
| Depreciation expense | | $ | 960 |
| | $ | 1,005 |
| | $ | 1,002 |
|
| Interest capitalized during development and construction | | 199 |
| | 139 |
| | 118 |
|
Property, plant and equipment, net of accumulated depreciation, of $12$11 billion and $15$10 billion was mortgaged, pledged or subject to liens as of December 31, 20152018 and 2014, respectively.2017, respectively, including assets classified as held-for-sale.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
The following table summarizes regulated and non-regulated generation and distribution property, plant and equipment and accumulated depreciation in millions as of the periods indicated:dates indicated (in millions):
| | | December 31, | | 2015 | | 2014 | | 2018 | | 2017 |
| Regulated generation, distribution assets and other, gross | | $ | 11,818 |
| | $ | 13,103 |
| | $ | 8,959 |
| | $ | 8,093 |
|
| Regulated accumulated depreciation | | (4,351 | ) | | (4,841 | ) | | (3,504 | ) | | (3,357 | ) |
| Regulated generation, distribution assets and other, net | | 7,467 |
| | 8,262 |
| | 5,455 |
| | 4,736 |
|
| Non-regulated generation, distribution assets and other, gross | | 16,673 |
| | 17,356 |
| | 16,283 |
| | 16,026 |
|
| Non-regulated accumulated depreciation | | (5,098 | ) | | (5,121 | ) | | (4,723 | ) | | (4,585 | ) |
| Non-regulated generation, distribution assets and other, net | | 11,575 |
| | 12,235 |
| | 11,560 |
| | 11,441 |
|
| Net electric generation, distribution assets and other | | $ | 19,042 |
| | $ | 20,497 |
| | $ | 17,015 |
| | $ | 16,177 |
|
The nextfollowing table presents amounts recognized related to asset retirement obligations in millions for the periods indicated:indicated (in millions):
|
| | | | | | | | |
| | | 2015 | | 2014 |
| Balance at January 1 | | $ | 209 |
| | $ | 142 |
|
| Additional liabilities incurred | | 43 |
| | 51 |
|
| Liabilities settled | | (6 | ) | | (11 | ) |
| Accretion expense | | 13 |
| | 12 |
|
| Change in estimated cash flows | | (7 | ) | | 15 |
|
| Other | | (5 | ) | | — |
|
| Balance at December 31 | | $ | 247 |
| | $ | 209 |
|
|
| | | | | | | | |
| | | 2018 | | 2017 |
| Balance at January 1 | | $ | 368 |
| | $ | 357 |
|
| Additional liabilities incurred | | 19 |
| | 1 |
|
| Liabilities settled | | (14 | ) | | (21 | ) |
| Accretion expense | | 18 |
| | 16 |
|
| Change in estimated cash flows | | 24 |
| | 25 |
|
| Other | | — |
| | (10 | ) |
| Balance at December 31 | | $ | 415 |
| | $ | 368 |
|
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
The Company's asset retirement obligations covered by the relevant guidance primarily include active ash landfills, water treatment basins and the removal or dismantlement of certain plants and equipment. ThereThe $24 million increase in estimated cash flows in 2018 is primarily due to an increase of $55 million in estimated ash pond closure costs and revised closure dates associated with an EPA rule regulating CCR at IPL and an increase in coal pile remediation costs at DPL. These were $2partially offset by a decrease of $32 million of legally restricted assets for the year ended December 31, 2015due to reductions in estimated closure costs associated with ash ponds and none for the year ended December 31, 2014 for purposes of settling asset retirement obligations.
Ownership of Certain Coal-Fired Facilities
DP&L has undivided ownership interestslandfills at DPL resulting in five coal-fired generation facilities jointly owned with other utilities. DP&L's share of the operating costs of such facilities is included in a reduction to Cost of Sales in on the Consolidated Statements of Operations and its shareOperations.
The Company used the cost approach to determine the fair value of investment in the facilities is included in Property, Plant and Equipment inARO liabilities, which was estimated by discounting expected cash outflows to their present value using market based rates at the Consolidated Balance Sheets. DP&L's undivided ownership interest in such facilities at December 31, 2015 isinitial recording of the liabilities. Cash outflows were based on the approximate future disposal costs as follows:determined by market information, historical information or other management estimates. These inputs to the fair value of the ARO liabilities are considered Level 3 inputs under the fair value hierarchy.
|
| | | | | | | | | | | | | | |
| | DP&L Share | | DP&L Investment |
| | Ownership | | Gross Plant In Service | | Accumulated Depreciation | | Construction Work In Process |
| Production units: | | | ($ in millions) |
| Conesville Unit 4 | 17 | % | | $ | 26 |
| | $ | 4 |
| | $ | 1 |
|
| Killen Station | 67 | % | | 342 |
| | 29 |
| | 2 |
|
| Miami Fort Units 7 and 8 | 36 | % | | 219 |
| | 32 |
| | 6 |
|
| Stuart Station | 35 | % | | 236 |
| | 19 |
| | 18 |
|
| Zimmer Station | 28 | % | | 188 |
| | 44 |
| | 12 |
|
| Transmission | various |
| | 43 |
| | 8 |
| | — |
|
| Total | | | $ | 1,054 |
| | $ | 136 |
| | $ | 39 |
|
4. FAIR VALUE
The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The estimated fair values of the Company's assets and liabilities have been determined using available market information. By virtue ofBecause these amounts beingare estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Valuation Techniques —The fair value measurement accounting guidance describes three main approaches to measuring the fair value of assets and liabilities: (1) market approach, (2) income approach and (3) cost approach. The market approach uses prices and other relevant information generated from market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future amounts to a single present value amount. The measurement is based on current market expectations of the return on those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company measures its investments and derivatives at fair value on a recurring basis. Additionally, in connection with annual or event-driven impairment evaluations, certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis. These include long-lived tangible assets (i.e., property, plant and equipment), goodwill and intangible assets (e.g., sales concessions, land use rights and water rights, etc.). In general, the Company determines the fair value of investments and derivatives using the market approach and the income approach, respectively. In the nonrecurring measurements of nonfinancial assets and liabilities, all three approaches are considered; however, the value estimated under the income approach is often the most representative of fair value.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Investments — The Company's investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are either measured at fair value primarily using quoted market prices which are considered Level 1 measurements in the fair value hierarchy.or based on comparisons to market data obtained for similar assets. Debt securities primarily consist of unsecured debentures and certificates of deposit and government debt securities held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to London Inter Bank Offered Rate, or LIBOR, a benchmarkmarket interest rate widely used by banks in the interbank lending market) or Selic (overnight borrowing rate) rates in Brazil. For the equityDebt securities which are not considered Level 1 measurements and for the debt securities,measured at fair value is determined frombased on comparisons to market data obtained for similar assets andassets.
Derivatives — Derivatives are considered Level 2 measurements in themeasured at fair value hierarchy.
Derivatives — Any Level 1 derivative instruments are exchange-traded commodity futures for which the pricing is observable in active markets, and as such, these are not expected to transfer to other levels. There have been no transfers between Level 1 and Level 2.
For all derivatives, with the exception of any classified as Level 1,using quoted market prices or the income approach is used, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach includeutilizing volatilities, spot and forward benchmark interest rates (such as LIBOR and Euro Inter Bank Offered Rate ("EURIBOR"))EURIBOR), foreign exchange rates, credit data, and commodity prices. Forward rates with the same tenorprices, as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published information provided from another source.applicable. When significant inputs are not observable, the Company uses relevant techniques to determine the inputs, such as regression analysis or prices for similarly traded instruments available in the market.
For derivatives for which there is a standard industry valuation model, the Company uses a third-party derivative accounting and valuation service provider that uses a standard model and observable inputs to estimate the fair value. For these derivatives, the Company performs analytical procedures and makes comparisons to other third-party information in order to assess the reasonableness of the fair value. For derivatives for which there is not a standard industry valuation model (such as PPAs and fuel supply agreements that are derivatives or include embedded derivatives), the Company has created internal valuation models to estimate the fair value, using observable data to the extent available. At each quarter-end, the models for the commodity and foreign currency-based derivatives are generally prepared and reviewed by employees who globally manage the respective commodity and foreign currency risks and are analytically reviewed independent of those employees.
Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR or EURIBOR). The Company then makes a credit valuation adjustment ("CVA") by further discounting the cash flows for nonperformance or credit risk based on the observable or estimated debt spread of the Company's subsidiary or its counterparty and the tenor of the respective derivative instrument. The CVA for potential future scenarios in which the derivative is in an asset is based on the counterparty's credit ratings, credit default swap spreads, and debt spreads, as available. The CVA for potential future scenarios in which the derivative is a liability is based on the Parent Company's or the subsidiary's current debt spread. In the absence of readily obtainable credit information, the Parent Company's or the subsidiary's estimated credit rating (based on applying a standard industry model to historical financial information and then considering other relevant information) and spreads of
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
comparably rated entities or the respective country's debt spreads are used as a proxy. All derivative instruments are analyzed individually and are subject to unique risk exposures.
The Company's methodology to fair value its derivatives is to start with any observable inputs; however, in certain instances the published forward rates or prices may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable inputs, such as proxy commodity prices or historical settlements to forecast forward prices. Specifically, where there is limited forward curve data with respect to foreign exchange contracts, beyond the traded points, the Company utilizes the purchasing power parityinterest rate differential approach to construct the remaining portion of the forward curve using relative inflation rates. In addition, in certain instances, there may not be market or market-corroborated data readily available, requiring the use of unobservable inputs.curve. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable requiring us to utilizethe use of proxy yield curves of similar credit quality.
To determine the fair value of a derivative, cash flows are discounted using the relevant spot benchmark interest rate. The Company then makes a credit valuation adjustment ("CVA"), as applicable, by further discounting the cash flows for nonperformance or credit risk based on the observable or estimated debt spread of the Company's subsidiary or its counterparty and the tenor of the respective derivative instrument. The CVA for potential future scenarios in which the derivative is in an asset position is based on the counterparty's credit ratings, credit default swap spreads, and debt spreads, as available. The CVA for potential future scenarios in which the derivative is in a liability position is based on the Parent Company's or the subsidiary's current debt spread. In the absence of readily obtainable credit information, the Parent Company's or the subsidiary's estimated credit rating (based on applying a standard industry model to historical financial information and then considering other relevant information) and spreads of comparably rated entities or the respective country's debt spreads are used as a proxy. All derivative instruments are analyzed individually and are subject to unique risk exposures.
The fair value hierarchy of an asset or a liability is based on the level of significance of the input assumptions. An input assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are classified as Level 3 when the use of unobservable inputs is significant. When the use of unobservable inputs is insignificant, assets and liabilities are classified as Level 2. Transfers between Level 3 and Level 2 are determined as of the end of the reporting period and result from changes in significance of unobservable inputs used to calculate the CVA.
Debt — Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated differently based upon interest rates and other features of the type of loan. In general, the carrying amount of variable rate debt is a close approximation of its fair value. For fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow ("DCF") analyses. In the DCF analysis, the discount rate is based on the credit rating of the individual debt instruments, if available, or the credit rating of the subsidiary. If the subsidiary's credit rating is not available, a synthetic credit rating is determined using certain key metrics, including cash flow ratios and interest coverage, as well as other industry-specific factors. For subsidiaries located outside the U.S., in the event that the country rating is lower than the credit rating previously determined, the country rating is used for purposes of the DCF analysis. The fair value of recourse and non-recourse debt excludes accrued interest at the valuation date. The fair value was determined using available market information as of December 31, 2015.2018. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to December 31, 2015.2018.
Nonrecurring Measurements measurements —For nonrecurring measurements derived using the income approach, fair value is generally determined using valuation models based on the principles of DCF. The income approach is most often used in the impairment evaluation of long-lived tangible assets, equity method investments, goodwill, and intangible assets. The Company uses its internally developed DCF valuation models as the primary means to determine nonrecurring fair value measurements though other valuation approaches prescribed under the fair value measurement accounting guidance are also considered. Depending on the complexity of a valuation, an independent valuation firm may be engaged to assist management in the valuation process. A few examples of input assumptions to such valuations include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates and power and commodity prices. Whenever possible, the Company attempts to obtain market observable data to develop input assumptions. Where the use of market observable data is limited or not available for certain input assumptions, the Company develops its own estimates using a variety of techniques such as regression analysis and extrapolations. Depending on the complexity of a valuation, an independent valuation firm may be engaged to assist management in the valuation process.
For nonrecurring measurements derived using the market approach, recent market transactions involving the sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
identify sale transactions of identical or similar assets. This approach is used in impairment evaluations of certain intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.
For nonrecurring measurements derived using the cost approach, fair value is typically based upon a replacement cost approach. Under this approach, the depreciated replacement cost of assets is derived by first estimating the current replacement cost of assets and then applying the remaining useful life percentages to such costs. Further adjustments for economic and functional obsolescence are made to the depreciated replacement cost. This approach involves a considerable amount of judgment, which is why its use is limited to the measurement of long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach.
Fair Value Considerations — In determining fair value, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk of the counterparty and the risk of the Company's or its counterparty's nonperformance. The conditions and criteria used to assess these factors are:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
Sources of market assumptions — The Company derives most of its market assumptions from market efficient data sources (e.g., Bloomberg and Reuters). To determine fair value, where market data is not readily available, management uses comparable market sources and empirical evidence to develop its own estimates of market assumptions.
Market liquidity — The Company evaluates market liquidity based on whether the financial or physical instrument, or the underlying asset, is traded in an active or inactive market. An active market exists if the prices are fully transparent to market participants, can be measured by market bid and ask quotes, the market has a relatively large proportion of trading volume as compared to the Company's current trading volume and the market has a significant number of market participants that will allow the market to rapidly absorb the quantity of assets traded without significantly affecting the market price. Another factor the Company considers when determining whether a market is active or inactive is the presence of government or regulatory controls over pricing that could make it difficult to establish a market-based price when entering into a transaction.
Nonperformance risk — Nonperformance risk refers to the risk that an obligation will not be fulfilled and affects the value at which a liability is transferred or an asset is sold. Nonperformance risk includes, but may not be limited to, the Company or its counterparty's credit and settlement risk. Nonperformance risk adjustments are dependent on credit spreads, letters of credit, collateral, other arrangements available and the nature of master netting arrangements. The Company and its subsidiaries are partiesis party to various interest rate swaps and options; foreign currency options and forwards; and derivatives and embedded derivatives, which subject the Company to nonperformance risk. The financial and physical instruments held at the subsidiary level are generally non-recourse to the Parent Company.
Nonperformance risk on the investments held by the Company is incorporated in the fair value derived from quoted market data to mark the investments to fair value.
Recurring Measurements
— The following table presents, by level within the fair value hierarchy, as described in Note 1—General and Summary of Significant Accounting Policies, the Company's financial assets and liabilities (in millions) that were measured at fair value on a recurring basis as of the dates indicated (in millions). For the Company's investments in marketable debt and equity securities, the security classes presented were determined based on the nature and risk of the security and are consistent with how the Company manages, monitors and measures its marketable securities:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2018 | | December 31, 2017 |
| | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | |
| DEBT SECURITIES: | | | | | | | | | | | | | | | | |
| Available-for-sale: | | | | | | | | | | | | | | | | |
| Unsecured debentures | | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 207 |
| | $ | — |
| | $ | 207 |
|
| Certificates of deposit | | — |
| | 243 |
| | — |
| | 243 |
| | — |
| | 153 |
| | — |
| | 153 |
|
| Total debt securities | | — |
| | 248 |
| | — |
| | 248 |
| | — |
| | 360 |
| | — |
| | 360 |
|
| EQUITY SECURITIES: | | | | | | | | | | | | | | | | |
| Mutual funds | | 19 |
| | 49 |
| | — |
| | 68 |
| | 20 |
| | 52 |
| | — |
| | 72 |
|
| Total equity securities | | 19 |
| | 49 |
| | — |
| | 68 |
| | 20 |
| | 52 |
| | — |
| | 72 |
|
| DERIVATIVES: | | | | | | | | | | | | | | | | |
| Interest rate derivatives | | — |
| | 28 |
| | 1 |
| | 29 |
| | — |
| | 15 |
| | — |
| | 15 |
|
| Cross-currency derivatives | | — |
| | 6 |
| | — |
| | 6 |
| | — |
| | 29 |
| | — |
| | 29 |
|
| Foreign currency derivatives | | — |
| | 18 |
| | 199 |
| | 217 |
| | — |
| | 29 |
| | 240 |
| | 269 |
|
| Commodity derivatives | | — |
| | 6 |
| | 4 |
| | 10 |
| | — |
| | 30 |
| | 5 |
| | 35 |
|
| Total derivatives — assets | | — |
| | 58 |
| | 204 |
| | 262 |
| | — |
| | 103 |
| | 245 |
| | 348 |
|
| TOTAL ASSETS | | $ | 19 |
| | $ | 355 |
| | $ | 204 |
| | $ | 578 |
| | $ | 20 |
| | $ | 515 |
| | $ | 245 |
| | $ | 780 |
|
| Liabilities | | | | | | | | | | | | | | | | |
| DERIVATIVES: | | | | | | | | | | | | | | | | |
| Interest rate derivatives | | $ | — |
| | $ | 67 |
| | $ | 141 |
| | $ | 208 |
| | $ | — |
| | $ | 111 |
| | $ | 151 |
| | $ | 262 |
|
| Cross-currency derivatives | | — |
| | 5 |
| | — |
| | 5 |
| | — |
| | 3 |
| | — |
| | 3 |
|
| Foreign currency derivatives | | — |
| | 41 |
| | — |
| | 41 |
| | — |
| | 30 |
| | — |
| | 30 |
|
| Commodity derivatives | | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | 19 |
| | 1 |
| | 20 |
|
| Total derivatives — liabilities | | — |
| | 116 |
| | 141 |
| | 257 |
| | — |
| | 163 |
| | 152 |
| | 315 |
|
| TOTAL LIABILITIES | | $ | — |
| | $ | 116 |
| | $ | 141 |
| | $ | 257 |
| | $ | — |
| | $ | 163 |
| | $ | 152 |
| | $ | 315 |
|
As of December 31, 2018, all AFS debt securities had stated maturities within one year. For the years ended December 31, 2018, 2017, and 2016, no other-than-temporary impairment of marketable securities were recognized in earnings or Other Comprehensive Income (Loss). Gains and losses on the sale of investments are determined using the specific-identification method. The following table presents gross proceeds from sale of AFS securities for the periods indicated:indicated (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2015 | | December 31, 2014 |
| | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | |
| AVAILABLE FOR SALE: | | | | | | | | | | | | | | | | |
Debt securities:(1) | | | | | | | | | | | | | | | | |
| Unsecured debentures | | $ | — |
| | $ | 327 |
| | $ | — |
| | $ | 327 |
| | $ | — |
| | $ | 501 |
| | $ | — |
| | $ | 501 |
|
| Certificates of deposit | | — |
| | 135 |
| | — |
| | 135 |
| | — |
| | 151 |
| | — |
| | 151 |
|
| Government debt securities | | — |
| | 28 |
| | — |
| | 28 |
| | — |
| | 57 |
| | — |
| | 57 |
|
| Subtotal | | — |
| | 490 |
| | — |
| | 490 |
| | — |
| | 709 |
| | — |
| | 709 |
|
| Equity securities: | | | | | | | | | | | | | | | | |
| Mutual funds | | — |
| | 15 |
| | — |
| | 15 |
| | — |
| | 25 |
| | — |
| | 25 |
|
| Subtotal | | — |
| | 15 |
| | — |
| | 15 |
| | — |
| | 25 |
| | — |
| | 25 |
|
| Total available for sale | | — |
| | 505 |
| | — |
| | 505 |
| | — |
| | 734 |
| | — |
| | 734 |
|
| TRADING: | | | | | | | | | | | | | | | | |
| Equity securities: | | | | | | | | | | | | | | | | |
| Mutual funds | | 15 |
| | — |
| | — |
| | 15 |
| | 15 |
| | — |
| | — |
| | 15 |
|
| Total trading | | 15 |
| | — |
| | — |
| | 15 |
| | 15 |
| | — |
| | — |
| | 15 |
|
| DERIVATIVES: | | | | | | | | | | | | | | | | |
| Foreign currency derivatives | | — |
| | 35 |
| | 292 |
| | 327 |
| | — |
| | 18 |
| | 218 |
| | 236 |
|
| Commodity derivatives | | — |
| | 41 |
| | 7 |
| | 48 |
| | — |
| | 37 |
| | 7 |
| | 44 |
|
| Total derivatives | | — |
| | 76 |
| | 299 |
| | 375 |
| | — |
| | 55 |
| | 225 |
| | 280 |
|
| TOTAL ASSETS | | $ | 15 |
| | $ | 581 |
| | $ | 299 |
| | $ | 895 |
| | $ | 15 |
| | $ | 789 |
| | $ | 225 |
| | $ | 1,029 |
|
| Liabilities | | | | | | | | | | | | | | | | |
| DERIVATIVES: | | | | | | | | | | | | | | | | |
| Interest rate derivatives | | $ | — |
| | $ | 54 |
| | $ | 304 |
| | $ | 358 |
| | $ | — |
| | $ | 206 |
| | $ | 210 |
| | $ | 416 |
|
| Cross currency derivatives | | — |
| | 43 |
| | — |
| | 43 |
| | — |
| | 29 |
| | — |
| | 29 |
|
| Foreign currency derivatives | | — |
| | 41 |
| | 15 |
| | 56 |
| | — |
| | 43 |
| | 9 |
| | 52 |
|
| Commodity derivatives | | — |
| | 29 |
| | 4 |
| | 33 |
| | — |
| | 16 |
| | 1 |
| | 17 |
|
| Total derivatives | | — |
| | 167 |
| | 323 |
| | 490 |
| | — |
| | 294 |
| | 220 |
| | 514 |
|
| TOTAL LIABILITIES | | $ | — |
| | $ | 167 |
| | $ | 323 |
| | $ | 490 |
| | $ | — |
| | $ | 294 |
| | $ | 220 |
| | $ | 514 |
|
|
| | | | | | | | | | | | |
| Year Ended December 31, | | 2018 | | 2017 | | 2016 |
Gross proceeds from sale of AFS securities (1) | | $ | 1,403 |
| | $ | 1,398 |
| | $ | 1,726 |
|
_____________________________
| |
(1) | Amortized cost approximated fair valueProceeds include $119 million of non-cash proceeds from non-convertible debentures at December 31, 2015 and 2014.Guaimbê Solar Complex. See Note 24—Acquisitions for further information. |
Any Level 1 derivative instruments are exchange-traded commodity futures for which the pricing is observable in active markets, and as such, these are not expected to transfer to other levels. There have been no transfers between Level 1 and Level 2.
The following tables present a reconciliation of net derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 20152018 and 2014 (presented2017 presented net by type of derivative in millions).derivative. Transfers between Level 3 and Level 2 are determined as of the end of the reporting period and principally result from changes in the significance of unobservable inputs used to calculate the credit valuation adjustment.adjustment (in millions).
|
| | | | | | | | | | | | | | | |
| Year Ended December 31, 2018 | Interest Rate | | Foreign Currency | | Commodity | | Total |
| Balance at January 1 | $ | (151 | ) | | $ | 240 |
| | $ | 4 |
| | $ | 93 |
|
| Total realized and unrealized gains (losses): | | | | | | | |
| Included in earnings | 22 |
| | (14 | ) | | (1 | ) | | 7 |
|
| Included in other comprehensive income — derivative activity | (8 | ) | | — |
| | — |
| | (8 | ) |
| Included in regulatory (assets) liabilities | — |
| | — |
| | 5 |
| | 5 |
|
| Settlements | 14 |
| | (27 | ) | | (4 | ) | | (17 | ) |
| Transfers of assets/(liabilities), net into Level 3 | (8 | ) | | — |
| | — |
| | (8 | ) |
| Transfers of (assets)/liabilities, net out of Level 3 | (9 | ) | | — |
| | — |
| | (9 | ) |
| Balance at December 31 | $ | (140 | ) | | $ | 199 |
| | $ | 4 |
| | $ | 63 |
|
| Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period | $ | 29 |
| | $ | (41 | ) | | $ | (1 | ) | | $ | (13 | ) |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 2013
|
| | | | | | | | | | | | | | | |
| Year Ended December 31, 2015 | Interest Rate | | Foreign Currency | | Commodity | | Total |
| Balance at January 1 | $ | (210 | ) | | $ | 209 |
| | $ | 6 |
| | $ | 5 |
|
| Total gains (losses) (realized and unrealized): | | | | | | | |
| Included in earnings | (1 | ) | | 198 |
| | (1 | ) | | 196 |
|
| Included in other comprehensive income - derivative activity | (31 | ) | | — |
| | — |
| | (31 | ) |
| Included in other comprehensive income - foreign currency translation activity | 9 |
| | (103 | ) | | — |
| | (94 | ) |
| Included in regulatory (assets) liabilities | — |
| | — |
| | (18 | ) | | (18 | ) |
| Settlements | 24 |
| | (7 | ) | | 16 |
| | 33 |
|
| Transfers of assets (liabilities) into Level 3 | (95 | ) | | (1 | ) | | — |
| | (96 | ) |
| Transfers of (assets) liabilities out of Level 3 | — |
| | (19 | ) | | — |
| | (19 | ) |
| Balance at December 31 | $ | (304 | ) | | $ | 277 |
| | $ | 3 |
| | $ | (24 | ) |
| Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period | $ | — |
| | $ | 187 |
| | $ | (1 | ) | | $ | 186 |
|
|
| | | | | | | | | | | | | | | |
| Year Ended December 31, 2017 | Interest Rate | | Foreign Currency | | Commodity | | Total |
| Balance at January 1 | $ | (179 | ) | | $ | 255 |
| | $ | 5 |
| | $ | 81 |
|
| Total realized and unrealized gains (losses): | | | | | | | |
| Included in earnings | (1 | ) | | 21 |
| | 1 |
| | 21 |
|
| Included in other comprehensive income — derivative activity | (23 | ) | | — |
| | — |
| | (23 | ) |
| Included in regulatory (assets) liabilities | — |
| | — |
| | 10 |
| | 10 |
|
| Settlements | 36 |
| | (36 | ) | | (12 | ) | | (12 | ) |
| Transfers of assets/(liabilities), net into Level 3 | (4 | ) | | — |
| | — |
| | (4 | ) |
| Transfers of (assets)/liabilities, net out of Level 3 | 20 |
| | — |
| | — |
| | 20 |
|
| Balance at December 31 | $ | (151 | ) | | $ | 240 |
| | $ | 4 |
| | $ | 93 |
|
| Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period | $ | 7 |
| | $ | (15 | ) | | $ | 1 |
| | $ | (7 | ) |
|
| | | | | | | | | | | | | | | |
| Year Ended December 31, 2014 | Interest Rate | | Foreign Currency | | Commodity | | Total |
| Balance at January 1 | $ | (101 | ) | | $ | 93 |
| | $ | 4 |
| | $ | (4 | ) |
| Total gains (losses) (realized and unrealized): | | | | | | | |
| Included in earnings | 2 |
| | 134 |
| | 1 |
| | 137 |
|
| Included in other comprehensive income - derivative activity | (154 | ) | | (2 | ) | | — |
| | (156 | ) |
| Included in other comprehensive income - foreign currency translation activity | 13 |
| | (25 | ) | | — |
| | (12 | ) |
| Included in regulatory (assets) liabilities | — |
| | — |
| | 16 |
| | 16 |
|
| Settlements | 30 |
| | (4 | ) | | (15 | ) | | 11 |
|
| Transfers of assets (liabilities) into Level 3 | — |
| | 10 |
| | — |
| | 10 |
|
| Transfers of (assets) liabilities out of Level 3 | — |
| | 3 |
| | — |
| | 3 |
|
| Balance at December 31 | $ | (210 | ) | | $ | 209 |
| | $ | 6 |
| | $ | 5 |
|
| Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period | $ | 2 |
| | $ | 130 |
| | $ | (1 | ) | | $ | 131 |
|
The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) as of December 31, 20152018 (in millions, except range amounts):
|
| | | | | | | | |
| Type of Derivative | | Fair Value | | Unobservable Input | | Amount or Range (Weighted Average) |
| Interest rate | | $ | (140 | ) | | Subsidiaries’ credit spreads | | 1.8% - 5.3% (3.7%) |
| Foreign currency: | | | | | | |
| Argentine peso | | 199 |
| | Argentine peso to U.S. dollar currency exchange rate after one year | | 52.7 - 142.6 (96.1) |
| Commodity: | | | | | | |
| Other | | 4 |
| | | | |
| Total | | $ | 63 |
| | | | |
|
| | | | | | | | | |
| Type of Derivative | | Fair Value | | Unobservable Input | | Amount or Range (Weighted Average) |
| | | (in millions) | | | | |
| Interest rate | | $ | (304 | ) | | Subsidiaries’ credit spreads | | 2.88%-8.88% (5.42%) |
|
| Foreign currency: | | | | | | |
| Argentine Peso | | 291 |
| | Argentine Peso to U.S. Dollar currency exchange rate after 1 year | | 17.51 - 35.44 (26.05) |
|
| Euro | | (14 | ) | | Subsidiary's credit spread | | 8.88 | % |
| Commodity: | | | | | | |
| Other | | 3 |
| | | | |
| Total | | $ | (24 | ) | | | | |
Changes in the above significant unobservable inputs that lead to a significant and unusual impact to current-period earnings are disclosed to the Financial Audit Committee. For interest rate derivatives, and foreign currency derivatives, increases (decreases) in the estimates of the Company's own credit spreads would decrease (increase) the value of the derivatives in a liability position. For foreign currency derivatives, increases (decreases) in the estimate of the above exchange rate would increase (decrease) the value of the derivative.
Nonrecurring Measurements—
When evaluating impairment of goodwill, long-lived assets discontinued operations and held-for-sale businesses, and equity method investments, the Company measures fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to their then-latest available carrying amount. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Measurement Date | | Carrying Amount | | Fair Value | | Pretax Loss |
| Year Ended December 31, 2015 | | | Level 1 | | Level 2 | | Level 3 | |
| Assets | | | | | | | | | | | | |
Long-lived assets held and used:(1) | | | | | | | | | | | | |
| Kilroot | | 08/28/2015 | | $ | 191 |
| | $ | — |
| | $ | — |
| | $ | 70 |
| | $ | 121 |
|
| Buffalo Gap III | | 09/30/2015 | | 234 |
| | — |
| | — |
| | 118 |
| | 116 |
|
| U.K. Wind (Development Projects) | | 06/30/2015 | | 38 |
| | — |
| | 1 |
| | — |
| | 37 |
|
| Other | | Various | | 32 |
| | — |
| | 21 |
| | — |
| | 11 |
|
Equity method investments (3) | | | | | | | | | | | | |
| Solar Spain | | 02/09/2015 | | 29 |
| | — |
| | — |
| | 29 |
| | — |
|
Goodwill(5) | | | | | | | | | | | | |
| DP&L | | 10/01/2015 | | 317 |
| | — |
| | — |
| | — |
| | 317 |
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2018 | | Measurement Date | | Carrying Amount (1) | | Fair Value | | Pre-tax Loss |
| Assets | | | Level 1 | | Level 2 | | Level 3 | |
| Dispositions and held-for-sale businesses: | | | | | | | | | | | | |
| Shady Point | | 12/31/2018 | | $ | 211 |
| | $ | — |
| | $ | — |
| | $ | 30 |
| | $ | 157 |
|
Long-lived assets held and used: (2) | | | | | | | | | | | | |
| Nejapa | | 12/31/2018 | | 42 |
| | — |
| | — |
| | 5 |
| | 37 |
|
| Equity method investments: | | | | | | | | | | | | |
| Guacolda | | 10/01/2018 | | 354 |
| | — |
| | — |
| | 209 |
| | 144 |
|
| Elsta | | 09/30/2018 | | 19 |
| | — |
| | 16 |
| | — |
| | 3 |
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2017 | | Measurement Date | | Carrying Amount (1) | | Fair Value | | Pre-tax Loss |
| Assets | | | Level 1 | | Level 2 | | Level 3 | |
Long-lived assets held and used: (2) | | | | | | | | | | | | |
| Laurel Mountain | | 12/31/2017 | | $ | 154 |
| | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | 121 |
|
| Kilroot | | 12/31/2017 | | 69 |
| | — |
| | — |
| | 20 |
| | 37 |
|
| DPL | | 02/28/2017 | | 77 |
| | — |
| | — |
| | 11 |
| | 66 |
|
| Other | | Various | | 18 |
| | — |
| | — |
| | — |
| | 18 |
|
| Dispositions and held-for-sale businesses: | | | | | | | | | | | | |
| DPL Peaker Assets | | 12/31/2017 | | 346 |
| | — |
| | 237 |
| | — |
| | 109 |
|
Kazakhstan Hydroelectric (3) | | 06/30/2017 | | 190 |
| | — |
| | 92 |
| | — |
| | 92 |
|
| Kazakhstan CHPs | | 03/31/2017 | | 171 |
| | — |
| | 29 |
| | — |
| | 94 |
|
_____________________________
| |
(1) | Represents the carrying values at the dates of initial measurement, before fair value adjustment. |
| |
(3) | Per the Company's policy, pre-tax loss is limited to the impairment of long-lived assets. Any additional loss will be recognized on completion of the sale. Upon disposal of Kazakhstan HPPs, the Company incurred an additional pre-tax loss on disposal of $33 million. See Note 20—Asset Impairment Expense and Note 23—Held-for-Sale and Dispositions for further information. |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 2013
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Measurement Date | | Carrying Amount | | Fair Value | | Pretax Loss |
| Year Ended December 31, 2014 | | | Level 1 | | Level 2 | | Level 3 | |
| Assets | | | | | | | | | | | | |
Long-lived assets held and used:(1) | | | | | | | | | | | | |
| DP&L (East Bend) | | 03/31/2014 | | $ | 14 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | 12 |
|
| Ebute | | 06/30/2014 | | 99 |
| | — |
| | — |
| | 47 |
| | 52 |
|
| Ebute | | 09/30/2014 | | 51 |
| | — |
| | — |
| | 36 |
| | 15 |
|
| U.K. Wind (Newfield) | | 06/06/2014 | | 12 |
| | — |
| | — |
| | — |
| | 12 |
|
Discontinued operations:(2) | | | | | | | | | | | | |
| Cameroon businesses | | 03/31/2014 | | 372 |
| | — |
| | 334 |
| | — |
| | 38 |
|
Equity method investments (4) | | | | | | | | | | | | |
| Silver Ridge Power | | 06/30/2014 | | 315 |
| | — |
| | — |
| | 273 |
| | 42 |
|
| Entek | | 09/25/2014 | | 211 |
| | — |
| | 125 |
| | — |
| | 86 |
|
Goodwill(5) | | | | | | | | | | | | |
| DPLER | | 02/28/2014 | | 136 |
| | — |
| | — |
| | — |
| | 136 |
|
| Buffalo Gap | | 03/31/2014 | | 28 |
| | — |
| | — |
| | — |
| | 28 |
|
_____________________________
| |
(1)
| See Note 21—Asset Impairment Expense for further information.
|
| |
(2)
| See Note 23—Discontinued Operations for further information. Fair value of long-lived assets held-for-sale is presented net of costs to sell.
|
| |
(3)
| See Note 8—Investments In and Advances to Affiliates for further information.
|
| |
(4)
| See Note 9—Other Non-Operating Expense for further information.
|
| |
(5)
| See Note 10—Goodwill and Other Intangible Assets for further information.
|
The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets held and equity method investmentsused measured on a nonrecurring basis during the year ended December 31, 20152018 (in millions, except range amounts):
|
| | | | | | | | | | | |
| December 31, 2018 | | Fair Value | | Valuation Technique | | Unobservable Input | | Range (Weighted Average) |
| Long-lived assets held and used: | | | | | | | | |
| Nejapa | | 5 |
| | Discounted cash flow | | Annual revenue growth | | -70% to -1% (-15%) |
|
| | | | | | | Pre-tax operating margin | | 37% to 82% (59%) |
|
| | | | | | | Weighted-average cost of capital | | 12 | % |
| Equity method invesments: | | | | | | | | |
| Guacolda | | 209 |
| | Discounted cash flow | | Annual dividend growth | | -70% to 467% (48%) |
|
| | | | | | | Weighted-average cost of equity | | 10 | % |
| Total | | $ | 214 |
| | | | | | |
|
| | | | | | | | | | |
| | | Fair Value | | Valuation Technique | | Unobservable Input | | Range (Weighted Average) |
| | | (in millions) | | | | | | ($ in millions) |
| Long-lived assets held and used: | | | | | | | | |
| Kilroot | | $ | 70 |
| | Discounted cash flow | | Annual revenue growth | | -88% to 6% (-7%) |
| | | | | | | Annual pretax operating margin | | -74% to 10% (0%) |
| | | | | | | Weighted Average Cost of Capital | | 6% |
| Buffalo Gap | | 118 |
| | Discounted cash flow | | Annual revenue growth | | -2% to 19% (3%) |
| | | | | | | Annual pretax operating margin | | -282% to 58% (24%) |
| | | | | | | Weighted Average Cost of Capital | | 9% |
| Equity method investment: | | | | | | | | |
| Solar Spain | | 29 |
| | Discounted cash flow | | Annual revenue growth | | -3% to 0% (0%) |
| | | | | | | Annual pretax operating margin | | -13% to 56% (24%) |
| | | | | | | Cost of equity | | 12% |
| Total | | $ | 217 |
| | | | | | |
Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets
The following table presents in millions the carrying amount, fair value and fair value hierarchy of the Company's financial assets and liabilities that are not measured at fair value in the Consolidated Balance Sheets as of December 31, 2015 and 2014,the periods indicated, but for which fair value is disclosed.disclosed (in millions).
|
| | | | | | | | | | | | | | | | | | | | |
| | | Carrying Amount | | Fair Value |
| | | Total | | Level 1 | | Level 2 | | Level 3 |
| December 31, 2015 | | | | | | | | | | |
| Assets | | | | | | | | | | |
Accounts receivable — noncurrent(1) | | $ | 270 |
| | $ | 342 |
| | $ | — |
| | $ | 20 |
| | $ | 322 |
|
| Liabilities | | | | | | | | | | |
| Non-recourse debt | | 15,792 |
| | 15,939 |
| | — |
| | 13,672 |
| | 2,267 |
|
| Recourse debt | | 5,015 |
| | 4,696 |
| | — |
| | 4,696 |
| | — |
|
| December 31, 2014 | | | | | | | | | | |
| Assets | | | | | | | | | | |
Accounts receivable — noncurrent(1) | | $ | 257 |
| | $ | 246 |
| | $ | — |
| | $ | — |
| | $ | 246 |
|
| Liabilities | | | | | | | | | | |
| Non-recourse debt | | 15,600 |
| | 16,008 |
| | — |
| | 12,538 |
| | 3,470 |
|
| Recourse debt | | 5,258 |
| | 5,552 |
| | — |
| | 5,552 |
| | — |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | December 31, 2018 |
| | | | Carrying Amount | | Fair Value |
| | | | Total | | Level 1 | | Level 2 | | Level 3 |
| Assets: | Accounts receivable — noncurrent (1) | | $ | 100 |
| | $ | 209 |
| | $ | — |
| | $ | — |
| | $ | 209 |
|
| Liabilities: | Non-recourse debt | | 15,645 |
| | 16,225 |
| | — |
| | 13,524 |
| | 2,701 |
|
| | Recourse debt | | 3,655 |
| | 3,621 |
| | — |
| | 3,621 |
| | — |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | December 31, 2017 |
| | | | Carrying Amount | | Fair Value |
| | | | Total | | Level 1 | | Level 2 | | Level 3 |
| Assets: | Accounts receivable — noncurrent (1) | | $ | 163 |
| | $ | 217 |
| | $ | — |
| | $ | 6 |
| | $ | 211 |
|
| Liabilities: | Non-recourse debt | | 15,340 |
| | 15,890 |
| | — |
| | 13,350 |
| | 2,540 |
|
| | Recourse debt | | 4,630 |
| | 4,920 |
| | — |
| | 4,920 |
| | — |
|
_____________________________
| |
(1) | These accounts receivable principallyamounts primarily relate to amounts due from CAMMESA, the administrator of the wholesale electricity market in Argentina, and are included in NoncurrentOther noncurrent assets — Otherin the accompanying Consolidated Balance Sheets. The fair value and carrying amount of these accounts receivable excludes value-added taxreceivables exclude VAT of $27$16 million and $36$31 million atas of December 31, 20152018 and 2014,2017, respectively. |
5. INVESTMENTS IN MARKETABLE SECURITIES
The Company's investments in marketable debt and equity securities as of December 31, 2015 and 2014 by security class and by level within the fair value hierarchy have been disclosed in Note 4—Fair Value. The security classes are determined based on the nature and risk of a security and are consistent with how the Company manages, monitors and measures its marketable securities. As of December 31, 2015, $462 million of available-for-sale ("AFS") debt securities had stated maturities within one year and $28 million had stated maturities between one and two years. Gains and losses on the sale of investments are determined using the specific-identification method. For the years ended December 31, 2015, 2014, and 2013, pretax realized gains and losses related to AFS and trading securities were $1 million or less, unrealized gains and losses on AFS securities were less than $1 million, and there were no other-than-temporary impairment of marketable securities recognized in earnings or OCI. The following table summarizes the gross proceeds from sale of AFS securities in millions for the years ended December 31, 2015, 2014, and 2013:
|
| | | | | | | | | | | | |
| | | 2015 | | 2014 | | 2013 |
| Gross proceeds from sales of AFS securities | | $ | 4,902 |
| | $ | 4,569 |
| | $ | 4,406 |
|
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Volume of Activity
— The following tables present,table presents the Company's maximum notional (in millions) over the remaining contractual period by type of derivative the Company's outstanding notional under its derivatives and the weighted-average remaining term as of December 31, 20152018, regardless of whether the derivative instrumentsthey are in qualifying cash flow hedging relationships:relationships, and the dates through which the maturities for each type of derivative range:
|
| | | | | | |
| Derivatives | | Maximum Notional Translated to USD | | Latest Maturity |
| Interest Rate (LIBOR and EURIBOR) | | $ | 4,584 |
| | 2044 |
| Cross-currency Swaps (Chilean Unidad de Fomento and Chilean peso) | | 344 |
| | 2029 |
| Foreign Currency: | | | | |
| Argentine peso | | 68 |
| | 2026 |
| Chilean peso | | 270 |
| | 2021 |
| Colombian peso | | 117 |
| | 2021 |
| Brazilian real | | 23 |
| | 2019 |
| Others, primarily with weighted average remaining maturities of a year or less | | 112 |
| | 2021 |
|
| | | | | | | | | | | | | | | | | | | |
| | | Current | | Maximum | | | | |
Interest Rate and Cross Currency (1) | | Derivative Notional | | Derivative Notional Translated to USD | | Derivative Notional | | Derivative Notional Translated to USD | | Weighted-Average Remaining Term | | % of Debt Currently Hedged by Index (2) |
| | | (in millions) | | (in years) | | |
| Interest Rate Derivatives: | | | | | | | | | | | | |
| LIBOR (U.S. Dollar) | | 2,639 |
| | $ | 2,639 |
| | 2,872 |
| | $ | 2,872 |
| | 11 | | 48 | % |
| EURIBOR (Euro) | | 482 |
| | 524 |
| | 482 |
| | 524 |
| | 6 | | 83 | % |
| Cross Currency Swaps: | | | | | | | | | | | | |
| Chilean Unidad de Fomento | | 4 |
| | 159 |
| | 4 |
| | 159 |
| | 13 | | 76 | % |
_____________________________
| |
(1)
| The Company's interest rate derivative instruments primarily include accreting and amortizing notionals. The maximum derivative notional represents the largest notional at any point between December 31, 2015 and the maturity of the derivative instrument, which includes forward-starting derivative instruments. The interest rate and cross currency derivatives range in maturity through 2033 and 2028, respectively. |
| |
(2)
| The percentage of variable-rate debt currently hedged is based on the related index and excludes forecasted issuances of debt and variable-rate debt tied to other indices where the Company has no interest rate derivatives. |
|
| | | | | | | | | | |
| | | December 31, 2015 |
| Foreign Currency Derivatives | | Notional(1) | | Notional Translated to USD | | Weighted-Average Remaining Term(2) |
| | | (in millions) | | (in years) |
| Foreign Currency Derivatives | | | | | | |
| Argentine Peso | | $ | 2,321 |
| | $ | 178 |
| | 10 |
| Brazilian Real | | 80 |
| | 21 |
| | <1 |
| British Pound | | 22 |
| | 32 |
| | <1 |
| Chilean Peso | | 84,669 |
| | 119 |
| | <1 |
| Chilean Unidad de Fomento | | 9 |
| | 311 |
| | <1 |
| Colombian Peso | | 252,166 |
| | 80 |
| | <1 |
| Euro | | 32 |
| | 35 |
| | <1 |
| Kazakhstani Tenge | | 1,691 |
| | 5 |
| | 1 |
_____________________________
| |
(1)
| Represents contractual notionals. The notionals for options have not been probability adjusted, which generally would decrease them. |
| |
(2)
| Represents the remaining tenor of our foreign currency derivatives weighted by the corresponding notional. These derivatives matures through 2026. |
|
| | | | | |
| December 31, 2015 | | | | Weighted-Average |
| Commodity Derivatives | | Notional | | Remaining Term(1) |
| | | (in millions) | | (in years) |
| Power (MWh) | | 10 |
| | 3 |
_____________________________
| |
(1)
| Represents the remaining tenor of our commodity derivatives weighted by the corresponding volume. These derivatives range in maturity through 2018. |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
Accounting and Reporting
— Assets and Liabilities
— The following tables present in millionsthe fair value of assets and liabilities related to the Company's derivative instruments as of the periods indicated first by whether or not they are designated hedging instruments, then by whether they are current or noncurrent to the extent they are subject to master netting agreements or similar agreements (where the rights to set-off relate to settlement of amounts receivable and payable under those derivatives) and by balances no longer accounted for as derivatives.(in millions):
| | | | | December 31, 2015 | | December 31, 2014 | |
| | | Designated | | Not Designated | | Total | | Designated | | Not Designated | | Total | |
| Fair Value | | | December 31, 2018 | | December 31, 2017 |
| Assets | | | | | | | | | | | | | | Designated | | Not Designated | | Total | | Designated | | Not Designated | | Total |
| Interest rate derivatives | | | $ | 29 |
| | $ | — |
| | $ | 29 |
| | $ | 15 |
| | $ | — |
| | $ | 15 |
|
| Cross-currency derivatives | | | 6 |
| | — |
| | 6 |
| | 29 |
| | — |
| | 29 |
|
| Foreign currency derivatives | | $ | 8 |
| | $ | 319 |
| | $ | 327 |
| | $ | 6 |
| | $ | 230 |
| | $ | 236 |
| | — |
| | 217 |
| | 217 |
| | 8 |
| | 261 |
| | 269 |
|
| Commodity derivatives | | 30 |
| | 18 |
| | 48 |
| | 25 |
| | 19 |
| | 44 |
| | — |
| | 10 |
| | 10 |
| | 5 |
| | 30 |
| | 35 |
|
| Total assets | | $ | 38 |
| | $ | 337 |
| | $ | 375 |
| | $ | 31 |
| | $ | 249 |
| | $ | 280 |
| | $ | 35 |
| | $ | 227 |
| | $ | 262 |
| | $ | 57 |
| | $ | 291 |
| | $ | 348 |
|
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Interest rate derivatives | | $ | 358 |
| | $ | — |
| | $ | 358 |
| | $ | 416 |
| | $ | — |
| | $ | 416 |
| | $ | 205 |
| | $ | 3 |
| | $ | 208 |
| | $ | 125 |
| | $ | 137 |
| | $ | 262 |
|
| Cross currency derivatives | | 43 |
| | — |
| | 43 |
| | 29 |
| | — |
| | 29 |
| |
| Cross-currency derivatives | | | 5 |
| | — |
| | 5 |
| | 3 |
| | — |
| | 3 |
|
| Foreign currency derivatives | | 35 |
| | 21 |
| | 56 |
| | 38 |
| | 14 |
| | 52 |
| | 28 |
| | 13 |
| | 41 |
| | 1 |
| | 29 |
| | 30 |
|
| Commodity derivatives | | 12 |
| | 21 |
| | 33 |
| | 7 |
| | 10 |
| | 17 |
| | — |
| | 3 |
| | 3 |
| | 9 |
| | 11 |
| | 20 |
|
| Total liabilities | | $ | 448 |
| | $ | 42 |
| | $ | 490 |
| | $ | 490 |
| | $ | 24 |
| | $ | 514 |
| | $ | 238 |
| | $ | 19 |
| | $ | 257 |
| | $ | 138 |
| | $ | 177 |
| | $ | 315 |
|
|
| | | | | | | | | | | | | | | | |
| | | December 31, 2018 | | December 31, 2017 |
| Fair Value | | Assets | | Liabilities | | Assets | | Liabilities |
| Current | | $ | 75 |
| | $ | 51 |
| | $ | 84 |
| | $ | 211 |
|
| Noncurrent | | 187 |
| | 206 |
| | 264 |
| | 104 |
|
| Total | | $ | 262 |
| | $ | 257 |
| | $ | 348 |
| | $ | 315 |
|
As of December 31, 2018, all derivative instruments subject to credit risk-related contingent features were in an asset position.
|
| | | | | | | | | | | | | | | | |
| | | December 31, 2015 | | December 31, 2014 |
| | | Assets | | Liabilities | | Assets | | Liabilities |
| Current | | $ | 86 |
| | $ | 144 |
| | $ | 77 |
| | $ | 148 |
|
| Noncurrent | | 289 |
| | 346 |
| | 203 |
| | 366 |
|
| Total | | $ | 375 |
| | $ | 490 |
| | $ | 280 |
| | $ | 514 |
|
| Derivatives subject to master netting agreement or similar agreement: | | | | | | | | |
| Gross amounts recognized in the balance sheet | | $ | 57 |
| | $ | 467 |
| | $ | 53 |
| | $ | 507 |
|
| Gross amounts of derivative instruments not offset | | (18 | ) | | (18 | ) | | (10 | ) | | (10 | ) |
| Gross amounts of cash collateral received/pledged not offset | | — |
| | (38 | ) | | — |
| | (26 | ) |
| Net amount | | $ | 39 |
| | $ | 411 |
| | $ | 43 |
| | $ | 471 |
|
| Other balances that had been, but are no longer, accounted for as derivatives that are to be amortized to earnings over the remaining term of the associated PPA | | $ | 147 |
| | $ | 166 |
| | $ | 161 |
| | $ | 180 |
|
|
| | | | | | | | | | |
Credit Risk-Related Contingent Features (1) | | | | | | | | December 31, 2017 |
| Present value of liabilities subject to collateralization | | | | | | | | $ | 15 |
|
| Cash collateral held by third parties or in escrow | | | | | | | | 9 |
|
Effective Portion of Cash Flow Hedges _____________________________
| |
(1) | Based on the credit rating of certain subsidiaries |
Earnings and Other Comprehensive Income (Loss) — The following tables present (in millions)table presents the pretaxpre-tax gains (losses) recognized in AOCL and earnings related to the effective portion ofall derivative instruments in qualifying cash flow hedging relationships (including amounts that were reclassified from AOCL as interest expense related to interest rate derivative instruments that previously, but no longer, qualify for cash flow hedge accounting), as defined in the accounting standards for derivatives and hedging, for the periods indicated:indicated (in millions):
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| Effective portion of cash flow hedges | | | | | | |
| Gains (losses) recognized in AOCL | | | | | | |
| Interest rate derivatives | | $ | (16 | ) | | $ | (66 | ) | | $ | (35 | ) |
| Cross-currency derivatives | | (26 | ) | | 31 |
| | 21 |
|
| Foreign currency derivatives | | (52 | ) | | (5 | ) | | (4 | ) |
| Commodity derivatives | | — |
| | 18 |
| | 30 |
|
| Total | | $ | (94 | ) | | $ | (22 | ) | | $ | 12 |
|
| Gains (losses) reclassified from AOCL to earnings | | | | | | |
| Interest rate derivatives | | $ | (52 | ) | | $ | (82 | ) | | $ | (101 | ) |
| Cross-currency derivatives | | (43 | ) | | 34 |
| | 8 |
|
| Foreign currency derivatives | | (16 | ) | | (20 | ) | | (8 | ) |
| Commodity derivatives | | (6 | ) | | 17 |
| | 56 |
|
| Total | | $ | (117 | ) | | $ | (51 | ) | | $ | (45 | ) |
Loss reclassified from AOCL to earnings due to discontinuance of hedge accounting (1) | | $ | — |
| | $ | (13 | ) | | $ | — |
|
| Gain (losses) recognized in earnings related to | | | | | | |
| Ineffective portion of cash flow hedges | | $ | (7 | ) | | $ | 3 |
| | $ | (1 | ) |
| Not designated as hedging instruments: | | | | | | |
| Foreign currency derivatives | | 148 |
| | 1 |
| | 19 |
|
| Commodity derivatives and other | | 25 |
| | 14 |
| | (16 | ) |
| Total | | $ | 173 |
| | $ | 15 |
| | $ | 3 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Years Ended December 31, | | Gains (Losses) Recognized in AOCL | | Classification in Consolidated Statements of Operations | | Gains (Losses) Reclassified from AOCL into Earnings |
| Type of Derivative | | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 |
| Interest rate derivatives | | $ | (103 | ) | | $ | (421 | ) | | $ | 155 |
| | Interest expense | | $ | (108 | ) | | $ | (139 | ) | | $ | (127 | ) |
| | | | | | | | | Non-regulated cost of sales | | (2 | ) | | (2 | ) | | (5 | ) |
| | | | | | | | | Net equity in earnings of affiliates | | (2 | ) | | (3 | ) | | (6 | ) |
| | | | | | | | | Gain on sale of investments | | (4 | ) | | — |
| | (21 | ) |
| Cross currency derivatives | | (20 | ) | | (25 | ) | | (18 | ) | | Interest expense | | (4 | ) | | — |
| | (10 | ) |
| | | | | | | | | Foreign currency transaction gains (losses) | | (20 | ) | | (23 | ) | | (18 | ) |
| Foreign currency derivatives | | 10 |
| | (28 | ) | | — |
| | Foreign currency transaction gains (losses) | | 32 |
| | 14 |
| | 12 |
|
| Commodity derivatives | | 40 |
| | 44 |
| | 2 |
| | Non-regulated revenue | | 43 |
| | 30 |
| | (3 | ) |
| | | | | | | | | Non-regulated cost of sales | | (12 | ) | | (2 | ) | | (2 | ) |
| Total | | $ | (73 | ) | | $ | (430 | ) | | $ | 139 |
| | | | $ | (77 | ) | | $ | (125 | ) | | $ | (180 | ) |
| |
(1) | Cash flow hedge was discontinued because it was probable the forecasted transaction will not occur. |
The pretax accumulated other comprehensive income (loss)AOCL is expected to be recognized as an increase (decrease) todecrease pre-tax income from continuing operations before income taxes overfor the next twelve months as of December 31, 2015 is $(106) million for interest rate hedges, $(3) million for cross currency swaps, $12 million for foreign currency hedges, and $16 million for commodity and other hedges.
For the year ended December 31, 2014, pretax losses of $62019 by $59 million, net of noncontrolling interests were reclassified into earnings as a result of the discontinuance of a cash flow hedge because it was probable that the forecasted transaction would not occur by the end of the originally specified time period (as documented at the inception of the hedging relationship) or within an additional two-month time period thereafter. There was no such item for the years ended December 31, 2015 and 2013.primarily due to interest rate derivatives.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 2013
Ineffective Portion of Cash Flow Hedges — The following table presents (in millions) the pretax gains (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated:
|
| | | | | | | | | | | | | | |
| | | | | Gains (Losses) Recognized in Earnings |
| | | Classification in Consolidated Statements of Operations | | Years Ended December 31, |
| Type of Derivative | | | 2015 | | 2014 | | 2013 |
| Interest rate derivatives | | Interest expense | | $ | (4 | ) | | $ | — |
| | $ | 42 |
|
| | | Net equity in earnings of affiliates | | — |
| | (1 | ) | | 1 |
|
| Foreign currency derivatives | | Foreign currency transaction gains (losses) | | (3 | ) | | (2 | ) | | — |
|
| Cross currency derivatives | | Interest expense | | 1 |
| | (1 | ) | | — |
|
| Total | | | | $ | (6 | ) | | $ | (4 | ) | | $ | 43 |
|
Not Designated for Hedge Accounting — The next table presents (in millions) the gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging, and amortization of balances that had been, but are no longer, accounted for as derivatives, for the periods indicated:
|
| | | | | | | | | | | | | | |
| | | | | Gains (Losses) Recognized in Earnings |
| | | Classification in Consolidated Statements of Operations | | Years Ended December 31, |
| Type of Derivative | | 2015 | | 2014 | | 2013 |
| Interest rate derivatives | | Interest expense | | $ | — |
| | $ | (3 | ) | | $ | (1 | ) |
| | | Net equity in earnings of affiliates | | — |
| | — |
| | (6 | ) |
| Foreign currency derivatives | | Foreign currency transaction gains (losses) | | 211 |
| | 146 |
| | 64 |
|
| | | Net equity in earnings of affiliates | | — |
| | (2 | ) | | (24 | ) |
| Commodity and other derivatives | | Non-regulated revenue | | (8 | ) | | 5 |
| | 11 |
|
| | | Non-regulated cost of sales | | (16 | ) | | (3 | ) | | 1 |
|
| | | Regulated cost of sales | | (5 | ) | | (6 | ) | | 2 |
|
| | | Income (loss) from operations of discontinued businesses | | — |
| | (7 | ) | | (18 | ) |
| | | Net gain (loss) from disposal and impairments of discontinued operations | | — |
| | 72 |
| | — |
|
| Total | | | | $ | 182 |
| | $ | 202 |
| | $ | 29 |
|
Credit Risk-Related Contingent Features
DP&L has certain over-the-counter commodity derivative contracts under master netting agreements that contain provisions that require DP&L to maintain an investment-grade issuer credit rating from credit rating agencies. Since DP&L's rating has fallen below investment grade, certain of the counterparties to the derivative contracts have requested immediate and ongoing full overnight collateralization of the mark-to-market loss (fair value excluding credit valuation adjustments), which was $28 million and $12 million as of December 31, 2015 and 2014, respectively, for all derivatives with credit risk-related contingent features. As of December 31, 2015 and 2014, DP&L had posted $8 million and $5 million, respectively, of cash collateral directly with third parties and in a broker margin account and DP&L held no cash collateral from counterparties to its derivative instruments that were in an asset position. After consideration of the netting of counterparty assets, DP&L could have been required to, but did not, provide additional collateral of $2 million and $1 million as of December 31, 2015 and 2014, respectively.
7.6. FINANCING RECEIVABLES
Financing receivables are defined as receivables that haveReceivables with contractual maturities of greater than one year. The Company hasyear are considered financing receivables, pursuantprimarily related to amended agreements or government resolutions that are due from certain Latin American governmental bodies, primarily in Argentina.CAMMESA. The following table below presents the breakdown of financing receivables in millions by country as of the periods indicated:dates indicated (in millions):
|
| | | | | | | | |
| December 31, | | 2018 | | 2017 |
| Argentina | | $ | 93 |
| | $ | 177 |
|
| Panama | | 14 |
| | — |
|
| Other | | 9 |
| | 17 |
|
| Total | | $ | 116 |
| | $ | 194 |
|
|
| | | | | | | | |
| December 31, | | 2015 | | 2014 |
| Argentina | | $ | 237 |
| | $ | 278 |
|
Cameroon (1) | | — |
| | 44 |
|
| United States | | 20 |
| | — |
|
| Brazil | | 39 |
| | 15 |
|
| Total long-term financing receivables | | $ | 296 |
| | $ | 337 |
|
_____________________________
| |
(1)
| Represents non-contingent consideration to be received in 2016 from the sale of the Cameroon businesses in 2014. Balance is classified as short-term as of December 31, 2015. See Note 23—Discontinued Operations.
|
Argentina — Collection of the principal and interest on these receivables is subject to various business risks and uncertainties, including, but not limited to, the completion andcontinued operation of power plants which generate cash for payments of these receivables, regulatory changes that could impact the timing and amount of collections, and economic conditions in Argentina. The Company monitors these risks, including the credit ratings of the Argentine government, on a quarterly basis to assess the collectability of these receivables. The Company accrues interest on these receivables once the recognition criteria have been met.if collectability is reasonably assured. The Company's collection estimates are based on assumptions that it believes to be reasonable, but are inherently uncertain. Actual future cash flows could differ from these estimates. The decrease in Argentina financing receivables was primarily due to planned collections and unfavorable FX impacts.
FONINVEMEM Agreements
—As a result of energy market reforms in 2004 and 2010, AES Argentina entered into three agreements with the Argentine government, referred to as the FONINVEMEM Agreements, to contribute a portion of their accounts receivable into a fund for financing the construction of combined cycle and gas-fired plants. These receivables accrue interest and are collected in monthly installments over 10 years once the related plant begins operations. In addition, AES Argentina receives an ownership interest in these newly built plants once the receivables have been fully repaid.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
FONINVEMEM I and II— The receivables under the first two FONINVEMEM Agreements have been actively collected since the related plants commenced operations in 2010. In assessing the collectability of the receivables under these agreements, the Company also considers how timely the collections have historically been made in accordance with the agreements.
FONINVEMEM III — The receivables related to the third FONINVEMEM Agreement will not be repaid until commercial operation of the related gas-fired plant has been achieved. In assessing the collectability of the receivables under this agreement, the Company also considers the extent to which significant milestones necessary to complete the plants have been achieved or are still probable.
The FONINVEMEM receivables are denominated in Argentine pesos, but indexed to U.S. Dollars,dollars, which represents a foreign currency derivative. Due to differences between spot rates, used to remeasure the receivables, and discounted forward rates, used to value the foreign currency derivative, these two items will not perfectly offset over the life of the receivable. Once settled, the foreign currency derivative will offset the accumulated unrealized foreign currency losses resulting from the devaluation of the FONINVEMEM receivable. As of December 31, 20152018 and 2014,2017, the amount of the foreign currency-related derivative assets associated with the FONINVEMEM financing receivables that were excluded from the table above had a fair value of $292$199 million and $208$240 million, respectively.
The receivables under the FONINVEMEM Agreements have been actively collected since the related plants commenced operations in 2010 and 2016. In assessing the collectability of the receivables under these agreements, the Company also considers historic collection evidence in accordance with the agreements.
Other Agreements
In 2013, Resolution No. 95/2013 ("Resolution 95") which developed a new energy regulatory framework that applies to all generation companies with certain exceptions became effective. The new regulatory framework remunerates fixed and variable costs plus a margin that will depend on the technology and fuel used to generate the electricity and the installed capacity— Other agreements primarily consist of each plant.
In the fourth quarter of 2014,resolutions passed by the Argentine government passed a resolution to contribute outstanding Resolution 95 receivables into a trust wherebyin which AES Argentina has committed to install additional capacity into the system. CAMMESA will finance the investment utilizing the outstanding receivables as a guarantee.
On July 10, 2015, the Argentine government passed Resolution No. 482/2015 ("Resolution 482") which updated the prices of Resolution 529/2014 retroactively to February 1, 2015, and created a new trust called FONINVEMEM 2015-2018 in order to investreceive compensation for investments in new generation plants.plants and technologies. The timing of collections depend on corresponding agreements and collectability of these receivables are assessed on an ongoing basis.
THE AES Argentina and certain Termoandes units will receive compensation under this program.CORPORATION
8.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
7. INVESTMENTS IN AND ADVANCES TO AFFILIATES
The following table summarizes the relevant effective equity ownership interest and carrying values for the Company's investments accounted for under the equity method as of the periods indicated.indicated:
|
| | | | | | | | | | | | | | | |
| December 31, | | | 2018 | | 2017 | | 2018 | | 2017 |
| Affiliate | Country | | Carrying Value (in millions) | | Ownership Interest % |
| sPower | United States | | $ | 515 |
| | $ | 508 |
| | 50 | % | | 50 | % |
OPGC (1) | India | | 293 |
| | 269 |
| | 49 | % | | 49 | % |
Guacolda (2) | Chile | | 209 |
| | 357 |
| | 33 | % | | 33 | % |
Other affiliates (3) | Various | | 97 |
| | 63 |
| | | | |
| Total | | | $ | 1,114 |
| | $ | 1,197 |
| | | | |
|
| | | | | | | | | | | | | | | |
| December 31, | | | 2015 | | 2014 | | 2015 | | 2014 |
| Affiliate | Country | | Carrying Value (in millions) | | Ownership Interest % |
| Solar Power PR | Puerto Rico | | $ | — |
| | $ | 2 |
| | — | % | | 50 | % |
Barry(1) | United Kingdom | | — |
| | — |
| | 100 | % | | 100 | % |
Elsta(1) | Netherlands | | 53 |
| | 54 |
| | 50 | % | | 50 | % |
Distributed Energy(1) | United States | | 17 |
| | — |
| | 94 | % | | — | % |
Guacolda(2) | Chile | | 344 |
| | 285 |
| | 33 | % | | 35 | % |
OPGC(3) | India | | 195 |
| | 194 |
| | 49 | % | | 49 | % |
| Other affiliates | Various | | 1 |
| | 2 |
| | | | |
| Total investments in and advances to affiliates | | | $ | 610 |
| | $ | 537 |
| | | | |
| |
(1) | Represent VIEsOPGC has one coal-fired project under development which is an expansion of our existing OPGC business. The project started construction in which the Company holds a variable interest butApril 2014 and is not the primary beneficiary.expected to begin operations in 2019. |
| |
(2) | The Company's ownership in Guacolda is held through AES Gener, a 67%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 33%. At December 31, 2014, AES owned 71% of AES Gener, resulting in an AES effective ownership in Guacolda of 35%. |
| |
(3) | OPGC has one coal-fired expansion project under development. The project started construction in April 2014Includes Fluence, Simple Energy, Bosforo, Elsta, Distributed Energy equity method investments, and is currently expected to begin operations in 2018.others. |
Guacolda — On September 1, 2015, AES Gener and Global Infrastructure Partners ("GIP") executed a restructuring of In October 2018, an other-than-temporary impairment was identified at Guacolda that increased Guacolda's tax basis in certain long-term assets and AES Gener's equity investment. This transaction was reflected within equity at the Guacolda level, but was not with or among the shareholders of AES. Accordingly, the AES proportion of the increased value in equity was recognized in net income. As a result, AES Gener recorded $66 million in net equity in earnings of affiliates for the year ended December 31, 2015, of which $46 million is attributable to The AES Corporation.
On April 11, 2014, AES Gener undertook a series of transactions, pursuant to which AES Gener acquired the interests that it did not previously own in Guacolda for $728 million and simultaneously sold the ownership interest to GIP for $730 million. The transaction provided GIP with substantive participating rights in Guacolda and,primarily as a result of increased renewable generation in Chile lowering energy prices, impacting management's ability to re-contract Guacolda's generation after expiration of existing PPAs. A calculation of the Company continues to account for itsfair value of Gener's investment in Guacolda usingwas required to evaluate whether there was a loss in the carrying value of the investment. Based on management's estimate of fair value of $209 million, the Company recognized an other-than-temporary impairment of $144 million in Other non-operating expense. The Guacolda equity method investment is reported in the South America SBU reportable segment.
Distributed Energy — In December 2018, Distributed Energy acquired the remaining equity interest in a partnership holding various solar projects for consideration of accounting. At no time during this$23 million. This transaction didresulted in a loss of $5 million, reported in Other expense in the Consolidated Statement of Operations. The projects, previously recorded as equity method investments, have been consolidated. See Note 24—Acquisitions for further discussion.
Simple Energy — In April 2018, the Company acquireinvested $35 million in Simple Energy, a non-controllingprovider of utility-branded marketplaces and omni-channel instant rebates. As the Company does not control Simple Energy, the investment is accounted for as an equity method investment and is reported as part of Corporate and Other.
Fluence — On January 1, 2018, Siemens and AES closed on the creation of the Fluence joint venture with each party holding a 50% ownership interest. The Company contributed $7 million in cash paidand $20 million in non-cash assets from the AES Advancion energy storage development business as consideration for the transaction, and received an equity interest in Fluence with a fair value of $50 million. See Note 23—Held-for-Sale and Dispositions for further discussion. Fluence is a global energy storage technology and services company. As the Company does not control Fluence, the investment is accounted for as an equity method investment. The Fluence equity method investment is reported as part of Corporate and Other.
sPower — In February 2017, the Company and Alberta Investment Management Corporation (“AIMCo”) entered into an agreement to acquire FTP Power LLC (“sPower”). In July 2017, AES closed on the acquisition of its 48% ownership interest in sPower for $461 million. In November 2017, AES acquired an additional 2% ownership interest in sPower for $19 million. As the Company does not control sPower, it is reflectedaccounted for as an equity method investment. The sPower portfolio includes solar and wind projects in Acquisitions, net of cash acquiredoperation, under construction, and in development located in the United States. The sPower equity method investment is reported in the US and Utilities SBU reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
and the cash proceeds from the sale of these ownership interests to GIP is reflected in Proceeds from the sale of businesses, net of cash sold on the Consolidated Statement of Cash Flows for the period ended December 31, 2014.
Distributed Energy — On February 18, 2015, the Company completed the acquisition of 100% of the common stock of Main Street Power Company, Inc., which has been renamed to Distributed Energy Inc. As part of this acquisition, the Company obtained additional investments accounted for under the equity method.
Silver Ridge Power — On July 1, 2014, the Puerto Rico solar business, Solar Power PR, LLC, was distributed by Silver Ridge Power, LLC ("SRP") to AES and Riverstone Holdings LLC and was accounted for as a direct equity method investment. On April 29, 2015, the Company purchased the remaining 50% of the common stock of Solar Power PR, LLC and now consolidates this entity. On July 2, 2014, the Company closed the sale of its 50% ownership interest in SRP for a purchase price of $179 million, excluding the Company's indirect ownership interests in SRP's solar generation businesses in Italy and Spain ("Solar Italy" and "Solar Spain," respectively). The buyer also had an option to purchase the Company's indirect 50% interest in the Italy solar generation business for an additional consideration of $42 million by August 2015. The buyer exercised its option to purchase Solar Italy on August 31, 2015, and the sale was completed on October 1, 2015.
In 2014, the sale of the Company's 50% ownership interest in SRP did not qualify as a sale for accounting purposes as the Company had continuing involvement in the business operations. As of July 2, 2014, the Company no longer retained an equity interest in SRP. As such, the then-remaining investment balance of $32 million related to Italy and Spain and the AOCL balance of $40 million were reclassified to Other noncurrent assets on the Consolidated Balance Sheets. As of December 31, 2014, the carrying value of these investments recorded in Other noncurrent assets was $64 million.
Solar Spain — On September 24, 2015, the Company completed the sale of Solar Spain, an equity method investment. Net proceeds from the sale transaction were $31 million and the Company recognized a pretax gain on sale of less than $1 million.
Upon the completion of the Solar Spain and Solar Italy sale transactions noted above, the Company ceased its involvement in SRP's business operations and accounted for these transactions as sales of real estate. Accordingly, as of December 31, 2015, the carrying value of these investments recorded in Other noncurrent assets was zero.
AES Barry Ltd. — The Company holds a 100% ownership interest in AES Barry Ltd. ("Barry"), a dormant entity in the U.K. that disposed of its generation and other operating assets. Due to a debt agreement, no material financial or operating decisions can be made without the banks' consent, and the Company does not control Barry. As of December 31, 20152018 and 2014,2017, other long-term liabilities included $49$43 million and $52$45 million related to this debt agreement.
Elsta — In 2014, long lived assets within Elsta were determined to not be recoverable and an impairment charge of approximately $82 million was recognized. The Company recognized its 50% share, or $41 million, through its proportion of the equity earnings in Elsta.
Entek — In September 2014, the Company executed an agreement, subject to the approval of the Company's Board of Directors, to sell its equity interest in AES Entek. Based on this agreement, during the third quarter of 2014, the Company determined there was an other-than-temporary decline in the fair value of its equity method investment in AES Entek and recognized a pretax impairment loss of $18 million in other non-operating expense. On October 13, 2014, the Company entered into a binding agreement to sell its 49.62% ownership interest in Entek for a purchase price of $125 million. This resulted in the recognition of an additional other-than-temporary impairment of $68 million due to the inclusion of the cumulative translation adjustment in the carrying value of the investment. For additional information see Note 9—Other Non-Operating Expense. The sale represents 100% of the Company's interest in assets in Turkey. On December 18, 2014, the transaction closed which resulted in a final loss on sale of $4 million. Entek does not meet the criteria to be reported as discontinued operations under ASU No. 2014-08, which was adopted by the Company on July 1, 2014. Accordingly, AES' proportion of Entek's results are reflected in the Consolidated Statements of Operations within continuing operations. Excluding the loss on sale, Entek's pretax loss attributable to AES was $9 million and $29 million for the years ended December 31, 2014 and 2013, respectively.
Summarized Financial Information
— The following tables summarize financial information of the Company's 50%-or-less-owned affiliates and majority-owned unconsolidated subsidiaries that are accounted for using the equity method in millions.(in millions):
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
| | | | 50%-or-less Owned Affiliates | | Majority-Owned Unconsolidated Subsidiaries | 50%-or-less Owned Affiliates | | Majority-Owned Unconsolidated Subsidiaries |
| Years ended December 31, | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Revenue | $ | 641 |
| | $ | 928 |
| | $ | 1,099 |
| | $ | 24 |
| | $ | 2 |
| | $ | 2 |
| $ | 962 |
| | $ | 762 |
| | $ | 586 |
| | $ | 40 |
| | $ | 16 |
| | $ | 23 |
|
| Operating margin | 152 |
| | 206 |
| | 295 |
| | 11 |
| | — |
| | — |
| 135 |
| | 165 |
| | 145 |
| | 3 |
| | 5 |
| | 9 |
|
| Net income (loss) | 210 |
| | 59 |
| | 53 |
| | 6 |
| | — |
| | — |
| 14 |
| | 72 |
| | 64 |
| | (3 | ) | | (15 | ) | | (2 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, | 2015 | | 2014 | | | | 2015 | | 2014 | | | 2018 | | 2017 | | | | 2018 | | 2017 | | |
| Current assets | $ | 376 |
| | $ | 450 |
| | | | $ | 20 |
| | $ | — |
| | | $ | 558 |
| | $ | 418 |
| | | | $ | 89 |
| | $ | 70 |
| | |
| Noncurrent assets | 2,132 |
| | 1,748 |
| | | | 211 |
| | 15 |
| | | 5,918 |
| | 5,372 |
| | | | 41 |
| | 102 |
| | |
| Current liabilities | 435 |
| | 299 |
| | | | 21 |
| | — |
| | | 546 |
| | 633 |
| | | | 35 |
| | 10 |
| | |
| Noncurrent liabilities | 1,044 |
| | 935 |
| | | | 153 |
| | 67 |
| | | 3,309 |
| | 2,629 |
| | | | 122 |
| | 147 |
| | |
| Noncontrolling interests | — |
| | 17 |
| | | | — |
| | — |
| | | |
| Stockholders' equity | 1,029 |
| | 947 |
| | | | 57 |
| | (52 | ) | | | 2,622 |
| | 2,527 |
| | | | (27 | ) | | 15 |
| | |
At December 31, 2015,2018, retained earnings included $244$236 million related to the undistributed earnings of the Company's 50%-or-less owned affiliates. Distributions received from these affiliates were $18$42 million, $28$69 million, and $6$24 million for the years ended December 31, 2015, 2014,2018, 2017, and 2013,2016, respectively. As of December 31, 2015,2018, the underlying equity in the net assets of our equity affiliates exceeded the aggregate carrying amount of our investments in equity affiliates exceeded the underlying equity in their net assets by $162$49 million.
9. OTHER NON-OPERATING EXPENSE
|
| | | | | | | |
| Years Ended December 31, | 2014 | | 2013 |
| | (in millions) |
| Entek | $ | 86 |
| | $ | — |
|
| Silver Ridge | 42 |
| | — |
|
| Elsta | — |
| | 129 |
|
| Total other non-operating expense | $ | 128 |
| | $ | 129 |
|
There was no other non-operating expense for the year ended December 31, 2015.
Entek — During 2014, the Company executed an agreement to sell its 49.62% interest in Entek, an investment accounted for under the equity method, for $125 million. Entek consists of natural gas and hydroelectric generation facilities, plus a coal-fired development project. The Company determined that there was an other-than-temporary decline in the fair value of its equity method investment in Entek and recognized pretax impairment expense of $86 million. The sale of the Company's interest in Entek closed on December 18, 2014. See Note 8—Investments in and Advances to Affiliates of this Form 10-K for further information.
Silver Ridge — During 2014, the Company determined that there was a decline in the fair value of its equity method investment in SRP that was other-than-temporary based on indications about the fair value of the projects in Italy and Spain that resulted from actual and proposed changes to their tariffs. Accordingly, the Company recognized pretax impairment expense of $42 million. The transaction related to our 50% ownership interest in SRP closed on July 2, 2014 for $179 million. See Note 8—Investments in and Advances to Affiliates of this Form 10-K for further information.
Elsta — During 2013, the Company identified an impairment indicator at Elsta, a combined cycle gas-fired plant in the Netherlands that is accounted for under the equity method, resulting from negative pricing indications noted during negotiations with its offtakers for an extension of the existing PPA. The Company recognized pretax impairment expense of $129 million by reducing the carrying value of $240 million to the estimated fair value of $111 million. The Company estimated fair value using probability-weighted outcomes which contemplated various scenarios involving the amendments to the existing PPA.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
10.8. GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill — The following table summarizes the changes in the carrying amount of goodwill by reportable segment for the years ended December 31, 20152018 and 20142017 (in millions):
|
| | | | | | | | | | | | | | | | | | | |
| | US and Utilities | | South America | | MCAC | | Eurasia | | Total |
| Balance as of December 31, 2017 | | | | | | | | | |
| Goodwill | $ | 2,786 |
| | $ | 868 |
| | $ | 16 |
| | $ | 122 |
| | $ | 3,792 |
|
| Accumulated impairment losses | (2,611 | ) | | — |
| | — |
| | (122 | ) | | (2,733 | ) |
| Net balance | 175 |
| | 868 |
| | 16 |
| | — |
| | 1,059 |
|
| Balance as of December 31, 2018 | | | | | | | | | |
| Goodwill | 2,786 |
| | 868 |
| | 16 |
| | 122 |
| | 3,792 |
|
| Accumulated impairment losses | (2,611 | ) | | — |
| | — |
| | (122 | ) | | (2,733 | ) |
| Net balance | $ | 175 |
| | $ | 868 |
| | $ | 16 |
| | $ | — |
| | $ | 1,059 |
|
Other Intangible Assets — The following table summarizes the balances comprising Other intangible assets in millions.the accompanying Consolidated Balance Sheets (in millions) as of the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | US | | Andes | | MCAC | | Europe | | Asia | | Total |
| Balance as of December 31, 2013 | | | | | | | | | | | |
| Goodwill | $ | 2,658 |
| | $ | 899 |
| | $ | 149 |
| | $ | 180 |
| | $ | 68 |
| | $ | 3,954 |
|
| Accumulated impairment losses | (2,152 | ) | | — |
| | — |
| | (180 | ) | | — |
| | (2,332 | ) |
| Net balance | 506 |
| | 899 |
| | 149 |
| | — |
| | 68 |
| | 1,622 |
|
| Impairment losses | (164 | ) | | — |
| | — |
| | — |
| | — |
| | (164 | ) |
| Balance as of December 31, 2014 | | | | | | | | | | | |
| Goodwill | 2,658 |
| | 899 |
| | 149 |
| | 122 |
| (1) | 68 |
| | 3,896 |
|
| Accumulated impairment losses | (2,316 | ) | | — |
| | — |
| | (122 | ) | | — |
| | (2,438 | ) |
| Net balance | 342 |
| | 899 |
| | 149 |
| | — |
| | 68 |
| | 1,458 |
|
| Impairment losses | (317 | ) | | — |
| | — |
| | — |
| | — |
| | (317 | ) |
| Goodwill acquired during the year | 16 |
| | — |
| | — |
| | — |
| | — |
| | 16 |
|
| Balance as of December 31, 2015 | | | | | | | | | | | |
| Goodwill | 2,674 |
| | 899 |
| | 149 |
| | 122 |
| | 68 |
| | 3,912 |
|
| Accumulated impairment losses | (2,633 | ) | | — |
| | — |
| | (122 | ) | | — |
| | (2,755 | ) |
| Net balance | $ | 41 |
| | $ | 899 |
| | $ | 149 |
| | $ | — |
| | $ | 68 |
| | $ | 1,157 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| | Gross Balance | | Accumulated Amortization | | Net Balance | | Gross Balance | | Accumulated Amortization | | Net Balance |
| Subject to Amortization | | | | |
|
| | | | | | |
| Internal-use software | $ | 467 |
| | $ | (344 | ) | | $ | 123 |
| | $ | 416 |
| | $ | (330 | ) | | $ | 86 |
|
| Contracts | 137 |
| | (24 | ) | | 113 |
| | 92 |
| | (21 | ) | | 71 |
|
| Project development rights | 93 |
| | (1 | ) | | 92 |
| | 57 |
| | (1 | ) | | 56 |
|
Contractual payment rights (1) | 57 |
| | (44 | ) | | 13 |
| | 65 |
| | (47 | ) | | 18 |
|
Emissions allowances (2) | 15 |
| | — |
| | 15 |
| | — |
| | — |
| | — |
|
Other (3) | 78 |
| | (44 | ) | | 34 |
| | 98 |
| | (42 | ) | | 56 |
|
| Subtotal | 847 |
| | (457 | ) | | 390 |
| | 728 |
| | (441 | ) | | 287 |
|
| Indefinite-Lived Intangible Assets | | | | | | | | | | | |
| Land use rights | 21 |
| | — |
| | 21 |
| | 45 |
| | — |
| | 45 |
|
| Water rights | 20 |
| | — |
| | 20 |
| | 20 |
| | — |
| | 20 |
|
| Other | 5 |
| | — |
| | 5 |
| | 14 |
| | — |
| | 14 |
|
| Subtotal | 46 |
| | — |
| | 46 |
| | 79 |
| | — |
| | 79 |
|
| Total | $ | 893 |
| | $ | (457 | ) | | $ | 436 |
| | $ | 807 |
| | $ | (441 | ) | | $ | 366 |
|
_____________________________
(1) Both the gross carrying amount and the accumulated impairment losses of the Europe segment have been reduced by $58 million with no impact on the net carrying amount for the segment. This relates to Ebute, which had fully impaired goodwill of $58 million and was sold in 2014.
DP&L — During the fourth quarter of 2015, the Company performed the annual goodwill impairment test at its DP&L reporting unit ("DP&L") and recognized a goodwill impairment expense of $317 million. The reporting unit failed Step 1 as its fair value was less than its carrying amount, which was primarily due to a decrease in forecasted dark spreads that were driven by decreases in projected forward power prices, and lower than expected revenues from a new Capacity Performance ("CP") product. The fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were forward commodity price curves, the amount of non-bypassable charges from the pending ESP, expected revenues from the new CP product, and planned environmental expenditures. In Step 2, goodwill was determined to have an implied negative fair value after the hypothetical purchase price allocation under the accounting guidance for business combinations; therefore, a full impairment of the remaining goodwill balance of $317 million was recognized. DP&L is reported in the US SBU reportable segment.
Main Street Power — During the first quarter of 2015, the Company completed the acquisition of 100% of the common stock of Main Street Power Company, Inc. The transaction included recognition of $16 million of Goodwill. See Note 25—Acquisitions for additional information.
Buffalo Gap — During the first quarter of 2014, the Company recognized an $18 million impairment of its goodwill at its Buffalo Gap reporting unit, which is comprised of three wind projects in Texas. During the fourth quarter of 2014, the Company performed the annual goodwill impairment test at its Buffalo Gap reporting unit. The reporting unit failed Step 1 and Step 2 was performed to measure the amount of goodwill impairment. In Step 2, after the hypothetical purchase price allocation under the relevant accounting guidance, the implied fair value of goodwill was negative. As a result, a full impairment of goodwill of $10 million was recognized. Buffalo Gap is reported in the US SBU reportable segment.
DPLER — During the first quarter of 2014, the Company performed an interim impairment test on the $136 million in goodwill at its DPLER reporting unit, a competitive retail marketer selling retail electricity to customers in Ohio and Illinois. The DPLER reporting unit was identified as being "at risk" during the fourth quarter of 2013. The impairment indicators arose based on market information available regarding actual and proposed sales of competitive retail marketers, which indicated a significant decline in valuations during the first quarter of 2014.
In Step 1 of the interim impairment test, the fair value of the reporting unit was determined to be less than its carrying amount under both the market approach and the income approach using a discounted cash flow valuation model. The significant assumptions included commodity price curves, estimated electricity to be demanded by its customers, changes in its customer base through attrition and expansion, discount rates, the assumed tax structure and the level of working capital required to run the business.
In Step 2 of the interim impairment test, the goodwill was determined to have an implied fair value of zero after the hypothetical purchase price allocation and the Company accordingly recognized a full impairment of the $136 million in goodwill at the DPLER reporting unit. DPLER is reported in the US SBU reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 2013
Other Intangible Assets — The following table summarizes the balances comprising other intangible assets in the accompanying Consolidated Balance Sheets (in millions) as of the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2015 | | December 31, 2014 |
| | Gross Balance | | Accumulated Amortization | | Net Balance | | Gross Balance | | Accumulated Amortization | | Net Balance |
| Subject to Amortization | | | | | | | | | | | |
Project development rights(1) | $ | 4 |
| | $ | (1 | ) | | $ | 3 |
| | $ | 28 |
| | $ | (1 | ) | | $ | 27 |
|
| Sales concessions | 71 |
| | (19 | ) | | 52 |
| | 86 |
| | (41 | ) | | 45 |
|
Contractual payment rights(2) | 66 |
| | (46 | ) | | 20 |
| | 69 |
| | (40 | ) | | 29 |
|
| Management rights | 24 |
| | (10 | ) | | 14 |
| | 33 |
| | (13 | ) | | 20 |
|
| Land use rights | 28 |
| | — |
| | 28 |
| | 25 |
| | — |
| | 25 |
|
| Contracts | 29 |
| | (12 | ) | | 17 |
| | 36 |
| | (19 | ) | | 17 |
|
Customer contracts and relationships (3) | 6 |
| | (6 | ) | | — |
| | 63 |
| | (39 | ) | | 24 |
|
Other(4) | 15 |
| | (3 | ) | | 12 |
| | 22 |
| | (5 | ) | | 17 |
|
| Subtotal | 243 |
| | (97 | ) | | 146 |
| | 362 |
| | (158 | ) | | 204 |
|
| Indefinite-Lived Intangible Assets | | | | | | | | | | | |
| Land use rights | 38 |
| | — |
| | 38 |
| | 37 |
| | — |
| | 37 |
|
| Water rights | 17 |
| | — |
| | 17 |
| | 20 |
| | — |
| | 20 |
|
| Other | 13 |
| | — |
| | 13 |
| | 20 |
| | — |
| | 20 |
|
| Subtotal | 68 |
| | — |
| | 68 |
| | 77 |
| | — |
| | 77 |
|
| Total | $ | 311 |
| | $ | (97 | ) | | $ | 214 |
| | $ | 439 |
| | $ | (158 | ) | | $ | 281 |
|
_____________________________
| |
(1) | 2014 balance includes U.K. Wind operations. In August 2014 these assets were sold, but did not meet the criteria to be reported as discontinued operations and their results are reflected within continuing operations. See Note 24—Dispositions and Held-for-Sale Businesses for further information.
|
| |
(2)
| Represent legal rights to receive system reliability payments from the regulator. |
| |
(3)(2)
| 2014 balance includes DPLER which is considered held-for-sale as of December 31, 2015. See Note 24—DispositionsAcquired or purchased emissions allowances are finite-lived intangible assets that are expensed when utilized and Held-for-Sale Businessesincluded in net income for further information.
the year. |
| |
(4)(3)
| Includes management rights, sales concessions, renewable energy certificates, emission allowancescredits and variousincentives, and other individually insignificant intangible assets noneassets. During the fourth quarter of which is individually significant.2018, the Company recognized an asset impairment of $23 million on gas extraction rights at Nejapa. See Note 20—Asset Impairment Expense for further information. |
The following tables summarize by category, other intangible assets acquired during the periodperiods indicated ($ in(in millions):
| | | | December 31, 2015 | |
| | Amount | | Subject to Amortization/Indefinite-Lived | | Weighted Average Amortization Period (in years) | | Amortization Method | |
| December 31, 2018 | | Amount | | Subject to Amortization/Indefinite-Lived | | Weighted Average Amortization Period (in years) | | Amortization Method |
| Internal-use software | | $ | 67 |
| | Subject to Amortization | | 6 | | Straight-line |
| Contracts | $ | 22 |
| | Subject to Amortization | | 5 | | Straight-line | 50 |
| | Subject to Amortization | | 24 | | Straight-line |
| Land-use rights | 13 |
| | Subject to Amortization | | N/A | | N/A | |
| Project development rights | | 35 |
| | Subject to Amortization | | 23 | | Straight-line |
| Emissions allowances | | 16 |
| | Subject to Amortization | | Various | | As utilized |
| Other | 5 |
| | Various | | N/A | | N/A | 11 |
| | Various | | N/A | | N/A |
| Total | $ | 40 |
| | $ | 179 |
| |
|
| | | | | | | | | |
| December 31, 2017 | Amount | | Subject to Amortization/Indefinite-Lived | | Weighted Average Amortization Period (in years) | | Amortization Method |
| Project Development Rights | $ | 53 |
| | Subject to Amortization | | 30 | | Straight-line |
| Contracts | 34 |
| | Subject to Amortization | | 25 | | Straight-line |
| Internal-use software | 17 |
| | Subject to Amortization | | 7 | | Straight-line |
| Other | 8 |
| | Various | | N/A | | N/A |
| Total | $ | 112 |
| | | | | | |
|
| | | | | | | | | |
| | December 31, 2014 |
| | Amount | | Subject to Amortization/ Indefinite-Lived | | Weighted Average Amortization Period (in years) | | Amortization Method |
| Renewable energy certificates | $ | 3 |
| | Indefinite | | N/A | | N/A |
| Land-use rights | 16 |
| | Subject to Amortization | | N/A | | N/A |
| Total | $ | 19 |
| | | | | | |
The following table summarizes the estimated amortization expense by intangible asset category for 20162019 through 2020:2023:
|
| | | | | | | | | | | | | | | | | | | |
| (in millions) | 2019 | | 2020 | | 2021 | | 2022 | | 2023 |
| Internal-use software | $ | 33 |
| | $ | 28 |
| | $ | 19 |
| | $ | 13 |
| | $ | 7 |
|
| Contracts | 4 |
| | 4 |
| | 4 |
| | 4 |
| | 4 |
|
| Other | 8 |
| | 8 |
| | 6 |
| | 6 |
| | 6 |
|
| Total | $ | 45 |
| | $ | 40 |
| | $ | 29 |
| | $ | 23 |
| | $ | 17 |
|
|
| | | | | | | | | | | | | | | | | | | |
| (in millions) | 2016 | | 2017 | | 2018 | | 2019 | | 2020 |
| Sales concessions | 7 |
| | 7 |
| | 7 |
| | 7 |
| | 7 |
|
| All other | 4 |
| | 4 |
| | 4 |
| | 3 |
| | 3 |
|
| Total | $ | 11 |
| | $ | 11 |
| | $ | 11 |
| | $ | 10 |
| | $ | 10 |
|
Intangible asset amortization expense was $25$47 million, $26$34 million and $29$37 million for the years ended December 31, 2015, 20142018, 2017 and 2013,2016, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
11.
9. REGULATORY ASSETS AND LIABILITIES
The Company has recorded regulatory assets and liabilities (in millions) that it expects to pass through to its customers in accordance with, and subject to, regulatory provisions as follows:
|
| | | | | | | | | |
| December 31, | 2015 | | 2014 | | Recovery/Refund Period |
| REGULATORY ASSETS | | | |
| Current regulatory assets: | | | | | |
Brazil tariff recoveries:(1) | | | | | |
| Energy purchases/sales | $ | 416 |
| | $ | 424 |
| | Annually as part of the tariff adjustment |
| Transmission costs, regulatory fees and other | 264 |
| | 63 |
| | Annually as part of the tariff adjustment |
El Salvador tariff recoveries(2) | 43 |
| | 92 |
| | Quarterly as part of the tariff adjustment |
Other(3) | 23 |
| | 58 |
| | Various |
| Total current regulatory assets | 746 |
| | 637 |
| | |
| Noncurrent regulatory assets: | | | | | |
Defined benefit pension obligations at IPL and DPL(4)(5) | 227 |
| | 329 |
| | Various |
Income taxes recoverable from customers(4)(6) | 36 |
| | 74 |
| | Various |
Brazil tariff recoveries:(1) | | | | | |
| Energy purchases/sales | 147 |
| | 266 |
| | Annually as part of the tariff adjustment |
| Transmission costs, regulatory fees and other | 140 |
| | 14 |
| | Annually as part of the tariff adjustment |
Deferred Midwest ISO costs(7) | 129 |
| | 111 |
| | To be determined |
Other(3) | 239 |
| | 78 |
| | Various |
| Total noncurrent regulatory assets | 918 |
| | 872 |
| | |
| TOTAL REGULATORY ASSETS | $ | 1,664 |
| | $ | 1,509 |
| | |
| REGULATORY LIABILITIES | | | | | |
| Current regulatory liabilities: | | | | | |
Brazil tariff reset adjustment(8) | $ | — |
| | $ | 76 |
| | Two years |
Efficiency program costs(9) | 12 |
| | 22 |
| | Annually as part of the tariff adjustment |
Brazil regulatory asset base adjustment(13) | 169 |
| | 123 |
| | Up to four tariff periods |
Brazil tariff refunds:(1) | | | | | |
| Energy purchases/sales | 105 |
| | 144 |
| | Annually as part of the tariff adjustment |
| Transmission costs, regulatory fees and other | 120 |
| | 174 |
| | Annually as part of the tariff adjustment |
Other(10) | 59 |
| | 66 |
| | Various |
| Total current regulatory liabilities | 465 |
| | 605 |
| | |
| Noncurrent regulatory liabilities: | | | | | |
Asset retirement obligations(11) | 759 |
| | 727 |
| | Over life of assets |
Brazil regulatory asset base adjustment(13) | 86 |
| | 61 |
| | Up to four tariff periods |
Brazil special obligations(12) | 370 |
| | 484 |
| | To be determined |
Brazil tariff refunds:(1) | | | | | |
| Energy purchases/sales | 30 |
| | 128 |
| | Annually as part of the tariff adjustment |
| Transmission costs, regulatory fees and other | 29 |
| | 97 |
| | Annually as part of the tariff adjustment |
Efficiency program costs(9) | 5 |
| | 11 |
| | Annually as part of the tariff adjustment |
Other(10) | 7 |
| | 1 |
| | Various |
| Total noncurrent regulatory liabilities | 1,286 |
| | 1,509 |
| | |
| TOTAL REGULATORY LIABILITIES | $ | 1,751 |
| | $ | 2,114 |
| | |
|
| | | | | | | | | |
| December 31, | 2018 | | 2017 | | Recovery/Refund Period |
| REGULATORY ASSETS | | | |
| Current regulatory assets: | | | | | |
| El Salvador energy pass through costs recovery | $ | 87 |
| | $ | 59 |
| | Quarterly |
| Other | 69 |
| | 60 |
| | Various |
| Total current regulatory assets | 156 |
| | 119 |
| | |
| Noncurrent regulatory assets: | | | | | |
IPL and DPL defined benefit pension obligations (1) | 283 |
| | 298 |
| | Various |
| IPL deferred Midwest ISO costs | 88 |
| | 102 |
| | 8 years |
| IPL environmental costs | 89 |
| | 48 |
| | Various |
| Other | 87 |
| | 94 |
| | Various |
| Total noncurrent regulatory assets | 547 |
| | 542 |
| | |
| TOTAL REGULATORY ASSETS | $ | 703 |
| | $ | 661 |
| | |
| REGULATORY LIABILITIES | | | | | |
| Current regulatory liabilities: | | | | | |
| Overcollection of costs to be passed back to customers | $ | 83 |
|
| $ | 14 |
| | 1 year |
| Other | 3 |
| | 3 |
| | Various |
| Total current regulatory liabilities | 86 |
| | 17 |
| | |
| Noncurrent regulatory liabilities: | | | | | |
| IPL and DPL accrued costs of removal and ARO's | 847 |
| | 830 |
| | Over life of assets |
| IPL and DPL income taxes payable to customers through rates | 246 |
| | 243 |
| | Various |
| Other | 53 |
| | 6 |
| | Various |
| Total noncurrent regulatory liabilities | 1,146 |
| | 1,079 |
| | |
| TOTAL REGULATORY LIABILITIES | $ | 1,232 |
| | $ | 1,096 |
| | |
_____________________________
| |
(1) | Recoverable or refundable per Brazilian National Electric Energy Agency ("ANEEL") regulations through the Annual Tariff Adjustment ("IRT"). These costs are generally non-controllable and primarily consist of purchased electricity, energy transmission, and sector costs that are considered volatile. The costs are passed through for a period of 12 months as part of the IRT. Any remaining balance is considered in the subsequent IRT, which results in a total of 24 months to recover or refund the costs. Favorable spot market sales are also subject to customer refunds through the IRT over the course of these time periods. |
| |
(2)
| Deferred fuel costs incurred by our El Salvador subsidiaries associated with purchase of energy from the El Salvador spot market and power generation plants. In El Salvador, the deferred fuel adjustment represents the variance between the actual fuel costs and the fuel costs recovered in the tariffs. The variance is recovered quarterly in the tariff reset period. |
| |
(3)
| Includes assets with and without a rate of return. Other current regulatory assets that did not earn a rate of return were $8 million and $22 million, as of December 31, 2015 and 2014, respectively. Other noncurrent regulatory assets that did not earn a rate of return were $237 million and $73 million, as of December 31, 2015 and 2014, respectively. Other current and noncurrent regulatory assets primarily consist of: |
| |
▪ | Unamortized losses on long-term debt reacquired or redeemed in prior periods at IPL and DPL, which are amortized over the lives of the original issues in accordance with the Federal Energy Regulatory Commission ("FERC") and PUCO rules. |
| |
▪ | Unamortized carrying charges and certain other costs related to Petersburg unit 4 at IPL. |
| |
▪ | Deferred storm costs incurred primarily in 2008 to repair storm damage at DPL; recovery was approved via order from the PUCO on December 17, 2014 and began January 2015. |
| |
▪ | Additional Regulatory Asset Base ("RAB") from a favorable decision on tariff reset (administrative appeal) at Eletropaulo. |
| |
(4)
| Past expenditures on which the Company does not earnearns a rate of return.return. |
| |
(5)Our regulatory assets primarily consist of costs that are generally non-controllable, such as purchased electricity, energy transmission, the difference between actual fuel costs and the fuel costs recovered in the tariffs, and other sector costs. These costs are recoverable or refundable as defined by the laws and regulations in our markets. Our regulatory assets also include defined pension and postretirement benefit obligations equal to the previously unrecognized actuarial gains and losses and prior services costs that are expected to be recovered through future rates. Other current and noncurrent regulatory assets primarily consist of: Demand charges at DPL; Unamortized premiums reacquired or redeemed on long-term debt at IPL and DPL, which are amortized over the lives of the original issuances; and Costs to comply with environmental regulations. Our regulatory liabilities primarily consist of obligations for removal costs which do not have an associated legal retirement obligation. Our regulatory liabilities also include deferred income taxes associated with the reduction of the U.S. federal income tax rate which will be passed through to our regulated customers via a decrease in future retail rates, see Note 21—Income Taxes for further information. In the accompanying Consolidated Balance Sheets the current regulatory assets and liabilities are reflected in Other current assets and Accrued and other liabilities, respectively, and the noncurrent regulatory assets and liabilities are reflected in Other noncurrent assets and Other noncurrent liabilities, respectively. The regulatory assets and liabilities primarily related to the US and Utilities SBU as of December 31, 2018 and December 31, 2017. | The regulatory accounting standards allow the defined pension and postretirement benefit obligation to be recorded as a regulatory asset equal to the previously unrecognized actuarial gains and losses and prior service costs that are expected to be recovered through future rates. Pension expense is recognized based on the plan's actuarially determined pension liability. Recovery of costs is probable, but not yet determined. Pension contributions made by our Brazilian subsidiaries are not included in regulatory assets as those contributions are not covered by the established tariff in Brazil. |
| |
(6)
| Probable recovery through future rates, based upon established regulatory practices, which permit the recovery of current taxes. This amount is expected to be recovered, |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
without interest, over
10. DEBT
NON-RECOURSE DEBT — The following table summarizes the periodcarrying amount and terms of non-recourse debt at our subsidiaries as book-tax temporary differences reverse and become current taxes.of the periods indicated (in millions):
|
| | | | | | | | | | | |
| NON-RECOURSE DEBT | Weighted Average Interest Rate | | Maturity | | December 31, |
| 2018 | | 2017 |
| Variable Rate: | | | | | | | |
| Bank loans | 4.46% | | 2019 – 2050 | | $ | 2,600 |
| | $ | 2,488 |
|
| Notes and bonds | 3.89% | | 2020 – 2030 | | 821 |
| | 900 |
|
Debt to (or guaranteed by) multilateral, export credit agencies or development banks (1) | 3.56% | | 2023 – 2034 | | 3,292 |
| | 3,668 |
|
| Fixed Rate: | | | | | | | |
| Bank loans | 4.62% | | 2019 – 2040 | | 1,684 |
| | 993 |
|
| Notes and bonds | 5.85% | | 2019 – 2073 | | 7,346 |
| | 7,388 |
|
Debt to (or guaranteed by) multilateral, export credit agencies or development banks (1) | 5.45% | | 2023 – 2034 | | 246 |
| | 271 |
|
| Other | 5.87% | | 2023 – 2061 | | 24 |
| | 26 |
|
| Unamortized (discount) premium & debt issuance (costs), net | | | | | (368 | ) | | (394 | ) |
| Subtotal | | | | | $ | 15,645 |
| | $ | 15,340 |
|
| Less: Current maturities | | | | | (1,659 | ) | | (2,164 | ) |
| Noncurrent maturities | | | | | $ | 13,986 |
| | $ | 13,176 |
|
_____________________________
| |
(7)
| Transmission service costs and other administrative costs from IPL's participation in the Midwest ISO market, which are recoverable but do not earn a rate of return. Recovery of costs is probable, but the timing is not yet determined. |
| |
(8)
| In July 2012, the Brazilian energy regulator (the "Regulator") approved the periodic review and reset of a component of Eletropaulo's regulated tariff, which determines the margin to be earned by Eletropaulo. The review and reset of this tariff component was retroactive to July 2011 and applied to customers' invoices from July 2012 to June 2015. From July 2011 through June 2012, Eletropaulo invoiced customers under the then-existing tariff rate, as required by the Regulator. As the new tariff rate was lower than the previous rate, Eletropaulo was required to reduce customer tariffs for the difference over the next year. Accordingly, from July 2011 through June 2012, Eletropaulo recognized a regulatory liability for the estimated future refunds, subsequently adjusted as of June 30, 2012 upon the finalization of the new tariff with the Regulator. The refund to customers was considered in the 2013 tariff adjustment, which contemplated an amortization of 67.55% from July 4, 2013. The remaining balance, representing 32.45%, was considered in the next annual tariff adjustment. There was no recorded current regulatory liability at Eletropaulo as of December 31, 2015. |
| |
(9)
| Amounts received for costs expected to be incurred to improve the efficiency of our plants in Brazil as part of the IRT. |
| |
(10)
| Other current and noncurrent regulatory liabilities primarily consist of liabilities owed to electricity generators due to variance in energy prices during rationing periods ("Free Energy"). Our Brazilian subsidiaries are authorized to refund this cost associated with monthly energy price variances between the wholesale energy market prices owed to the power generation plants producing Free Energy and the capped price reimbursed by the local distribution companies which are passed through to the final customers through energy tariffs. The balance excludes asset retirement obligations that were reclassified out of Other. |
| |
(11)
| Obligations for removal costs which do not have an associated legal retirement obligation as defined by the accounting standards on asset retirement obligations. |
| |
(12)
| Obligations established by ANEEL in Brazil associated with electric utility concessions and represent amounts received from customers or donations not subject to return. These donations are allocated to support energy network expansion and to improve utility operations to meet customers' needs. The term of the obligation is established by ANEEL. Settlement shall occur when the concession ends. |
| |
(13)
| Represents adjustments to the RAB resulting from an administrative ruling in December 2013 compelling Eletropaulo to refund customers beginning July 2014. |
The current regulatory assets and liabilities are recorded in Other current assets and Accrued and other liabilities, respectively, on the accompanying Consolidated Balance Sheets. The noncurrent regulatory assets and liabilities are recorded in Other noncurrent assets and Other noncurrent liabilities, respectively, in the accompanying Consolidated Balance Sheets. The following table summarizes regulatory assets and liabilities by reportable segment in millions as of the periods indicated:
|
| | | | | | | | | | | | | | | |
| December 31, | 2015 | | 2014 |
| | Regulatory Assets | | Regulatory Liabilities | | Regulatory Assets | | Regulatory Liabilities |
| Brazil SBU | $ | 971 |
| | $ | 932 |
| | $ | 787 |
| | $ | 1,347 |
|
| US SBU | 650 |
| | 819 |
| | 631 |
| | 767 |
|
| MCAC SBU (El Salvador) | 43 |
| | — |
| | 91 |
| | — |
|
| Total | $ | 1,664 |
| | $ | 1,751 |
| | $ | 1,509 |
| | $ | 2,114 |
|
12. DEBT
NON-RECOURSE DEBT — The next table summarizes the carrying amount (in millions) and terms of non-recourse debt as of the periods indicated:
|
| | | | | | | | | | | | |
| NON-RECOURSE DEBT | Weighted Average Interest Rate | | Maturity | | December 31, |
| 2015 | | 2014 |
VARIABLE RATE:(1) | | | | | | | |
| Bank loans | 4.37 | % | | 2016 – 2033 | | $ | 2,352 |
| | $ | 1,893 |
|
| Notes and bonds | 14.98 | % | | 2016 – 2022 | | 1,474 |
| | 1,912 |
|
Debt to (or guaranteed by) multilateral, export credit agencies or development banks(2) | 2.39 | % | | 2021 – 2034 | | 3,078 |
| | 2,375 |
|
| Other | 12.65 | % | | 2016 – 2043 | | 47 |
| | 668 |
|
| FIXED RATE: | | | | | | | |
| Bank loans | 5.11 | % | | 2016 – 2032 | | 558 |
| | 750 |
|
| Notes and bonds | 5.54 | % | | 2016 – 2073 | | 7,948 |
| | 7,654 |
|
Debt to (or guaranteed by) multilateral, export credit agencies or development banks(2) | 5.39 | % | | 2023 – 2034 | | 309 |
| | 259 |
|
| Other | 8.66 | % | | 2016 – 2049 | | 26 |
| | 89 |
|
| SUBTOTAL | | | | | 15,792 |
| | 15,600 |
|
| Less: Current maturities | | | | | (2,529 | ) | | (1,982 | ) |
| TOTAL | | | | | $ | 13,263 |
| | $ | 13,618 |
|
| |
(1) | The interest rate on variable rate debt represents the total of a variable component that is based on changes in an interest rate index and of a fixed component. The Company has interest rate swaps and option agreements in an aggregate notional principal amount of approximately $3.2 billion on non-recourse debt outstanding at December 31, 2015. These agreements economically fix the variable component of the interest rates on the portion of the variable-rate debt being hedged so that the total interest rate on that debt has been fixed at rates ranging from approximately 2.87% to 8.24%. These agreements expire at various dates from 2016 through 2033. |
| |
(2)
| Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions. |
The interest rate on variable rate debt represents the total of a variable component that is based on changes in an interest rate index and of a fixed component. The Company has interest rate swaps and option agreements in an aggregate notional principal amount of approximately $3.9 billion on non-recourse debt outstanding at December 31, 2018. These agreements economically fix the variable component of the interest rates on the portion of the variable rate debt being hedged so that the total interest rate on that debt has been fixed at rates ranging from approximately 2.24% to 8.00%.
Non-recourse debt (in millions) as of December 31, 20152018 is scheduled to reach maturity as presented in the table below:shown below (in millions):
|
| | | |
| December 31, | Annual Maturities |
| 2019 | $ | 1,697 |
|
| 2020 | 1,458 |
|
| 2021 | 1,601 |
|
| 2022 | 1,530 |
|
| 2023 | 1,316 |
|
| Thereafter | 8,411 |
|
| Unamortized (discount) premium & debt issuance (costs), net | (368 | ) |
| Total | $ | 15,645 |
|
|
| | | |
| December 31, | Annual Maturities |
| 2016 | $ | 2,529 |
|
| 2017 | 1,022 |
|
| 2018 | 1,359 |
|
| 2019 | 950 |
|
| 2020 | 1,431 |
|
| Thereafter | 8,501 |
|
| Total non-recourse debt | $ | 15,792 |
|
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
As of December 31, 2015,2018, AES subsidiaries with facilities under construction had a total of approximately $2.6 billion$811 million of committed but unused credit facilities available to fund construction and other related costs. Excluding these facilities under construction, AES subsidiaries had approximately $2.4$1.8 billion in a number of available butvarious unused committed credit lines to support their working capital, debt service reserves and other business needs. These credit lines can be used for borrowings, letters of credit, or a combination of these uses.
Significant transactions
— During the year ended December 31, 2015, we2018, the Company's subsidiaries had the following significant debt transactions at our subsidiaries:transactions:
Gener |
| | | | | | | | | | | | | |
| Subsidiary | Transaction Period | | Issuances | | Repayments | | Gain (Loss) on Extinguishment of Debt |
Southland (1) | Q1, Q2, Q3, Q4 | | $ | 757 |
| | $ | — |
| | $ | — |
|
| Tietê | Q1 | | 385 |
| | (231 | ) | | — |
|
| Alto Maipo | Q2 | | 104 |
| | — |
| | — |
|
| DPL | Q2 | | — |
| | (106 | ) | | (6 | ) |
| Gener | Q3 | | — |
| | (104 | ) | | (7 | ) |
| Angamos | Q3 | | — |
| | (98 | ) | | — |
|
| IPALCO | Q4 | | 105 |
| | (89 | ) | | — |
|
| Total | | | $ | 1,351 |
| | $ | (628 | ) | | $ | (13 | ) |
_____________________________
| |
(1) | Issuances relate to the June 2017, long-term non-recourse debt financing to fund the Southland re-powering construction projects. |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
AES Argentina — In February 2017, AES Argentina issued new$300 million aggregate principal of unsecured and unsubordinated notes due in 2024. The net proceeds from this issuance were used for the prepayment of $75 million of non-recourse debt related to the construction of $1.1 billion, offset by repayments of $423 million which includesthe San Nicolas Plant resulting in a lossgain on extinguishment of debt of $19 million;approximately $65 million.
IPALCO issued new debt of $847 million, offset by repayments of $602 million which includes a loss on extinguishment of debt of $22 million;
Sul issued new debt of $513 million, offset by repayments of $486 million which includes a loss on extinguishment of debt of $4 million;
Eletropaulo issued new debt of $354 million; offset by repayments of $211 million;
DPL issued new debt of $325 million; more than offset by repayments of $475 million which includes a loss on extinguishment of debt of $2 million;
Panama issued new debt of $300 million, offset by repayments of $287 million which includes a loss on extinguishment of debt of $15 million;
Mong Duong drew $203 million under its construction loan facility;
Tietê issued new debt of $153 million, more than offset by repayments of $226 million;
Andres issued new debt of $180 million, offset by repayments of $176 million which includes a loss on extinguishment of debt of $11 million; and
Itabo made repayments of $123 million which includes a loss on extinguishment of debt of $8 million.
Non-Recourse Debt Covenants, Restrictions and Defaults — The terms of the Company's non-recourse debt include certain financial and non-financialnonfinancial covenants. These covenants are limited to subsidiary activity and vary among the subsidiaries. These covenants may include, but are not limited to, maintenance of certain reserves and financial ratios, minimum levels of working capital and limitations on incurring additional indebtedness.
As of December 31, 20152018 and 2014,2017, approximately $513$627 million and $245$642 million, respectively, of restricted cash was maintained in accordance with certain covenants of the non-recourse debt agreements, and these amounts were included within Restricted cash and Debt service reserves and other deposits in the accompanying Consolidated Balance Sheets.
Various lender and governmental provisions restrict the ability of certain of the Company's subsidiaries to transfer their net assets to the Parent Company. Such restricted net assets of subsidiaries amounted to approximately $2$2.9 billion at December 31, 2015.2018.
The following table summarizes the Company's subsidiary non-recourse debt in default (in millions) as of December 31, 2015.2018. Due to the defaults, these amounts are included in the current portion of non-recourse debt:
|
| | | | | | | | | |
| | Primary Nature
of Default | | December 31, 2018 |
| Subsidiary | Default | | Net Assets |
| AES Puerto Rico | Covenant | | $ | 317 |
| | $ | 139 |
|
| AES Ilumina (Puerto Rico) | Covenant | | 34 |
| | 17 |
|
| Total | | | $ | 351 |
| (1) |
|
| | | | | | | | | |
| | Primary Nature
of Default | | December 31, 2015 |
| Subsidiary | Default | | Net Assets |
| Maritza (Bulgaria) | Covenant | | $ | 559 |
| | $ | 657 |
|
| Sul (Brazil) | Covenant | | 333 |
| | 439 |
|
| Kavarna (Bulgaria) | Covenant | | 140 |
| | 74 |
|
| Sogrinsk (Kazakhstan) | Covenant | | $ | 6 |
| | 8 |
|
| Total | | | $ | 1,038 |
| | |
As(1) This does not include $483 million of December 31, 2015, nonenon-recourse debt at Colon, one of the Company’s subsidiaries in Panama, that has been classified as current. Colon is currently in compliance with all provisions of its financing agreements, but does not expect to complete a required contract assignment to the lenders by the March 31, 2019 deadline. The Company is working with the lenders to modify the loan agreement to amend the requirement of this technical covenant in 2019. If this amendment is executed, the debt will be re-classified as noncurrent.
The above defaults are not payment defaults. All of the subsidiary non-recourse defaults were triggered by failure to comply with other covenants and/or 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 applicable subsidiary.
In the eventThe AES Corporation's recourse debt agreements include cross-default clauses that there is a default, bankruptcy or maturity acceleration atwill trigger if a subsidiary or group of subsidiaries that meetsfor which the applicable definition of materiality under the corporatenon-recourse debt agreements of The AES Corporation, there could be a cross-default to the Company's recourse debt. Materiality is defined in the Parent's senior secured credit facility as having provideddefault provides more than 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
quarters. As of December 31, 2015, none of2018, the Company has no defaults listed above individually or in the aggregatewhich result in or are at risk of triggering a cross-default under the recourse debt of the Parent Company. In the event the Parent Company is not in compliance with the financial covenants of its senior secured revolving credit facility, restricted payments will be limited to regular quarterly shareholder dividends at the then-prevailing rate. Payment defaults and bankruptcy defaults would preclude the making of any restricted payments.
Interest Expense — Interest expense for the year ended December
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015 was reduced by $64 million related to the reversal of a monetary correction previously recognized as interest expense at Eletropaulo. This interest expense was on a contingent regulatory liability that was also reversed in the current period. Interest expense for the year ended December 31, 2014 was reduced by approximately $48 million related to reversing contingent interest accruals associated with disputed purchased energy obligations at Sul for which it was determined, based on developments during 2014, that the likelihood of an unfavorable outcome for the payment of interest on the disputed obligations was no longer probable. Interest expense for the year ended December 31, 2013 was reduced by approximately $34 million related to the recognition of ineffectiveness on derivative interest rate swaps accounted for as cash flow hedges.2018, 2017, AND 2016
RECOURSE DEBT — The following table below summarizes the carrying amount (in millions) and terms of recourse debt of the Company as of the periods indicated:indicated (in millions):
|
| | | | | | | | | | | |
| | Interest Rate | | Final Maturity | | December 31, 2018 | | December 31, 2017 |
| Senior Unsecured Note | 8.00% | | 2020 | | $ | — |
| | $ | 228 |
|
| Senior Unsecured Note | 4.00% | | 2021 | | 500 |
| | — |
|
| Senior Unsecured Note | 7.38% | | 2021 | | — |
| | 690 |
|
| Drawings on secured credit facility | LIBOR + 2.00% | | 2021 | | — |
| | 207 |
|
| Senior Secured Term Loan | LIBOR + 1.75% | | 2022 | | 366 |
| | 521 |
|
| Senior Unsecured Note | 4.88% | | 2023 | | 713 |
| | 713 |
|
| Senior Unsecured Note | 4.50% | | 2023 | | 500 |
| | — |
|
| Senior Unsecured Note | 5.50% | | 2024 | | 63 |
| | 738 |
|
| Senior Unsecured Note | 5.50% | | 2025 | | 544 |
| | 573 |
|
| Senior Unsecured Note | 6.00% | | 2026 | | 500 |
| | 500 |
|
| Senior Unsecured Note | 5.13% | | 2027 | | 500 |
| | 500 |
|
| Unamortized (discount) premium & debt issuance (costs), net | | | | | (31 | ) | | (40 | ) |
| Subtotal | | | | | $ | 3,655 |
| | $ | 4,630 |
|
| Less: Current maturities | | | | | (5 | ) | | (5 | ) |
| Noncurrent maturities | | | | | $ | 3,650 |
| | $ | 4,625 |
|
|
| | | | | | | | | | | |
| RECOURSE DEBT | Interest Rate | | Final Maturity | | December 31, 2015 |
| | December 31, 2014 |
| Senior Unsecured Note | 7.75% | | 2015 | | $ | — |
| | $ | 151 |
|
| Senior Unsecured Note | 9.75% | | 2016 | | — |
| | 164 |
|
| Senior Unsecured Note | 8.00% | | 2017 | | 181 |
| | 525 |
|
| Senior Unsecured Note | LIBOR + 3% | | 2019 | | 775 |
| | 775 |
|
| Senior Unsecured Note | 8.00% | | 2020 | | 469 |
| | 625 |
|
| Senior Unsecured Note | 7.38% | | 2021 | | 1,000 |
| | 1,000 |
|
| Senior Unsecured Note | 4.88% | | 2023 | | 750 |
| | 750 |
|
| Senior Unsecured Note | 5.50% | | 2024 | | 750 |
| | 750 |
|
| Senior Unsecured Note | 5.50% | | 2025 | | 575 |
| | — |
|
| Term Convertible Trust Securities | 6.75% | | 2029 | | 517 |
| | 517 |
|
| Unamortized (Discounts)/Premiums | | | | | (2 | ) | | 1 |
|
| SUBTOTAL | | | | | 5,015 |
| | 5,258 |
|
| Less: Current maturities | | | | | — |
| | (151 | ) |
| Total | | | | | $ | 5,015 |
| | $ | 5,107 |
|
The following table below summarizes the principal amounts due net of unamortized discounts, under our recourse debt for the next five years and thereafter in millions:(in millions):
|
| | | |
| December 31, | Net Principal Amounts Due |
| 2019 | $ | 5 |
|
| 2020 | 5 |
|
| 2021 | 505 |
|
| 2022 | 350 |
|
| 2023 | 1,213 |
|
| Thereafter | 1,608 |
|
| Unamortized (discount) premium & debt issuance (costs), net | (31 | ) |
| Total recourse debt | $ | 3,655 |
|
|
| | | |
| December 31, | Net Principal Amounts Due |
| 2016 | $ | — |
|
| 2017 | 181 |
|
| 2018 | — |
|
| 2019 | 774 |
|
| 2020 | 469 |
|
| Thereafter | 3,591 |
|
| Total recourse debt | $ | 5,015 |
|
In April 2015,December 2018, the Company issued $575 million aggregate principal amount of 5.50% senior notes due 2025. Concurrent with this offering, the Company redeemed via tender offers $344prepaid $150 million aggregate principal of its existing 8.00%senior secured term loan due in 2022. As a result of the transaction, the Company recognized a loss on extinguishment of debt of $1 million.
In March 2018, the Company purchased via tender offers $671 million aggregate principal of its existing 5.50% senior unsecured notes due in 2024 and $29 million of its existing 5.50% senior unsecured notes due in 2025. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $44 million.
In March 2018, the Company issued $500 million aggregate principal of 4.00% senior notes due in 2021 and $500 million of 4.50% senior notes due in 2023. The Company used the proceeds from these issuances to purchase via tender offer in full the $228 million balance of its 8.00% senior notes due in 2020 and the $690 million balance of its 7.375% senior notes due in 2021. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $125 million.
In August 2017, the Company issued $500 million aggregate principal amount of 5.125% senior notes due in 2027. The Company used these proceeds to redeem at par $240 million aggregate principal of its existing LIBOR + 3.00% senior unsecured notes due in 2019 and $156purchased $217 million of its existing 8.00% senior unsecured notes due in 2020. As a result of the latter transactions, the Company recognized a loss on extinguishment of debt of $36 million.
In May 2017, the Company closed on $525 million aggregate principal LIBOR + 2.00% secured term loan due in 2022. In June 2017, the Company used these proceeds to redeem at par all $517 million aggregate principal of its existing Term Convertible Securities. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $82 million that is included in the Consolidated Statement of Operations.$6 million.
In March 2015,2017, the Company redeemed in full the $151via tender offers $276 million balanceaggregate principal of its 7.75%existing 7.375% senior unsecured notes due October 2015in 2021 and the $164$24 million balance of its 9.75%existing 8.00% senior unsecured notes due April 2016.in 2020. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $23 million that is included in the Consolidated Statement of Operations.$47 million.
In February 2014, the Company redeemed in full the $110 million balance of its 7.75% senior unsecured notes due March 2014. On March 7, 2014, the Company issued $750 million aggregate principal amount of 5.50% senior notes due 2024. Concurrent with this offering, the Company redeemed via tender offers $625 million aggregate principal of its existing 8.00% senior unsecured notes due 2017. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $132 million that is included in the Consolidated Statements of Operations.
On May 20, 2014, the Company issued $775 million aggregate principal amount of senior unsecured floating rate notes due June 2019. The notes bear interest at a rate of 3% above three-month LIBOR, reset quarterly. Concurrent with this offering,
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
the Company repaid $767 million of its existing senior secured term loan due 2018. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $10 million that is included in the Consolidated Statement of Operations. On June 16, 2014, the Company repaid in full the remaining balance of approximately $29 million of its senior secured term loan due 2018.
On July 25, 2014, the Company issued two notices to call $320 million aggregate principal amount of unsecured notes, $160 million of which was used to retire notes due in 2015 and $160 million of which was used to retire notes due in 2016. The Company closed these transactions on August 25, 2014. As a result of this transaction, the Company recognized a loss on extinguishment of debt of $40 million that is included in the Consolidated Statement of Operations.
Recourse Debt Covenants and Guarantees — The Company's obligations under the senior secured credit facility and senior secured term loan are, subject to certain exceptions, secured by (i) all of the capital stock of
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by the Company; and (ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements.
The senior secured credit facility isand senior secured term loan are subject to mandatory prepayment under certain circumstances, including the sale of certain assets. In such a situation, the net cash proceeds from the sale must be applied pro rata to repay the term loan, if any, using 60% of net cash proceeds, reduced to 50% when and if the parent'sParent Company's recourse debt to cash flow ratio is less than 5:1. The lenders have the option to waive their pro rata redemption.
The senior secured credit facility contains customary covenants and restrictions on the Company's ability to engage in certain activities, including, but not limited to, limitations on other indebtedness, liens, investments and guarantees; limitations on restricted payments such as shareholder dividends and equity repurchases; restrictions on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet or derivative arrangements; and other financial reporting requirements.
The senior secured credit facility also contains financial covenants, evaluated quarterly, requiring the Company to maintain certain financial ratios including a cash flow to interest coverage ratio, calculated quarterly, which provides that a minimum ratio of the Company's adjusted operating cash flow to the Company's interest charges related toon recourse debt of 1.3× must be maintained at all1.3 times and a maximum ratio of recourse debt to cash flow ratio, calculated quarterly, which provides that the ratio of the Company's total recourse debt to the Company's adjusted operating cash flow must not exceed a maximum of 7.5×.7.5 times.
The terms of the Company's senior unsecured notes and senior secured credit facilityterm loan contain certain covenants including without limitation, limitationlimitations on the Company's ability to incur liens or enter into sale and leaseback transactions.
TERM CONVERTIBLE TRUST SECURITIES — In 1999, AES Trust III, a wholly-owned special purpose business trust and a VIE, issued approximately 10.35 million of $50 par value Term Convertible Preferred Securities ("TECONS")TECONS with a quarterly coupon payment of $0.844 for total proceeds of $517 million and concurrently purchased $517 million of 6.75% Junior Subordinated Convertible Debentures due 2029 (the "6.75% Debentures") issued by AES. The Company consolidates AES Trust III in its consolidated financial statements and classifies the TECONS as recourse debt on its Consolidated Balance Sheet. The Company's obligations under the 6.75% Debentures and other relevant trust agreements, in aggregate, constitute a full and unconditional guarantee by the Company of the TECON Trusts' obligations. As of December 31, 2015 and 2014, the sole assets of AES Trust III are the 6.75% Debentures.
AES, at its option, canmay redeem the 6.75% Debentures which would result in the required redemption of the TECONS issued by AES Trust III currently for $50 per TECON. The TECONS must be redeemed upon maturityAs of December 31, 2016, the sole assets of AES Trust III were the 6.75% Debentures. The TECONS are convertible into the common stock of AES at each holder's option prior to October 15, 2029 at the rate of 1.4216, representing a conversion price of $35.17 per share. The maximum number of shares of common stock AES would be required to issue should all holders decide to convert their securities would be 14.7 million shares.
Dividends on the TECONS are payable quarterly at an annual rate of 6.75%. The Trust is permitted to defer payment of dividends for up to 20 consecutive quarters, provided thatIn June 2017, the Company has exercisedredeemed the 6.75% Debentures and redeemed at par all remaining aggregate principal of its right to defer interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the TECONS would accumulate quarterly and accrue interest, and the Company may not declare or pay dividends on its common stock. AES has not exercised the option to defer any dividends at this time and all dividends due under the Trust have been paid.existing TECONs.
13.11. COMMITMENTS
LEASES—The Company and its subsidiaries enterenters into long-term non-cancelable lease arrangements which, for accounting purposes, are classified as either an operating lease or capital lease.leases. Operating leases primarily include certain transmission lines, office rental and site leases. Operating lease rental expense for the years ended December 31, 2015, 2014,2018, 2017, and 20132016 was $67$51 million, $58$61 million and $46$61 million, respectively. Capital leases primarily include transmission lines, at our
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
subsidiaries in Brazil, vehicles, and officeoffices, and other operating equipment. Capital leases are recognized in Property, Plant and Equipment within "ElectricElectric generation, distribution assets and distribution assets."other. The gross value of the capital lease assets as of December 31, 20152018 and 20142017 was $72$13 million and $80$27 million, respectively. The following table below presentsshows the future minimum lease payments under operating and capital leases for continuing operations together with the present value of the net minimum lease payments under capital leases as of December 31, 20152018 for 20162019 through 20202023 and thereafter in millions:(in millions):
| | | | Future Commitments for | Future Commitments for |
| December 31, | Capital Leases | | Operating Leases | Capital Leases | | Operating Leases |
| 2016 | $ | 14 |
| | $ | 77 |
| |
| 2017 | 12 |
| | 78 |
| |
| 2018 | 11 |
| | 79 |
| |
| 2019 | 10 |
| | 80 |
| $ | 1 |
| | $ | 74 |
|
| 2020 | 10 |
| | 79 |
| 1 |
| | 38 |
|
| 2021 | | 1 |
| | 25 |
|
| 2022 | | 1 |
| | 26 |
|
| 2023 | | 1 |
| | 25 |
|
| Thereafter | 90 |
| | 898 |
| 7 |
| | 455 |
|
| Total | 147 |
| | $ | 1,291 |
| $ | 12 |
| | $ | 643 |
|
| Less: Imputed interest | 90 |
| | | (6 | ) | | |
| Present value of total minimum lease payments | $ | 57 |
| | | $ | 6 |
| | |
CONTRACTS — The Company's operating subsidiaries enterCompany enters into long-term contracts for construction projects, maintenance and service, transmission of electricity, operations services and purchasepurchases of electricity and fuel. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances only. Electricity purchase contracts primarily include energy auction agreements at our Brazil subsidiaries with extended terms from 2013 through 2028.circumstances. The following table below presentsshows the future minimum commitments for continuing operations under these contracts as of December 31, 2015
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
2018 for 20162019 through 20202023 and thereafter. Actualthereafter as well as actual purchases under these contracts for the years ended December 31, 2015, 2014,2018, 2017, and 2013 are also presented, in millions:2016 (in millions):
|
| | | | | | | | | | | |
| Actual purchases during the year ended December 31, | Electricity Purchase Contracts | | Fuel Purchase Contracts | | Other Purchase Contracts |
| 2016 | $ | 420 |
| | $ | 1,790 |
| | $ | 817 |
|
| 2017 | 747 |
| | 1,619 |
| | 1,945 |
|
| 2018 | 827 |
| | 1,838 |
| | 1,671 |
|
| Future commitments for the year ending December 31, | | | | | |
| 2019 | $ | 786 |
| | $ | 1,494 |
| | $ | 1,375 |
|
| 2020 | 602 |
| | 1,027 |
| | 681 |
|
| 2021 | 371 |
| | 882 |
| | 336 |
|
| 2022 | 234 |
| | 575 |
| | 561 |
|
| 2023 | 393 |
| | 463 |
| | 213 |
|
| Thereafter | 5,187 |
| | 1,734 |
| | 778 |
|
| Total | $ | 7,573 |
| | $ | 6,175 |
| | $ | 3,944 |
|
|
| | | | | | | | | | | |
| Actual purchases during the year ended December 31, | Electricity Purchase Contracts | | Fuel Purchase Contracts | | Other Purchase Contracts |
| 2013 | $ | 2,665 |
| | $ | 1,590 |
| | $ | 1,743 |
|
| 2014 | 3,104 |
| | 1,521 |
| | 1,386 |
|
| 2015 | 2,592 |
| | 1,262 |
| | 2,121 |
|
| Future commitments for the year ending December 31, | | | | | |
| 2016 | $ | 2,623 |
| | $ | 1,120 |
| | $ | 1,332 |
|
| 2017 | 2,444 |
| | 835 |
| | 1,047 |
|
| 2018 | 2,634 |
| | 532 |
| | 1,081 |
|
| 2019 | 2,799 |
| | 314 |
| | 873 |
|
| 2020 | 2,918 |
| | 311 |
| | 655 |
|
| Thereafter | 24,176 |
| | 2,141 |
| | 4,395 |
|
| Total | $ | 37,594 |
| | $ | 5,253 |
| | $ | 9,383 |
|
14.12. CONTINGENCIES
Guarantees and Letters of Credit —In connection with certain project financing, acquisitionfinancings, acquisitions and dispositions, power purchasepurchases and other agreements, the Parent Company has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, the Parent Company has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations relate to future performance commitments which the Company or its businesses expectexpects to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 1916 years.
The following table summarizes the Parent Company's contingent contractual obligations as of December 31, 2015.2018. Amounts presented in the following table below represent the Parent Company's current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts includeThere were no obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of its businesses of $14 million.businesses.
|
| | | | | | | | |
| Contingent Contractual Obligations | | Amount (in millions) | | Number of Agreements | | Maximum Exposure Range for Each Agreement (in millions) |
| Guarantees and commitments | | $ | 685 |
| | 33 | | $0 — 157 |
| Letters of credit under the unsecured credit facility | | 368 |
| | 10 | | $1 — 247 |
| Letters of credit under the senior secured credit facility | | 78 |
| | 23 | | $0 — 49 |
Asset sale related indemnities (1) | | 27 |
| | 1 | | $27 |
| Total | | $ | 1,158 |
| | 67 | | |
|
| | | | | | | | |
| Contingent Contractual Obligations | | Amount | | Number of Agreements | | Maximum Exposure Range for Each Agreement |
| | | (in millions) | | | | (in millions) |
| Guarantees and commitments | | $ | 369 |
| | 14 | | $1 - 53 |
Asset sale related indemnities(1) | | 27 |
| | 1 | | 27 |
| Cash collateralized letters of credit | | 32 |
| | 4 | | $1 - 15 |
| Letters of credit under the senior secured credit facility | | 62 |
| | 7 | | <$1 - 29 |
| Total | | $ | 490 |
| | 26 | | |
| |
(1) | Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal. |
(1) Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal.
As of December 31, 2015, the Parent Company had no commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit discussed above. During the year ended December 31, 2015,2018, the Company paid letter of credit fees ranging from 0.2%1% to 2.5%3% per annum on the outstanding amounts of letters of credit.
Environmental — The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As ofFor the periods ended December 31, 20152018 and 20142017, the Company had recognized liabilities of $10$5 million and $12 million, respectively, for projected environmental remediation costs. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Moreover, where no liability has been recognized, it is reasonably possible that the Company may be required to incur remediation costs or make expenditures in amounts that could be material but could not be estimated as of December 31, 2015.2018. In aggregate, the Company estimates that the range of potential losses related to environmental matters, where estimable, to be up to $1$17 million. The amounts considered reasonably possible do not include amounts accrued as discussed above.
Litigation —The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and, accordingly, has recordedrecognized aggregate liabilities for all claims of
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
approximately $189$53 million and $199$50 million as of December 31, 20152018 and 2014,2017, respectively. These amounts are reported on the Consolidated Balance Sheets within Accrued and other liabilities and Other noncurrent liabilities. A significant portion of these accrued liabilities relate to employment, non-income taxregulatory matters and customercommercial disputes in international jurisdictions (principally Brazil). Certain of the Company's subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings.jurisdictions. There can be no assurance that these accrued liabilities will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.
The Company believes, based upon information it currently possesses and taking into account established accruals for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company's consolidated financial statements. However, whereWhere no accrued liability has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of December 31, 2015.2018. The material contingencies where a loss is reasonably possible primarily include claims under financing agreements; disputes with offtakers, suppliers and EPC contractors; alleged breaches of contract; alleged violation of monopoly laws and regulations; income tax and non-income tax matters with tax authorities; and regulatory matters. In aggregate, the Company estimates that the range of potential losses, where estimable, related to these reasonably possible material contingencies to be between $1.1 billion$79 million and $1.4 billion.$439 million. The amounts considered reasonably possible do not include amounts accrued, as discussed above. These material contingencies do not include income tax-related contingencies which are considered part of our uncertain tax positions.
Regulatory — During 2013, the Company recognized a regulatory liability of $269 million for a contingency related to an administrative ruling which required Eletropaulo to refund customers' amounts related to the regulatory asset base. In 2014, Eletropaulo started refunding customers as part of the tariff. In January 2015, ANEEL updated the tariff to exclude any further customer refunds. On June 30, 2015, ANEEL included in the tariff reset the reimbursement to Eletropaulo of these amounts previously refunded to customers to begin in July 2015. During 2015, as a result of favorable events, management reassessed the contingency and determined that it no longer meets the recognition criteria under ASC 450 — Contingencies. Management believes that it is now only reasonably possible that Eletropaulo will have to refund these amounts to customers. Accordingly, the Company reversed the remaining regulatory liability for this contingency of $161 million in 2015, which increased Regulated Revenue by $97 million and reduced Interest Expense by $64 million. Amounts related to this case are now included
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
as part of our reasonably possible contingent range mentioned in the preceding paragraph.
15.13. BENEFIT PLANS
Defined Contribution Plan —The Company sponsors four defined contribution plans ("the DC Plans"). Two are forplans cover U.S. non-union employees, of whichemployees; one is for employees of the Parent Company and certain U.S.US and Utilities SBU businessesbusiness employees, and one is for DPL employees. One plan includes bothThe remaining two plans include union and non-union employees at IPL. One defined contribution plan is forIPL and union employees at DPL. The DC Plans are qualified under section 401 of the Internal Revenue Code. AllMost U.S. employees of the Company are eligible to participate in the appropriate Planplan except for those employees who are covered by a collective bargaining agreement, unless such agreement specifically provides that the employee is considered an eligible employee under a Plan. Theplan. Within the DC Plans, providethe Company provides matching contributions in AES common stock or cash,addition to other contributions at the discretion of the Compensation Committee of the Board of Directors in AES common stock or cash and discretionary tax deferred contributions from the participants.non-matching contributions. Participants are fully vested in their own contributions. The Company's contributions and the Company's matching contributions. Participants vest in other company contributions ratably over a five-year period ending on the fifth anniversary of their hire date.various time periods ranging from immediate up to five years. For the yearyears ended December 31, 2015, the Company's contributions to the2018, 2017 and 2016, costs for defined contribution plans were approximately $18$21 million, $23 million and for the years ended December 31, 2014 and 2013, contributions were $22$15 million, and $23 million per year, respectively.
Defined Benefit Plans — Certain of the Company's subsidiaries have defined benefit pension plans covering substantially all of their respective employees.employees ("the DB Plans"). Pension benefits are based on years of credited service, age of the participant, and average earnings. Of the 3330 active defined benefit plansDB Plans as of December 31, 2015, 52018, five are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
The following table reconciles the Company's funded status, both domestic and foreign, as of the periods indicated:indicated (in millions):
|
| | | | | | | | | | | | | | | | |
| | | 2018 | | 2017 |
| | | U.S. | | Foreign | | U.S. | | Foreign |
| CHANGE IN PROJECTED BENEFIT OBLIGATION: | | | | | | | | |
| Benefit obligation as of January 1 | | $ | 1,257 |
| | $ | 470 |
| | $ | 1,188 |
| | $ | 411 |
|
| Service cost | | 15 |
| | 12 |
| | 13 |
| | 10 |
|
| Interest cost | | 40 |
| | 22 |
| | 41 |
| | 22 |
|
| Employee contributions | | — |
| | 1 |
| | — |
| | 1 |
|
| Plan amendments | | 10 |
| | — |
| | 1 |
| | (1 | ) |
| Plan curtailments | | — |
| | — |
| | 3 |
| | — |
|
| Plan settlements | | — |
| | (21 | ) | | — |
| | (2 | ) |
| Benefits paid | | (105 | ) | | (17 | ) | | (71 | ) | | (22 | ) |
| Plan combinations | | — |
| | (4 | ) | | — |
| | — |
|
| Actuarial (gain) loss | | (99 | ) | | (8 | ) | | 82 |
| | 29 |
|
| Effect of foreign currency exchange rate changes | | — |
| | (38 | ) | | — |
| | 22 |
|
| Benefit obligation as of December 31 | | $ | 1,118 |
| | $ | 417 |
| | $ | 1,257 |
| | $ | 470 |
|
| CHANGE IN PLAN ASSETS: | | | | | | | | |
| Fair value of plan assets as of January 1 | | $ | 1,127 |
| | $ | 455 |
| | $ | 1,044 |
| | $ | 402 |
|
| Actual return on plan assets | | (35 | ) | | 6 |
| | 141 |
| | 31 |
|
| Employer contributions | | 39 |
| | 21 |
| | 13 |
| | 18 |
|
| Employee contributions | | — |
| | 1 |
| | — |
| | 1 |
|
| Plan settlements | | — |
| | (21 | ) | | — |
| | (2 | ) |
| Benefits paid | | (105 | ) | | (17 | ) | | (71 | ) | | (22 | ) |
| Effect of foreign currency exchange rate changes | | — |
| | (35 | ) | | — |
| | 27 |
|
| Fair value of plan assets as of December 31 | | $ | 1,026 |
| | $ | 410 |
| | $ | 1,127 |
| | $ | 455 |
|
| RECONCILIATION OF FUNDED STATUS | | | | | | | | |
| Funded status as of December 31 | | $ | (92 | ) | | $ | (7 | ) | | $ | (130 | ) | | $ | (15 | ) |
|
| | | | | | | | | | | | | | | | |
| December 31, | | 2015 | | 2014 |
| (in millions) | | U.S. | | Foreign | | U.S. | | Foreign |
| CHANGE IN PROJECTED BENEFIT OBLIGATION: | | | | | | | | |
| Benefit obligation as of January 1 | | $ | 1,235 |
| | $ | 4,363 |
| | $ | 1,059 |
| | $ | 4,749 |
|
| Service cost | | 16 |
| | 15 |
| | 14 |
| | 16 |
|
| Interest cost | | 48 |
| | 351 |
| | 50 |
| | 489 |
|
| Employee contributions | | — |
| | 3 |
| | — |
| | 4 |
|
| Plan amendments | | 5 |
| | 2 |
| | 8 |
| | (3 | ) |
| Plan settlements | | (3 | ) | | — |
| | — |
| | — |
|
| Benefits paid | | (61 | ) | | (300 | ) | | (59 | ) | | (415 | ) |
| Actuarial (gain) loss | | (68 | ) | | (160 | ) | | 163 |
| | 87 |
|
| Effect of foreign currency exchange rate changes | | — |
| | (1,301 | ) | | — |
| | (564 | ) |
| Benefit obligation as of December 31 | | $ | 1,172 |
| | $ | 2,973 |
| | $ | 1,235 |
| | $ | 4,363 |
|
| CHANGE IN PLAN ASSETS: | | | | | | | | |
| Fair value of plan assets as of January 1 | | $ | 1,061 |
| | $ | 3,272 |
| | $ | 941 |
| | $ | 3,605 |
|
| Actual return on plan assets | | (7 | ) | | 182 |
| | 123 |
| | 360 |
|
| Employer contributions | | 31 |
| | 89 |
| | 56 |
| | 135 |
|
| Employee contributions | | — |
| | 3 |
| | — |
| | 4 |
|
| Plan settlements | | (3 | ) | | — |
| | — |
| | — |
|
| Benefits paid | | (61 | ) | | (300 | ) | | (59 | ) | | (415 | ) |
| Effect of foreign currency exchange rate changes | | — |
| | (962 | ) | | — |
| | (417 | ) |
| Fair value of plan assets as of December 31 | | $ | 1,021 |
| | $ | 2,284 |
| | $ | 1,061 |
| | $ | 3,272 |
|
| RECONCILIATION OF FUNDED STATUS | | | | | | | | |
| Funded status as of December 31 | | $ | (151 | ) | | $ | (689 | ) | | $ | (174 | ) | | $ | (1,091 | ) |
The following table summarizes the amounts recognized on the Consolidated Balance Sheets in millions related to the funded status of the plans,DB Plans, both domestic and foreign, as of the periods indicated:indicated (in millions):
|
| | | | | | | | | | | | | | | | |
| December 31, | | 2018 | | 2017 |
| Amounts Recognized on the Consolidated Balance Sheets | | U.S. | | Foreign | | U.S. | | Foreign |
| Noncurrent assets | | $ | — |
| | $ | 64 |
| | $ | — |
| | $ | 69 |
|
| Accrued benefit liability—current | | — |
| | (6 | ) | | — |
| | (6 | ) |
| Accrued benefit liability—noncurrent | | (92 | ) | | (65 | ) | | (130 | ) | | (78 | ) |
| Net amount recognized at end of year | | $ | (92 | ) | | $ | (7 | ) | | $ | (130 | ) | | $ | (15 | ) |
|
| | | | | | | | | | | | | | | | |
| December 31, | | 2015 | | 2014 |
| AMOUNTS RECOGNIZED ON THE CONSOLIDATED BALANCE SHEETS | | U.S. | | Foreign | | U.S. | | Foreign |
| Noncurrent assets | | $ | — |
| | $ | 67 |
| | $ | — |
| | $ | 51 |
|
| Accrued benefit liability—current | | — |
| | (5 | ) | | — |
| | (4 | ) |
| Accrued benefit liability—noncurrent | | (151 | ) | | (751 | ) | | (174 | ) | | (1,138 | ) |
| Net amount recognized at end of year | | $ | (151 | ) | | $ | (689 | ) | | $ | (174 | ) | | $ | (1,091 | ) |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
The nextfollowing table summarizes the Company's U.S. and foreign accumulated benefit obligation as of the periods indicated (in millions):
|
| | | | | | | | | | | | | | | |
| December 31, | 2018 | | 2017 |
| | U.S. | | Foreign | | U.S. | | Foreign |
| Accumulated Benefit Obligation | $ | 1,101 |
| | $ | 376 |
| | $ | 1,236 |
| | $ | 433 |
|
| Information for pension plans with an accumulated benefit obligation in excess of plan assets: | | | | | | | |
| Projected benefit obligation | $ | 1,118 |
| | $ | 89 |
| | $ | 1,257 |
| | $ | 109 |
|
| Accumulated benefit obligation | 1,101 |
| | 79 |
| | 1,236 |
| | 97 |
|
| Fair value of plan assets | 1,026 |
| | 33 |
| | 1,127 |
| | 33 |
|
| Information for pension plans with a projected benefit obligation in excess of plan assets: | | | | | | | |
| Projected benefit obligation | $ | 1,118 |
| | $ | 220 |
| | $ | 1,257 |
| | $ | 238 |
|
| Fair value of plan assets | 1,026 |
| | 150 |
| | 1,127 |
| | 154 |
|
|
| | | | | | | | | | | | | | | | |
| December 31, | 2015 | | 2014 | |
| | U.S. | | Foreign | | U.S. | | Foreign | |
| Accumulated Benefit Obligation | $ | 1,150 |
| | $ | 2,931 |
| | $ | 1,208 |
| | $ | 4,301 |
| |
| Information for pension plans with an accumulated benefit obligation in excess of plan assets: | | | | | | | | |
| Projected benefit obligation | $ | 1,172 |
| | $ | 2,683 |
| | $ | 1,235 |
| | $ | 4,021 |
| |
| Accumulated benefit obligation | 1,150 |
| | 2,656 |
| | 1,208 |
| | 3,979 |
| |
| Fair value of plan assets | 1,021 |
| | 1,931 |
| | 1,061 |
| | 2,885 |
| |
| Information for pension plans with a projected benefit obligation in excess of plan assets: | | | | | | | | |
| Projected benefit obligation | $ | 1,172 |
| | $ | 2,697 |
| (1) | $ | 1,235 |
| | $ | 4,038 |
| (1) |
| Fair value of plan assets | 1,021 |
| | 1,942 |
| (1) | 1,061 |
| | 2,897 |
| (1) |
| |
(1)
| $686 million and $1.1 billion of the total net unfunded projected benefit obligation is due to Eletropaulo in Brazil as of December 31, 2015 and 2014, respectively. |
The following table below summarizes the significant weighted average assumptions used in the calculation of benefit obligation and net periodic benefit cost, both domestic and foreign, as of the periods indicated:
|
| | | | | | | | | | | | |
| December 31, | 2015 | | 2014 | |
| | U.S. | | Foreign | | U.S. | | Foreign | |
| Benefit Obligation: | | | | | | | | |
| Discount rates | 4.44 | % | | 11.37 | % | (2) | 4.04 | % | | 10.47 | % | (2) |
| Rates of compensation increase | 3.34 | % | (1) | 6.32 | % | | 3.94 | % | (1) | 6.41 | % | |
| Periodic Benefit Cost: | | | | | | | | |
| Discount rate | 4.04 | % | | 10.47 | % | | 4.89 | % | | 10.80 | % | |
| Expected long-term rate of return on plan assets | 6.67 | % | | 9.77 | % | | 6.92 | % | | 10.44 | % | |
| Rate of compensation increase | 3.94 | % | (1) | 6.41 | % | | 3.94 | % | (1) | 6.44 | % | |
|
| | | | | | | | | | | | | |
| December 31, | | 2018 | | 2017 | |
| | | U.S. | | Foreign | | U.S. | | Foreign | |
| Benefit Obligation: | Discount rate | 4.35 | % | | 5.63 | % | | 3.67 | % | | 5.23 | % | |
| | Rate of compensation increase | 3.34 | % | | 4.79 | % | | 3.34 | % | | 4.65 | % | |
| Periodic Benefit Cost: | Discount rate | 3.67 | % | | 5.23 | % | (1) | 4.28 | % | | 5.83 | % | (1) |
| | Expected long-term rate of return on plan assets | 5.73 | % | | 3.94 | % | | 6.67 | % | | 5.30 | % | |
| | Rate of compensation increase | 3.34 | % | | 4.65 | % | | 3.34 | % | | 4.86 | % | |
_____________________________
| |
(1) | A U.S. subsidiary of the Company has defined benefit obligations of $6 million and $748 million as of December 31, 2015 and 2014, respectively, for which salary bands, rather than rates of compensation increases, are used to determine future benefit costs. Rates of compensation increases in the table above do not include amounts related to these specific defined benefit plans. A plan with a defined benefit obligation of $742 million at December 31, 2014 and which used salary bands at that date is using a rate of compensation increase as at December 31, 2015. The rate of compensation increase for this plan is included in the weighted average in the above table for calculating the benefit obligation as at December 31, 2015, but is not included in the weighted average for calculating the benefit obligation as at December 31, 2014 or the periodic benefit cost for 2014 or 2015. |
| |
(2)
| Includes an inflation factor that is used to calculate future periodic benefit cost, but is not used to calculate the benefit obligation. |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
The Company establishes its estimated long-term return on plan assets considering various factors, which include the targeted asset allocation percentages, historic returns, and expected future returns.
The measurement of pension obligations, costs, and liabilities is dependent on a variety of assumptions. These assumptions include estimates of the present value of projected future pension payments to all plan participants, taking into consideration the likelihood of potential future events such as salary increases and demographic experience. These assumptions may have an effect on the amount and timing of future contributions.
The assumptions used in developing the required estimates include the following key factors: discount rates; salary growth; retirement rates; inflation; expected return on plan assets; and mortality rates.
The effects of actual results differing from the Company's assumptions are accumulated and amortized over future periods and, therefore, generally affect the Company's recognized expense in such future periods.
Effective January 1, 2016 Unrecognized gains or losses are amortized using the Company will apply a disaggregated discount rate“corridor approach, for determining service cost and interest cost for its defined” under which the net gain or loss in excess of 10% of the greater of the projected benefit pension plans and post-retirement plans inobligation or the U.S. and U.K. Refer to Note 1—General and Summarymarket-related value of Significant Accounting Policies for further information relating to this change in estimate.the assets, if applicable, is amortized.
Sensitivity of the Company's pension funded status to the indicated increase or decrease in the discount rate and long-term rate of return on plan assets assumptions is shown below. Note that these sensitivities may be asymmetric and are specific to the base conditions at year-end 2015.2018. They also may not be additive, so the impact of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown. The funded status as of December 31, 20152018 is affected by the assumptions as of that date. Pension expense for 20152018 is affected by the December 31, 20142017 assumptions. The impact on pension expense from a one percentage point change in these assumptions is shown in the following table below (in millions):
|
| | | | |
| Increase of 1% in the discount rate | | $ | (12 | ) |
| Decrease of 1% in the discount rate | | 12 |
|
| Increase of 1% in the long-term rate of return on plan assets | | (16 | ) |
| Decrease of 1% in the long-term rate of return on plan assets | | 16 |
|
|
| | | | |
| Increase of 1% in the discount rate | | $ | (32 | ) |
| Decrease of 1% in the discount rate | | 27 |
|
| Increase of 1% in the long-term rate of return on plan assets | | (36 | ) |
| Decrease of 1% in the long-term rate of return on plan assets | | 36 |
|
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
The following table summarizes the components of the net periodic benefit cost, in millions, both domestic and foreign, for the years indicated:indicated (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, | | 2018 | | 2017 | | 2016 |
| Components of Net Periodic Benefit Cost: | | U.S. | | Foreign | | U.S. | | Foreign | | U.S. | | Foreign |
| Service cost | | $ | 15 |
| | $ | 12 |
| | $ | 13 |
| | $ | 10 |
| | $ | 13 |
| | $ | 9 |
|
| Interest cost | | 40 |
| | 22 |
| | 41 |
| | 23 |
| | 42 |
| | 21 |
|
| Expected return on plan assets | | (64 | ) | | (17 | ) | | (69 | ) | | (21 | ) | | (68 | ) | | (19 | ) |
| Amortization of prior service cost | | 5 |
| | — |
| | 6 |
| | — |
| | 7 |
| | (1 | ) |
| Amortization of net loss | | 18 |
| | 3 |
| | 18 |
| | 2 |
| | 18 |
| | 2 |
|
| Curtailment loss recognized | | 1 |
| | — |
| | 4 |
| | — |
| | 4 |
| | — |
|
| Settlement loss recognized | | — |
| | 4 |
| | — |
| | — |
| | — |
| | — |
|
| Total pension cost | | $ | 15 |
| | $ | 24 |
| | $ | 13 |
| | $ | 14 |
| | $ | 16 |
| | $ | 12 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, | | 2015 | | 2014 | | 2013 |
| Components of Net Periodic Benefit Cost: | | U.S. | | Foreign | | U.S. | | Foreign | | U.S. | | Foreign |
| Service cost | | $ | 16 |
| | $ | 15 |
| | $ | 14 |
| | $ | 16 |
| | $ | 16 |
| | $ | 26 |
|
| Interest cost | | 48 |
| | 351 |
| | 50 |
| | 489 |
| | 46 |
| | 515 |
|
| Expected return on plan assets | | (70 | ) | | (247 | ) | | (67 | ) | | (362 | ) | | (64 | ) | | (484 | ) |
| Amortization of prior service cost | | 7 |
| | — |
| | 6 |
| | (1 | ) | | 5 |
| | — |
|
| Amortization of net loss | | 20 |
| | 28 |
| | 13 |
| | 37 |
| | 23 |
| | 77 |
|
| Settlement gain recognized | | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
|
| Total pension cost | | $ | 21 |
| | $ | 147 |
| | $ | 16 |
| | $ | 180 |
| | $ | 26 |
| | $ | 134 |
|
The following table summarizes in millions the amounts reflected in AOCL, including AOCL attributable to noncontrolling interests, on the Consolidated Balance Sheet as of December 31, 2015,2018, that have not yet been recognized as components of net periodic benefit cost and amounts expected to be reclassified to earnings in the next fiscal year:(in millions):
|
| | | | | | | |
| December 31, 2018 | Accumulated Other Comprehensive Income (Loss) |
| | U.S. | | Foreign |
| Prior service cost | $ | (4 | ) | | $ | 1 |
|
| Unrecognized net actuarial loss | (19 | ) | | (76 | ) |
| Total | $ | (23 | ) | | $ | (75 | ) |
|
| | | | | | | | | | | | | | | |
| December 31, 2015 | Accumulated Other Comprehensive Income (Loss) | | Amounts expected to be reclassified to earnings in next fiscal year |
| | U.S. | | Foreign | | U.S. | | Foreign |
| Prior service cost | $ | — |
| | $ | (5 | ) | | $ | — |
| | $ | — |
|
| Unrecognized net actuarial gain (loss) | (6 | ) | | (1,092 | ) | | — |
| | (18 | ) |
| Total | $ | (6 | ) | | $ | (1,097 | ) | | $ | — |
| | $ | (18 | ) |
The following table summarizes the Company's target allocation for 20152018 and pension plan asset allocation, both domestic and foreign, as of the periods indicated:
|
| | | | | | | | | | | | | | | |
| | | | | | Percentage of Plan Assets as of December 31, |
| | Target Allocations | | 2018 | | 2017 |
| Asset Category | U.S. | | Foreign | | U.S. | | Foreign | | U.S. | | Foreign |
| Equity securities | 20% | | 3% | | 16.85 | % | | 3.75 | % | | 31.90 | % | | 4.61 | % |
| Debt securities | 78% | | 94% | | 80.20 | % | | 93.57 | % | | 64.53 | % | | 93.10 | % |
| Real estate | 2% | | —% | | 2.35 | % | | 0.44 | % | | 3.20 | % | | 0.44 | % |
| Other | —% | | 3% | | 0.60 | % | | 2.24 | % | | 0.37 | % | | 1.85 | % |
| Total pension assets | | | | | 100.00 | % | | 100.00 | % | | 100.00 | % | | 100.00 | % |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
|
| | | | | | | | | | | | | | | | |
| | | | | | Percentage of Plan Assets as of December 31, |
| | Target Allocations | | 2015 | | 2014 |
| Asset Category | U.S. | | Foreign | | U.S. | | Foreign | | U.S. | | Foreign |
| Equity securities | 46 | % | | 15% -29% | | 44.76 | % | | 13.23 | % | | 44.02 | % | | 16.28 | % |
| Debt securities | 50 | % | | 60% - 85% | | 50.05 | % | | 81.10 | % | | 50.90 | % | | 78.85 | % |
| Real estate | 2 | % | | 0% - 3% | | 2.94 | % | | 3.24 | % | | 2.45 | % | | 3.15 | % |
| Other | 2 | % | | 0% - 5% | | 2.25 | % | | 2.43 | % | | 2.63 | % | | 1.72 | % |
| Total pension assets | | | | | 100.00 | % | | 100.00 | % | | 100.00 | % | | 100.00 | % |
The U.S. plansDB Plans seek to achieve the following long-term investment objectives:
maintenance of sufficient income and liquidity to pay retirement benefits and other lump sum payments;
long-term rate of return in excess of the annualized inflation rate;
long-term rate of return, net of relevant fees, that meets or exceeds the assumed actuarial rate; and
long-term competitive rate of return on investments, net of expenses, that equals or exceeds various benchmark rates.
The asset allocation is reviewed periodically to determine a suitable asset allocation which seeks to manage risk through portfolio diversification and takes into account among other possible factors, the above-stated objectives, in conjunction with current funding levels, cash flow conditions and economic and industry trends. The following table summarizes the Company's U.S. planDB Plan assets by category of investment and level within the fair value hierarchy in millions as of the periods indicated:indicated (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2015 | | December 31, 2014 |
| U.S. Plans | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
Equity securities — | Mutual funds | 457 |
| | — |
| | — |
| | 457 |
| | 467 |
| | — |
| | — |
| | 467 |
|
| Debt securities — | Government debt securities | 53 |
| | — |
| | — |
| | 53 |
| | 67 |
| | — |
| | — |
| | 67 |
|
| | Mutual funds(1) | 458 |
| | — |
| | — |
| | 458 |
| | 473 |
| | — |
| | — |
| | 473 |
|
Real Estate — | Real Estate | — |
| | 30 |
| | — |
| | 30 |
| | — |
| | 26 |
| | — |
| | 26 |
|
Other — | Cash and cash equivalents | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | — |
| | 4 |
|
| | Other investments | — |
| | 23 |
| | — |
| | 23 |
| | — |
| | 24 |
| | — |
| | 24 |
|
| | Total plan assets | $ | 968 |
| | $ | 53 |
| | $ | — |
| | $ | 1,021 |
| | $ | 1,011 |
| | $ | 50 |
| | $ | — |
| | $ | 1,061 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2018 | | December 31, 2017 |
| U.S. Plans | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Equity securities: | Mutual funds | $ | 173 |
| | $ | — |
| | $ | — |
| | $ | 173 |
| | $ | 359 |
| | $ | — |
| | $ | — |
| | $ | 359 |
|
| Debt securities: | Government debt securities | 170 |
| | — |
| | — |
| | 170 |
| | 135 |
| | — |
| | — |
| | 135 |
|
| | Mutual funds (1) | 653 |
| | — |
| | — |
| | 653 |
| | 593 |
| | — |
| | — |
| | 593 |
|
| Real estate: | Real estate | — |
| | 24 |
| | — |
| | 24 |
| | — |
| | 36 |
| | — |
| | 36 |
|
| Other: | Cash and cash equivalents | 6 |
| | — |
| | — |
| | 6 |
| | 4 |
| | — |
| | — |
| | 4 |
|
| | Total plan assets | $ | 1,002 |
| | $ | 24 |
| | $ | — |
| | $ | 1,026 |
| | $ | 1,091 |
| | $ | 36 |
| | $ | — |
| | $ | 1,127 |
|
_____________________________
| |
(1) | Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment. |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
The investment strategy of the foreign plansDB Plans seeks to maximize return on investment while minimizing risk. The assumed asset allocation has less exposure to equities in order to closely match market conditions and near term forecasts. The following table summarizes the Company's foreign DB plan assets by category of investment and level within the fair value hierarchy in millions as of the periods indicated:indicated (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2018 | | December 31, 2017 |
| Foreign Plans | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Equity securities: | Mutual funds | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
| | $ | 20 |
| | $ | — |
| | $ | — |
| | $ | 20 |
|
| | Private equity | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Debt securities: | Government debt securities | 13 |
| | — |
| | — |
| | 13 |
| | 11 |
| | — |
| | — |
| | 11 |
|
| | Mutual funds (1) | 287 |
| | 84 |
| | — |
| | 371 |
| | 323 |
| | 90 |
| | — |
| | 413 |
|
| Real estate: | Real estate | — |
| | — |
| | 2 |
| | 2 |
| | — |
| | — |
| | 2 |
| | 2 |
|
| Other: | Cash and cash equivalents | 2 |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
|
| | Other assets | 1 |
| | — |
| | 6 |
| | 7 |
| | 1 |
| | — |
| | 7 |
| | 8 |
|
| | Total plan assets | $ | 317 |
| | $ | 84 |
| | $ | 9 |
| | $ | 410 |
| | $ | 355 |
| | $ | 90 |
| | $ | 10 |
| | $ | 455 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2015 | | December 31, 2014 |
| Foreign Plans | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
Equity securities — | Common stock | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| | Mutual funds | 167 |
| | — |
| | — |
| | 167 |
| | 274 |
| | — |
| | — |
| | 274 |
|
| | Private equity(1) | — |
| | — |
| | 126 |
| | 126 |
| | — |
| | — |
| | 237 |
| | 237 |
|
Debt securities — | Certificates of deposit | — |
| | 2 |
| | — |
| | 2 |
| | — |
| | 3 |
| | — |
| | 3 |
|
| | Unsecured debentures | — |
| | 5 |
| | — |
| | 5 |
| | — |
| | 10 |
| | — |
| | 10 |
|
| | Government debt securities | 11 |
| | 79 |
| | — |
| | 90 |
| | 12 |
| | 98 |
| | — |
| | 110 |
|
| | Mutual funds(2) | 218 |
| | 1,535 |
| | — |
| | 1,753 |
| | 215 |
| | 2,236 |
| | — |
| | 2,451 |
|
| | Other debt securities | — |
| | 2 |
| | — |
| | 2 |
| | — |
| | 6 |
| | — |
| | 6 |
|
Real estate — | Real estate(1) | — |
| | — |
| | 74 |
| | 74 |
| | — |
| | — |
| | 103 |
| | 103 |
|
Other — | Cash and cash equivalents | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| | Participant loans(3) | — |
| | — |
| | 37 |
| | 37 |
| | — |
| | — |
| | 52 |
| | 52 |
|
| | Other assets | 16 |
| | — |
| | 3 |
| | 19 |
| | — |
| | — |
| | 4 |
| | 4 |
|
| | Total plan assets | $ | 421 |
| | $ | 1,623 |
| | $ | 240 |
| | $ | 2,284 |
| | $ | 523 |
| | $ | 2,353 |
| | $ | 396 |
| | $ | 3,272 |
|
| |
(1) | Plan assets of our Brazilian subsidiaries are invested in private equities and commercial real estate through the plan administrator in Brazil. The fair value of these assets is determined using the income approach through annual appraisals based on a discounted cash flow analysis. |
| |
(2)
| Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment. |
| |
(3)
| Loans to participants are stated at cost, which approximates fair value. |
The following table presents a reconciliation of all plan assets measured at fair value using significant unobservable inputs (Level 3) in millions for the periods indicated:
|
| | | | | | | | |
| December 31, | | 2015 | | 2014 |
| Balance at January 1 | | $ | 396 |
| | $ | 530 |
|
| Actual return on plan assets: | | | | |
| Returns relating to assets still held at reporting date | | (36 | ) | | (87 | ) |
| Purchases, sales and settlements, net | | — |
| | 1 |
|
| Transfers of (assets) liabilities into Level 3 | | — |
| | 5 |
|
| Change due to exchange rate changes | | (120 | ) | | (53 | ) |
| Balance at December 31 | | $ | 240 |
| | $ | 396 |
|
The following table summarizes the estimated cash flows for U.S. and foreign expected employer contributions and expected future benefit payments, both domestic and foreign in millions:(in millions):
|
| | | | | | | | |
| | | U.S. | | Foreign |
| Expected employer contribution in 2019 | | $ | 9 |
| | $ | 14 |
|
| Expected benefit payments for fiscal year ending: | | | | |
| 2019 | | 69 |
| | 23 |
|
| 2020 | | 70 |
| | 21 |
|
| 2021 | | 72 |
| | 23 |
|
| 2022 | | 72 |
| | 24 |
|
| 2023 | | 73 |
| | 25 |
|
| 2024 - 2028 | | 367 |
| | 155 |
|
|
| | | | | | | | |
| | | U.S. | | Foreign |
| Expected employer contribution in 2016 | | $ | 22 |
| | $ | 100 |
|
| Expected benefit payments for fiscal year ending: | | | | |
| 2016 | | 65 |
| | 268 |
|
| 2017 | | 67 |
| | 277 |
|
| 2018 | | 69 |
| | 289 |
|
| 2019 | | 71 |
| | 299 |
|
| 2020 | | 73 |
| | 309 |
|
| 2021 - 2025 | | 380 |
| | 1,686 |
|
16.14. EQUITY
Equity Transactions with Noncontrolling Interests
Brazil Reorganization Distributed Energy — In 2015,2018, Distributed Energy, through multiple transactions, sold noncontrolling interests in multiple project companies to tax equity partners. These transactions resulted in a $98 million increase to noncontrolling interest. Distributed Energy is reported in the CompanyUS and Utilities SBU reportable segment.
Alto Maipo — In March 2017, AES Gener completed athe legal and financial restructuring of AES Brasiliana. This transaction resulted in no change of ownership or control. The $27 million impactAlto Maipo. As part of this equity transaction was recognized in additional paid-in capital.
Gener — On November 18, 2015,restructuring, AES indirectly acquired the Company sold a 4% stake in AES Gener S.A. ("Gener") through its 99.9% owned subsidiary inversions Cachagua S.p.A ("Cachagua") for $145 million, net of transaction costs. The sale was of previously issued common shares of Gener to certain institutional investors and is not a sale of in-substance real estate. While the sale decreased Parent40% ownership interest from 70.7% to 66.7%, the Parent continues to retain its controlling financial interest in the subsidiary. The difference of $24 million between the fair value of the consideration received, net of taxes and transaction costs, and the amount by which the NCI is adjusted was recognized in additional paid-in capital. No pretax gain or loss was recognized in net income asnoncontrolling shareholder for a result of this transaction.de
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
Jordan — On March 15, 2015, the Company executed an agreement to sell 40% of its interest in
minimis payment, and sold a wholly-owned subsidiary in Jordan that owns a controlling6.7% interest in the Jordan IPP4 gas-fired plant for $30 million. The sale was completed on February 18, 2016. See Note 30—Subsequent Events for further information.
IPALCO — In February 2015, La Caisse de depot et placement du Quebec ("CDPQ") purchased 15% of AES US Investment, Inc., a wholly-owned subsidiary that owns 100% of IPALCO Enterprises, Inc. ("IPALCO"), for $247 million, with an optionproject to invest an additional $349 million in IPALCO through 2016 in exchange for a 17.65% equity stake. In April 2015, CDPQ invested $214 million of the $349 million in IPALCO, whichconstruction contractor. This transaction resulted in CDPQ's combined equity interest in IPALCOa $196 million increase to be 24.90%. Upon investing the remaining commitment of $135 million, CDPQ's equity interests in IPALCO will total 30%.
As a result of these transactions, $84 million in taxes and transaction costs were recognized as a net decreaseParent Company’s Stockholders’ Equity due to equity. The Company also recognized an increase in additional paid-in-capital of $377$229 million, offset by the reclassification of accumulated other comprehensive losses from NCI to additional paid-in capital and a reduction to retained earningsthe Parent Company Stockholders’ Equity of $377 million for the excess of the fair value of the shares over their book value. Since the noncontrolling interest is contingently redeemable, the fair value of the consideration received of $460 million, net of proportional dividends, is classified in temporary equity as redeemable stock of subsidiaries on the Consolidated Balance Sheets.$33 million. No gain or loss was recognized in net income as the sale was not considered to be a sale of in-substance real estate. Any subsequent adjustments to allocate earnings and dividends to CDPQ will be classified as noncontrollingAfter completion of the sale, the Company has an effective 62% economic interest within permanent equity and adjustments to the amount in temporary equity will occur only if and when it is probable that the shares will become redeemable.Alto Maipo. As the Company maintained control of the partnership after the sale, IPALCOAlto Maipo continues to be accounted for as a consolidated subsidiaryby the Company within the USSouth America SBU reportable segment.
Dominican Republic — In December 2014 Estrella andSeptember 2017, Linda Groups, an investor-based group in theGroup acquired 5% of our Dominican Republic acquired 8%business for $60 million, pre-tax. This transaction resulted in a net increase of $25 million to the Company’s additional paid-in-capital and noncontrolling interest, in our businesses in the Dominican Republic for $83 million, net of transaction costs, with options to acquire an additional 2% for $24 million at any time between the closing date and December 31, 2015, and an additional 10% for $125 million at any time between the closing date and December 31, 2016. In December 2015, Estrella and Linda Groups exercised its first call option of additional 2% for $18 million, net of discount and transaction costs. This resulted in Estrella and Linda Groups having a total of 10% noncontrolling interest in our businesses in the Dominican Republic.
As a result of these transactions, $29 million and $7 million, net of taxes and transaction costs, was recognized in additional paid-in capital at December 31, 2014 and 2015, respectively. No gain or loss was recognized in net income as the sale iswas not considered to be a sale of in-substance real estate. As the Company maintained control after the sale, our businesses in the Dominican Republic continue to be consolidated by the Company within the MCAC SBU reportable segment.
Masinloc — On June 25, 2014, the Company executed an agreement to sell approximately 45% of its interest in Masin-AES Pte Ltd., a wholly-owned subsidiary that owns the Company's business interests in the Philippines, for $453 million, subject to certain purchase price adjustments. On July 15, 2014, the Company completed the Masinloc sale transaction and received cumulative net proceeds of $436 million, including $23 million contingent upon the achievement of certain restructuring efficiencies. The transaction was accounted for as a sale of in-substance real estate. Noncontrolling interest of $130 million and a pretax gain on sale of investment of approximately $283 million, net of transaction costs, were recognized during the third quarter of 2014. The portion of the proceeds related to the contingency has been deferred.
After completion of the sale, the Company owns a 51% net ownership interest in Masinloc and will continue to manage and operate the plant, with 41% owned by Electricity Generating Public Company Limited and 8% owned by the International Finance Corporation. As the Company maintained control after the sale, Masinloc continues to be accounted for as a consolidated subsidiary within the Asia SBU reportable segment.
The following table summarizes the net income attributable to The AES Corporation and all transfers (to) from noncontrolling interests in millions for the periods indicated:indicated (in millions):
|
| | | | | | | | | | | | |
| | | December 31, |
| | | 2018 | | 2017 | | 2016 |
| Net income (loss) attributable to The AES Corporation | | $ | 1,203 |
| | $ | (1,161 | ) | | $ | (1,130 | ) |
| Transfers from noncontrolling interest: | | | | | | |
| Increase (decrease) in The AES Corporation's paid-in capital for sale of subsidiary shares | | (3 | ) | | 13 |
| | 84 |
|
Additional paid-in-capital, IPALCO shares, transferred to redeemable stock of subsidiaries (1) | | — |
| | — |
| | (84 | ) |
| Increase (decrease) in The AES Corporation's paid-in-capital for purchase of subsidiary shares | | — |
| | 240 |
| | (2 | ) |
| Net transfers (to) from noncontrolling interest | | (3 | ) | | 253 |
| | (2 | ) |
| Change from net income (loss) attributable to The AES Corporation and transfers (to) from noncontrolling interests | | $ | 1,200 |
| | $ | (908 | ) | | $ | (1,132 | ) |
|
| | | | | | | | |
| | | December 31, |
| | | 2015 | | 2014 |
| Net income attributable to The AES Corporation | | $ | 306 |
| | $ | 769 |
|
| Transfers from the noncontrolling interest: | | | | |
| Net increase in The AES Corporation's paid-in capital for sale of subsidiary shares | | 323 |
| | 29 |
|
Additional paid-in capital, IPALCO shares, transferred to redeemable stock of subsidiaries (1) | | (377 | ) | | — |
|
| Increase in The AES Corporation's paid-in capital for purchase of subsidiary shares | | — |
| | 7 |
|
| Net transfers (to) from noncontrolling interest | | (54 | ) | | 36 |
|
| Change from net income attributable to The AES Corporation and transfers (to) from noncontrolling interests | | $ | 252 |
| | $ | 805 |
|
Accumulated Other Comprehensive Loss — The changes in AOCL by component, net of tax and noncontrolling interests, for the periods indicated were as follows (in millions):
(1) See Note19—Redeemable stock of subsidiaries for further information on increase in paid-in capital transferred to redeemable stock of subsidiaries. |
| | | | | | | | | | | | | | | |
| | Foreign currency translation adjustment, net | | Derivative gains (losses), net | | Unfunded pension obligations, net | | Total |
| Balance at December 31, 2016 | $ | (2,147 | ) | | $ | (323 | ) | | $ | (286 | ) | | $ | (2,756 | ) |
| Other comprehensive income (loss) before reclassifications | 18 |
| | (14 | ) | | (19 | ) | | (15 | ) |
| Amount reclassified to earnings | 643 |
| | 37 |
| | 248 |
| | 928 |
|
| Other comprehensive income | $ | 661 |
| | $ | 23 |
| | $ | 229 |
| | $ | 913 |
|
| Reclassification from NCI due to Alto Maipo Restructuring | — |
| | (33 | ) | | — |
| | (33 | ) |
| Balance at December 31, 2017 | $ | (1,486 | ) | | $ | (333 | ) | | $ | (57 | ) | | $ | (1,876 | ) |
| Other comprehensive income (loss) before reclassifications | $ | (214 | ) | | $ | (64 | ) | | $ | — |
| | $ | (278 | ) |
| Amount reclassified to earnings | (21 | ) | | 78 |
| | 7 |
| | 64 |
|
| Other comprehensive income (loss) | $ | (235 | ) | | $ | 14 |
| | $ | 7 |
| | $ | (214 | ) |
| Cumulative effect of a change in accounting principle | — |
| | 19 |
| | — |
| | 19 |
|
| Balance at December 31, 2018 | $ | (1,721 | ) | | $ | (300 | ) | | $ | (50 | ) | | $ | (2,071 | ) |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 2013
Accumulated Other Comprehensive Loss
The changes in AOCL by component, net of tax and noncontrolling interests in millions for the year endedDecember 31, 2015 were as follows:
|
| | | | | | | | | | | | | | | |
| | Foreign currency translation adjustment, net | | Unrealized derivative losses, net | | Unfunded pension obligations, net | | Total |
| Balance at the beginning of the period | $ | (2,595 | ) | | $ | (396 | ) | | $ | (295 | ) | | $ | (3,286 | ) |
| Other comprehensive (loss) income before reclassifications | (674 | ) | | (5 | ) | | 19 |
| | (660 | ) |
| Amount reclassified to earnings | $ | — |
| | $ | 48 |
| | $ | 2 |
| | 50 |
|
| Other comprehensive (loss) income | (674 | ) | | 43 |
| | 21 |
| | (610 | ) |
| Cumulative effect of a change in accounting principle | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 13 |
|
| Balance at the end of the period | (3,256 | ) | | (353 | ) | | (274 | ) | | (3,883 | ) |
Reclassifications out of AOCL are presented in the following table. Amounts for the periods indicated were as follows (in millions):are in millions and those in parenthesis indicate debits to the Consolidated Statements of Operations:
|
| | | | | | | | | | | | | | |
| Details About | | | | December 31, |
| AOCL Components | | Affected Line Item in the Consolidated Statements of Operations | | 2018 | | 2017 | | 2016 |
| Foreign currency translation adjustments, net | | | | |
| | | Gain (loss) on disposal and sale of business interests | | $ | 19 |
| | $ | (188 | ) | | $ | — |
|
| | | Net loss from disposal and impairments of discontinued operations | | 2 |
| | (455 | ) | | (992 | ) |
| | | Net income (loss) attributable to The AES Corporation | | $ | 21 |
| | $ | (643 | ) | | $ | (992 | ) |
| Derivative gains (losses), net | | | | |
| | | Non-regulated revenue | | $ | (6 | ) | | $ | 25 |
| | $ | 111 |
|
| | | Non-regulated cost of sales | | (3 | ) | | (12 | ) | | (57 | ) |
| | | Interest expense | | (49 | ) | | (79 | ) | | (107 | ) |
| | | Foreign currency transaction gains | | (59 | ) | | 15 |
| | 8 |
|
| | | Income from continuing operations before taxes and equity in earnings of affiliates | | (117 | ) | | (51 | ) | | (45 | ) |
| | | Income tax expense | | 24 |
| | 1 |
| | 8 |
|
| | | Income (loss) from continuing operations | | (93 | ) | | (50 | ) | | (37 | ) |
| | | Less: (Income) loss from continuing operations attributable to noncontrolling interests | | 15 |
| | 13 |
| | 9 |
|
| | | Net income (loss) attributable to The AES Corporation | | $ | (78 | ) | | $ | (37 | ) | | $ | (28 | ) |
| Amortization of defined benefit pension actuarial losses, net | | | | |
| | | Non-regulated cost of sales | | — |
| | 1 |
| | — |
|
| | | General and administrative expenses | | — |
| | (1 | ) | | (1 | ) |
| | | Other expense | | (6 | ) | | — |
| | (1 | ) |
| | | Income from continuing operations before taxes and equity in earnings of affiliates | | (6 | ) | | — |
| | (2 | ) |
| | | Income tax expense | | 2 |
| | — |
| | 3 |
|
| | | Income from continuing operations | | (4 | ) | | — |
| | 1 |
|
| | | Net loss from disposal and impairments of discontinued operations | | (2 | ) | | (266 | ) | | (11 | ) |
| | | Net income (loss) | | (6 | ) | | (266 | ) | | (10 | ) |
| | | Less: (Income) loss from continuing operations attributable to noncontrolling interests | | (1 | ) | | — |
| | 9 |
|
| | | Add: Loss from discontinued operations attributable to noncontrolling interests | | — |
| | 18 |
| | — |
|
| | | Net income (loss) attributable to The AES Corporation | | $ | (7 | ) | | $ | (248 | ) | | $ | (1 | ) |
| Total reclassifications for the period, net of income tax and noncontrolling interests | | $ | (64 | ) | | $ | (928 | ) | | $ | (1,021 | ) |
|
| | | | | | | | | | | | | | |
| Details About | | | | December 31, |
| AOCL Components | | Affected Line Item in the Consolidated Statements of Operations | | 2015 | | 2014 | | 2013 |
| Foreign currency translation adjustment, net | | | | |
| | | Gain on sale of businesses | | $ | — |
| | $ | 4 |
| | $ | (2 | ) |
| | | Net loss from disposal and impairments of discontinued operations | | — |
| | (38 | ) | | (35 | ) |
| | | Net income attributable to The AES Corporation | | $ | — |
| | $ | (34 | ) | | $ | (37 | ) |
| Unrealized derivative gains (losses), net | | | | |
| | | Non-regulated revenue | | $ | 43 |
| | $ | 30 |
| | $ | (3 | ) |
| | | Non-regulated cost of sales | | (14 | ) | | (4 | ) | | (7 | ) |
| | | Interest expense | | (112 | ) | | (139 | ) | | (137 | ) |
| | | Gain on sale of businesses | | (4 | ) | | — |
| | (21 | ) |
| | | Foreign currency transaction gains (losses) | | 12 |
| | (9 | ) | | (6 | ) |
| | | Income from continuing operations before taxes and equity in earnings of affiliates | | (75 | ) | | (122 | ) | | (174 | ) |
| | | Income tax expense | | 11 |
| | 26 |
| | 41 |
|
| | | Net equity in earnings of affiliates | | (2 | ) | | (3 | ) | | (6 | ) |
| | | Income from continuing operations | | (66 | ) | | (99 | ) | | (139 | ) |
| | | Less: (Income) from continuing operations attributable to noncontrolling interests | | 18 |
| | 27 |
| | 11 |
|
| | | Net income attributable to The AES Corporation | | $ | (48 | ) |
| $ | (72 | ) | | $ | (128 | ) |
| Amortization of defined benefit pension actuarial loss, net | | | | |
| | | Regulated cost of sales | | $ | (25 | ) | | $ | (33 | ) | | $ | (73 | ) |
| | | Non-regulated cost of sales | | 2 |
| | (5 | ) | | (4 | ) |
| | | General and administrative expenses | | (2 | ) | | — |
| | (1 | ) |
| | | Income from continuing operations before taxes and equity in earnings of affiliates | | (25 | ) |
| (38 | ) | | (78 | ) |
| | | Income tax expense | | 9 |
| | 7 |
| | 26 |
|
| | | Income from continuing operations | | (16 | ) |
| (31 | ) | | (52 | ) |
| | | Net loss from disposal and impairments of discontinued operations | | — |
| | 2 |
| | — |
|
| | | Net Income | | (16 | ) | | (29 | ) | | (52 | ) |
| | | Less: (Income) from continuing operations attributable to noncontrolling interests | | 14 |
| | 19 |
| | 39 |
|
| | | Net income attributable to The AES Corporation | | $ | (2 | ) |
| $ | (10 | ) | | $ | (13 | ) |
| Total reclassifications for the period, net of income tax and noncontrolling interests | | $ | (50 | ) |
| $ | (116 | ) | | $ | (178 | ) |
_____________________________
| |
(1)
| Amounts in parentheses indicate debits to the Consolidated Statements of Operations. |
Common Stock Dividends — The Parent Company paid dividends of $0.10$0.13 per outstanding share to its common stockholders during the first, second, third and fourth quarters of 20152018 for dividends declared in December 2014, April 2015,2017, February, July 2015 and October 2015.2018, respectively.
On December 11, 2015,7, 2018, the Board of Directors declared a quarterly common stock dividend of $0.11$0.1365 per share payable on February 16, 201615, 2019 to shareholders of record at the close of business on February 2, 2016.1, 2019.
Secondary Offering and Concurrent Stock Repurchase — On May 18, 2015, the Parent Company completed an underwritten secondary public offering (the "Offering") of approximately 60 million shares of its common stock by the Terrific Investment Corporation (the "Selling Stockholder"), a subsidiary controlled by China Investment Corporation at a price of $13.25 per share. Of the 60 million shares, 40 million were sold to the market and 20 million were reserved to be repurchased by the Parent Company. The Parent Company did not receive any of the proceeds from the Offering and the Selling Stockholder has fully sold its stake in AES common stock. Concurrent with this offering, on May 18, 2015, the Parent Company completed the repurchase of the 20 million shares of its common stock from the Selling Stockholder at a price per share of $13.07, for an aggregate purchase price of $261 million.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
Stock Repurchase Program — In October 2015, the Company's Board of Directors authorized an increase to the Company's common stock repurchase program (the "Program") for up to an additional $400 million of repurchases of the Company's common stock, bringing the cumulative total of authorized repurchases under the Program to $2.1 billion.
During the year ended December 31, 2015, the CompanyNo shares were repurchased 39.7 million shares of its common stock under the Program at a total cost of $482 million under the existing stock repurchase program.in 2018. The cumulative repurchaserepurchases from the commencement of the Program in July 2010 through December 31, 20152018 totaled 145.6154.3 million shares for a total cost of $1.8$1.9 billion, at an average price per share of $12.31$12.12 (including a nominal amount of commissions). As of December 31, 2015, $3432018, $264 million remained available for repurchase under the Program.
The common stock repurchased has been classified as treasury stock and accounted for using the cost method. A total of 149,037,831154,905,595 and 110,687,849155,924,785 shares were held as treasury stock at December 31, 20152018 and 20142017, respectively. Restricted stock units under the Company's employee benefit plans are issued from treasury stock. The Company has not retired any common stock repurchased since it began the Program in July 2010.
17.15. SEGMENTS AND GEOGRAPHIC INFORMATION
The segment reporting structure uses the Company's organizationalmanagement reporting structure as its foundation to reflect how the Company manages the businesses internally and is mainly organized by geographic regions which provide betterprovides a socio-political-economic understanding of our business. 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. The Companymanagement reporting structure is organized by sixfour SBUs led by our President and Chief Executive Officer: US Andes, Brazil,and Utilities, South America, MCAC, Europe, and AsiaEurasia SBUs. Using the accounting guidance on segment reporting, the Company determined that it has sixits four operating and sixsegments are aligned with its four reportable segments corresponding to its SBUs. All prior period results have been retrospectively revised to reflect the new segment reporting structure.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Corporate and Other — CorporateThe results of the Fluence and Simple Energy equity affiliates are included in "Corporate and Other". Also included are the results of the AES self-insurance company and corporate overhead costs which are not directly associated with the operations of our sixfour reportable segments, are included in "Corporate and Other." Also included are certain intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.
The Company uses Adjusted PTC as its primary segment performance measure. Adjusted PTC, a non-GAAP measure, is defined by the Company as 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; (c) gains, losses, gains or losses due tobenefits and costs associated with dispositions and acquisitions of business interests, including early plant closures; (d) losses due to impairmentsimpairments; (e) gains, losses and 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. The Company has concluded that Adjusted PTC bestbetter reflects the underlying business performance of the Company and is the most relevant measure considered in the Company's internal evaluation of the financial performance of its segments. Additionally, given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure that better assists investors in determining which businesses have the greatest impact on the Company's results.
Revenue and Adjusted PTC are presented before intersegmentinter-segment eliminations, which includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees, and the write-off of intercompany balances, as applicable. All intra-segment activity has been eliminated within the segment. Inter-segment activity has been eliminated within the total consolidated results.
The following tables present financial information by segment for the periods indicated (in millions):
|
| | | | | | | | | | | |
| | Total Revenue |
| Year Ended December 31, | 2018 | | 2017 | | 2016 |
| US and Utilities SBU | $ | 4,230 |
| | $ | 4,162 |
| | $ | 4,330 |
|
| South America SBU | 3,533 |
| | 3,252 |
| | 2,956 |
|
| MCAC SBU | 1,728 |
| | 1,519 |
| | 1,274 |
|
| Eurasia SBU | 1,255 |
| | 1,590 |
| | 1,670 |
|
| Corporate and Other | 41 |
| | 35 |
| | 77 |
|
| Eliminations | (51 | ) | | (28 | ) | | (26 | ) |
| Total Revenue | $ | 10,736 |
| | $ | 10,530 |
| | $ | 10,281 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Revenue Year Ended December 31, | Total Revenue | | Intersegment | | External Revenue |
| 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 |
| US SBU | $ | 3,593 |
| | $ | 3,826 |
| | $ | 3,630 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3,593 |
| | $ | 3,826 |
| | $ | 3,630 |
|
| Andes SBU | 2,489 |
| | 2,642 |
| | 2,639 |
| | (10 | ) | | (4 | ) | | (1 | ) | | 2,479 |
| | 2,638 |
| | 2,638 |
|
| Brazil SBU | 4,666 |
| | 6,009 |
| | 5,015 |
| | — |
| | — |
| | — |
| | 4,666 |
| | 6,009 |
| | 5,015 |
|
| MCAC SBU | 2,353 |
| | 2,682 |
| | 2,713 |
| | (2 | ) | | (2 | ) | | (1 | ) | | 2,351 |
| | 2,680 |
| | 2,712 |
|
| Europe SBU | 1,191 |
| | 1,439 |
| | 1,347 |
| | (4 | ) | | (6 | ) | | — |
| | 1,187 |
| | 1,433 |
| | 1,347 |
|
| Asia SBU | 684 |
| | 558 |
| | 550 |
| | — |
| | — |
| | — |
| | 684 |
| | 558 |
| | 550 |
|
| Corporate and Other | 31 |
| | 15 |
| | 7 |
| | (28 | ) | | (13 | ) | | (8 | ) | | 3 |
| | 2 |
| | (1 | ) |
| Total Revenue | $ | 15,007 |
| | $ | 17,171 |
| | $ | 15,901 |
| | $ | (44 | ) | | $ | (25 | ) | | $ | (10 | ) | | $ | 14,963 |
| | $ | 17,146 |
| | $ | 15,891 |
|
|
| | | | | | | | | | | |
| Reconciliation from Income from Continuing Operations before Taxes and Equity in Earnings of Affiliates: | Total Adjusted PTC |
| Year Ended December 31, | 2018 | | 2017 | | 2016 |
| Income from continuing operations before taxes and equity in earnings of affiliates | $ | 2,018 |
| | $ | 771 |
| | $ | 187 |
|
| Add: Net equity earnings in affiliates | 39 |
| | 71 |
| | 36 |
|
| Less: Income from continuing operations before taxes, attributable to noncontrolling interests | (509 | ) | | (521 | ) | | (354 | ) |
| Pre-tax contribution | 1,548 |
| | 321 |
| | (131 | ) |
| Unrealized derivative 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 | — |
| | 31 |
| | — |
|
| Total Adjusted PTC | $ | 1,185 |
| | $ | 1,017 |
| | $ | 850 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Adjusted Pretax Contribution
Year Ended December 31, | Total Adjusted PTC | | Intersegment | | External Adjusted PTC |
| 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 |
| US SBU | $ | 360 |
| | $ | 445 |
| | 440 |
| | $ | 12 |
| | $ | 10 |
| | 11 |
| | $ | 372 |
| | $ | 455 |
| | $ | 451 |
|
| Andes SBU | 482 |
| | 421 |
| | 353 |
| | 17 |
| | 6 |
| | 19 |
| | 499 |
| | 427 |
| | 372 |
|
| Brazil SBU | 91 |
| | 242 |
| | 212 |
| | 2 |
| | 3 |
| | 3 |
| | 93 |
| | 245 |
| | 215 |
|
| MCAC SBU | 327 |
| | 352 |
| | 339 |
| | 18 |
| | 26 |
| | 12 |
| | 345 |
| | 378 |
| | 351 |
|
| Europe SBU | 235 |
| | 348 |
| | 345 |
| | 5 |
| | 5 |
| | 7 |
| | 240 |
| | 353 |
| | 352 |
|
| Asia SBU | 96 |
| | 46 |
| | 142 |
| | 3 |
| | 2 |
| | 2 |
| | 99 |
| | 48 |
| | 144 |
|
| Corporate and Other | (441 | ) | | (533 | ) | | (624 | ) | | (57 | ) | | (52 | ) | | (54 | ) | | (498 | ) | | (585 | ) | | (678 | ) |
| Total Adjusted Pretax Contribution | 1,150 |
| | 1,321 |
| | 1,207 |
| | — |
| | — |
| | — |
| | 1,150 |
| | 1,321 |
| | 1,207 |
|
|
| | | | | | | | | | | |
| | Total Adjusted PTC |
| Year Ended December 31, | 2018 | | 2017 | | 2016 |
| US and Utilities SBU | $ | 511 |
| | $ | 424 |
| | $ | 392 |
|
| South America SBU | 519 |
| | 446 |
| | 428 |
|
| MCAC SBU | 300 |
| | 277 |
| | 222 |
|
| Eurasia SBU | 222 |
| | 290 |
| | 283 |
|
| Corporate, Other and Eliminations | (367 | ) | | (420 | ) | | (475 | ) |
| Total Adjusted PTC | $ | 1,185 |
| | $ | 1,017 |
| | $ | 850 |
|
|
| | | | | | | | | | | |
| Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates: | | |
| Non-GAAP Adjustments: | | | | | |
| Unrealized derivative gains | 166 |
| | 135 |
| | 57 |
|
| Unrealized foreign currency losses | (96 | ) | | (110 | ) | | (41 | ) |
| Disposition/acquisition gains | 42 |
| | 361 |
| | 30 |
|
| Impairment losses | (504 | ) | | (416 | ) | | (588 | ) |
| Loss on extinguishment of debt | (183 | ) | | (274 | ) | | (225 | ) |
| Pre-tax contribution | 575 |
| | 1,017 |
| | 440 |
|
| Add: Income from continuing operations before taxes, attributable to noncontrolling interests | 652 |
| | 578 |
| | 633 |
|
| Less: Net equity in earnings of affiliates | 105 |
| | 19 |
| | 25 |
|
| Income from continuing operations before taxes and equity in earnings of affiliates | $ | 1,122 |
| | $ | 1,576 |
| | $ | 1,048 |
|
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 2013
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total Assets | | Depreciation and Amortization | | Capital Expenditures |
| Year Ended December 31, | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 |
| US SBU | $ | 9,844 |
| | $ | 10,062 |
| | $ | 9,952 |
| | $ | 443 |
| | $ | 450 |
| | $ | 440 |
| | $ | 861 |
| | $ | 534 |
| | $ | 426 |
|
| Andes SBU | 8,744 |
| | 7,888 |
| | 7,356 |
| | 175 |
| | 182 |
| | 186 |
| | 949 |
| | 702 |
| | 471 |
|
| Brazil SBU | 6,422 |
| | 8,439 |
| | 8,388 |
| | 185 |
| | 260 |
| | 259 |
| | 299 |
| | 416 |
| | 588 |
|
| MCAC SBU | 4,830 |
| | 4,948 |
| | 5,075 |
| | 155 |
| | 144 |
| | 145 |
| | 201 |
| | 192 |
| | 111 |
|
| Europe SBU | 3,127 |
| | 3,525 |
| | 4,191 |
| | 134 |
| | 154 |
| | 155 |
| | 118 |
| | 228 |
| | 341 |
|
| Asia SBU | 3,197 |
| | 2,972 |
| | 2,810 |
| | 32 |
| | 32 |
| | 33 |
| | 13 |
| | 429 |
| | 576 |
|
| Assets held-for-sale | 96 |
| | — |
| | 1,718 |
| | — |
| | (1 | ) | | 55 |
| | — |
| | 13 |
| | 52 |
|
| Corporate and Other | 590 |
| | 1,132 |
| | 921 |
| | 20 |
| | 24 |
| | 21 |
| | 17 |
| | 30 |
| | 14 |
|
| Total | $ | 36,850 |
| | $ | 38,966 |
| | $ | 40,411 |
| | $ | 1,144 |
| | $ | 1,245 |
| | $ | 1,294 |
| | $ | 2,458 |
| | $ | 2,544 |
| | $ | 2,579 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total Assets | | Depreciation and Amortization | | Capital Expenditures |
| Year Ended December 31, | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| US and Utilities SBU | $ | 12,286 |
| | $ | 11,548 |
| | $ | 10,815 |
| | $ | 449 |
| | $ | 487 |
| | $ | 519 |
| | $ | 1,373 |
| | $ | 905 |
| | $ | 858 |
|
| South America SBU | 10,941 |
| | 11,126 |
| | 10,487 |
| | 300 |
| | 301 |
| | 251 |
| | 662 |
| | 477 |
| | 569 |
|
| MCAC SBU | 4,462 |
| | 4,087 |
| | 3,680 |
| | 141 |
| | 122 |
| | 117 |
| | 302 |
| | 435 |
| | 431 |
|
| Eurasia SBU | 4,538 |
| | 6,002 |
| | 5,777 |
| | 99 |
| | 127 |
| | 149 |
| | 51 |
| — |
| 211 |
| — |
| 279 |
|
| Discontinued operations | — |
| | 86 |
| | 4,936 |
| | — |
| | 123 |
| | 128 |
| | — |
| | 315 |
| | 303 |
|
| Corporate, Other and Eliminations | 294 |
| | 263 |
| | 429 |
| | 14 |
| | 9 |
| | 12 |
| | 8 |
| | 13 |
| | 18 |
|
| Total | $ | 32,521 |
| | $ | 33,112 |
| | $ | 36,124 |
| | $ | 1,003 |
| | $ | 1,169 |
| | $ | 1,176 |
| | $ | 2,396 |
| | $ | 2,356 |
| | $ | 2,458 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Interest Income | | Interest Expense |
| Year Ended December 31, | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 |
| US SBU | $ | — |
| | $ | — |
| | $ | — |
| | $ | 262 |
| | $ | 285 |
| | $ | 290 |
|
| Andes SBU | 77 |
| | 87 |
| | 37 |
| | 154 |
| | 160 |
| | 135 |
|
| Brazil SBU | 299 |
| | 249 |
| | 210 |
| | 349 |
| | 331 |
| | 364 |
|
| MCAC SBU | 30 |
| | 26 |
| | 20 |
| | 179 |
| | 178 |
| | 138 |
|
| Europe SBU | 1 |
| | 1 |
| | 2 |
| | 73 |
| | 98 |
| | 80 |
|
| Asia SBU | 115 |
| | 2 |
| | 6 |
| | 85 |
| | 25 |
| | 30 |
|
| Corporate and Other | 2 |
| | — |
| | — |
| | 334 |
| | 394 |
| | 445 |
|
| Total | $ | 524 |
| | $ | 365 |
| | $ | 275 |
| | $ | 1,436 |
| | $ | 1,471 |
| | $ | 1,482 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Interest Income | | Interest Expense |
| Year Ended December 31, | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| US and Utilities SBU | $ | 10 |
| | $ | 5 |
| | $ | 4 |
| | $ | 287 |
| | $ | 315 |
| | $ | 299 |
|
| South America SBU | 92 |
| | 95 |
| | 95 |
| | 283 |
| | 297 |
| | 247 |
|
| MCAC SBU | 20 |
| | 13 |
| | 7 |
| | 124 |
| | 111 |
| | 100 |
|
| Eurasia SBU | 186 |
| | 130 |
| | 139 |
| | 145 |
| | 167 |
| | 179 |
|
| Corporate, Other and Eliminations | 2 |
| | 1 |
| | — |
| | 217 |
| | 280 |
| | 309 |
|
| Total | $ | 310 |
| | $ | 244 |
| | $ | 245 |
| | $ | 1,056 |
| | $ | 1,170 |
| | $ | 1,134 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Investments in and Advances to Affiliates | | Net Equity in Earnings of Affiliates |
| Year Ended December 31, | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| US and Utilities SBU | $ | 538 |
| | $ | 535 |
| | $ | 23 |
| | $ | 35 |
| | $ | 41 |
| | $ | 9 |
|
| South America SBU | 213 |
| | 358 |
| | 363 |
| | 15 |
| | 28 |
| | 15 |
|
| MCAC SBU | 5 |
| | (5 | ) | | (1 | ) | | (7 | ) | | (4 | ) | | (2 | ) |
| Eurasia SBU | 293 |
| | 307 |
| | 236 |
| | 14 |
| | 9 |
| | 13 |
|
| Corporate, Other and Eliminations | 65 |
| | 2 |
| | — |
| | (18 | ) | | (3 | ) | | 1 |
|
| Total | $ | 1,114 |
| | $ | 1,197 |
| | $ | 621 |
| | $ | 39 |
| | $ | 71 |
| | $ | 36 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Investments in and Advances to Affiliates | | Equity in Earnings (Losses) |
| Year Ended December 31, | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 |
| US SBU | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Andes SBU | 345 |
| | 287 |
| | 248 |
| | 83 |
| | 42 |
| | 44 |
|
| Brazil SBU | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| MCAC SBU | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
| Europe SBU | 53 |
| | 54 |
| | 286 |
| | 10 |
| | (25 | ) | | (5 | ) |
| Asia SBU | 195 |
| | 194 |
| | 186 |
| | 8 |
| | 10 |
| | 10 |
|
| Corporate and Other | 16 |
| | 1 |
| | 289 |
| | 4 |
| | (8 | ) | | (28 | ) |
| Total | $ | 610 |
| | $ | 537 |
| | $ | 1,010 |
| | $ | 105 |
| | $ | 19 |
| | $ | 25 |
|
The following table below presents information, by country, about the Company's consolidated operations for each of the three years ended December 31, 2015, 2014,2018, 2017, and 2013,2016, and as of December 31, 20152018 and 2014 in millions.2017 (in millions). Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
|
| | | | | | | | | | | | | | | | | | | |
| | Total Revenue | | Property, Plant & Equipment, net |
| Year Ended December 31, | 2018 | | 2017 | | 2016 | | 2018 | | 2017 |
United States (1) | $ | 3,462 |
| | $ | 3,487 |
| | $ | 3,790 |
| | $ | 8,731 |
| | $ | 7,968 |
|
| Non-U.S.: | | | | | | | | | |
| Chile | 2,087 |
| | 1,944 |
| | 1,707 |
| | 5,453 |
| | 5,066 |
|
| Dominican Republic | 884 |
| | 826 |
| | 614 |
| | 903 |
| | 935 |
|
| El Salvador | 768 |
| | 686 |
| | 601 |
| | 334 |
| | 340 |
|
| Brazil | 527 |
| | 541 |
| | 450 |
| | 1,287 |
| | 1,286 |
|
| Argentina | 487 |
| | 435 |
| | 359 |
| | 234 |
| | 223 |
|
| Panama | 438 |
| | 338 |
| | 312 |
| | 1,777 |
| | 1,615 |
|
| Colombia | 428 |
| | 332 |
| | 437 |
| | 302 |
| | 332 |
|
| Bulgaria | 426 |
| | 367 |
| | 334 |
| | 1,183 |
| | 1,290 |
|
| Mexico | 399 |
| | 352 |
| | 342 |
| | 666 |
| | 687 |
|
| United Kingdom | 390 |
| | 328 |
| | 337 |
| | 90 |
| | 108 |
|
Vietnam (2) | 245 |
| | 278 |
| | 340 |
| | 2 |
| | 2 |
|
| Jordan | 95 |
| | 95 |
| | 136 |
| | 418 |
| | 431 |
|
Philippines (3) | 93 |
| | 449 |
| | 401 |
| | — |
| | — |
|
| Kazakhstan | — |
| | 67 |
| | 103 |
| | — |
| | — |
|
| Other Non-U.S. | 7 |
| | 5 |
| | 18 |
| | 16 |
| | 13 |
|
| Total Non-U.S. | 7,274 |
| | 7,043 |
| | 6,491 |
| | 12,665 |
| | 12,328 |
|
| Total | $ | 10,736 |
| | $ | 10,530 |
| | $ | 10,281 |
| | $ | 21,396 |
| | $ | 20,296 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Revenue | | Property, Plant & Equipment, net |
| Year Ended December 31, | 2015 | | 2014 | | 2013 | | 2015 | | 2014 |
United States(1) | $ | 3,597 |
| | $ | 3,828 |
| | $ | 3,630 |
| | $ | 8,028 |
| | $ | 7,713 |
|
| Non-U.S.: | | | | | | | | | |
| Brazil | 4,666 |
| | 6,009 |
| | 5,015 |
| | 3,286 |
| | 4,725 |
|
| Chile | 1,523 |
| | 1,624 |
| | 1,569 |
| | 4,596 |
| | 4,012 |
|
| El Salvador | 736 |
| | 832 |
| | 860 |
| | 318 |
| | 304 |
|
| Dominican Republic | 632 |
| | 802 |
| | 832 |
| | 783 |
| | 702 |
|
| Colombia | 557 |
| | 552 |
| | 523 |
| | 446 |
| | 430 |
|
| Philippines | 406 |
| | 451 |
| | 497 |
| | 736 |
| | 752 |
|
| Argentina | 399 |
| | 463 |
| | 545 |
| | 193 |
| | 222 |
|
| United Kingdom | 396 |
| | 533 |
| | 558 |
| | 191 |
| | 324 |
|
| Mexico | 383 |
| | 434 |
| | 440 |
| | 716 |
| | 733 |
|
| Bulgaria | 382 |
| | 410 |
| | 422 |
| | 1,259 |
| | 1,457 |
|
| Puerto Rico | 302 |
| | 348 |
| | 328 |
| | 599 |
| | 551 |
|
| Panama | 297 |
| | 263 |
| | 250 |
| | 1,028 |
| | 1,030 |
|
| Jordan | 248 |
| | 262 |
| | 142 |
| | 470 |
| | 484 |
|
Vietnam(2) | 233 |
| | — |
| | — |
| | 2 |
| | 1,491 |
|
| Kazakhstan | 155 |
| | 161 |
| | 156 |
| | 146 |
| | 206 |
|
| Sri Lanka | 45 |
| | 107 |
| | 53 |
| | — |
| | 7 |
|
Cameroon(3) | — |
| | — |
| | — |
| | — |
| | — |
|
Ukraine(4) | — |
| | — |
| | — |
| | — |
| | — |
|
Other Non-U.S. (5) | 6 |
| | 67 |
| | 71 |
| | 19 |
| | 8 |
|
| Total Non-U.S. | 11,366 |
| | 13,318 |
| | 12,261 |
| | 14,788 |
| | 17,438 |
|
| Total | $ | 14,963 |
| | $ | 17,146 |
| | $ | 15,891 |
| | $ | 22,816 |
| | $ | 25,151 |
|
| |
(1) | Excludes revenueIncludes Puerto Rico revenues of $2$257 million, $247 million and $23$301 million for the years ended December 31, 20142018, 2017 and 2013,2016, respectively, related to Condon and Mid-West Wind, which are reflectedproperty, plant & equipment of $553 million and $565 million as discontinued operations in the accompanying Consolidated Statements of Operations.December 31, 2018 and 2017, respectively. |
| |
(2) | Property, plant & equipment as of December 31, 2015 includesThe Mong Duong II power project is operated under a build, operate and transfer contract. Future expected payments for the impact of adopting ASU No. 2014-05, Service Concession Arrangements,construction performance obligation are recognized in Loan receivable on a modified retrospective basis as of January 1, 2015.the Consolidated Balance Sheets. See Note 1—General and Summary of Significant Accounting Policies18—Revenuefor morefurther information. |
| |
(3) | Excludes revenueThe Masinloc property, plant and equipment was classified as held-for-sale as of $230 million and $473 million for the years ended December 31, 20142017, and 2013, respectively, related to Sonel, which is reflected as discontinueddeconsolidated upon completion of the sale in March 2018. See Note 23—Held-For-Sale and Dispositions for further information. |
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
operations in the accompanying Consolidated Statements of Operations.
| |
(4)
| Excludes revenue of $187 million for the years ended December 31, 2013 related to Kievoblenergo and Rivnooblenergo, which are reflected as discontinued operations in the accompanying Consolidated Statements of Operations. |
| |
(5)
| Excludes revenue of $6 million for the years ended December 31, 2013 related to Saurashtra, which is reflected as discontinued operations in the accompanying Consolidated Statements of Operations. |
18.16. SHARE-BASED COMPENSATION
STOCK OPTIONS — AES grants options to purchase shares of common stock under stock option plans to employees and non-employee directors. Under the terms of the plans, the Company may issue options to purchase shares of the Company's common stock at a price equal to 100% of the market price at the date the option is granted. Stock options are generally granted based upon a percentage of an employee's base salary. Stock options issued under these plans in 2015, 2014 and 2013 have a three-year vesting schedule and vest in one-third increments over the three-year period. The stock options have a contractual term of ten years. At December 31, 2015, approximately 16 million shares were remaining for award under the plans. In all circumstances, stock options granted by AES do not entitle the holder the right, or obligate AES, to settle the stock option in cash or other assets of AES.
The following table presents the weighted average fair value of each option grant and the underlying weighted average assumptions, as of the grant date, using the Black-Scholes option-pricing model:
|
| | | | | | | | | | | | |
| December 31, | | 2015 | | 2014 | | 2013 |
| Expected volatility | | 25 | % | | 24 | % | | 23 | % |
| Expected annual dividend yield | | 3 | % | | 1 | % | | 1 | % |
| Expected option term (years) | | 7 |
| | 6 |
| | 6 |
|
| Risk-free interest rate | | 1.86 | % | | 1.86 | % | | 1.13 | % |
| Fair value at grant date | | $ | 2.07 |
| | $ | 3.26 |
| | $ | 2.23 |
|
The Company does not discount the grant date fair values to estimate post-vesting restrictions. Post-vesting restrictions include black-out periods when the employee is not able to exercise stock options based on their potential knowledge of information prior to the release of that information to the public.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
The following table summarizes the components of stock-based compensation related to employee stock options recognized in the Company's consolidated financial statements in millions:
|
| | | | | | | | | | | | |
| December 31, | | 2015 | | 2014 | | 2013 |
| Pretax compensation expense | | $ | 3 |
| | $ | 3 |
| | $ | 2 |
|
| Tax benefit | | (1 | ) | | (1 | ) | | (1 | ) |
| Stock options expense, net of tax | | $ | 2 |
| | $ | 2 |
| | $ | 1 |
|
| Total intrinsic value of options exercised | | $ | 1 |
| | $ | 1 |
| | $ | 5 |
|
| Total fair value of options vested | | 3 |
| | 2 |
| | 2 |
|
| Cash received from the exercise of stock options | | 5 |
| | 3 |
| | 13 |
|
No cash was used to settle stock options or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2015, 2014 and 2013. As of December 31, 2015, $4 million of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted average period of 1.8 years.
A summary of the option activity for the year ended December 31, 2015 follows (number of options in thousands, dollars in millions except per option amounts):
|
| | | | | | | | | | | | | |
| | | Options | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Term (in years) | | Aggregate Intrinsic Value |
| Outstanding at December 31, 2014 | | 7,062 |
| | $ | 14.83 |
| | | | |
| Exercised | | (419 | ) | | 10.76 |
| | | | |
| Forfeited and expired | | (1,347 | ) | | 17.49 |
| | | | |
| Granted | | 1,859 |
| | 11.89 |
| | | | |
| Outstanding at December 31, 2015 | | 7,155 |
| | $ | 13.81 |
| | 6 | | $ | 1 |
|
| Vested and expected to vest at December 31, 2015 | | 6,771 |
| | $ | 13.88 |
| | 5.8 | | $ | 1 |
|
| Eligible for exercise at December 31, 2015 | | 4,292 |
| | $ | 14.70 |
| | 4.1 | | $ | 1 |
|
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the Company's closing stock price on the last trading day of 2015 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2015. The amount of the aggregate intrinsic value will change based on the fair market value of the Company's stock.
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2015, AES has estimated a weighted average forfeiture rate of 15.28% for stock options granted in 2015. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $3.3 million on a straight-line basis over a three year period (approximately $1.1 million per year) related to stock options granted during the year ended December 31, 2015.
RESTRICTED STOCK
Restricted Stock Units — The Company issues restricted stock units ("RSUs")RSUs under its long-term compensation plan. The RSUs are generally granted based upon a percentage of the participant's base salary. The units have a three-year vesting schedule and vest in one-third increments over the three-year period. Units granted prior to 2011 are required to be held for an additional two years before they can be converted into shares, and thus become transferable. There is no such requirement for units granted in 2011 and afterwards. In all circumstances, restricted stock unitsRSUs granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock unitRSU in cash or other assets of AES.
For the years ended December 31, 2015, 2014,2018, 2017, and 2013,2016, RSUs issued had a grant date fair value equal to the closing price of the Company's stock on the grant date. The Company does not discount the grant date fair values to reflect any post-vesting restrictions. RSUs granted to employees during the years ended December 31, 2015, 2014,2018, 2017, and 20132016 had grant date fair values per RSU of $12.03, $14.60$10.55, $11.93 and $11.19,$9.42, respectively.
The following table summarizes the components of the Company's stock-based compensation related to its employee RSUs recognized in the Company's consolidated financial statements in millions:(in millions):
| | | December 31, | | 2015 | | 2014 | | 2013 | | 2018 | | 2017 | | 2016 |
| RSU expense before income tax | | $ | 13 |
| | $ | 12 |
| | $ | 12 |
| | $ | 11 |
| | $ | 17 |
| | $ | 14 |
|
| Tax benefit | | (3 | ) | | (3 | ) | | (3 | ) | | (2 | ) | | (4 | ) | | (4 | ) |
| RSU expense, net of tax | | $ | 10 |
| | $ | 9 |
| | $ | 9 |
| | $ | 9 |
| | $ | 13 |
| | $ | 10 |
|
Total value of RSUs converted (1) | | $ | 16 |
| | $ | 25 |
| | $ | 10 |
| | $ | 10 |
| | $ | 10 |
| | $ | 7 |
|
| Total fair value of RSUs vested | | $ | 12 |
| | $ | 13 |
| | $ | 12 |
| | $ | 16 |
| | $ | 15 |
| | $ | 13 |
|
_____________________________
| |
(1) | Amount represents fair market value on the date of conversion. |
ThereCash was no cashnot used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
December 31, 2015, 2014,2018, 2017, and 2013.2016. As of December 31, 2015, $16 million of2018, total unrecognized compensation cost related to RSUs of $10 million is expected to be recognized over a weighted average period of approximately 1.91.7 years. There were no modifications to RSU awards during the year ended December 31, 2015.2018.
A summary of the activity of RSUs for the year ended December 31, 20152018 follows (number of RSUs(RSUs in thousands):
|
| | | | | | | | | |
| | | RSUs | | Weighted Average Grant Date Fair Values | | Weighted Average Remaining Vesting Term |
| Nonvested at December 31, 2017 | | 2,966 |
| | $ | 11.02 |
| | |
| Vested | | (1,428 | ) | | 11.05 |
| | |
| Forfeited and expired | | (528 | ) | | 10.95 |
| | |
| Granted | | 913 |
| | 10.55 |
| | |
| Nonvested at December 31, 2018 | | 1,923 |
| | $ | 10.80 |
| | 1.4 |
| Vested and expected to vest at December 31, 2018 | | 1,782 |
| | $ | 10.79 |
| | |
|
| | | | | | | | | |
| | | RSUs | | Weighted Average Grant Date Fair Values | | Weighted Average Remaining Vesting Term |
| Nonvested at December 31, 2014 | | 1,997 |
| | $ | 13.20 |
| | |
| Vested | | (954 | ) | | 13.01 |
| | |
| Forfeited and expired | | (236 | ) | | 12.71 |
| | |
| Granted | | 1,585 |
| | 12.03 |
| | |
| Nonvested at December 31, 2015 | | 2,392 |
| | $ | 12.55 |
| | 1.7 |
| Vested at December 31, 2015 | | — |
| | $ | — |
| | |
| Vested and expected to vest at December 31, 2015 | | 2,105 |
| | $ | 12.55 |
| | |
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2015,2018, AES has estimated a weighted average forfeiture rate of 13.53%9.35% for RSUs granted in 2015.2018. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $16$9 million on a straight-line basis over a three year period related to RSUs granted during the year ended December 31, 2015.three-year period.
The following table below summarizes the RSUs that vested and were converted during the years ended December 31, 2015, 2014, and 2013 (number of RSUsperiods indicated (RSUs in thousands):
|
| | | | | | | | | |
| Year Ended December 31, | | 2018 | | 2017 | | 2016 |
| RSUs vested during the year | | 1,428 |
| | 1,337 |
| | 1,063 |
|
| RSUs converted during the year, net of shares withheld for taxes | | 950 |
| | 865 |
| | 705 |
|
| Shares withheld for taxes | | 478 |
| | 472 |
| | 358 |
|
OTHER SHARE BASED COMPENSATION
The Company has three other share-based award programs. The Company has recorded expenses of $20 million, $8 million and $10 million for 2018, 2017 and 2016, respectively, related to these programs.
Stock options — AES grants options to purchase shares of common stock under stock option plans to non-employee directors. Under the terms of the plans, the Company may issue options to purchase shares of the Company's common stock at a price equal to 100% of the market price at the date the option is granted. Stock options issued in 2017 and 2018 have a three-year vesting schedule and vest in one-third increments over the
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
|
| | | | | | | | | |
| | | 2015 | | 2014 | | 2013 |
| RSUs vested during the year | | 954 |
| | 1,037 |
| | 942 |
|
| RSUs converted during the year, net of shares withheld for taxes | | 1,238 |
| | 1,734 |
| | 905 |
|
| Shares withheld for taxes | | 549 |
| | 796 |
| | 407 |
|
three-year period. The stock options have a contractual term of 10 years. In all circumstances, stock options granted by AES do not entitle the holder the right, or obligate AES, to settle the stock option in cash or other assets of AES.
Performance Stock Units — TheIn 2016, 2017 and 2018, the Company issues performance stock units ("PSUs")issued PSUs to officers under its long-term compensation plan. PSUs are restricted stock units of which 50% of the units awarded include a market condition and the remaining 50% include a performance condition. Vesting will occur if the applicable continued employmentconditions. Performance conditions are satisfied and (a) for the units subject to the market condition the Total Stockholder Return ("TSR")based on AES common stock exceeds the TSR of the Standard and Poor's 500 Utilities Sector Index over the three-year measurement period beginning on January 1 of the grant year and ending on December 31 of the third year and (b) for the units subject to the performance condition if the Company's actual Adjusted EBITDA meets the performance target over the three-year measurement period beginning on January 1 of the grant yearProportional Free Cash Flow targets for 2016, 2017 and ending on December 31 of the third year.2018. The market and performance conditions determine the vesting and final share equivalent per PSU and can result in earning an award payout range of 0% to 200%, depending on the achievement. The Company believes that it is probable that the performance condition will be met and will continue to be evaluated throughout the performance period. In all circumstances, PSUs granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock unitunits in cash or other assets of AES.
Performance Cash Units — In 2016, 2017 and 2018, the Company issued PCUs to its officers under its long-term compensation plan. The effectvalue of these units is dependent on the market condition on PSUs issued to officers of the Company during 2015 is reflected in the award's fair value on the grant date. The results of the valuation estimated the fair value at $8.22 per share, equating to 69% of the Company's closing stock price on the date of grant. PSUs that included a market condition granted during the year ended December 31, 2015, 2014, and 2013 had a grant date fair value per RSU of $8.22, $15.19 and $13.28, respectively. The fair value of the PSUs with a performance condition had a grant date fair value of $11.89 equal to the closing price of the Company's stock on the grant date. The Company believes that it is probable that the performance condition will be met; this will continue to be evaluated throughout the performance period. If the fair value of the market condition was not applied to PSUs issued to officers, the total grant date fair value of PSUs granted during the year ended December 31, 2015 would have increased by $1.1 million.
Restricted stock units with a market condition awarded to officers of the Company prior to 2011 contained only the market condition measuring the TSRstockholder return on AES common stock. These units were requiredstock as compared to be heldthe total stockholder return of the Standard and Poor's 500 Utilities Sector Index, Standard and Poor's 500 Index and MSCI Emerging Market Index over a three-year measurement period. Since PCUs are settled in cash, they qualify for an additional two years subsequent to vesting before they could be converted into sharesliability accounting and become transferable. Thereperiodic measurement is no such requirement for the shares granted during 2011 and afterwards.
required.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)17. REDEEMABLE STOCK OF SUBSIDIARIES
DECEMBER 31, 2015, 2014, AND 2013
The following table summarizes the componentsis a reconciliation of the Company's stock-based compensation related to its PSUs recognizedchanges in the Company's consolidated financial statements in millions:
|
| | | | | | | | | | | | |
| December 31, | | 2015 | | 2014 | | 2013 |
| PSU expense before income tax | | $ | 5 |
| | $ | 6 |
| | $ | 4 |
|
| Tax benefit | | (1 | ) | | (2 | ) | | (1 | ) |
| PSU expense, net of tax | | $ | 4 |
|
| $ | 4 |
|
| $ | 3 |
|
Total value of PSUs converted(1) | | $ | 1 |
| | $ | 4 |
| | $ | — |
|
| Total fair value of PSUs vested | | 3 |
| | 1 |
| | — |
|
| |
(1)
| Amount represents fair market value on the date of conversion. |
There was no cash used to settle PSUs or compensation cost capitalized as partredeemable stock of the cost of an asset for the years ended December 31, 2015, 2014, and 2013. As of December 31, 2015, $7 million of total unrecognized compensation cost related to PSUs is expected to be recognized over a weighted average period of approximately 1.7 years. There were no modifications to PSU awards during the year ended December 31, 2015.
A summary of the activity of PSUs for the year ended December 31, 2015 follows (number of PSUs in thousands)subsidiaries (in millions):
|
| | | | | | | |
| December 31, | 2018 | | 2017 |
| Balance at the beginning of the period | $ | 837 |
| | $ | 782 |
|
| Contributions from holders of redeemable stock of subsidiaries | 34 |
| | 50 |
|
| Net income (loss) attributable to redeemable stock of subsidiaries | 2 |
| | (14 | ) |
Fair value adjustment | 4 |
| | 25 |
|
| Other comprehensive income (loss) attributable to redeemable stock of subsidiaries | 2 |
| | (2 | ) |
| Acquisition and reclassification of stock of subsidiaries | — |
| | (4 | ) |
| Balance at the end of the period | $ | 879 |
| | $ | 837 |
|
|
| | | | | | | | | |
| | | PSUs | | Weighted Average Grant Date Fair Values | | Weighted Average Remaining Vesting Term |
| Nonvested at December 31, 2014 | | 1,331 |
| | $ | 14.27 |
| | |
| Vested | | (161 | ) | | 16.73 |
| | |
| Forfeited and expired | | (245 | ) | | 15.27 |
| | |
| Granted | | 626 |
| | 10.06 |
| | |
| Nonvested at December 31, 2015 | | 1,551 |
| | $ | 12.16 |
| | 1.2 |
| Vested at December 31, 2015 | | — |
| | $ | — |
| | |
| Vested and expected to vest at December 31, 2015 | | 1,298 |
| | 11.92 |
| | |
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2015, AES has estimated a forfeiture rate of 15.28% for PSUs granted in 2015. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $5 million on a straight-line basis over a three year period (approximately $1.8 million per year) related to PSUs granted during the year ended December 31, 2015.
The table below summarizes the PSUs that vested and were converted during the years ended December 31, 2015, 2014, and 2013 (number of PSUs in thousands):
|
| | | | | | | | | |
| | | 2015 | | 2014 | | 2013 |
| PSUs vested during the year | | 161 |
| | 85 |
| | — |
|
| PSUs converted during the year, net of shares withheld for taxes | | 96 |
| | 287 |
| | — |
|
| Shares withheld for taxes | | 65 |
| | 141 |
| | — |
|
19. REDEEMABLE STOCK OF SUBSIDIARIES
The following table summarizes the Company's redeemable stock of subsidiaries balances as of the periods indicated:indicated (in millions):
|
| | | | | | | |
| December 31, | 2018 | | 2017 |
| IPALCO common stock | $ | 618 |
| | $ | 618 |
|
Colon quotas (1) | 201 |
| | 159 |
|
| IPL preferred stock | 60 |
| | 60 |
|
| Total redeemable stock of subsidiaries | $ | 879 |
| | $ | 837 |
|
|
| | | | | | | | |
| | | December 31, |
| Redeemable stock of subsidiaries (in millions) | | 2015 | | 2014 |
| Additional paid-in capital, IPALCO shares | | $ | 377 |
| | $ | — |
|
| Book value, IPALCO shares - noncontrolling interest | | 83 |
| | — |
|
Total fair value of consideration received (1) | | 460 |
| | — |
|
| IPL cumulative preferred stock | | 60 |
| | 60 |
|
| DPL cumulative preferred stock | | 18 |
| | 18 |
|
Total cumulative preferred stock of subsidiaries (2) | | 78 |
| | 78 |
|
| Total redeemable stock of subsidiaries | | $ | 538 |
| | $ | 78 |
|
| |
(1) | Characteristics of quotas are similar to common stock. |
(1) See Note16—Equity for further information on IPALCO equity transactions with noncontrolling interests.
(2) Refer below for further information on outstanding sharesColon — Our partner in Colon made capital contributions of cumulative preferred stock of subsidiaries.
Our subsidiaries IPL$34 million and DPL had outstanding shares of cumulative preferred stock of $78$50 million atduring the year ended December 31, 20152018 and 2014.2017, respectively. Any subsequent adjustments to allocate earnings and dividends to our partner, or measure the investment at fair value, will be classified as temporary equity each reporting period as it is probable that the shares will become redeemable.
IPL — IPL had $60 million of cumulative preferred stock outstanding at December 31, 20152018 and 2014,2017, which representedrepresent five series of preferred stock. The total annual dividend requirements were approximately $3 million at December 31, 20152018 and 2014.2017. Certain series of the preferred stock were redeemable solely at the option of the issuer at prices between $100 and $118 per share. Holders of the preferred stock are entitled to elect a majority of IPL's board of directors if IPL has not paid dividends
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
to its preferred stockholders for four consecutive quarters. Based on the preferred stockholders' ability to elect a majority of IPL's board of directors in this circumstance, the redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred stock is considered temporary equity.
IPALCO — As part of a purchase agreement executed in 2014, CDPQ had an option to invest $349 million in IPALCO through 2016 in exchange for a 17.65% equity stake. In March 2016, CDPQ exercised the remaining option by investing $134 million in IPALCO, which resulted in CDPQ's combined direct and presentedindirect interest in IPALCO of 30%. The Company recognized an increase to additional paid-in-capital and a reduction to retained earnings of $84 million for the excess of the fair value of the shares over their book value. In June 2016, CDPQ contributed an additional $24 million to IPALCO, with no impact to the ownership structure of the investment. Any subsequent
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
adjustments to allocate earnings and dividends to CDPQ will be classified as NCI within permanent equity as it is not probable that the shares will become redeemable.
18. REVENUE
The following table presents our revenue from contracts with customers and other revenue for the year ended December 31, 2018 (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2018 |
| | US and Utilities SBU | | South America SBU | | MCAC SBU | | Eurasia SBU | | Corporate, Other and Eliminations | | Total |
| Regulated Revenue | | | | | | | | | | | |
| Revenue from contracts with customers | $ | 2,885 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,885 |
|
| Other regulated revenue | 54 |
| | — |
| | — |
| | — |
| | — |
| | 54 |
|
| Total regulated revenue | $ | 2,939 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,939 |
|
| Non-Regulated Revenue | | | | | | | | | | | |
| Revenue from contracts with customers | $ | 972 |
| | $ | 3,529 |
| | $ | 1,642 |
| | $ | 943 |
| | $ | (11 | ) | | $ | 7,075 |
|
Other non-regulated revenue (1) | 319 |
| | 4 |
| | 86 |
| | 312 |
| | 1 |
| | 722 |
|
| Total non-regulated revenue | $ | 1,291 |
| | $ | 3,533 |
| | $ | 1,728 |
| | $ | 1,255 |
| | $ | (10 | ) | | $ | 7,797 |
|
| Total revenue | $ | 4,230 |
| | $ | 3,533 |
| | $ | 1,728 |
| | $ | 1,255 |
| | $ | (10 | ) | | $ | 10,736 |
|
_____________________________
| |
(1) | Other non-regulated revenue primarily includes lease and derivative revenue not accounted for under ASC 606. |
Contract Balances — The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. Accounts receivable represent unconditional rights to consideration and consist of both billed amounts and unbilled amounts typically resulting from sales under long-term contracts when revenue recognized exceeds the amount billed to the customer. We bill both generation and utilities customers on a contractually agreed-upon schedule, typically at periodic intervals (e.g., monthly). The calculation of revenue earned but not yet billed is based on the number of days not billed in the mezzanine levelmonth, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month.
Our contract liabilities consist of deferred revenue which is classified as current or noncurrent based on the timing of when we expect to recognize revenue. The current portion of our contract liabilities is reported in Accrued and other liabilities and the noncurrent portion is reported in Other noncurrent liabilities on the Consolidated Balance Sheets in accordanceSheets. The contract liabilities from contracts with relevant accounting guidance for noncontrolling interestscustomers were $109 million and redeemable securities.$131 million as of December 31, 2018 and January 1, 2018, respectively.
DPL — DPL had $18Of the $131 million of cumulative preferred stock outstandingcontract liabilities reported at January 1, 2018, $36 million was recognized as revenue during the period ended December 31, 20152018.
A significant financing arrangement exists for our Mong Duong plant in Vietnam. The plant was constructed under a build, operate, and 2014, which represented three seriestransfer contract and will be transferred to the Vietnamese government after the completion of preferred stock issued by DP&L, a wholly-owned subsidiary25 year PPA. The performance obligation to construct the facility was substantially completed in 2015. Approximately $1.4 billion of DPL. The total annual dividend requirements were approximately $1 million atcontract consideration related to the construction, but not yet collected through the 25 year PPA, was reflected as a loan receivable as of December 31, 2015 and 2014. 2018.
Remaining Performance Obligations — The DP&L preferred stock may be redeemedtransaction price allocated to remaining performance obligations represents future consideration for unsatisfied (or partially unsatisfied) performance obligations at DP&L's option as determined by its board of directors at per-share redemption prices between $101 and $103 per share, plus cumulative preferred dividends. In addition, DP&L's Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect membersthe end of the DP&L Boardreporting period. As of DirectorsDecember 31, 2018, the aggregate amount of transaction price allocated to remaining performance obligations was $15 million, primarily consisting of fixed consideration for the sale of renewable energy credits (RECs) in long-term contracts in the event that cumulative dividendsU.S. We expect to recognize revenue on approximately one-fifth of the remaining performance obligations in 2019, with the remainder recognized thereafter. The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the amount above excludes contracts with an original length of one year or less, contracts for which we recognize revenue based on the preferred stock are in arrears in an aggregate amount equivalentwe have the right to at least four full quarterly dividends. Based oninvoice for services performed, and variable consideration allocated entirely to a wholly unsatisfied performance obligation when the preferred stockholders' abilityconsideration relates specifically to elect members of DP&L's board of directors in this circumstance,our efforts to satisfy the redemption ofperformance obligation and depicts the preferred shares is consideredamount to which we expect to be entitled. As such, consideration for energy is excluded from the amounts above as the variable consideration relates to the amount of energy delivered and reflects the value the Company expects to receive for the energy transferred. Estimates of revenue expected to be recognized in future periods also exclude unexercised customer options to purchase additional goods or services that do not solely withinrepresent material rights to the control of the issuer and the preferred stock is considered temporary equity and presented in the mezzanine level of the Consolidated Balance Sheets in accordance with the relevant accounting guidance for noncontrolling interests and redeemable securities.customer.
20.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
19. OTHER INCOME AND EXPENSE
Other Income — Other income generally includes gains on asset sales and liability extinguishments, favorable judgments on contingencies, gains on contract terminations, allowance for funds used during construction and other income from miscellaneous transactions. The components are summarized as follows (in millions):
|
| | | | | | | | | | | |
| Year Ended December 31, | 2018 | | 2017 | | 2016 |
Gain on remeasurement of contingent consideration (1) | $ | 32 |
| | $ | — |
| | $ | — |
|
| Allowance for funds used during construction (US Utilities) | 8 |
| | 26 |
| | 29 |
|
| Gain on sale of assets | 4 |
| | 1 |
| | 4 |
|
Legal settlements (2) | — |
| | 60 |
| | — |
|
| Other | 28 |
| | 33 |
| | 31 |
|
| Total other income | $ | 72 |
| | $ | 120 |
| | $ | 64 |
|
|
| | | | | | | | | | | |
| Years Ended December 31, | 2015 | | 2014 | | 2013 |
| Contract termination | $ | 20 |
| | $ | — |
| | $ | 60 |
|
| Gain on sale of assets | 19 |
| | 68 |
| | 12 |
|
| Allowance for Funds Used During Construction (US Utilities) | 17 |
| | 9 |
| | 6 |
|
| Contingency reversal | — |
| | 18 |
| | 10 |
|
| Gain on extinguishment of tax and other liabilities | — |
| | — |
| | 9 |
|
| Other | 27 |
| | 29 |
| | 28 |
|
| Total other income | $ | 83 |
| | $ | 124 |
| | $ | 125 |
|
| |
(1) | Related to the amendment of the Oahu purchase agreement. See Note 24 —Acquisitions for further information. |
| |
(2) | In December 2016, the Company and YPF entered into a settlement in which all parties agreed to give up any and all legal action related to gas supply contracts that were terminated in 2008 and have been in dispute since 2009. In January 2017, the YPF board approved the agreement and paid the Company $60 million, thereby resolving all uncertainties around the dispute. |
Other Expense — Other expense generally includes losses on asset sales and dispositions, losses on legal contingencies, and losses from other miscellaneous transactions. The components are summarized as follows (in millions):
|
| | | | | | | | | | | |
| Year Ended December 31, | 2018 | | 2017 | | 2016 |
Loss on sale and disposal of assets (1) | $ | 30 |
| | $ | 28 |
| | $ | 12 |
|
| Non-service pension and other postretirement costs | 10 |
| | 1 |
| | 3 |
|
Allowance for other receivables (2) | 7 |
| | — |
| | 52 |
|
| Water rights write-off | — |
| | 19 |
| | 6 |
|
| Other | 11 |
| | 10 |
| | 7 |
|
| Total other expense | $ | 58 |
| | $ | 58 |
| | $ | 80 |
|
|
| | | | | | | | | | | |
| Years Ended December 31, | 2015 | | 2014 | | 2013 |
| Loss on sale and disposal of assets | $ | 48 |
| | $ | 47 |
| | $ | 51 |
|
| Legal contingency | 9 |
| | 11 |
| | 9 |
|
| Contract termination | — |
| | — |
| | 7 |
|
| Other | 8 |
| | 10 |
| | 9 |
|
| Total other expense | $ | 65 |
| | $ | 68 |
| | $ | 76 |
|
| |
(1) | In September 2018, the Company recorded a $20 million loss due to damage associated with a lightning incident at the Andres facility in the Dominican Republic. |
| |
(2) | During the fourth quarter of 2016, we recognized a full allowance on a non-trade receivable in the MCAC SBU as a result of payment delays and discussions with the counterparty. The allowance was related to certain reimbursements the Company was expecting in connection with a legal matter. |
21.20. ASSET IMPAIRMENT EXPENSE
|
| | | | | | | | | | | | |
| Year ended December 31, (in millions) | | 2018 | | 2017 | | 2016 |
| Shady Point | | $ | 157 |
| | $ | — |
| | $ | — |
|
| Nejapa | | 37 |
| | — |
| | — |
|
| DPL | | — |
| | 175 |
| | 859 |
|
| Laurel Mountain | | — |
| | 121 |
| | — |
|
| Kazakhstan Hydroelectric | | — |
| | 92 |
| | — |
|
| Kazakhstan CHPs | | — |
| | 94 |
| | — |
|
| Kilroot | | — |
| | 37 |
| | — |
|
| Buffalo Gap II | | — |
| | — |
| | 159 |
|
| Buffalo Gap I | | — |
| | — |
| | 77 |
|
| Other | | 14 |
| | 18 |
| | 1 |
|
| Total | | $ | 208 |
| | $ | 537 |
| | $ | 1,096 |
|
|
| | | | | | | | | | | | |
| Years ended December 31, | | 2015 | | 2014 | | 2013 |
| | | (in millions) |
| Kilroot | | $ | 121 |
| | $ | — |
| | $ | — |
|
| Buffalo Gap III | | 116 |
| | — |
| | — |
|
| U.K. Wind | | 37 |
| | 12 |
| | — |
|
| Ebute | | — |
| | 67 |
| | — |
|
| East Bend (DP&L) | | — |
| | 12 |
| | — |
|
| Beaver Valley | | — |
| | — |
| | 46 |
|
| Conesville (DP&L) | | — |
| | — |
| | 26 |
|
| Itabo (San Lorenzo) | | — |
| | — |
| | 16 |
|
| Other | | 11 |
| | — |
| | 7 |
|
| Total asset impairment expense | | $ | 285 |
| | $ | 91 |
| | $ | 95 |
|
KilrootNejapa — During 2015,the fourth quarter of 2018, the Company tested the recoverability of its long-lived assets at Nejapa, a landfill gas plant in El Salvador. Decreased production as a result of the landfill owner´s failure to perform improvements necessary to continue extracting gas from the landfill was identified as an impairment indicator. The Company determined that the carrying amount was not recoverable. The asset group, consisting of property, plant,
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
and equipment and intangible assets, was determined to have a fair value of $5 million using the income approach. As a result, the Company recognized an asset impairment expense of $37 million as of December 31, 2018. Nejapa is reported in the US and Utilities SBU reportable segment.
DPL — In March 2017, the Board of Directors of DPL approved the retirement of the DPL operated and co-owned Stuart coal-fired and diesel-fired generating units, and the Killen coal-fired generating unit and combustion turbine on or before June 1, 2018. The Company performed an impairment analysis and determined that the carrying amounts of the facilities were not recoverable. The Stuart and Killen asset groups were determined to have fair values of $3 million and $8 million, respectively, using the income approach. As a result, the Company recognized total asset impairment expense of $66 million. The Stuart and Killen units were retired in May 2018. Prior to their retirement, Stuart and Killen were reported in the US and Utilities SBU reportable segment.
In December 2017, DPL entered into an agreement for the sale of six of its combustion turbine and diesel-fired generation facilities and related assets ("DPL peaker assets"). Upon meeting the held-for-sale criteria, the Company performed an impairment analysis and determined that the carrying value of the asset group of $346 million was greater than its fair value less costs to sell of $237 million. As a result, the Company recognized asset impairment expense of $109 million. DPL completed the sale of the peaker assets in March 2018. Prior to their sale, the DPL peaker assets were reported in the US and Utilities SBU reportable segment. See Note 23—Held-for-Sale and Dispositions for further information.
During the second quarter of 2016, the Company tested the recoverability of its long-lived generation assets at DPL. Uncertainty created by the Supreme Court of Ohio’s June 20, 2016 opinion regarding ESP 2, lower expectations of future revenue resulting from the most recent PJM capacity auction and higher anticipated environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. The Company performed an impairment analysis and determined that the carrying amount of Killen, a coal-fired generation facility, and certain DPL peaking generation facilities were not recoverable. The Killen and DPL peaking generation asset groups were determined to have a fair value of $84 million and $5 million, respectively, using the income approach. As a result, the Company recognized total asset impairment expense of $235 million. DPL is reported in the US and Utilities SBU reportable segment.
During the fourth quarter of 2016, the Company tested the recoverability of its long-lived coal-fired generation assets and one gas-fired peaking plant at DPL. Uncertainty around the useful life of Stuart and Killen related to the Company’s ESP proceedings and lower forward dark spreads and capacity prices were collectively determined to be an impairment indicator for these assets. Market information indicating a significant decrease in the fair value of Zimmer and Miami Fort was determined to be an indicator of impairment for these assets. The lower forward dark spreads and capacity prices, along with the indicators at the other coal-fired facilities, collectively, resulted in an indicator of impairment for the Conesville asset group. For the gas-fired peaking plant, significant incremental capital expenditures relative to its fair value, and an impairment charge taken at this facility in the second quarter of 2016, were collectively determined to be impairment indicators for this asset. The Company performed an impairment analysis for each of these asset groups and determined that their carrying amounts were not recoverable. The Stuart, Killen, Miami Fort, Zimmer, Conesville and the gas-fired peaking plant asset groups were determined to have fair values of $57 million, $43 million, $36 million, $24 million, $1 million and $2 million, respectively, using the market approach for Miami Fort and Zimmer and the income approach for the remaining asset groups. As a result, the Company recognized total asset impairment expense of $624 million. DPL is reported in the US and Utilities SBU reportable segment.
Laurel Mountain — During the fourth quarter of 2017, the Company tested the recoverability of its long-lived assets at Laurel Mountain, a wind farm in the U.S. Impairment indicators were identified based on a decline in forward pricing. The Company determined that the carrying amount was not recoverable. The Laurel Mountain asset group was determined to have a fair value of $33 million using the income approach. As a result, the Company recognized an asset impairment expense of $121 million. Laurel Mountain is reported in the US and Utilities SBU reportable segment.
Kilroot — During the fourth quarter of 2017, the Company tested the recoverability of its long-lived assets at Kilroot, a coal-coal and oil-fired plant in Northern Ireland, as Kilroot was not successful in bidding its coal units into the U.K., when the regulator established lowerDecember 2017 capacity pricesauction for the Irish Single Electricity Market.newly implemented I-SEM market. The Company determined that the carrying amount of the asset group was not recoverable. The Kilroot asset group was determined to have a fair value of $70$20 million using the income approach. As a result, the Company recognized an asset impairment expense
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
of $37 million, which was limited to the carrying value of the coal units. Kilroot is reported in the Eurasia SBU reportable segment.
Kazakhstan Hydroelectric — In April 2017, the Republic of Kazakhstan stated the concession agreements would not be extended for Shulbinsk HPP and Ust-Kamenogorsk HPP, two hydroelectric plants in Kazakhstan, and initiated the process to transfer these plants back to the government. Upon meeting the held-for-sale criteria in the second quarter of 2017, the Company performed an impairment analysis and determined the carrying value of the asset group of $190 million, which included cumulative translation losses of $100 million, was greater than its fair value less costs to sell of $92 million. As a result, the Company recognized asset impairment expense of $92 million limited to the carrying value of the long-lived assets. The Company completed the transfer of the plants in October 2017. Prior to their transfer, the Kazakhstan hydroelectric plants were reported in the Eurasia SBU reportable segment. See Note 23—Held-for-Sale and Dispositions for further information.
Kazakhstan CHPs — In January 2017, the Company entered into an agreement for the sale of Ust-Kamenogorsk CHP and Sogrinsk CHP, its combined heating and power coal plants in Kazakhstan. Upon meeting the held-for-sale criteria in the first quarter of 2017, the Company performed an impairment analysis and determined that the carrying value of the asset group of $171 million, which included cumulative translation losses of $92 million, was greater than its fair value less costs to sell of $29 million. As a result, the Company recognized asset impairment expense of $94 million limited to the carrying value of the long-lived assets. The Company completed the sale of its interest in the Kazakhstan CHP plants in April 2017. Prior to their sale, the plants were reported in the Eurasia SBU reportable segment. See Note 23—Held-for-Sale and Dispositions for further information.
Buffalo Gap I — During 2016, the Company tested the recoverability of its long-lived assets at Buffalo Gap I. Low wind production during 2016 resulted in management lowering future expectations of production and therefore future forecasted revenues. As such this was determined to be an impairment indicator. The Company determined that the carrying amount of the asset group was not recoverable. The Buffalo Gap I asset group was determined to have a fair value of $36 million using the income approach. As a result, the Company recognized asset impairment expense of $121 million. Kilroot$77 million ($23 million attributable to AES). Buffalo Gap I is reported in the EuropeUS and Utilities SBU reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
Buffalo Gap IIIII — During 2015,2016, the Company tested the recoverability of its long-lived assets at Buffalo Gap III, a wind farm in Texas.II. Impairment indicators were identified based on a decline in forward power curves coupled with the near term expiration of favorable contracted cash flows.curves. The Company determined that the carrying amount was not recoverable. The Buffalo Gap IIIII asset group was determined to have a fair value of $118$92 million using the income approach. As a result, the Company recognized asset impairment expense of $116 million.$159 million ($49 million attributable to AES). Buffalo Gap IIIII is reported in the US and Utilities SBU reportable segment.
U.K. Wind (Development Projects)21. INCOME TAXES
U.S. Tax Reform — During 2015,In 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “TCJA”). The TCJA significantly changed U.S. corporate income tax law. Among other changes effective in 2017, the TCJA required companies to pay a one-time tax on certain unrepatriated earnings of foreign subsidiaries. Many other changes took effect in 2018, including a limit on the deductibility of interest expense and a new regime for taxing certain earnings of foreign subsidiaries.
The Company recognized the income tax effects of the TCJA in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) which provides SEC guidance on the application of ASC 740, Income Taxes, in the reporting period in which the TCJA was signed into law. Accordingly, the Company’s 2017 financial statements reflected provisional amounts for those impacts for which the accounting under ASC 740 was incomplete, but a reasonable estimate could be determined. As of December 31, 2018, the Company's accounting for the initial impacts of the TCJA are complete under SAB 118.
For the year ended December 31, 2018 the Company decidedincreased its estimate of the one-time transition tax by $194 million to no longer pursue two wind projects in$869 million. The estimated tax expense recognized for the U.K. based on recent regulatory clarifications specificyear ended December 31, 2017 relating to these projects,the remeasurement of deferred tax assets and liabilities from an income tax rate of 35% to 21%, decreased $77 million, resulting in a full impairment. Impairment indicators were also identified at four other wind projects based on their current development status and a reassessmenttotal remeasurement benefit of $38 million.
Argentine Tax Reform — In December 2017, the likelihood that each project would be pursued given aviation concerns, regulatory changes, economic considerations and other factors. The Company determined that the carrying amounts of each of these asset groups, which totaled $38 million, were not recoverable. In aggregate, the asset groups were determined to have a fair value of $1 million using the market approach and, as a result, the Company recognized asset impairment expense of $37 million. The U.K. Wind (Development Projects) are reported in the Europe SBU reportable segment.
Ebute — During 2014, the Company identified impairment indicators at Ebute in Nigeria, resulting from the continued lack of gas supply, the increased likelihood of selling the asset group before the end of its useful life, and indications about the potential proceeds that could be received from a future sale. The Company determined that the carrying amount of the asset group was not recoverable. The Company recognized asset impairment of $67 million, which represents the difference between the carrying amount of $103 million and fair value less cost to sell of $36 million. In November 2014, the Company completed the sale of its interest in Ebute. See Note 24—Dispositions for additional details. PriorArgentine government enacted reforms to its sale, Ebute was reported in the Europe SBU reportable segment.
U.K. Wind (Newfield) — During 2014, the Company tested the recoverability of long-lived assets at its Newfield wind development project in the U.K. after their government refused to grant a permit necessary for the project to continue. The Company determinedincome tax laws that the carrying amount of the asset group was not recoverable. The Newfield asset group was determined to have no fair value using the income approach. As a result, the Company recognized asset impairment expense of $12 million. U.K. Wind (Newfield) is reported in the Europe SBU reportable segment.
East Bend (DP&L) — During 2014, the Company identified impairment indicators at East Bend, a coal-fired plant in Ohio jointly owned by DP&L, resulting from the increased likelihood that the asset group would be disposed prior to the end of its useful life. The Company determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2 million using the market approach, and the Company recognized asset impairment expense of $12 million. The Company's interest in East Bend was sold in December 2014. Prior to its sale, East Bend was reported in the US SBU reportable segment.
Beaver Valley — During 2013, Beaver Valley, a wholly-owned coal-fired plant in Pennsylvania, entered into an agreement to early terminate its PPA with the offtaker in exchange for a lump-sum payment of $60 million. The termination of the PPA resulted in a significant reductiondecrease to statutory income tax rates for our Argentine businesses from 35% to 30% in 2018-2019 and to 25% for 2020 and future years. The impact of remeasuring deferred taxes to account for the enacted change in future applicable income tax rates was recognized as income tax benefit in the future cash flows of the asset group and was considered an impairment indicator. The carrying amount of the asset group was not recoverable. The carrying amount of the asset group exceeded the fair value of the asset group, resulting in asset impairment expense of $46 million. Beaver Valley is reported in the US SBU reportable segment.fourth quarter
Conesville (DP&L) — During 2013, the Company tested the recoverability of long-lived assets at Conesville, a coal-fired plant in Ohio jointly-owned by DP&L. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit failing Step 1 of the annual goodwill impairment test were determined to be impairment indicators. The Company performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The Conesville asset group was determined to have zero fair value using discounted cash flows under the income approach. As a result, the Company recognized asset impairment expense of $26 million. Conesville is reported in the US SBU reportable segment.
Itabo (San Lorenzo) — During 2013, the Company tested the recoverability of long-lived assets at San Lorenzo, a LNG fueled plant of Itabo. Itabo was informed by Super-Intendencia de Electridad ("SIE"), the system regulator in the Dominican Republic, that it would not receive capacity revenue going forward. This communication in combination with current adverse market conditions were determined to be an impairment indicator. The Company performed a long-lived asset impairment test considering different scenarios and determined that, based on undiscounted cash flows, the carrying amount of San Lorenzo was not recoverable. The fair value of San Lorenzo was determined using the market approach based on a broker quote and it was determined that its carrying amount of $23 million exceeded the estimated fair value of $7 million. As a result, the Company recognized asset impairment expense of $16 million. Itabo is reported in the MCAC SBU reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
22. INCOME TAXES
of 2017, resulting in a decrease of $21 million to consolidated income tax expense.
Chilean Tax Reform — In February 2016, the Chilean government enacted further reforms to its income tax laws that resulted in an increase to statutory income tax rates for most of our Chilean businesses from 25% to 25.5% in 2017 and to 27% for 2018 and future years. The impact of remeasuring deferred taxes to account for the enacted change in future applicable income tax rates was recognized as a discrete income tax expense in the first quarter of 2016, resulting in an increase of $26 million to consolidated income tax expense.
Income Tax Provision — The nextfollowing table summarizes the expense for income taxes on continuing operations in millions for the periods indicated:indicated (in millions):
|
| | | | | | | | | | | | |
| December 31, | | 2018 | | 2017 | | 2016 |
| Federal: | Current | $ | 7 |
| | $ | — |
| | $ | 2 |
|
| | Deferred | 186 |
| | 545 |
| | (361 | ) |
| State: | Current | 2 |
| | — |
| | 1 |
|
| | Deferred | 5 |
| | 1 |
| | (4 | ) |
| Foreign: | Current | 378 |
| | 335 |
| | 318 |
|
| | Deferred | 130 |
| | 109 |
| | 76 |
|
| Total | | $ | 708 |
| | $ | 990 |
| | $ | 32 |
|
|
| | | | | | | | | | | | |
| December 31, | | 2015 | | 2014 | | 2013 |
Federal — | Current | $ | 9 |
| | $ | — |
| | $ | (28 | ) |
| | Deferred | (56 | ) | | (121 | ) | | (110 | ) |
State — | Current | 1 |
| | 1 |
| | 1 |
|
| | Deferred | (5 | ) | | 1 |
| | 1 |
|
Foreign — | Current | 505 |
| | 457 |
| | 509 |
|
| | Deferred | 11 |
| | 81 |
| | (30 | ) |
| Total | | $ | 465 |
| | $ | 419 |
| | $ | 343 |
|
Effective and Statutory Rate Reconciliation — The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to the Company's effective tax rate as a percentage of income from continuing operations before taxes for the periods indicated:
|
| | | | | | | | | |
| December 31, | | 2018 | | 2017 | | 2016 |
| Statutory Federal tax rate | | 21 | % | | 35 | % | | 35 | % |
| State taxes, net of Federal tax benefit | | 2 | % | | (7 | )% | | (18 | )% |
| Taxes on foreign earnings | | 9 | % | | — | % | | (46 | )% |
| Valuation allowance | | (2 | )% | | 10 | % | | 10 | % |
| Uncertain tax positions | | — | % | | — | % | | 4 | % |
| Noncontrolling Interest on Buffalo Gap impairments | | — | % | | — | % | | 31 | % |
| Change in tax law | | 6 | % | | 90 | % | | 12 | % |
| Other—net | | (1 | )% | | — | % | | (11 | )% |
| Effective tax rate | | 35 | % | | 128 | % | | 17 | % |
|
| | | | | | | | | |
| December 31, | | 2015 | | 2014 | | 2013 |
| Statutory Federal tax rate | | 35 | % | | 35 | % | | 35 | % |
| State taxes, net of Federal tax benefit | | (5 | )% | | (1 | )% | | (3 | )% |
| Taxes on foreign earnings | | 3 | % | | (14 | )% | | (4 | )% |
| Valuation allowance | | (5 | )% | | (1 | )% | | — | % |
| Uncertain tax positions | | — | % | | — | % | | (5 | )% |
| Bad debt deduction | | — | % | | — | % | | (3 | )% |
| Change in tax law | | — | % | | 4 | % | | (1 | )% |
| Goodwill impairment | | 10 | % | | 4 | % | | 12 | % |
| Other—net | | 3 | % | | — | % | | 2 | % |
| Effective tax rate | | 41 | % | | 27 | % | | 33 | % |
For 2018, the 6% change in tax law item relates primarily to changes in estimate under SAB 118 of the impacts of adoption of the TCJA. The Company recognized tax expense of $194 million related to revised estimates of the one-time transition tax in accordance with proposed regulations issued by the U.S. Treasury in 2018. The adjustment was due in large part to the approach the proposed regulations adopted to determine the fair value of our interests in publicly traded subsidiaries. The Company also recognized tax benefit of $77 million related to revised estimates of deferred tax remeasurement. Included in the favorable (14)% 20149% taxes on foreign earnings percentage aboveitem is approximately (8)%$124 million of U.S. GILTI tax expense related to foreign subsidiaries, including the sale of approximately 45%our interest in Masinloc.
For 2017, the 90% change in tax law item relates primarily to the impact of U.S. and Argentina tax reform. The impact of the Company'sU.S one-time transition tax and remeasurement of deferred taxes represents 88% and 5%, respectively, which is partially offset by the tax benefit resulting from Argentina tax reform representing 3%.
For 2016, the 31% Buffalo Gap impairments item relates to the amounts of impairment allocated to noncontrolling interest in Masin AES Pte Ltd., which owns the Company's interests in the Philippines, and the sale of the Company's interests in four U.K. wind projects. Neither of these transactions gave rise to income tax expense.is nondeductible.
Income Tax Receivables and Payables — The current income taxes receivable and payable are included in Other Current Assets and Accrued and Other Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The noncurrent income taxes receivable and payable are included in Other Noncurrent Assets and Other Noncurrent Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The nextfollowing table summarizes the income taxes receivable and payable in millions as of Decemberthe periods indicated (in millions):
|
| | | | | | | | |
| December 31, | | 2018 | | 2017 |
| Income taxes receivable—current | | $ | 163 |
| | $ | 147 |
|
| Income taxes receivable—noncurrent | | 8 |
| | — |
|
| Total income taxes receivable | | $ | 171 |
| | $ | 147 |
|
| Income taxes payable—current | | $ | 210 |
| | $ | 129 |
|
| Income taxes payable—noncurrent | | 7 |
| | 17 |
|
| Total income taxes payable | | $ | 217 |
| | $ | 146 |
|
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015 and 2014:
|
| | | | | | | | |
| | | 2015 | | 2014 |
| Income taxes receivable—current | | $ | 167 |
| | $ | 217 |
|
| Total income taxes receivable | | $ | 167 |
| | $ | 217 |
|
| Income taxes payable—current | | $ | 264 |
| | $ | 299 |
|
| Income taxes payable—noncurrent | | 35 |
| | 2 |
|
| Total income taxes payable | | $ | 299 |
| | $ | 301 |
|
Deferred Income Taxes — Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss and tax credit carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.
As of December 31, 2015,2018, the Company had federal net operating loss carryforwards for tax return purposes of approximately $3.5$1.1 billion expiring in years 20212033 to 2034. Approximately $87 million of the net operating loss carryforward related to stock option deductions will be recognized in additional paid-in capital when realized.2036. The Company also had federal general business tax credit carryforwards of approximately $18$22 million expiring primarily from 2021 to 2035,2038, and federal alternative minimum tax credits of approximately $5$15 million that carry forward without expiration. Themay be fully recovered by 2021 under the TCJA. Additionally, the Company had state net operating loss carryforwards as of December 31, 20152018 of approximately $8.4$8.5 billion expiring in years 20162019 to 2035.2038. As of December 31, 2015,2018, the Company had foreign net operating loss carryforwards of approximately $3.5$2.4 billion that expire at various times beginning in 20162019 and some of which carry forward without expiration, and tax credits available in foreign jurisdictions of approximately $32$14 million, $24$13 million of which expire in 2021 and $8$1 million of which carryforward without expiration.expire in years 2024 to 2029.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
Valuation allowances decreased $103$120 million during 20152018 to $894$868 million at December 31, 2015. This net decrease was primarily the result of foreign exchange losses and valuation allowance releases at certain of our Brazil and Vietnam subsidiaries.
Valuation allowances decreased $93 million during 2014 to $997 million at December 31, 2014.2018. This net decrease was primarily the result of valuation allowance activity at certain of our Brazil subsidiaries and U.S. states.
Valuation allowances increased $112 million during 2017 to $988 million at December 31, 2017. This net increase was primarily the releaseresult of valuation allowance against U.S. capital loss carryforwards.activity at certain of our Brazil subsidiaries.
The Company believes that it is more likely than not that the net deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income. The Company continues to monitor the utilization of its deferred tax asset for its U.S. consolidated net operating loss carryforward. Although management believes it is more likely than not that this deferred tax asset will be realized through generation of sufficient taxable income prior to expiration of the loss carryforwards, such realization is not assured.
The following table summarizes the deferred tax assets and liabilities, in millions, as of December 31, 2015 and 2014:the periods indicated (in millions):
|
| | | | | | | | |
| December 31, | | 2018 | | 2017 |
| Differences between book and tax basis of property | | $ | (1,418 | ) | | $ | (1,424 | ) |
| Other taxable temporary differences | | (243 | ) | | (143 | ) |
| Total deferred tax liability | | (1,661 | ) | | (1,567 | ) |
| Operating loss carryforwards | | 1,066 |
| | 1,439 |
|
| Capital loss carryforwards | | 52 |
| | 63 |
|
| Bad debt and other book provisions | | 62 |
| | 66 |
|
| Tax credit carryforwards | | 55 |
| | 51 |
|
| Other deductible temporary differences | | 111 |
| | 60 |
|
| Total gross deferred tax asset | | 1,346 |
| | 1,679 |
|
| Less: valuation allowance | | (868 | ) | | (988 | ) |
| Total net deferred tax asset | | 478 |
| | 691 |
|
| Net deferred tax (liability) | | $ | (1,183 | ) | | $ | (876 | ) |
|
| | | | | | | | |
| | | 2015 | | 2014 |
| Differences between book and tax basis of property | | $ | (2,240 | ) | | $ | (2,364 | ) |
| Other taxable temporary differences | | (299 | ) | | (302 | ) |
| Total deferred tax liability | | (2,539 | ) | | (2,666 | ) |
| Operating loss carryforwards | | 2,206 |
| | 2,224 |
|
| Capital loss carryforwards | | 66 |
| | 137 |
|
| Bad debt and other book provisions | | 191 |
| | 221 |
|
| Retirement costs | | 149 |
| | 275 |
|
| Tax credit carryforwards | | 55 |
| | 58 |
|
| Other deductible temporary differences | | 219 |
| | 363 |
|
| Total gross deferred tax asset | | 2,886 |
| | 3,278 |
|
| Less: valuation allowance | | (894 | ) | | (997 | ) |
| Total net deferred tax asset | | 1,992 |
| | 2,281 |
|
| Net deferred tax (liability) | | $ | (547 | ) | | $ | (385 | ) |
The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested outside of the U.S. and, accordingly,Except for the one-time transition tax in the U.S., no U.S. deferred taxes have been recorded with respect to suchour indefinitely reinvested earnings in accordance with the relevant accounting guidance for income taxes. Should the earnings be remitted as dividends, the Company may be subject to additional foreign withholding and state income taxes. Under the TCJA, future distributions from foreign subsidiaries will generally be subject to a federal dividends received deduction in the U.S. As of December 31, 2018, the cumulative amount of U.S. GAAP foreign un-remitted earnings upon which additional income taxes net of allowable foreign tax credits.have not been provided is approximately $4 billion. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings.
Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The Company's income tax benefits related to the tax status of these operations are estimated to be $21$35 million, $38$26 million and $70$20 million for the years ended December 31, 2015, 20142018, 2017 and 2013,2016, respectively. The per share effect of these benefits after noncontrolling interests was $0.02, $0.04, $0.03 and $0.09$0.02 for the years ended December 31, 2015, 20142018, 2017 and 2013,2016, respectively.
The Included in the Company's business in Vietnam began commercial operations in 2015. As part of its power purchase contract with the Vietnam government, the business will be subject to the following reduced income tax rates: 0% for four years, followed by 5% for nine years, followed by 10% forbenefits is the remaining life of the contract term. See Item 1.—Business—Our Organization and Segments for additional information regarding the power purchase contract.
The benefit related to our operations in Vietnam, which is estimated to be $8$19 million, $13 million and $15 million for the yearyears ended December 31, 2015.2018, 2017 and 2016, respectively. The per share effect of these benefits related to our operations in Vietnam after noncontrolling interest was $0.01, $0.01 and $0.01 for the yearyears ended December 31, 2015.2018, 2017 and 2016, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
The following table summarizesshows the income (loss) from continuing operations, before income taxes, net equity in earnings of affiliates and noncontrolling interests, in millions, for the years ended December 31, 2015, 2014 and 2013:periods indicated (in millions):
|
| | | | | | | | | | | | |
| December 31, | | 2018 | | 2017 | | 2016 |
| U.S. | | $ | (218 | ) | | $ | (511 | ) | | $ | (1,305 | ) |
| Non-U.S. | | 2,236 |
| | 1,282 |
| | 1,492 |
|
| Total | | $ | 2,018 |
| | $ | 771 |
| | $ | 187 |
|
|
| | | | | | | | | | | | |
| | | 2015 | | 2014 | | 2013 |
| U.S. | | $ | (612 | ) | | $ | (560 | ) | | $ | (575 | ) |
| Non-U.S. | | 1,734 |
| | 2,136 |
| | 1,623 |
|
| Total | | $ | 1,122 |
| | $ | 1,576 |
| | $ | 1,048 |
|
Uncertain Tax Positions — Uncertain tax positions have been classified as noncurrent income tax liabilities unless they are expected to be paid inwithin one year. The Company's policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
As of December 31, 2015 and 2014, The following table shows the total amount of gross accrued income taxtaxes related to interest included in the Consolidated Balance Sheets was $8 million and $14 million, respectively. The total amount of gross accrued income tax related penalties included in the Consolidated Balance Sheets as of December 31, 2015 and 2014 was $0 million and $1 million, respectively.for the periods indicated (in millions):
|
| | | | | | | | |
| December 31, | | 2018 | | 2017 |
| Interest related | | $ | 4 |
| | $ | 7 |
|
| Penalties related | | — |
| | — |
|
The total expense following table shows the expense/(benefit) for interest related to interest and penalties on unrecognized tax benefits for the years ended December 31, 2015, 2014 and 2013 amounted to $0 million, $3 million and $(4) million, respectively. For the years ended December 31, 2015, 2014 and 2013, the total expense (benefit) for penalties related to unrecognized tax benefits amounted to $0 million, $0 million and $(3) million, respectively.periods indicated (in millions):
|
| | | | | | | | | | | | |
| December 31, | | 2018 | | 2017 | | 2016 |
| Total expense (benefit) for interest related to unrecognized tax benefits | | $ | (3 | ) | | $ | 1 |
| | $ | 2 |
|
| Total expense for penalties related to unrecognized tax benefits | | — |
| | — |
| | — |
|
We are potentially subject to income tax audits in numerous jurisdictions in the U.S. and internationally until the applicable statute of limitations expires. Tax audits by their nature are often complex and can require several years to complete. The following is a summary of tax years potentially subject to examination in the significant tax and business jurisdictions in which we operate:
|
| | |
| Jurisdiction | | Tax Years Subject to Examination |
| Argentina | | 2009-20152012-2018 |
| Brazil | | 2010-20152013-2018 |
| Chile | | 2012-20152015-2018 |
| Colombia | | 2013-20152016-2018 |
| Dominican Republic | | 2012-20152016-2018 |
| El Salvador | | 2012-20152016-2018 |
| Netherlands | | 2013-20152014-2018 |
PhilippinesPanama | | 2012-20152015-2018 |
| United Kingdom | | 2010-20152012-2018 |
| United States (Federal) | | 2011-20152015-2018 |
As of December 31, 2015, 20142018, 2017 and 2013,2016, the total amount of unrecognized tax benefits was $373$463 million, $395$348 million and $392$352 million, respectively. The total amount of unrecognized tax benefits that would benefit the effective tax rate as of December 31, 2015, 20142018, 2017 and 20132016 is $343$446 million, $366$332 million and $360$332 million, respectively, of which $24$33 million, $24$29 million and $26$24 million, respectively, would be in the form of tax attributes that would warrant a full valuation allowance. Further, the total amount of unrecognized tax benefit that would benefit the effective tax rate as of 2018 would be reduced by approximately $161 million of tax expense related to remeasurement from 35% to 21%.
The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax benefits within 12 months of December 31, 20152018 is estimated to be between $15$0 million and $25$10 million, primarily relating to statute of limitation lapses and tax exam settlements.
Next
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits in millions for the periods indicated:indicated (in millions):
|
| | | | | | | | | | | | |
| | | 2018 | | 2017 | | 2016 |
| Balance at January 1 | | $ | 348 |
| | $ | 352 |
| | $ | 364 |
|
| Additions for current year tax positions | | 2 |
| | — |
| | 2 |
|
| Additions for tax positions of prior years | | 146 |
| | 2 |
| | 1 |
|
| Reductions for tax positions of prior years | | (26 | ) | | (5 | ) | | (1 | ) |
| Settlements | | — |
| | — |
| | (13 | ) |
| Lapse of statute of limitations | | (7 | ) | | (1 | ) | | (1 | ) |
| Balance at December 31 | | $ | 463 |
| | $ | 348 |
| | $ | 352 |
|
|
| | | | | | | | | | | | |
| December 31, | | 2015 | | 2014 | | 2013 |
| Balance at January 1 | | $ | 395 |
| | $ | 392 |
| | $ | 475 |
|
| Additions for current year tax positions | | 6 |
| | 8 |
| | 7 |
|
| Additions for tax positions of prior years | | 12 |
| | 14 |
| | 10 |
|
| Reductions for tax positions of prior years | | (7 | ) | | (2 | ) | | (3 | ) |
| Effects of foreign currency translation | | (7 | ) | | (3 | ) | | — |
|
| Settlements | | (19 | ) | | (2 | ) | | (65 | ) |
| Lapse of statute of limitations | | (7 | ) | | (12 | ) | | (32 | ) |
| Balance at December 31 | | $ | 373 |
| | $ | 395 |
| | $ | 392 |
|
The Company and certain of its subsidiaries are currently under examination by the relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the amount of unrecognized tax benefit recorded. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe we have appropriately accrued for our uncertain tax benefits. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits and the range of anticipated increases or decreases in unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of current or future examinations may exceed our provision for current unrecognized tax benefits in amounts that could be material, but cannot be estimated as of December 31, 2015.2018. Our effective tax rate and net income in any given future period could therefore be materially impacted.
23.22. DISCONTINUED OPERATIONS
Due to a portfolio evaluation in the first half of 2016, management decided to pursue a strategic shift of its distribution companies in Brazil, Sul and Eletropaulo, to reduce the Company's exposure to the Brazilian distribution market. The disposals of Sul and Eletropaulo were completed in October 2016 and June 2018, respectively.
Eletropaulo — In November 2017, Eletropaulo converted its preferred shares into ordinary shares and transitioned the listing of those shares to the Novo Mercado, which is a listing segment of the Brazilian stock exchange with the highest standards of corporate governance. Upon conversion of the preferred shares into ordinary shares, AES no longer controlled Eletropaulo, but maintained significant influence over the business. As discussed in Note 1—General and Summary of Significant Accounting Policies, effective July 1, 2014,a result, the Company prospectively adopted ASU No. 2014-08. There have been no businesses classifieddeconsolidated Eletropaulo. After deconsolidation, the Company's 17% ownership interest was reflected as an equity method investment. The Company recorded an after-tax loss on deconsolidation of $611 million, which primarily consisted of $455 million related to cumulative translation losses and $243 million related to pension losses reclassified from AOCL.
In December 2017, all the remaining criteria were met for Eletropaulo to qualify as a discontinued operation. Therefore, its results of operations and financial position were reported as such in the consolidated financial statements for all periods presented.
In June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo through a bidding process hosted by the Brazilian securities regulator, CVM. Gross proceeds of $340 million were received at our subsidiary in Brazil, subject to the payment of taxes. Upon disposal of Eletropaulo, the Company recorded a pre-tax gain on sale of $243 million (after-tax $199 million).
Excluding the gain on sale, Eletropaulo's pre-tax loss attributable to AES was immaterial for the year ended December 31, 2018. Eletropaulo's pre-tax loss attributable to AES, including the loss on deconsolidation, for the years ended December 31, 2017 and 2016 was $633 million and $192 million, respectively. Prior to its classification as discontinued operations, subsequentEletropaulo was reported in the South America SBU reportable segment.
Sul — The Company executed an agreement for the sale of Sul, a wholly-owned subsidiary, in June 2016. The results of operations and financial position of Sul are reported as discontinued operations in the consolidated financial statements for all periods presented. Upon meeting the held-for-sale criteria, the Company recognized an after-tax loss of $382 million comprised of a pre-tax impairment charge of $783 million, offset by a tax benefit of $266 million related to the impairment of the Sul long lived assets and a tax benefit of $135 million for deferred taxes related to the investment in Sul. Prior to the impairment charge, the carrying value of the Sul asset group of $1.6 billion was greater than its approximate fair value less costs to sell. However, the impairment charge was limited to the carrying value of the long lived assets of the Sul disposal group.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
this ASU adoption. Discontinued operations prior
On October 31, 2016, the Company completed the sale of Sul and received final proceeds less costs to adoptionsell of ASU No. 2014-08 include$484 million, excluding contingent consideration. Upon disposal of Sul, the resultsCompany incurred an additional after-tax loss on sale of $737 million. The cumulative impact to earnings of the following businesses:impairment and loss on sale was $1.1 billion. This includes the reclassification of approximately $1 billion of cumulative translation losses resulting in a net reduction to the Company’s stockholders’ equity of $92 million.
Cameroon (soldSul’s pre-tax loss attributable to AES for the year ended December 31, 2016 was $1.4 billion. Prior to its classification as discontinued operations, Sul was reported in June 2014)the South America SBU reportable segment.
Saurashtra (soldBorsod — In 2011, Borsod, which held two coal and biomass-fired generation plants in February 2014)
U.S. wind projects (soldHungary, filed for liquidation and was deconsolidated with its historical operating results reflected in January 2014)
Poland wind projects (solddiscontinued operations under prior accounting guidance. In October 2018, the liquidation was completed and the Company recognized a deferred gain of $26 million, primarily comprised of a $20 million write-off of cumulative translation balances. Prior to its liquidation, Borsod was reported in November 2013)
Ukraine utilities (sold in April 2013)the Eurasia SBU reportable segment.
The following table summarizes revenue,the carrying amounts of the major classes of assets and liabilities of discontinued operations at December 31, 2017:
|
| | | |
| (in millions) | December 31, 2017 |
| Assets of discontinued operations and held-for-sale businesses: | |
Investments in and advances to affiliates (1) | $ | 86 |
|
| Total assets of discontinued operations | 86 |
|
Other assets of businesses classified as held-for-sale (2) | 1,948 |
|
| Total assets of discontinued operations and held-for-sale businesses | $ | 2,034 |
|
| Liabilities of discontinued operations and held-for-sale businesses: | |
Other liabilities of businesses classified as held-for-sale (2) | 1,033 |
|
| Total liabilities of discontinued operations and held-for-sale businesses | $ | 1,033 |
|
_____________________________
| |
(1) | Represents the Company's 17% ownership interest in Eletropaulo. |
| |
(2) | Masinloc, Eletrica Santiago, and the DPL peaker assets were classified as held-for-sale as of December 31, 2017. See Note 23—Held-for-Sale and Dispositions for further information. |
Excluding the gain on sale of Eletropaulo and deferred gain on liquidation of Borsod, income from operations, income tax expense, and impairment and loss on disposal of all discontinued operations prior toand cash flows from operating and investing activities of discontinued operations were immaterial for the adoption of ASU No. 2014-08year ended December 31, 2018.
The following table summarizes the major line items constituting losses from discontinued operations for the periods indicated (in millions):
|
| | | | | | | |
| December 31, | 2017 | | 2016 |
| Income (loss) from discontinued operations, net of tax: | | | |
| Revenue — regulated | $ | 3,320 |
| | $ | 4,036 |
|
| Cost of sales | (3,151 | ) | | (3,954 | ) |
Other income and expense items that are not major (1) | (166 | ) | | (160 | ) |
| Income (loss) from operations of discontinued businesses | 3 |
| | (78 | ) |
| Loss from disposal and impairments of discontinued businesses | (611 | ) | | (1,385 | ) |
| Income (loss) from discontinued operations | (608 | ) | | (1,463 | ) |
| Less: Net income attributable to noncontrolling interests | (25 | ) | | (142 | ) |
| Income (loss) from discontinued operations attributable to The AES Corporation | (633 | ) | | (1,605 | ) |
| Income tax benefit (expense) | (21 | ) | | 495 |
|
| Loss from discontinued operations, net of tax | $ | (654 | ) | | $ | (1,110 | ) |
_____________________________
| |
(1) | Includes a loss contingency recognized by our equity method investment in discontinued operations. |
The following table summarizes the operating and investing cash flows from discontinued operations for the periods indicated (in millions):
|
| | | | | | | |
| December 31, | 2017 | | 2016 |
| Cash flows provided by operating activities of discontinued operations | $ | 164 |
| | $ | 529 |
|
| Cash flows used in investing activities of discontinued operations | (288 | ) | | (368 | ) |
|
| | | | | | | |
| Years Ended December 31, | 2014 | | 2013 |
| Revenue | $ | 233 |
| | $ | 689 |
|
| Income (loss) from operations of discontinued businesses, before income tax | $ | 50 |
| | $ | (3 | ) |
| Income tax expense | (23 | ) | | (24 | ) |
| Income (loss) from operations of discontinued businesses, after income tax | $ | 27 |
| | $ | (27 | ) |
| Net loss from disposal and impairments of discontinued businesses, after income tax | $ | (56 | ) | | $ | (152 | ) |
Cameroon23. HELD-FOR-SALE AND DISPOSITIONS
Held-for-Sale
Shady Point — In September 2013,December 2018, the Company executed agreementsentered into an agreement to sell Shady Point, a U.S. coal-fired generating facility, for the sale of its 56% equity interests in three businesses in Cameroon: Sonel, an integrated utility, Kribi, a gas and light fuel oil plant, and Dibamba, a heavy fuel oil plant.$30 million, subject to customary purchase price adjustments. The sale was completed in June 2014. Net proceeds fromis subject to regulatory approval and is expected to close during the sale transaction were $200 million, with $156 million received and non-contingent considerationsecond half of $44 million to be received in 2016. Between meeting the held-for-sale criteria in September 2013 and completing the sale in June 2014, the Company recognized impairments2019. As of $101 million and an additional loss on sale of $7 million. These businesses were previously reported in the Europe SBU reportable segment.
Saurashtra — In October 2013, the Company executed an agreement for the sale of Saurashtra, a wind project in India. The sale transactionDecember 31, 2018, Shady Point was completed in February 2014 and net proceeds of $8 million were received. Saurashtra was previously reported in the Asia SBU reportable segment.
U.S. wind projects — In November 2013, the Company executed an agreement for the sale of its 100% membership interests in three wind projects: Condon in California, Lake Benton I in Minnesota and Storm Lake II in Iowa. Upon meeting the held-for-sale criteria for these three projects, the Company recognized impairment expense of $47 million (of which $7 million was attributable to noncontrolling interests held by tax equity partners) representing the difference between their aggregate carrying amount of $77 million and the fair value less costs to sell of $30 million. The sale transaction closed in January 2014 and net proceeds of $27 million were received. These businesses were previously reported in the US SBU reportable segment.
Under the terms of the sale agreement, the buyer was provided an option to purchase the Company's 100% interest in Armenia Mountain, a wind project in Pennsylvania at a fixed price of $75 million. Approximately $3 million of the $27 million net proceeds was deferred and allocated to this option. The buyer exercised the option in March 2015 and the sale was completed in July 2015. See Note 24—Dispositions and Held-For-Sale Businesses for further information.
Poland wind projects — In November 2013, the Company completed the sale of Poland Wind, a wholly-owned subsidiary with ownership interests ranging between 61%–89% in ten wind development projects. Net proceeds from the sale transaction were $7 million and a loss on disposal of $2 million was recognized. In the third quarter of 2013, the Company recognized impairments of $65 million on these projects when they were classified as held and used. Poland Wind was previously reported in the Europe SBU reportable segment.
Ukraine utilities — In April 2013, the Company completed the sale of its two utility businesses in Ukraine and received net proceeds of $113 million. The Company sold its 89.1% equity interest in Kyivoblenergo and its 84.6% equity interest in Rivneoblenergo. The Company recognized net impairments of $38 million during 2013. These businesses were previously reported in the Europe SBU reportable segment.
24. DISPOSITIONS AND HELD-FOR-SALE BUSINESSES
Dispositions
Armenia Mountain — On July 1, 2015, the Company completed the sale of its interest in Armenia Mountain, a wind project in Pennsylvania. Net proceeds from the sale were $64 million and the Company recognized a pretax gain on sale of $22 million. As Armenia Mountain doesheld-for-sale, but did not meet the criteria to be reported as a discontinued operation, its results are reflected within continuing operationsoperations. Shady Point's carrying value as of December 31, 2018 was $30 million. Excluding impairment charges, pre-tax income attributable to AES was $19 million in each of the years ended December 31, 2018, 2017 and 2016. Shady Point is reported in the Consolidated Statements of Operations. Excluding the gain on sale, Armenia Mountain'sUS and Utilities SBU reportable segment. See Note 20—Asset Impairment Expense for further information.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
pretax income attributable
Redondo Beach — In October 2018, the Company entered into an agreement to sell land held by AES was $6 million, $7 million, and $4 million forRedondo Beach, a gas-fired generating facility in California. The sale is expected to close during the years endedfirst half of 2019. As of December 31, 2015, 2014, and 2013, respectively. Prior to its sale, Armenia Mountain2018, the $24 million carrying value of the land held by Redondo Beach was classified as held-for-sale. Redondo Beach is reported in the US and Utilities SBU reportable segment. See Note 23 —Discontinued Operations for more information about transactions preceding the sale.
Ebute Dispositions
CTNG — On November 20, 2014, the CompanyIn December 2018, AES Gener completed the sale of its interestCTNG, an entity that holds transmission lines in Ebute, which included its 95% interestChile, for $225 million, subject to customary post-closing adjustments, resulting in AES Nigeria Barge Limited and its 100% interest in AES Nigeria Barge Operations Limited. Proceeds from the sale were $22 million and the Company recognized a $6 million loss on the sale in the fourth quarter of 2014. As Ebute does not meet the criteria to be reported as a discontinued operation, its results are reflected within continuing operations in the Consolidated Statements of Operations. Excluding the loss on sale, Ebute's pretax (loss) attributable to AES was $(27) million and $(29) million for the years ended December 31, 2014 and 2013, respectively. Prior to its sale, Ebute was reported in the Europe SBU reportable segment.
U.K. Wind (Operating Projects) — On August 22, 2014, the Company sold 100% of its interests in four operating wind projects located in the U.K.. Total net proceeds from the sale were $158 million and the Company recognized a pretaxpre-tax gain on sale of $78$129 million. As these wind projects doThe sale did not meet the criteria to be reported as discontinued operations, their results are reflected within continuing operationsoperations. Prior to its sale, CTNG was reported in the Consolidated StatementsSouth America SBU reportable segment.
Electrica Santiago — In May 2018, AES Gener completed the sale of Operations. Excluding theElectrica Santiago for total consideration of $287 million, resulting in a pre-tax gain on sale of $69 million after post-closing adjustments. Electrica Santiago consisted of four gas and diesel-fired generation plants in Chile. The sale did not meet the pretax income (loss) attributablecriteria to AES for these disposed projects was $(18) million and $3 million for the years ended December 31, 2014 and 2013, respectively.be reported as discontinued operations. Prior to its sale, Electrica Santiago was reported in the sale, U.K. Wind (Operating Projects)South America SBU reportable segment.
Stuart and Killen — In May 2018, DPL retired the co-owned Stuart coal-fired and diesel-fired generating units, and the Killen coal-fired generating unit and combustion turbine. Prior to their retirement, Stuart and Killen were reported in the EuropeUS and Utilities SBU reportable segment. See Note 20—Asset Impairment Expense for further information.
Cartagena Masinloc — On April 26, 2013,In March 2018, the Company soldcompleted the sale of its remainingentire 51% equity interest in Cartagena,Masinloc for cash proceeds of $1.05 billion, resulting in a gas-fired generation business in Spain, upon the exercisepre-tax gain on sale of $772 million after post-closing adjustments, subject to U.S. income tax. Masinloc consisted of a purchase option includedcoal-fired generation plant in operation, a coal-fired generation plant under construction and an energy storage facility all located in the 2012Philippines. The sale agreement wheredid not meet the Company sold its majority interest in the business. Net proceeds from the exercise of the option were approximately $24 million and the Company recognized a pretax gain of $20 million during the second quarter of 2013.criteria to be reported as discontinued operations. Prior to its sale, CartagenaMasinloc was reported in the EuropeEurasia SBU reportable segment.
Held-For-Sale Businesses
DPLER — In December 2015,2014, the Company executed an agreement forcompleted the sale of 45% of its ownership interest in Masinloc for $436 million, including $23 million of consideration that was contingent upon the achievement of certain tax restructuring efficiencies. In December 2017, the related contingency expired and the $23 million of contingent consideration was recognized as a gain in Gain (loss) on disposal and sale of business interests in the Consolidated Statement of Operations.
DPL peaker assets — In March 2018, DPL completed the sale of six of its combustion turbine and diesel-fired generation facilities and related assets ("DPL peaker assets") for total proceeds of $239 million, inclusive of estimated working capital and subject to customary post-closing adjustments, resulting in a loss on sale of $2 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, the DPL peaker assets were reported in the US and Utilities SBU reportable segment.
Beckjord facility — In February 2018, DPL transferred its interest in Beckjord, a coal-fired generation facility retired in 2014, including its obligations to remediate the facility and its site. The transfer resulted in cash expenditures of $15 million, inclusive of disposal charges, and a loss on disposal of $12 million. Prior to the transfer, Beckjord was reported in the US and Utilities SBU reportable segment.
Advancion Energy Storage — In January 2018, the Company deconsolidated the AES Advancion energy storage development business and contributed it to the Fluence joint venture, resulting in a gain on sale of $23 million. See Note 7—Investments in and Advances to Affiliates for further discussion. Prior to the transfer, the AES Advancion energy storage development business was reported as part of Corporate and Other.
Zimmer and Miami Fort — In December 2017, DPL and AES Ohio Generation completed the sale of Zimmer and Miami Fort, two coal-fired generating plants, for net proceeds of $70 million, resulting in a gain on sale of $13 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, Zimmer and Miami Fort were reported in the US and Utilities SBU reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Kazakhstan Hydroelectric— Affiliates of the Company (the “Affiliates”) previously operated Shulbinsk HPP and Ust-Kamenogorsk HPP (the “HPPs”), two hydroelectric plants in Kazakhstan, under a concession agreement with the Republic of Kazakhstan (“RoK”). In April 2017, the RoK initiated the process to transfer these plants back to the RoK. The RoK indicated that arbitration would be necessary to determine the correct Return Share Transfer Payment ("RST") and, rather than paying the Affiliates, deposited the RST into an escrow account. In exchange, the Affiliates transferred 100% of the shares in the HPPs to the RoK, under protest and with a full reservation of rights. The Company recorded a loss on disposal of $33 million in the fourth quarter of 2017. In February 2018, the Affiliates initiated the arbitration process in international court to recover at least $75 million of the RST placed in escrow, based on the September 30, 2017 RST calculation. As of December 31, 2018, the arbitration proceedings are ongoing, and additional losses are not considered probable at this time. However, additional losses may be incurred if some or all of the disputed consideration is not paid by the RoK via a mutually acceptable settlement, or upon any unfavorable decision rendered by the arbiter. The transfer did not meet the criteria to be reported as discontinued operations. Prior to their transfer, the Kazakhstan HPPs were reported in the Eurasia SBU reportable segment. See Note 20—Asset Impairment Expense for further information. Kazakhstan CHPs— In April 2017, the Company completed the sale of Ust-Kamenogorsk CHP and Sogrinsk CHP, its combined heating and power coal plants in Kazakhstan, for net proceeds of $24 million. The Company recognized a pre-tax loss on sale of $49 million, primarily related to cumulative translation losses. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, the Kazakhstan CHP plants were reported in the Eurasia SBU reportable segment. See Note 20—Asset Impairment Expense for further information. UK Wind— During 2016, the Company determined it no longer had control of its wind development projects in the United Kingdom (“UK Wind”) as the Company no longer held seats on the board of directors. In accordance with accounting guidance, UK Wind was deconsolidated and a loss on deconsolidation of $20 million was recorded to Gain (loss) on disposal and sale of business interests in the Consolidated Statement of Operations to write off the Company’s noncontrolling interest in the project. The UK Wind projects were reported in the Eurasia SBU reportable segment.
DPLER— In January 2016, the Company completed the sale of DPLER, a competitive retail marketer selling electricity to customers in Ohio. Accordingly,Ohio, and recognized a gain on sale of $49 million. Proceeds of $76 million were received in December 2015. DPLER has been classified as held-for-sale as of December 31, 2015, but doesdid not meet the criteria to be reported as a discontinued operation. DPLER's results arewere therefore reflected within continuing operations in the Consolidated Statements of Operations. DPLER's pretax income attributablePrior to AES was $11 million, $(129) million and $6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Theits sale, of DPLER was completed on January 1, 2016 and proceeds of $76 million were received on December 31, 2015. The proceeds were classified as restricted cash with a corresponding amount recorded in accrued and other liabilities in the Consolidated Balance Sheet as of December 31, 2015. DPLER is reported in the US and Utilities SBU reportable segment.
Kelanitissa— In August 2015,January 2016, the Company executed an agreement forcompleted the sale of its 90% ownership interest in Kelanitissa, a diesel-fired generation plant in Sri Lanka. Accordingly, Kelanitissa has been classified as held-for-sale asLanka, for $18 million, resulting in a loss on sale of December 31, 2015, but does$5 million. The sale did not meet the criteria to be reported as a discontinued operation.operations. Kelanitissa's results arewere therefore reflected within continuing operations in the Consolidated Statements of Operations. Kelanitissa's pretaxPrior to its sale, Kelanitissa was reported in the Eurasia SBU reportable segment.
Jordan — In February 2016, the Company completed the sale of 40% of its interest in a wholly-owned subsidiary in Jordan that owns a controlling interest in the Jordan IPP4 gas-fired plant for $21 million. The transaction was accounted for as a sale of in-substance real estate and a pre-tax gain of $4 million, net of transaction costs, was recognized in net income. The cash proceeds from the sale are reflected in Proceeds from the sale of business interests, net of cash and restricted cash sold on the Consolidated Statement of Cash Flows for the period ended December 31, 2016. After completion of the sale, the Company has a 36% economic interest in Jordan IPP4 and continues to manage and operate the plant. As the Company maintained control after the sale, Jordan IPP4 continues to be consolidated by the Company within the Eurasia SBU reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Excluding any impairment charge or gain/loss on sale, pre-tax income (loss) attributable to AES of disposed businesses was $(7)as follows (in millions):
|
| | | | | | | | | | | |
| Year Ended December 31, | 2018 | | 2017 | | 2016 |
| Masinloc | $ | 9 |
| | $ | 103 |
| | $ | 103 |
|
Stuart and Killen (1)(2) | 77 |
| | 17 |
| | — |
|
| DPL peaker assets | 7 |
| | 17 |
| | 20 |
|
| Zimmer and Miami Fort | — |
| | 26 |
| | (14 | ) |
| Kazakhstan Hydroelectric | — |
| | 33 |
| | 34 |
|
| Kazakhstan CHPs | — |
| | 13 |
| | 12 |
|
| Other | 14 |
| | 9 |
| | 11 |
|
| Total | $ | 107 |
| | $ | 218 |
| | $ | 166 |
|
_____________________________
| |
(1) | The Company entered into contracts to buy back all open capacity years for Stuart and Killen at prices lower than the PJM capacity revenue prices. As such, the Company continues to earn capacity margin. |
| |
(2) | Reductions in the asset retirement obligations for ash ponds and landfills at Stuart and Killen in 2018 resulted in a $32 million reduction to cost of sales. See Note 3—Property, Plant and Equipment for further information. |
24. ACQUISITIONS
Distributed Energy — In December 2018, Distributed Energy acquired the outstanding noncontrolling interest in a partnership holding various solar projects from its tax equity partner for $23 million $1of consideration in a non-cash transaction through the assumption of debt, increasing the Company's ownership to 100%. The partnership was previously classified as an equity method investment. The transaction was accounted for as an asset acquisition, therefore the Company remeasured the equity investment at fair value and recognized a loss of $5 million in Other expense in the Consolidated Statement of Operations. The fair value of the investment, along with the consideration transferred, plus transaction costs, were allocated to the individual assets acquired and $16 million for the years ended December 31, 2015, 2014 and 2013, respectively. The sale of Kelanitissa was completedliabilities assumed based on January 27, 2016 and proceeds of $18 million were received. Kelanitissatheir relative fair values. Distributed Energy is reported in the AsiaUS and Utilities SBU reportable segment.
25. ACQUISITIONS
Main StreetIn September 2016, Distributed Energy acquired the equity interest of various projects held by multiple partnerships for approximately $43 million. These partnerships were previously classified as equity method investments. In accordance with the accounting guidance for business combinations, the Company recorded the opening balance sheets of the acquired businesses based on the purchase price allocation as of the acquisition date.
Oahu —In November 2018, AES Oahu amended a 2017 agreement to acquire 100% of Na Pua Makani Power Partners, a partnership designed to develop and hold a wind project in Hawaii. The fair value of the initial consideration was $53 million, of which $48 million was contingent on meeting predefined development milestones. The transaction was accounted for as an acquisition of a variable interest entity that did not meet the definition of a business, therefore the assets acquired and liabilities assumed were recorded at their fair values, which equaled the fair value of the consideration. As a result of the amendment, the Company paid $11 million in 2018 and the contingent consideration was reduced to $5 million, resulting in a $32 million gain on remeasurement of contingent consideration recorded in Other income in the Consolidated Statement of Operations. AES Oahu is reported in the US and Utilities SBU reportable segment.
Guaimbê Solar Complex ��� In September 2018, AES Tietê completed the acquisition of the Guaimbê Solar Complex (“Guaimbê”) from Cobra do Brasil for $152 million, subject to post-closing adjustments, comprised of the exchange of $119 million of non-convertible debentures in project financing and additional cash consideration of $33 million. The transaction was accounted for as an asset acquisition, therefore the consideration transferred, plus transaction costs, were allocated to the individual assets acquired and liabilities assumed based on their relative fair values. Any differences arising from post-closing adjustments will be allocated accordingly. Guaimbê is reported in the South America SBU reportable segment.
Alto Sertão II — On February 18, 2015, In August 2017, the Company completed the acquisition of 100%the Alto Sertão II Wind Complex (“Alto Sertão II”) from Renova Energia S.A. for $179 million, plus the assumption of $346 million of non-recourse debt. At closing, the Company made a cash payment of $143 million, which excluded holdbacks related to indemnifications. In September 2018, an additional $12 million was paid to settle a portion of the common stockremaining indemnification liability. In the first quarter of Main Street Power2018, the Company Inc. for approximately $25 million, pursuantfinalized the purchase price allocation related to the terms and conditionsacquisition of a definitive agreement dated January 24, 2015.Alto Sertão II. There were no significant adjustments made to the preliminary purchase price
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
allocation recorded in the third quarter of 2017 when the acquisition was completed. The purchase consideration was composed of $20 million cash and the fair value of earn-out payments of $5 million. At December 31, 2015, the assets acquired (including $4 million cash) and liabilities assumed at the acquisition date were recorded at fair value, including a contingent liability for earn-out payments of $18 million, based on the final purchase price allocation which resulted in the recognition of $16 million of goodwill.at March 31, 2018. Subsequent changes to the fair value of the earn-out payments will be reflected in earnings. Alto Sertão II is reported in the South America SBU reportable segment.
26.25. EARNINGS PER SHARE
Basic and diluted earnings per share are based on the weighted-average number of shares of common stock and potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units,RSUs, stock options and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.
The following table is a reconciliation of the numerator and denominator of the basic and diluted earnings per share
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
computation for income from continuing operations for the years ended December 31, 2015, 20142018, 2017 and 2013,2016, where income represents the numerator and weighted-average shares represent the denominator. Values are in millions except per share data:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | 2018 | | 2017 | | 2016 |
| (in millions, except per share data) | Income | | Shares | | $ per Share | | Loss | | Shares | | $ per Share | | Loss | | Shares | | $ per Share |
| BASIC EARNINGS (LOSS) PER SHARE | | | | | | | | | | | | | | | | | |
Income (loss) from continuing operations attributable to The AES Corporation common stockholders (1) | $ | 985 |
| | 662 |
| | $ | 1.49 |
| | $ | (507 | ) | | 660 |
| | $ | (0.77 | ) | | $ | (25 | ) | | 660 |
| | $ | (0.04 | ) |
| EFFECT OF DILUTIVE SECURITIES | | | | |
| | | | | | | | | | | | |
| Restricted stock units | — |
| | 3 |
| | (0.01 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| DILUTED EARNINGS (LOSS) PER SHARE | $ | 985 |
| | 665 |
| | $ | 1.48 |
| | $ | (507 | ) | | 660 |
| | $ | (0.77 | ) | | $ | (25 | ) | | 660 |
| | $ | (0.04 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | 2015 | | 2014 | | 2013 |
| | Income | | Shares | | $ per Share | | Income | | Shares | | $ per Share | | Income | | Shares | | $ per Share |
| BASIC EARNINGS PER SHARE | | | | | | | | | | | | | | | | | |
| Income from continuing operations attributable to The AES Corporation common stockholders | $ | 306 |
| | 687 |
| | $ | 0.45 |
| | $ | 789 |
| | 720 |
| | $ | 1.10 |
| | $ | 284 |
| | 743 |
| | $ | 0.38 |
|
| EFFECT OF DILUTIVE SECURITIES | | | | |
| | | | | | | | | | | | |
| Stock options | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
|
| Restricted stock units | — |
| | 2 |
| | (0.01 | ) | | — |
| | 3 |
| | (0.01 | ) | | — |
| | 4 |
| | — |
|
| DILUTED EARNINGS PER SHARE | $ | 306 |
| | 689 |
| | $ | 0.44 |
| | $ | 789 |
| | 724 |
| | $ | 1.09 |
| | $ | 284 |
| | 748 |
| | $ | 0.38 |
|
| |
(1) | Loss from continuing operations, net of tax, of $20 million less the $5 million adjustment to retained earnings to record the DP&L redeemable preferred stock at its redemption value as of December 31, 2016. |
The calculation of diluted earnings per share excluded 8stock awards and convertible debentures which would be anti-dilutive. The calculation of diluted earnings per share excluded 2 million, 67 million and 78 million stock awards outstanding for the years ended December 31, 2015, 20142018, 2017 and 2013,2016, respectively, that could potentially dilute basic earnings per share in the future. Additionally, for the yearsyear ended December 31, 2015, 2014 and 2013,2016, all 15 million convertible debentures were omittedexcluded from the earnings per share calculation. The stock awards andCompany redeemed all of its existing convertible debentures were excluded fromin June 2017.
For the years ended December 31, 2017 and 2016, respectively, the calculation of diluted earnings per share also excluded 4 million and 5 million outstanding restricted stock units that could potentially dilute earnings per share in the future because they were anti-dilutive.their impact would be anti-dilutive given the loss from continuing operations. Had the Company generated income, 2 million potential shares of common stock related to the restricted stock units would have been included in diluted average shares outstanding for each period.
27.26. RISKS AND UNCERTAINTIES
AES is a diversified power generation and utility company organized into sixfour market-oriented SBUs. See additional discussion of the Company's principal markets in Note 17—15—Segment and Geographic Information. Within our sixfour SBUs, we have two primary lines of business: Generationgeneration and Utilities.utilities. The Generationgeneration line of business uses a wide range of fuels and technologies to generate electricity such as coal, gas, hydro, wind, solar and biomass. Our Utilitiesutilities business is comprised ofcomprises businesses that transmit, distribute, and in certain circumstances, generate power. In addition, the Company has operations in the renewables area. These efforts include projects primarily in wind and solar. Operating and Economic Risks — The Company operates in several developing economies where macroeconomic conditions are usually more volatile than developed economies. Deteriorating market conditions often expose the Company to the risk of decreased earnings and cash flows due to, among other factors, adverse fluctuations in the commodities and foreign currency spot markets. Additionally, credit markets around the globe continue to tighten their standards, which could impact our ability to finance growth projects through access to capital markets. Currently, the Company has a below-investment grade rating from Standard & Poor's of BB-.BB+, Fitch of BB+, and Moody's of Ba1. This could affect the Company's ability to finance new and/or existing development
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
projects at competitive interest rates. As of December 31, 2015,2018, the Company had $1.3$1.2 billion of unrestricted cash and cash equivalents.
During 2015, 76%2018, 68% of our revenue was generated outside the U.S. and a significant portion of our international operations is conducted in developing countries. We continue to invest in several developing countries to expand our existing platform and operations. International operations, particularly the operation, financing and development of projects in developing countries, entail significant risks and uncertainties, including, without limitation:
economic, social and political instability in any particular country or region;
inability to economically hedge energy prices;
volatility in commodity prices;
adverse changes in currency exchange rates;
government restrictions on converting currencies or repatriating funds;
unexpected changes in foreign laws, regulatory framework, or in trade, monetary or fiscal policies;
high inflation and monetary fluctuations;
restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;
threatened or consummated expropriation or nationalization of our assets by foreign governments;
unwillingness of governments, government agencies, similar organizations or other counterparties to honor their commitments;
unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and economically unfavorable to counterparties, against such counterparties, whether such counterparties are governments or private parties;
inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;
adverse changes in government tax policy;
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
difficulties in enforcing our contractual rights, enforcing judgments, or obtaining a just result in local jurisdictions; and
potentially adverse tax consequences of operating in multiple jurisdictions.
Any of these factors, individually or in combination with others, could materially and adversely affect our business, results of operations and financial condition. In addition, our Latin American operations experience volatility in revenue and earnings which have caused and are expected to cause significant volatility in our results of operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability, indexation of certain PPAs to fuel prices, and currency fluctuations being experienced in many of these countries; particularly in Argentina, where $124 million in net foreign currency transaction gains were recognized in 2015 primarily from foreign currency derivatives related to government receivables.countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses.
Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any inability to obtain reasonable increases in tariffs or tariff adjustments for increased expenses, could adversely impact our results of operations or our ability to meet publicly announced projections or analysts' expectations. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions where we operate, particularly our Utilityutility businesses where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:
changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs;
changes in the definition or determination of controllable or noncontrollable costs;
adverse changes in tax law;
changes in the definition of events which may or may not qualify as changes in economic equilibrium;
changes in the timing of tariff increases;
other changes in the regulatory determinations under the relevant concessions; or
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
changes in environmental regulations, including regulations relating to GHG emissions in any of our businesses.
Any of the above events may result in lower margins for the affected businesses, which can adversely affect our results of operations.
Foreign Currency Risks — AES operates businesses in many foreign countries and such operations could be impacted by significant fluctuations in foreign currency exchange rates. Fluctuations in currency exchange rate between U.S. Dollardollar and the following currencies could create significant fluctuations toin earnings and cash flows: the Argentine peso, the Brazilian real, the Dominican Republic peso, the Euro, the Chilean peso, the Colombian peso, and the Philippine peso and the Kazakhstan tenge.peso.
Argentina — In December 2015, the Argentine government lifted foreign currency controls, which resulted in a depreciation of the Argentine peso against the US dollar by approximately 30%. Over the course of 2015, the Argentinean Peso devalued by approximately 50% against the US dollar. Our businesses in Argentina are dependent on the solvency of the Argentine government with which we have long-term receivables. See Note 7—Financing Receivables for further information on the long-term receivables. Further weakening of the Argentine Peso and local economic activity could cause significant volatility in our results of operations, cash flows, and the value of our assets.
Concentrations — Due to the geographical diversity of its operations, the Company does not have any significant concentration of customers or sources of fuel supply. Several of the Company's generation businesses rely on PPAs with one or a limited number of customers for the majority of, and in some cases all of, the relevant businesses' output over the term of the PPAs. However, no single customer accounted for 10% or more of total revenue in 2015, 20142018, 2017 or 2013.2016.
The cash flows and results of operations of our businesses depend on the credit quality of theirour customers and the continued ability of theirour customers and suppliers to meet their obligations under PPAs and fuel supply agreements. If a substantial portion of the Company's long-term PPAs and/or fuel supply were modified or terminated, the Company would be adversely affected to the extent that it would be unable to replace such contracts at equally favorable terms.
Bulgaria — Maritza, the Company's generation facility in Bulgaria, has experienced ongoing delays in the collection of outstanding receivables as a result of liquidity issues faced by our offtaker, NEK. As of December 31, 2015, Maritza's outstanding accounts receivable were $351 million, of which $307 million were overdue. No allowance has been recognized on the receivables as the Company continues to assert that collection is probable.The Bulgarian government elected in 2014 has undertaken an initiative to reform its energy sector, which is necessary to restore NEK's liquidity. NEK's credit rating was downgraded and its transmission license was revoked by the Bulgarian Regulator, which are events of default under the PPA and triggered additional events of default by Maritza under the project
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014, AND 2013
debt agreements.
Although Maritza continued to collect overdue receivables throughout 2015, collections continue to be at risk, which could result in an allowance to be recorded against the remaining receivables and exacerbate liquidity problems at Maritza if the situation were to deteriorate significantly.
28.27. RELATED PARTY TRANSACTIONS
Certain of our businesses in Panama and the Dominican Republic and Kazakhstan are partially owned by governments either directly or through state-owned institutions. In the ordinary course of business, these businesses enter into energy purchase and sale transactions, and transmission agreements with other state-owned institutions which are controlled by such governments. At two of our generation businesses in Mexico, the offtakers exercise significant influence, but not control, through representation on these businesses' Boards of Directors. These offtakers are also required to hold a nominal ownership interest in such businesses. In Chile, we provide capacity and energy under contractual arrangements to our investment which is accounted for under the equity method of accounting. Additionally, the Company provides certain support and management services to several of its affiliates under various agreements.
The Company's Consolidated Statements of Operations included the following transactions with related parties in millions for the periods indicated:indicated (in millions):
|
| | | | | | | | | | | |
| Years Ended December 31, | 2018 | | 2017 | | 2016 |
| Revenue—Non-Regulated | $ | 1,533 |
| | $ | 1,297 |
| | $ | 1,100 |
|
| Cost of Sales—Non-Regulated | 342 |
| | 220 |
| | 210 |
|
| Interest income | 14 |
| | 8 |
| | 4 |
|
| Interest expense | 54 |
| | 36 |
| | 39 |
|
|
| | | | | | | | | | | |
| Years Ended December 31, | 2015 | | 2014 | | 2013 |
| Revenue—Non-Regulated | $ | 1,099 |
| | $ | 1,188 |
| | $ | 1,110 |
|
| Cost of Sales—Non-Regulated | 330 |
| | 331 |
| | 276 |
|
| Interest Income | 25 |
| | 17 |
| | 20 |
|
| Interest Expense | 33 |
| | 9 |
| | 8 |
|
The following table summarizes the balances receivable from and payable to related parties included in the Company's Consolidated Balance Sheets in millions as of the periods indicated:indicated (in millions):
|
| | | | | | | |
| December 31, | 2018 | | 2017 |
| Receivables from related parties | $ | 371 |
| | $ | 250 |
|
| Accounts and notes payable to related parties | 754 |
| | 727 |
|
|
| | | | | | | |
| December 31, | 2015 | | 2014 |
| Receivables from related parties | $ | 181 |
| | $ | 349 |
|
| Accounts and notes payable to related parties | 524 |
| | 567 |
|
China Investment Corporation ("CIC") Transaction — On May 18, 2015, the Parent Company completed the repurchase of 20 million shares of its common stock from Terrific Investment Corporation, at a price per share of $13.07, for an aggregate purchase price of $261 million. Terrific Investment Corporation is a subsidiary controlled by CIC, a previously significant shareholder of The AES corporation. See Note 16—Equity for additional information.
29.28. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Financial Data — The following tables summarize the unaudited quarterly Condensed Consolidated Statements of Operations for the Company for 20152018 and 20142017 (amounts in millions, except per share data). Amounts have been restated to reflect discontinued operations in all periods presented and reflect all adjustments necessary in the opinion of management for a fair statement of the results for interim periods.
|
| | | | | | | | | | | | | | | |
| Quarter Ended 2015 | Mar 31 | | June 30 | | Sept 30 | | Dec 31 |
| Revenue | $ | 3,984 |
| | $ | 3,858 |
| | $ | 3,721 |
| | $ | 3,400 |
|
| Operating margin | 721 |
| | 754 |
| | 673 |
| | 718 |
|
Income from continuing operations, net of tax(1) | 254 |
| | 264 |
| | 203 |
| | 41 |
|
| Discontinued operations, net of tax | — |
| | — |
| | — |
| | — |
|
| Net income | $ | 254 |
| | $ | 264 |
| | $ | 203 |
| | $ | 41 |
|
| Net income (loss) attributable to The AES Corporation | $ | 142 |
| | $ | 69 |
| | $ | 180 |
| | $ | (85 | ) |
| Basic income (loss) per share: | | | | | | | |
| Income (loss) from continuing operations attributable to The AES Corporation, net of tax | $ | 0.20 |
| | $ | 0.10 |
| | $ | 0.27 |
| | $ | (0.13 | ) |
| Discontinued operations attributable to The AES Corporation, net of tax | — |
| | — |
| | — |
| | — |
|
| Basic income (loss) per share attributable to The AES Corporation | $ | 0.20 |
| | $ | 0.10 |
| | $ | 0.27 |
| | $ | (0.13 | ) |
| Diluted income (loss) per share: | | | | | | | |
| Income (loss) from continuing operations attributable to The AES Corporation, net of tax | $ | 0.20 |
| | $ | 0.10 |
| | $ | 0.26 |
| | $ | (0.13 | ) |
| Discontinued operations attributable to The AES Corporation, net of tax | — |
| | — |
| | — |
| | — |
|
| Diluted income (loss) per share attributable to The AES Corporation | $ | 0.20 |
| | $ | 0.10 |
| | $ | 0.26 |
| | $ | (0.13 | ) |
| Dividends declared per common share | $ | — |
| | $ | 0.10 |
| | $ | 0.10 |
| | $ | 0.21 |
|
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
|
| | | | | | | | | | | | | | | |
| Quarter Ended 2014 | Mar 31 | | June 30 | | Sept 30 | | Dec 31 |
| Revenue | $ | 4,262 |
| | $ | 4,311 |
| | $ | 4,441 |
| | $ | 4,132 |
|
| Operating margin | 794 |
| | 819 |
| | 767 |
| | 708 |
|
Income (loss) from continuing operations, net of tax(2,3) | 89 |
| | 281 |
| | 508 |
| | 298 |
|
| Discontinued operations, net of tax | (23 | ) | | (6 | ) | | — |
| | — |
|
| Net income (loss) | $ | 66 |
|
| $ | 275 |
|
| $ | 508 |
|
| $ | 298 |
|
| Net income (loss) attributable to The AES Corporation | $ | (58 | ) | | $ | 133 |
| | $ | 488 |
| | $ | 206 |
|
| Basic income (loss) per share: | | | | | | | |
| Income (loss) from continuing operations attributable to The AES Corporation, net of tax | $ | (0.07 | ) | | $ | 0.20 |
| | $ | 0.68 |
| | $ | 0.29 |
|
| Discontinued operations attributable to The AES Corporation, net of tax | (0.01 | ) | | (0.02 | ) | | — |
| | — |
|
| Basic income (loss) per share attributable to The AES Corporation | $ | (0.08 | ) | | $ | 0.18 |
| | $ | 0.68 |
| | $ | 0.29 |
|
| Diluted income (loss) per share: | | | | | | | |
| Income (loss) from continuing operations attributable to The AES Corporation, net of tax | $ | (0.07 | ) | | $ | 0.20 |
| | $ | 0.67 |
| | $ | 0.29 |
|
| Discontinued operations attributable to The AES Corporation, net of tax | (0.01 | ) | | (0.02 | ) | | — |
| | — |
|
| Diluted income (loss) per share attributable to The AES Corporation | $ | (0.08 | ) | | $ | 0.18 |
| | $ | 0.67 |
| | $ | 0.29 |
|
| Dividends declared per common share | $ | — |
| | $ | 0.05 |
| | $ | 0.05 |
| | $ | 0.15 |
|
|
| | | | | | | | | | | | | | | |
| Quarter Ended 2018 | Mar 31 | | Jun 30 | | Sep 30 | | Dec 31 |
| Revenue | $ | 2,740 |
| | $ | 2,537 |
| | $ | 2,837 |
| | $ | 2,622 |
|
| Operating margin | 656 |
| | 600 |
| | 671 |
| | 646 |
|
Income from continuing operations, net of tax (1) | 778 |
| | 224 |
| | 192 |
| | 155 |
|
Income (loss) from discontinued operations, net of tax (2) | (1 | ) | | 192 |
| | (1 | ) | | 26 |
|
| Net income | $ | 777 |
| | $ | 416 |
| | $ | 191 |
| | $ | 181 |
|
| Net income attributable to The AES Corporation | $ | 684 |
| | $ | 290 |
| | $ | 101 |
| | $ | 128 |
|
| Basic earnings per share: | | | | | | | |
| Income from continuing operations attributable to The AES Corporation common stockholders, net of tax | $ | 1.04 |
| | $ | 0.15 |
| | $ | 0.15 |
| | $ | 0.15 |
|
| Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax | — |
| | 0.29 |
| | — |
| | 0.04 |
|
| Net income attributable to The AES Corporation common stockholders | $ | 1.04 |
| | $ | 0.44 |
| | $ | 0.15 |
| | $ | 0.19 |
|
| Diluted earnings per share: | | | | | | | |
| Income from continuing operations attributable to The AES Corporation common stockholders, net of tax | $ | 1.03 |
| | $ | 0.15 |
| | $ | 0.15 |
| | $ | 0.15 |
|
| Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax | — |
| | 0.29 |
| | — |
| | 0.04 |
|
| Net income attributable to The AES Corporation common stockholders | $ | 1.03 |
| | $ | 0.44 |
| | $ | 0.15 |
| | $ | 0.19 |
|
| Dividends declared per common share | $ | 0.13 |
| | $ | — |
| | $ | 0.13 |
| | $ | 0.27 |
|
|
| | | | | | | | | | | | | | | |
| Quarter Ended 2017 | Mar 31 | | Jun 30 | | Sep 30 | | Dec 31 |
| Revenue | $ | 2,581 |
| | $ | 2,613 |
| | $ | 2,693 |
| | $ | 2,643 |
|
| Operating margin | 557 |
| | 623 |
| | 640 |
| | 645 |
|
Income (loss) from continuing operations, net of tax (3) | 97 |
| | 142 |
| | 235 |
| | (622 | ) |
Income (loss) from discontinued operations, net of tax (4) | 1 |
| | 8 |
| | 26 |
| | (664 | ) |
| Net income (loss) | $ | 98 |
| | $ | 150 |
| | $ | 261 |
| | $ | (1,286 | ) |
| Net income (loss) attributable to The AES Corporation | $ | (24 | ) | | $ | 53 |
| | $ | 152 |
| | $ | (1,342 | ) |
| Basic earnings (loss) per share: | | | | | | | |
| Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax | $ | (0.04 | ) | | $ | 0.08 |
| | $ | 0.22 |
| | $ | (1.03 | ) |
| Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax | — |
| | — |
| | 0.01 |
| | (1.00 | ) |
| Net income (loss) attributable to The AES Corporation common stockholders | $ | (0.04 | ) | | $ | 0.08 |
| | $ | 0.23 |
| | $ | (2.03 | ) |
| Diluted earnings per share: | | | | | | | |
| Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax | $ | (0.04 | ) | | $ | 0.08 |
| | $ | 0.22 |
| | $ | (1.03 | ) |
| Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax | — |
| | — |
| | 0.01 |
| | (1.00 | ) |
| Net income (loss) attributable to The AES Corporation common stockholders | $ | (0.04 | ) | | $ | 0.08 |
| | $ | 0.23 |
| | $ | (2.03 | ) |
| Dividends declared per common share | $ | 0.12 |
| | $ | — |
| | $ | 0.12 |
| | $ | 0.25 |
|
_____________________________
| |
(1) | Includes pretaxpre-tax gains on sales of business interests of $788 million,$89 millionand $128 million, in the first, second and fourth quarters of 2018, respectively, and pre-tax losses of $21 million in the third quarter of 2018 (See Note 23—Held-for-Sale and Dispositions), pre-tax impairment expense of $8$92 million, $37 million, $231$74 million and $326$42 million, forin the first, second, third and fourth quarters of 2015, respectively. SeeNote9—Other Non-Operating Expense, 2018, respectively (See Note 10—Goodwill and Other Intangible Assets, and Note 21—20—Asset Impairment Expensefor further discussion.), other-than-temporary impairment of Guacolda of $144 million in the fourth quarter of 2018 (See Note 7—Investments in and Advances to Affiliates), SAB 118 charges to finalize the provisional estimate of one-time transition tax on foreign earnings of $33 million and $161 million in the third and fourth quarters of 2018, respectively, and a SAB 118 income tax benefit to finalize the provisional estimate of remeasurement of deferred tax assets and liabilities to the lower corporate tax rate of $77 million in the fourth quarter of 2018 (See Note 21—Income Taxes). |
| |
(2) | Includes a pretax gain on sale of approximately $283Eletropaulo of $199 million forin the thirdsecond quarter of 2014 related to the sale of a noncontrolling interest in Masinloc. See2018 (See Note 16—Equity for further discussion. Includes pretax gain of approximately $78 million for the third quarter of 2014 related to the sale of the U.K. wind projects. See Note 24—Dispositions and Held-for-Sale Businesses for further discussion. Includes pretax interest income of $59 million recognized on FONIVEMEM III receivables at AES Argentina in the fourth quarter of 2014. Also includes a pretax foreign currency derivative gain of $106 million recognized on the FONIVEMEM III receivables in the fourth quarter of 2014. See Note 7—Financing Receivables for further discussion. Includes pretax loss of $41 million recognized in Net equity in earnings of affiliates corresponding to the Company's share of an asset impairment at Elsta in the fourth quarter of 2014. See Note 8—Investments In And Advances To Affiliates for further discussion.22—Discontinued Operations). |
| |
(3) | Includes pretaxprovisional tax expense related to a one-time transition tax on foreign earnings of $675 million and the remeasurement of deferred tax assets and liabilities to the lower corporate tax rate of $39 million in the fourth quarter of 2017 (See Note 21—Income Taxes), pre-tax impairment expense of $166$168 million, $107 million, $31$90 million and $79$277 million, forin the first, second third and fourth quarters of 2014, respectively. SeeNote9—Other Non-Operating Expense, 2017, respectively (SeeNote 10—Goodwill and Other Intangible Assets, and Note 21—20—Asset Impairment Expensefor further discussion.), and pre-tax losses on sales of business interests of $48 million in second quarter of 2017 (See Note 23—Held-for-Sale and Dispositions). |
| |
(4) | Includes loss on deconsolidation of Eletropaulo of $611 million in the fourth quarter of 2017 (See Note 22—Discontinued Operations). |
30. SUBSEQUENT EVENTS
Stock Repurchase Program — Subsequent to December 31, 2015, the Parent Company repurchased an additional 8.7 million shares at a cost of $79 million, bringing the cumulative repurchases total from July 2010 through February 23, 2016 to 154.3 million shares for a total cost of $1.9 billion, at an average price per share of $12.12 (including a nominal amount of commissions). As of February 23, 2016, $264 million remains available under the Program. See Note 16—Equity for additional informationregarding the Company's common stock repurchase program.
DPLER — On December 29, 2015, the Company entered into an agreement for the sale of DPLER. This transaction closed January 1, 2016. See Note 24—Dispositions and Held-for-Sale Businesses for further information.
Recourse Debt — Subsequent to December 31, 2015, the Parent Company repurchased $125 million of its outstanding senior notes.
Kelanitissa — On January 27, 2016, the Company completed the sale of Kelanitissa for $18 million. See Note 24—Dispositions and Held-For-Sale Businesses for additional information.The Company expects to recognize an immaterial loss on this transaction during the first quarter of 2016.
IPP4 — On February 18, 2016, the Company completed the sale of a noncontrolling interest in its Jordan IPP4 gas-fired plant for $21 million. Upon completion of the sale, the Company continues to hold a 36% ownership interest in IPP4 and will continue to manage and operate the plant. IPP4 is reported in the Europe SBU reportable segment.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934, as amended (the "Exchange Act") is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.
The Company carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of December 31, 2015,2018, our disclosure controls and procedures were effective.
Management's Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:
pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
provide reasonable assurance that unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements are prevented or detected timely.
Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2015.2018. In making this assessment, management used the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in 2013. Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2015.2018.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2015,2018, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which appears herein.
Changes in Internal Control Over Financial Reporting:
There were no changes that occurred during the quarter ended December 31, 20152018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TheTo the Stockholders and the Board of Directors and Stockholders of The AES Corporation:
Opinion on Internal Control over Financial Reporting
We have audited The AES Corporation'sCorporation’s internal control over financial reporting as of December 31, 2015,2018, based on criteria established in Internal Control-IntegratedControl — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework)framework) (the COSO criteria). In our opinion, The AES Corporation'sCorporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “financial statements”), and our report dated February 26, 2019, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management'sManagement’s Report on Internal Control over Financial Reporting.Reporting. Our responsibility is to express an opinion on the Company'sCompany’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company'scompany’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company'scompany’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company'scompany’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, The AES Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of The AES Corporation as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2015 of The AES Corporation and our report dated February 23, 2016 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
McLean,Tysons, Virginia
February 23, 201626, 2019
ITEM 9B. OTHER INFORMATION
None.
PART III
| |
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The following information is incorporated by reference from the Registrant's Proxy Statement for the Registrant's 20152019 Annual Meeting of Stockholders which the Registrant expects will be filed on or around March 7, 20166, 2019 (the "2016"2019 Proxy Statement"):
information regarding the directors required by this item found under the heading Board of Directors;
information regarding AES's Code of Ethics found under the heading AES Code of Business Conduct and Corporate Governance Guidelines;
information regarding compliance with Section 16 of the Exchange Act required by this item found under the heading Governance Matters—Section 16(a) Beneficial Ownership Reporting Compliance; and
information regarding AES's Financial Audit Committee found under the heading The Committees of the Board—Financial Audit Committee (the “Audit Committee”).
| |
| • | information regarding the directors required by this item found under the heading Board of Directors; |
| |
| • | information regarding AES' Code of Ethics found under the heading Additional Governance Matters - AES Code of Business Conduct and Corporate Governance Guidelines; |
| |
| • | information regarding compliance with Section 16 of the Exchange Act required by this item found under the heading Additional Governance Matters - Other Governance Information - Section 16(a) Beneficial Ownership Reporting Compliance; and |
| |
| • | information regarding AES' Financial Audit Committee found under the heading Board and Committee Governance Matters - Financial Audit Committee (the “Audit Committee”). |
Certain information regarding executive officers required by this Item is presented as a supplementary item in Part I hereof (pursuant to Instruction 3 to Item 401(b) of Regulation S-K). The other information required by this Item, to the extent not included above, will be contained in our 20162019 Proxy Statement and is herein incorporated by reference.
| |
ITEM 11. | EXECUTIVE COMPENSATION |
ITEM 11. EXECUTIVE COMPENSATION
The following information required by Item 402 of Regulation S-K is contained in the 20162019 Proxy Statement under "Director Compensation" and "Executive Compensation" (excluding the information under the caption “Report of the Compensation Committee”) and is incorporated herein by reference: thereference.
The information regarding executive compensationrequired by Item 407(e)(5) of Regulation S-K is contained under the heading Compensation Discussion and Analysis andcaption “Report of the Compensation Committee Report on Executive Compensation under the heading ReportReport” of the Compensation Committee.Proxy Statement. Such information shall not be deemed to be “filed.”
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ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
| |
(a) | Security Ownership of Certain Beneficial Owners.Owners and Management. |
See the information contained under the caption “Securityheading Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers”Officers of the 20162019 Proxy Statement, which information is incorporated herein by reference.
| |
(b) | Security Ownership of Directors and Executive Officers. |
See the information contained under the caption “Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers” of the 2016 Proxy Statement, which information is incorporated herein by reference.
None.
| |
(d)
| Securities Authorized for Issuance under Equity Compensation Plans. |
The following table provides information about shares of AES common stock that may be issued under AES' equity compensation plans, as of December 31, 2015:2018:
Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2015)2018)
| | | | (a) | | (b) | | (c) | (a) | | (b) | | (c) |
| Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted average exercise price of outstanding options, warrants and rights | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted average exercise price of outstanding options, warrants and rights | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) |
Equity compensation plans approved by security holders(1) | 14,101,219 |
| (2) | $ | 13.81 |
| | 15,986,481 |
| 9,794,600 |
| (2) | $ | 12.36 |
| | 14,534,999 |
|
| Equity compensation plans not approved by security holders | — |
| | $ | — |
| | — |
| — |
| | — |
| | — |
|
| Total | 14,101,219 |
| | $ | 13.81 |
| | 15,986,481 |
| 9,794,600 |
| | $ | 12.36 |
| | 14,534,999 |
|
_____________________________
| |
(1) | The following equity compensation plans have been approved by the Company'sThe AES Corporation's Stockholders: |
| |
(A) | The AES Corporation 2003 Long Term Compensation Plan was adopted in 2003 and provided for 17,000,000 shares authorized for issuance thereunder. In 2008, an amendment to the Plan to provide an additional 12,000,000 shares was approved by AES'sAES' stockholders, bringing the total authorized shares to 29,000,000. In 2010, an additional amendment to the Plan to provide an additional 9,000,000 shares was approved by AES'sAES' stockholders, bringing the total authorized shares to 38,000,000. In 2015, an additional amendment to the Plan to provide an additional 7,750,000 shares was approved by AES'sAES' stockholders, bringing the total authorized shares to 45,750,000. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $13.79$12.36 (excluding performance stock units, restricted stock units and director stock units), with 15,986,48114,534,999 shares available for future issuance).issuance. |
| |
(B) | The AES Corporation 2001 Plan for outside directors adopted in 2001 provided for 2,750,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $19.58. In conjunction with the 2010 amendment to the 2003 Long |
Term Compensation plan, ongoing award issuance from this plan was discontinued in 2010. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 2,069,035 shares is not included in Column (c) above.
| |
(C)
| The AES Corporation Second Amended and Restated Deferred Compensation Plan for directors provided for 2,000,000 shares authorized for issuance. Column (b) excludes the Director stock units granted thereunder. In conjunction with the 2010 amendment to the 2003 Long Term Compensation Plan, ongoing award issuance from this plan was discontinued in 2010 as Director stock units will be issued from the 2003 Long Term Compensation Plan. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 105,341 shares is not included in Column (c) above. |
issuance under outstanding awards, are not available for future issuance and thus the amount of 105,341 shares is not included in Column (c) above.
| |
(2) | Includes 5,494,3114,366,156 (of which 1,067,734592,813 are vested and 4,426,5773,773,343 are unvested) shares underlying PSU and RSU awards (assuming 2016 PSU median performance at aand 2017 and 2018 PSUs maximum level)performance), 1,451,5331,646,376 shares underlying Director stock unit awards, and 7,155,3753,782,068 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 14,101,2199,794,600 shares. |
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information regarding related party transactions required by this item is included in the 20162019 Proxy Statement found under the headings Transactions with Related Persons Proposal I: Election of Directorsand The Committees of the Board and Committee Governance Matters and are incorporated herein by reference.
| |
ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information concerning principal accountant fees and servicesrequired by this Item 14 is included in the 20162019 Proxy Statement contained under the heading headings Information Regarding The Independent Registered Public Accounting Firm'sFirm, Audit Fees, ServicesAudit Related Fees, and IndependencePre-Approval Policies and Procedures and is incorporated herein by reference.
PART IV
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ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULE
|
| | |
| Financial Statements and Schedules: | | Page |
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| | |
| | |
| | |
| | |
| | |
| | S-2-S-7 |
|
| | |
| 3.1 | | |
| 3.2 | | |
| 4 | | There are numerous instruments defining the rights of holders of long-term indebtedness of the Registrant and its consolidated subsidiaries, none of which exceeds ten percent of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any of such agreements to the Commission upon request. Since these documents are not required filings under Item 601 of Regulation S-K, the Company has elected to file certain of these documents as Exhibits 4.(a)—4.(r)(q). |
| 4.(a) | | Junior Subordinated Indenture, dated as of March 1, 1997, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association (formerly known as The First National Bank of Chicago) is incorporated herein by reference to Exhibit 4.(a) of the Company's Form 10-K for the year ended December 31, 2008. |
4.(b) | | Third Supplemental Indenture, dated as of October 14, 1999, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association is incorporated herein by reference to Exhibit 4.(b) of the Company's Form 10-K for the year ended December 31, 2008. |
4.(c) | | |
4.(d)(b) | | Form of Second Supplemental Indenture, dated as of June 11, 1999, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association (formerly known as The First National Bank of Chicago) is incorporated herein by reference to Exhibit 4.01 of the Company's Form 8-K filed on June 11, 1999 (SEC File No. 001-12291). |
4.(e) | | Third Supplemental Indenture, dated as of September 12, 2000, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association is incorporated herein by reference to Exhibit 4.(e) of the Company's Form 10-K for the year ended December 31, 2008. |
4.(f) | | Form of Fifth Supplemental Indenture, dated as of February 9, 2001, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on February 8, 2001 (SEC File No. 001-12291). |
4.(g) | | Form of Sixth Supplemental Indenture, dated as of February 22, 2001, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on February 21, 2001 (SEC File No. 001-12291). |
4.(h) | | |
4.(i)(c) | | Form of Tenth Supplemental Indenture, dated as of February 13, 2004, between The AES Corporation and Wells Fargo Bank, National Association (as successor by consolidation to Wells Fargo Bank Minnesota, National Association) is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on February 13, 2004 (SEC File No. 001-12291). |
4.(j) | | Eleventh Supplemental Indenture, dated as of October 15, 2007, between The AES Corporation and Wells Fargo Bank, National Association is incorporated herein by reference to Exhibit 4.7 of the Company's Form S-4 filed on December 7, 2007. |
4.(k) | | Twelfth Supplemental Indenture, dated as of October 15, 2007, between The AES Corporation and Wells Fargo Bank, National Association is incorporated herein by reference to Exhibit 4.8 of the Company's Form S-4 filed on December 7, 2007. |
4.(l) | | Thirteenth Supplemental Indenture, dated as of May 19, 2008, between The AES Corporation and Wells Fargo Bank, National Association is incorporated herein by reference to Exhibit 4.(l) of the Company's Form 10-K for the year ended December 31, 2008. |
4.(m) | | Fourteenth Supplemental Indenture, dated as of April 2, 2009, between The AES Corporation and Wells Fargo Bank, National Association is incorporated herein by reference to Exhibit 99.1 of the Company's Form 8-K filed on April 2, 2009. |
4.(n) | | Fifteenth Supplemental Indenture, dated as of June 15, 2011, between The AES Corporation and Wells Fargo Bank, National Association is incorporated herein by reference to Exhibit 4.3 of the Company's Form 8-K filed on June 15, 2011. |
4.(o) | | Indenture, dated October 3, 2011, between Dolphin Subsidiary II, Inc. and Wells Fargo Bank, National Association is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on October 5, 2011. |
4.(p) | | |
4.(q)(d) | | |
4.(r)(e) | | Eighteenth Supplemental Indenture, dated May 20, 2014, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on May 20, 2014. |
4.(s) | | |
| 4.(f) | | |
| 4.(g) | | |
| 4.(h) | | |
| 4.(i) | | |
| 10.1 | | The AES Corporation Profit Sharing and Stock Ownership Plan are incorporated herein by reference to Exhibit 4(c)(1) of the Registration Statement on Form S-8 (Registration No. 33-49262) filed on July 2, 1992. (P) |
| 10.2 | | The AES Corporation Incentive Stock Option Plan of 1991, as amended, is incorporated herein by reference to Exhibit 10.30 of the Company's Form 10-K for the year ended December 31, 1995 (SEC File No. 00019281). |
|
| | (P) |
| 10.3 | | Applied Energy Services, Inc. Incentive Stock Option Plan of 1982 is incorporated herein by reference to Exhibit 10.31 of the Registration Statement on Form S-1 (Registration No. 33-40483). (P) |
| 10.4 | | Deferred Compensation Plan for Executive Officers, as amended, is incorporated herein by reference to Exhibit 10.32 of Amendment No. 1 to the Registration Statement on Form S-1 (Registration No. 33-40483). (P) |
| 10.5 | | |
| 10.6 | | |
| 10.7 | | The AES Corporation Supplemental Retirement Plan is incorporated herein by reference to Exhibit 10.63 of the Company's Form 10-K for the year ended December 31, 1994 (SEC File No. 00019281). (P) |
| 10.7A | | |
| 10.8 | | |
| 10.9 | | |
| 10.10 | | |
| 10.10A | | |
| 10.11 | | |
| 10.12 | | |
|
| | |
| 10.13 | | |
| 10.14 | | |
| 10.15 | | |
| 10.16 | | |
| 10.17 | | |
| 10.18 | | |
| 10.18A | | |
| 10.19 | | |
| 10.19A | | |
| 10.20 | | |
| 10.21 | | |
| 10.22 | | |
| 10.23 | | |
| 10.24 | | |
| 10.25 | | |
| 10.26 | | |
| 10.27 | | |
| 10.27A | | Sixth Amended and Restated Credit and Reimbursement Agreement dated as of July 26, 2013 among The AES Corporation, a Delaware corporation, the Banks listed on the signature pages thereof, Citibank, N.A., as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc., as Lead Arranger and Book Runner, Banc of America Securities LLC, as Lead Arranger and Book Runner and Co-Syndication Agent, Barclays Capital, as Lead Arranger and Book Runner and Co-Syndication Agent, RBS Securities Inc., as Lead Arranger and Book Runner and Co-Syndication Agent and Union Bank, N.A., as Lead Arranger and Book Runner and Co-Syndication Agent is incorporated herein by reference to Exhibit 10.1.A of the Company's Form 8-K filed on July 29, 2013. |
| 10.27B | | |
| 10.27C | | |
| 10.27D | | |
| 10.27E | | |
| 10.28 | | |
| 10.29 | | |
| 10.30 | | |
| 10.31 | | |
10.3110.32 | | Agreement and Plan of Merger, dated Aprilas of February 19, 2011,2017, by and among The AES Corporation, DPL Inc.Lumos Holdings, LLC, PIP5 Lumos LLC, AES Lumos Merger Sub, LLC, PIP5 Lumos MS LLC, FTP Power LLC and Dolphin Sub, Inc.Fir Tree Solar LLC is incorporated herein by reference to Exhibit 2.110.31 of the Company's Form 8-K filed on April 20, 2011.10-K for the year ending December 31, 2016. |
10.3210.33 | | Credit |
10-K for the year ending December 31, 2017.
|
| | |
10.32A21.1 | | Amendment No.1 dated February 27, 2013 to the Credit Agreement dated as of May 27, 2011 among The AES Corporation, as borrower, the banks listed therein and Bank of America N.A., as administrative agent is incorporated herein by reference to exhibit 10.1 of the Company's Form 10-Q for the period ending March 31, 2013. |
10.33 | | Common Stock Repurchase Agreement, dated as of December 11, 2013, by and between The AES Corporation and Terrific Investment Corporation is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 13, 2013. |
12 | | Statement of computation of ratio of earnings to fixed charges (filed herewith). |
21 | | |
| 23.1 | | |
| 24 | | |
| 31.1 | | |
|
| | |
| 31.2 | | |
| 32.1 | | |
| 32.2 | | |
| 101.INS | | XBRL Instance Document (filed herewith).- the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
| 101.SCH | | XBRL Taxonomy Extension Schema Document (filed herewith). |
| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith). |
| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document (filed herewith). |
| 101.LAB | | XBRL Taxonomy Extension Label Linkbase Document (filed herewith). |
| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith). |
Schedule I—
Financial Information of Registrant
Schedule II—Valuation and Qualifying Accounts
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | | | |
| | | THE AES CORPORATION (Company) |
| | | | |
| Date: | February 23, 201626, 2019 | By: | | /s/ ANDRÉS GLUSKI |
| | | Name: | | Andrés Gluski |
| | | | | President, Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
|
| | | | |
| Name | | Title | | Date |
| | | | | |
| * | | President, Chief Executive Officer (Principal Executive Officer) and Director | | |
| Andrés Gluski | | | February 23, 201626, 2019 |
| | | | | |
| * | | Director | | |
| Charles L. Harrington | | | February 23, 201626, 2019 |
| * | | Director | | |
| Kristina M. Johnson | | | February 23, 201626, 2019 |
| | | | | |
| * | | Director | | |
| Tarun Khanna | | | February 23, 201626, 2019 |
| | | | | |
| * | | Director | | |
| Holly K. Koeppel | | | February 23, 2016 |
| | | | |
* | | Director | | |
Philip Lader | | | February 23, 201626, 2019 |
| | | | | |
| * | | Director | | |
| James H. Miller | | | February 23, 201626, 2019 |
| | | | | |
| * | | Director | | |
| Alain Monié | | | February 26, 2019 |
| | | | |
| * | | Chairman of the Board and Lead Independent Director
| | |
| John B. Morse | | | February 23, 201626, 2019 |
| | | | | |
| * | | Director | | |
| Moises Naim | | | February 23, 201626, 2019 |
| | | | | |
| * | | Chairman of the Board and Lead Independent Director | | |
Charles O. RossottiJeffrey W. Ubben | | | February 23, 201626, 2019 |
| | | | | |
/s/ THOMAS M. O'FLYNN GUSTAVO PIMENTA | | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | | |
Thomas M. O'FlynnGustavo Pimenta | | | February 23, 201626, 2019 |
| | | | | |
/s/ FABIAN E. SOUZASARAH R. BLAKE | | Vice President and Controller (Principal Accounting Officer) | | |
Fabian E. SouzaSarah R. Blake | | | February 23, 201626, 2019 |
|
| | | |
| *By: | /s/ BRIAN A. MILLERPAUL L. FREEDMAN | | February 23, 201626, 2019 |
| | Attorney-in-fact | | |
THE AES CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedules other than thosethat listed above are omitted as the information is either not applicable, not required, or has been furnished in the consolidated financial statements or notes thereto included in Item 8 hereof.
See Notes to Schedule I
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
BALANCE SHEETS
| | | | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2018 | | 2017 |
| | | (in millions) | | (in millions) |
| ASSETS | | | | | | | | |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 186 |
| | $ | 511 |
| | $ | 19 |
| | $ | 10 |
|
| Restricted cash | | 32 |
| | 81 |
| |
| Accounts and notes receivable from subsidiaries | | 264 |
| | 380 |
| | 285 |
| | 143 |
|
| Deferred income taxes | | — |
| | 142 |
| |
| Prepaid expenses and other current assets | | 26 |
| | 57 |
| | 31 |
| | 27 |
|
| Total current assets | | 508 |
| | 1,171 |
| | 335 |
| | 180 |
|
| Investment in and advances to subsidiaries and affiliates | | 7,764 |
| | 9,063 |
| | 6,834 |
| | 8,239 |
|
| Office Equipment: | | | | | | | | |
| Cost | | 135 |
| | 157 |
| | 27 |
| | 27 |
|
| Accumulated depreciation | | (112 | ) | | (114 | ) | | (19 | ) | | (18 | ) |
| Office equipment, net | | 23 |
| | 43 |
| | 8 |
| | 9 |
|
| Other Assets: | | | | | | | | |
| Deferred financing costs (net of accumulated amortization of $75 and $81, respectively) | | 49 |
| | 61 |
| |
| Other intangible assets, net of accumulated amortization | | | 3 |
| | 3 |
|
| Deferred financing costs, net of accumulated amortization of $4 and $2, respectively | | | 4 |
| | 5 |
|
| Deferred income taxes | | 1,028 |
| | 872 |
| | 24 |
| | 289 |
|
| Other Assets | | 1 |
| | 1 |
| |
| Other assets | | | 2 |
| | 2 |
|
| Total other assets | | 1,078 |
| | 934 |
| | 33 |
| | 299 |
|
| Total | | $ | 9,373 |
| | $ | 11,211 |
| |
| Total assets | | | $ | 7,210 |
| | $ | 8,727 |
|
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | | | | | | |
| Current Liabilities: | | | | | | | | |
| Accounts payable | | $ | 16 |
| | $ | 25 |
| | $ | 15 |
| | $ | 18 |
|
| Accounts and notes payable to subsidiaries | | 97 |
| | 80 |
| | 74 |
| | 381 |
|
| Accrued and other liabilities | | 204 |
| | 212 |
| | 206 |
| | 246 |
|
| Senior notes payable—current portion | | — |
| | 151 |
| | 5 |
| | 5 |
|
| Total current liabilities | | 317 |
| | 468 |
| | 300 |
| | 650 |
|
| Long-term Liabilities: | | | | | | | | |
| Senior notes payable | | 4,498 |
| | 4,590 |
| | 3,650 |
| | 4,625 |
|
| Junior subordinated notes and debentures payable | | 517 |
| | 517 |
| |
| Accounts and notes payable to subsidiaries | | 873 |
| | 1,352 |
| | 28 |
| | 967 |
|
| Other long-term liabilities | | 19 |
| | 12 |
| | 24 |
| | 20 |
|
| Total long-term liabilities | | 5,907 |
| | 6,471 |
| | 3,702 |
| | 5,612 |
|
| Stockholders' equity: | | | | | | | | |
| Common stock | | 8 |
| | 8 |
| | 8 |
| | 8 |
|
| Additional paid-in capital | | 8,718 |
| | 8,409 |
| | 8,154 |
| | 8,501 |
|
| Retained Earnings | | 143 |
| | 512 |
| |
| Accumulated deficit | | | (1,005 | ) | | (2,276 | ) |
| Accumulated other comprehensive loss | | (3,883 | ) | | (3,286 | ) | | (2,071 | ) | | (1,876 | ) |
| Treasury stock | | (1,837 | ) | | (1,371 | ) | | (1,878 | ) | | (1,892 | ) |
| Total stockholders' equity | | 3,149 |
| | 4,272 |
| | 3,208 |
| | 2,465 |
|
| Total | | $ | 9,373 |
| | $ | 11,211 |
| |
| Total liabilities and equity | | | $ | 7,210 |
| | $ | 8,727 |
|
See Notes to Schedule I.
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF OPERATIONS
| | | For the Years Ended December 31, | | 2015 | | 2014 | | 2013 | | 2018 | | 2017 | | 2016 |
| | | (in millions) | | (in millions) |
| Revenue from subsidiaries and affiliates | | $ | 24 |
| | $ | 29 |
| | $ | 32 |
| | $ | 36 |
| | $ | 28 |
| | $ | 14 |
|
| Equity in earnings of subsidiaries and affiliates | | 859 |
| | 1,313 |
| | 498 |
| | 1,909 |
| | 630 |
| | (615 | ) |
| Interest income | | 24 |
| | 59 |
| | 66 |
| | 39 |
| | 49 |
| | 19 |
|
| General and administrative expenses | | (154 | ) | | (161 | ) | | (171 | ) | | (142 | ) | | (158 | ) | | (144 | ) |
| Other Income | | 24 |
| | 8 |
| | 14 |
| |
| Other Expense | | (6 | ) | | (30 | ) | | (11 | ) | |
| Other income | | | 25 |
| | 5 |
| | 7 |
|
| Other expense | | | — |
| | (554 | ) | | (65 | ) |
| Loss on extinguishment of debt | | (105 | ) | | (193 | ) | | (165 | ) | | (171 | ) | | (92 | ) | | (14 | ) |
| Interest expense | | (364 | ) | | (422 | ) | | (436 | ) | | (220 | ) | | (317 | ) | | (344 | ) |
| Income (loss) before income taxes | | 302 |
| | 603 |
| | (173 | ) | | 1,476 |
| | (409 | ) | | (1,142 | ) |
| Income tax benefit | | 4 |
| | 166 |
| | 287 |
| |
| Net income | | $ | 306 |
| | $ | 769 |
| | $ | 114 |
| |
| Income tax benefit (expense) | | | (273 | ) | | (752 | ) | | 12 |
|
| Net income (loss) | | | $ | 1,203 |
| | $ | (1,161 | ) | | $ | (1,130 | ) |
See Notes to Schedule I.
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
YEARS ENDED DECEMBER 31, 2015, 2014,2018, 2017, AND 20132016
| | | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 |
| | (in millions) | (in millions) |
| NET INCOME | $ | 306 |
| | $ | 769 |
| | $ | 114 |
| |
| NET INCOME (LOSS) | | $ | 1,203 |
| | $ | (1,161 | ) | | $ | (1,130 | ) |
| Foreign currency translation activity: | | | | | | | | | | |
| Foreign currency translation adjustments, net of income tax (expense) benefit of $1, $(7) and $10, respectively | (674 | ) | | (366 | ) | | (263 | ) | |
| Reclassification to earnings, net of income tax (expense) benefit of $0, $0 and $0, respectively | — |
| | 34 |
| | 36 |
| |
| Foreign currency translation adjustments, net of income tax benefit of $2, $11 and $1, respectively | | (214 | ) | | 18 |
| | 117 |
|
| Reclassification to earnings, net of $0 income tax for all periods | | (21 | ) | | 643 |
| | 992 |
|
| Total foreign currency translation adjustments, net of tax | (674 | ) | | (332 | ) | | (227 | ) | (235 | ) | | 661 |
| | 1,109 |
|
| Derivative activity: | | | | | | | | | | |
| Change in derivative fair value, net of income tax (expense) benefit of $4, $51 and $(31), respectively | (5 | ) | | (180 | ) | | 46 |
| |
| Reclassification to earnings, net of income tax (expense) benefit of $(12), $(37) and $(32), respectively | 48 |
| | 72 |
| | 128 |
| |
| Change in derivative fair value, net of income tax benefit (expense) of $16, $13 and $(5), respectively | | (64 | ) | | (14 | ) | | 2 |
|
| Reclassification to earnings, net of income tax benefit (expense) of $(13), $1 and $1, respectively | | 78 |
| | 37 |
| | 28 |
|
| Total change in fair value of derivatives, net of tax | 43 |
| | (108 | ) | | 174 |
| 14 |
| | 23 |
| | 30 |
|
| Pension activity: | | | | | | | | | | |
| Prior service cost for the period, net of income tax (expense) benefit of $0, $0 and $0, respectively | 1 |
| | (1 | ) | | — |
| |
| Change in pension adjustments due to net actuarial gain (loss) for the period, net of income tax (expense) benefit of $(7), $9 and $(42), respectively | 18 |
| | (13 | ) | | 78 |
| |
| Reclassification of earnings due to amortization of net actuarial loss, net of income tax (expense) benefit of $(2), $0 and $(5), respectively | 2 |
| | 10 |
| | 13 |
| |
| Prior service cost for the period, net of income tax expense of $1, $1 and $5, respectively | | (2 | ) | | 1 |
| | 9 |
|
| Change in pension adjustments due to net actuarial gain (loss) for the period, net of income tax benefit (expense) of $(1), $6 and $10, respectively | | 2 |
| | (20 | ) | | (22 | ) |
| Reclassification of earnings, net of income tax benefit (expense) of $(2), $(126) and $2, respectively | | 7 |
| | 248 |
| | 1 |
|
| Total change in unfunded pension obligation | 21 |
| | (4 | ) | | 91 |
| 7 |
| | 229 |
| | (12 | ) |
| OTHER COMPREHENSIVE INCOME (LOSS) | (610 | ) | | (444 | ) | | 38 |
| (214 | ) | | 913 |
| | 1,127 |
|
| COMPREHENSIVE INCOME (LOSS) | $ | (304 | ) | | $ | 325 |
| | $ | 152 |
| $ | 989 |
| | $ | (248 | ) | | $ | (3 | ) |
See Notes to Schedule I.
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF CASH FLOWS
| | | For the Years Ended December 31, | | 2015 | | 2014 | | 2013 | | 2018 | | 2017 | | 2016 |
| | | (in millions) | | (in millions) |
| Net cash provided by operating activities | | $ | 475 |
| | $ | 449 |
| | $ | 418 |
| | $ | 409 |
| | $ | 148 |
| | $ | 818 |
|
| Investing Activities: | | | | | | | | | | | | |
| Expenses related to asset sales | | — |
| | (4 | ) | | (5 | ) | |
| Proceeds from the sale of business interests, net of expenses | | | 1,222 |
| | — |
| | — |
|
| Investment in and net advances to subsidiaries | | (221 | ) | | (69 | ) | | 201 |
| | (216 | ) | | (339 | ) | | (650 | ) |
| Return of capital | | 501 |
| | 740 |
| | 230 |
| | 242 |
| | 243 |
| | 247 |
|
| Decrease in restricted cash | | 49 |
| | 96 |
| | 50 |
| |
| Additions to property, plant and equipment | | (11 | ) | | (31 | ) | | (11 | ) | | (13 | ) | | (13 | ) | | (12 | ) |
| (Purchase) sale of short term investments, net | | — |
| | (1 | ) | | 1 |
| |
| Net cash provided by (used in) investing activities | | 318 |
| | 731 |
| | 466 |
| | 1,235 |
| | (109 | ) | | (415 | ) |
| Financing Activities: | | | | | | | | | | | | |
| Borrowings (payments) under the revolver, net | | — |
| | — |
| | — |
| |
| (Repayments) Borrowings under the revolver, net | | | (207 | ) | | 207 |
| | — |
|
| Borrowings of notes payable and other coupon bearing securities | | 575 |
| | 1,525 |
| | 750 |
| | 1,000 |
| | 1,025 |
| | 500 |
|
| Repayments of notes payable and other coupon bearing securities | | (915 | ) | | (2,117 | ) | | (1,210 | ) | | (1,933 | ) | | (1,353 | ) | | (808 | ) |
| Loans (to) from subsidiaries | | — |
| | 263 |
| | (152 | ) | |
| Loans from (Repayments to) subsidiaries | | | (143 | ) | | 309 |
| | 183 |
|
| Purchase of treasury stock | | (482 | ) | | (308 | ) | | (322 | ) | | — |
| | — |
| | (79 | ) |
| Proceeds from issuance of common stock | | 4 |
| | 1 |
| | 13 |
| | 7 |
| | 1 |
| | 1 |
|
| Common stock dividends paid | | (276 | ) | | (144 | ) | | (119 | ) | | (344 | ) | | (317 | ) | | (290 | ) |
| Payments for deferred financing costs | | (6 | ) | | (20 | ) | | (17 | ) | | (11 | ) | | (12 | ) | | (12 | ) |
| Other Financing | | (18 | ) | | — |
| | — |
| |
| Net cash (used in) provided by financing activities | | (1,118 | ) | | (800 | ) | | (1,057 | ) | |
| Distributions to noncontrolling interests | | | — |
| | — |
| | (2 | ) |
| Other financing | | | (5 | ) | | (7 | ) | | (3 | ) |
| Net cash used in financing activities | | | (1,636 | ) | | (147 | ) | | (510 | ) |
| Effect of exchange rate changes on cash | | — |
| | — |
| | (1 | ) | | 1 |
| | 6 |
| | 1 |
|
| Increase (decrease) in cash and cash equivalents | | (325 | ) | | 380 |
| | (174 | ) | |
| Increase (Decrease) in cash and cash equivalents | | | 9 |
| | (102 | ) | | (106 | ) |
| Cash and cash equivalents, beginning | | 511 |
| | 131 |
| | 305 |
| | 10 |
| | 112 |
| | 218 |
|
| Cash and cash equivalents, ending | | $ | 186 |
| | $ | 511 |
| | $ | 131 |
| | $ | 19 |
| | $ | 10 |
| | $ | 112 |
|
| Supplemental Disclosures: | | | | | | | | | | | | |
| Cash payments for interest, net of amounts capitalized | | $ | 314 |
| | $ | 373 |
| | $ | 442 |
| | $ | 232 |
| | $ | 282 |
| | $ | 296 |
|
| Cash payments for income taxes, net of refunds | | $ | — |
| | $ | (2 | ) | | $ | 11 |
| | $ | 10 |
| | $ | 2 |
| | $ | 6 |
|
See Notes to Schedule I.
THE AES CORPORATION
SCHEDULE I
NOTES TO SCHEDULE I
1. Application of Significant Accounting Principles
The Schedule I Condensed Financial Information of the Parent includes the accounts of The AES Corporation (the “Parent Company”) and certain holding companies.
Accounting for Subsidiaries and AffiliatesACCOUNTING FOR SUBSIDIARIES AND AFFILIATES —The Parent Company has accounted for the earnings of its subsidiaries on the equity method in the financial information.
Income TaxesINCOME TAXES —Positions taken on the Parent Company's income tax return which satisfy a more-likely-than-not threshold will be recognized in the financial statements. The income tax expense or benefit computed for the Parent Company reflects the tax assets and liabilities on a stand-alone basis and the effect of filing a consolidated U.S. income tax return with certain other affiliated companies.companies as well as effects of U.S. tax law reform enacted in 2017.
Accounts and Notes Receivable from SubsidiariesACCOUNTS AND NOTES RECEIVABLE FROM SUBSIDIARIES —Amounts have been shown in current or long-term assets based on terms in agreements with subsidiaries, but payment is dependent upon meeting conditions precedent in the subsidiary loan agreements.
2. Debt
Senior and Secured Notes and Loans Payable ($ in millions)
|
| | | | | | | | | | | | |
| | | | | | | December 31, |
| | | Interest Rate | | Maturity | | 2018 | | 2017 |
| Senior Unsecured Note | | 8.00% | | 2020 | | $ | — |
| | $ | 228 |
|
| Senior Unsecured Note | | 7.38% | | 2021 | | — |
| | 690 |
|
| Drawings on secured credit facility | | LIBOR + 2.00% | | 2021 | | — |
| | 207 |
|
| Senior Unsecured Note | | 4.00% | | 2021 | | 500 |
| | — |
|
| Senior Secured Term Loan | | LIBOR + 1.75% | | 2022 | | 366 |
| | 521 |
|
| Senior Unsecured Note | | 4.50% | | 2023 | | 500 |
| | — |
|
| Senior Unsecured Note | | 4.88% | | 2023 | | 713 |
| | 713 |
|
| Senior Unsecured Note | | 5.50% | | 2024 | | 63 |
| | 738 |
|
| Senior Unsecured Note | | 5.50% | | 2025 | | 544 |
| | 573 |
|
| Senior Unsecured Note | | 6.00% | | 2026 | | 500 |
| | 500 |
|
| Senior Unsecured Note | | 5.13% | | 2027 | | 500 |
| | 500 |
|
| Unamortized (discounts)/premiums & debt issuance (costs) | | | | | | (31 | ) | | (40 | ) |
| Subtotal | | | | | | $ | 3,655 |
| | $ | 4,630 |
|
| Less: Current maturities | | | | | | (5 | ) | | (5 | ) |
| Total | | | | | | $ | 3,650 |
| | $ | 4,625 |
|
|
| | | | | | | | | | | | |
| | | | | | | December 31, |
| | | Interest Rate | | Maturity | | 2015 | | 2014 |
| Senior Unsecured Note | | 7.75% | | 2015 | | $ | — |
| | $ | 151 |
|
| Senior Unsecured Note | | 9.75% | | 2016 | | — |
| | 164 |
|
| Senior Unsecured Note | | 8.00% | | 2017 | | 181 |
| | 525 |
|
| Senior Unsecured Note | | LIBOR + 3.00% | | 2019 | | 775 |
| | 775 |
|
| Senior Unsecured Note | | 8.00% | | 2020 | | 469 |
| | 625 |
|
| Senior Unsecured Note | | 7.38% | | 2021 | | 1,000 |
| | 1,000 |
|
| Senior Unsecured Note | | 4.88% | | 2023 | | 750 |
| | 750 |
|
| Senior Unsecured Note | | 5.50% | | 2024 | | 750 |
| | 750 |
|
| Senior Unsecured Note | | 5.50% | | 2025 | | 575 |
| | — |
|
| Unamortized premium (discounts) | | | | | | (2 | ) | | 1 |
|
| SUBTOTAL | | | | | | 4,498 |
| | 4,741 |
|
| Less: Current maturities | | | | | | — |
| | (151 | ) |
| Total | | | | | | $ | 4,498 |
| | $ | 4,590 |
|
Junior Subordinated Notes Payable ($ in millions)
|
| | | | | | | | | | | | |
| | | | | | | December 31, |
| | | Interest Rate | | Maturity | | 2015 | | 2014 |
| Term Convertible Trust Securities | | 6.75% | | 2029 | | $ | 517 |
| | $ | 517 |
|
FUTURE MATURITIES OF RECOURSE DEBT — Recourse debt asAs of December 31, 2015 is2018 scheduled to reach maturity asmaturities are presented in the following table below in millions:(in millions):
|
| | | |
| December 31, | Annual Maturities |
| 2019 | $ | 5 |
|
| 2020 | 5 |
|
| 2021 | 505 |
|
| 2022 | 350 |
|
| 2023 | 1,213 |
|
| Thereafter | 1,608 |
|
| Unamortized (discount)/premium & debt issuance (costs) | (31 | ) |
| Total debt | $ | 3,655 |
|
|
| | | |
| December 31, | Annual Maturities |
| 2016 | $ | — |
|
| 2017 | 181 |
|
| 2018 | — |
|
| 2019 | 774 |
|
| 2020 | 469 |
|
| Thereafter | 3,591 |
|
| Total debt | $ | 5,015 |
|
3. Dividends from Subsidiaries and Affiliates
Cash dividends received from consolidated subsidiaries were $748 million, $880 million,$1.9 billion, $1.2 billion and $818 million$1 billion for the years ended December 31, 2015, 2014,2018, 2017, and 2013,2016, respectively. For the year ended December 31, 2018, $1.2 billion of the dividends paid to the Parent Company are derived from the sale of business interests and are classified as an investing activity for cash flow purposes. All other dividends are classified as operating activities. There were no cash dividends received from affiliates accounted for by the equity method for the years ended December 31, 2015, 2014,2018, 2017, and 2013.2016.
4. Guarantees and Letters of Credit
GUARANTEES—In connection with certain of its project financing, acquisition and power purchase agreements, the Parent Company has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments, excluding those collateralized by letter of credit and other obligations discussed below, were limited as of December 31, 2015,2018 by the terms of the agreements, to an aggregate of approximately $396$712 million, representing 1534 agreements with individual exposures ranging from less than $1
million up to $53$157 million. These amounts exclude normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal.
LETTERS OF CREDIT—At December 31, 2015,2018, the Parent Company had $62$78 million in letters of credit outstanding under the senior secured credit facility, representing 23 agreements with individual exposures up to $49 million, and $368 million in letters of credit outstanding under the senior unsecured credit facility, representing 7 agreements with individual exposures ranging from less than $1 million up to $29 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. At December 31, 2015, the Company had $32 million in cash collateralized letters of credit outstanding representing 410 agreements with individual exposures ranging from $1 million up to $15 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations.$247 million. During 2015,2018, the Parent Company paid letter of credit fees ranging from 0.2%1% to 2.5%3% per annum on the outstanding amounts.
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
|
| | | | | | | | | | | | | | | | | | | |
| (in millions) | Balance at Beginning of the Period | | Charged to Cost and Expense | | Amounts Written off | | Translation Adjustment | | Balance at the End of the Period |
| Allowance for accounts receivables | | | | | | | | | |
| (current and noncurrent) | | | | | | | | | |
| Year Ended December 31, 2013 | $ | 195 |
| | $ | 38 |
| | $ | (77 | ) | | $ | (22 | ) | | $ | 134 |
|
| Year Ended December 31, 2014 | 134 |
| | 61 |
| | (88 | ) | | (11 | ) | | 96 |
|
| Year Ended December 31, 2015 | 96 |
| | 88 |
| | (60 | ) | | (29 | ) | | 95 |
|
