10-K 1 a2017form10-k.htm 10-K Document
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
____________________________________
FORM 10-K
_____________________________________ 
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2017
-OR-
¨
TRANSITION REPORT FILED PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
COMMISSION FILE NUMBER 1-12291
aeslogominia01a04.jpg
THE AES CORPORATION
(Exact name of registrant as specified in its charter)
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
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  x    No  o
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 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 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer x
 
Accelerated filer ¨
 
Smaller reporting company ¨
 
Emerging growth company ¨
 
 
 
 
 
 
 
Non-accelerated filer ¨
 
(Do not check if a smaller reporting company)
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, 2017, the last business day of the Registrant's most recently completed second fiscal quarter (based on the adjusted closing sale price of $10.75 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $7.10 billion.
The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, on February 21, 2018 was 660,449,495.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant's Proxy Statement for its 2018 annual meeting of stockholders are incorporated by reference in Parts II and III
 





THE AES CORPORATION FISCAL YEAR 2017 FORM 10-K
TABLE OF CONTENTS





GLOSSARY OF TERMS
The following terms and abbreviations appear in the text of this report and have the definitions indicated below:
Adjusted EPS
Adjusted Earnings Per Share, a non-GAAP measure
Adjusted PTC
Adjusted Pre-tax Contribution, a non-GAAP measure of operating performance
AES
The Parent Company and its subsidiaries and affiliates
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
BOT
Build, Operate and Transfer
BTA
Best Technology Available
CAA
United States Clean Air Act
CAMMESA
Wholesale Electric Market Administrator in Argentina
CCGT
Combined Cycle Gas Turbine
CDPQ
La Caisse de dépôt et placement du Quebéc
CEO
Chief Executive Officer
CHP
Combined 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
CPI
United States Consumer Price Index
CPP
Clean Power Plan
CRES
Competitive Retail Electric Service
CSAPR
Cross-State Air Pollution Rule
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.
DPLER
DPL Energy Resources, Inc.
DPP
Dominican Power Partners
EBITDA
Earnings before Interest, Taxes, Depreciation & Amortization
EPA
United States Environmental Protection Agency
EPC
Engineering, Procurement, and Construction
ERC
Energy Regulatory Commission
ERCOT
Electric Reliability Council of Texas
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
EVP
Executive Vice President
FASB
Financial Accounting Standards Board
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
GAAP
Generally Accepted Accounting Principles in the United States
GHG
Greenhouse Gas
GRIDCO
Grid Corporation of Odisha Ltd.
GWh
Gigawatt Hours
HLBV
Hypothetical Liquidation Book Value
IBEX
Independent Bulgarian Power Exchange
IDEM
Indiana Department of Environmental Management
IPALCO
IPALCO Enterprises, Inc.
IPL
Indiana, Indianapolis Power & Light Company
IPP
Independent Power Producers
ISO
Independent System Operator
IURC
Indiana Utility Regulatory Commission

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LIBOR
London Inter Bank Offered Rate
LNG
Liquefied Natural Gas
MATS
Mercury and Air Toxics Standards
MISO
Midcontinent Independent System Operator, Inc.
MRE
Energy Reallocation Mechanism
MW
Megawatts
MWh
Megawatt Hours
NCI
Noncontrolling Interest
NCRE
Non-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
NM
Not Meaningful
NOV
Notice of Violation
NOX
Nitrogen Dioxide
NPDES
National Pollutant Discharge Elimination System
NSPS
New Source Performance Standards
NYSE
New York Stock Exchange
O&M
Operations and Maintenance
ONS
National System Operator
OPGC
Odisha Power Generation Corporation, Ltd.
Parent Company
The AES Corporation
Pet Coke
Petroleum Coke
PIS
Partially Integrated System
PJM
PJM Interconnection, LLC
PM
Particulate Matter
PPA
Power Purchase Agreement
PREPA
Puerto Rico Electric Power Authority
PSD
Prevention of Significant Deterioration
PSU
Performance Stock Unit
PUCO
The Public Utilities Commission of Ohio
PURPA
Public Utility Regulatory Policies Act
QF
Qualifying Facility
RGGI
Regional Greenhouse Gas Initiative
RMRR
Routine Maintenance, Repair and Replacement
RSU
Restricted Stock Unit
RTO
Regional Transmission Organization
SADI
Argentine Interconnected System
SBU
Strategic Business Unit
SCE
Southern California Edison
SEC
United States Securities and Exchange Commission
SEM
Single Electricity Market
SIC
Central Interconnected Electricity System
SIN
National Interconnected System
SING
Northern Interconnected Electricity System
SIP
State Implementation Plan
SNE
National Secretary of Energy
SO2
Sulfur Dioxide
SSO
Standard Service Offer
TECONS
Term Convertible Preferred Securities
U.S.
United States
VAT
Value Added Tax
VIE
Variable Interest Entity
Vinacomin
Vietnam National Coal-Mineral Industries Holding Corporation Ltd.
YPF
Argentina state-owned gas company

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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, including the fact that the global economy faces considerable uncertainty for the foreseeable future, which further increases many of the risks discussed in this Form 10-K;
changes in inflation, demand for power, interest rates and foreign currency exchange rates, including our ability to hedge our interest rate and foreign currency risk;
changes in the price of electricity at which our generation businesses sell into the wholesale market and our utility businesses purchase to distribute to their customers, and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk;
changes in the prices and availability of coal, gas and other fuels (including our ability to have fuel transported to our facilities) and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk, and our ability to meet credit support requirements for fuel and power supply contracts;
changes in and access to the financial markets, particularly changes affecting the availability and cost of capital in order to refinance existing debt and finance capital expenditures, acquisitions, investments and other corporate purposes;
our ability to manage liquidity and comply with covenants under our recourse and non-recourse debt, including our ability to manage our significant liquidity needs and to comply with covenants under our senior secured credit facility and other existing financing obligations;
changes in our or any of our subsidiaries' corporate credit ratings or the ratings of our or any of our subsidiaries' debt securities or preferred stock, and changes in the rating agencies' ratings criteria;
our ability to purchase and sell assets at attractive prices and on other attractive terms;
our ability to compete in markets where we do business;
our ability to manage our operational and maintenance costs, the performance and reliability of our generating plants, including our ability to reduce unscheduled down times;
our ability to locate and acquire attractive "greenfield" or "brownfield" projects and our ability to finance, construct and begin operating our "greenfield" or "brownfield" projects on schedule and within budget;
our ability to enter into long-term contracts, which limit volatility in our results of operations and cash flow, such as PPAs, fuel supply, and other agreements and to manage counterparty credit risks in these agreements;
variations in weather, especially mild winters and cooler summers in the areas in which we operate, the occurrence of difficult hydrological conditions for our hydropower plants, as well as hurricanes and other storms and disasters, and low levels of wind or sunlight for our wind and solar facilities;
our ability to meet our expectations in the development, construction, operation and performance of our new facilities, whether greenfield, brownfield or investments in the expansion of existing facilities;
the success of our initiatives in other renewable energy projects and energy storage projects;
our ability to keep up with advances in technology;
the potential effects of threatened or actual acts of terrorism and war;
the expropriation or nationalization of our businesses or assets by foreign governments, with or without adequate compensation;
our ability to achieve reasonable rate treatment in our utility businesses;

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changes in laws, rules and regulations affecting our international businesses;
changes in laws, rules and regulations affecting our North America business, including, but not limited to, regulations which may affect competition, the ability to recover net utility assets and other potential stranded costs by our utilities;
changes in law resulting from new local, state, federal or international energy legislation and changes in political or regulatory oversight or incentives affecting our wind business and solar projects, our other renewables projects and our initiatives in GHG reductions and energy storage, including tax incentives;
changes in environmental laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, mercury, hazardous air pollutants and other substances, GHG legislation, regulation, and/or treaties and coal ash regulation;
changes in tax laws, including U.S. tax reform, and the effects of our strategies to reduce tax payments;
the effects of litigation and government and regulatory investigations;
our ability to maintain adequate insurance;
decreases in the value of pension plan assets, increases in pension plan expenses, and our ability to fund defined benefit pension and other 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.

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ITEM 1. BUSINESS
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 vision is to be the world's leading sustainable power company that safely provides reliable, affordable energy. 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 due to the availability of reliable, affordable electric power.
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In 2017, we announced the sale or retirement of 4.3 GW of mostly merchant coal-fired generation, representing 30% of our coal-fired capacity.
Future growth across our company will be heavily weighted toward less carbon-intensive wind, solar and gas generation. In 2017, AES and AIMCo completed the joint acquisition of sPower, the leading independent solar developer in the United States. sPower has 1.3 GW of solar and wind projects and an additional 10 GW of renewables in its development pipeline. sPower's robust development pipeline and expertise position AES to significantly grow our renewables portfolio in the coming years.
Growth in renewables not only provides an opportunity for direct investments in solar and wind generation, but also presents significant potential for energy storage. We are a leader in lithium-ion, battery-based energy storage, with approximately 400 MW in operation, under construction or in advanced development across seven countries. We believe that battery-based energy storage will play a critical role in an increasingly renewables-based generation mix. In January 2018, we partnered with Siemens to form Fluence, a new global energy storage technology and services company. Through a sales partnership with Siemens' global sales force, Fluence will be able to sell energy storage solutions and services in 160 countries as this market grows.
AES continues to invest in LNG opportunities to provide cleaner alternatives to countries with oil-fired power generation. Specifically, AES introduced LNG in the Dominican Republic in 2003 and currently has a 380 MW

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CCGT and LNG storage and regasification facility under construction in Panama.
In the United States, primarily at IPL, we completed a multi-year rate base investment in environmental upgrades to our coal plants and are in the process of re-powering several units from coal to gas.
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 by 25% from 2016 to 2020 and by 50% from 2016 to 2030.
In February 2018, we announced a reorganization as a part of our on-going strategy to simplify our portfolio, optimize our cost structure and reduce our carbon intensity. Reflecting this simplified portfolio, we will manage our global operations separate from our growth and commercial activities.
Strategic Priorities
We have made significant progress towards meeting our strategic goals to maximize value for our shareholders.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Leveraging Our Platforms
 
 
 
 
Focusing our growth in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns
 
 
 
 
 
 
 
 
In 2017, brought on-line seven projects for a total of 279 MW
 
 
 
 
4,401 MW currently under construction and expected to come on-line through 2021
 
 
 
 
Will continue to advance select projects from our development pipeline
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reducing Complexity
 
 
 
 
Exiting businesses and markets where we do not have a competitive advantage, simplifying our portfolio and reducing risk
 
 
 
 
Since 2011
 
 
 
 
 
Announced or closed $5.4 billion in equity proceeds from sales or sell-downs
 
 
 
 
 
Decreased total number of countries where we have operations from 28 to 16
 
 
 
 
In 2017, announced or closed $1.1 billion in equity proceeds from sales or sell-downs of three businesses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Performance Excellence
 
 
 
 
Striving to be the low-cost manager of a portfolio of assets and deriving synergies and scale from our businesses
 
 
 
 
Since 2012, achieved $300 million in cost savings and revenue enhancements, including $50 million in 2017
 
 
 
 
 
Includes overhead reductions, procurement efficiencies and operational improvements
 
 
 
 
 
Expect to achieve an additional $50 million in 2018 and another $50 million from 2019 to 2020, for a total of $400 million in annual savings in 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expanding Access to Capital
 
 
 
 
Optimizing risk-adjusted returns in existing businesses and growth projects
 
 
 
 
Adjust our global exposure to commodity, fuel, country and other macroeconomic risks
 
 
 
 
Building strategic partnerships at the project and business level with an aim to optimize our risk-adjusted returns in our business and growth projects
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Allocating Capital in a Disciplined Manner
 
 
 
 
Maximizing risk-adjusted returns to our shareholders by investing our free cash flow to strengthen our credit and deliver attractive growth in cash flow and earnings
 
 
 
 
In 2017, we generated substantial cash by executing on our strategy, which we allocated in line with our capital allocation framework
 
 
 
 
 
 
 
 
 
 
Used $341 million to prepay and refinance Parent Company debt
 
 
 
 
 
Returned $317 million to shareholders through quarterly dividends
 
 
 
 
 
 
Increased our quarterly dividend by 8.3% to $0.13 per share beginning in the first quarter of 2018
 
 
 
 
 
Invested $481 million in our subsidiaries
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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_____________________________
(1)
Investments in subsidiaries excludes $2.2 billion investment in DPL
(2) 
Excludes working capital adjustments and growth activity prior to the close of the acquisition.
Segments
We are organized into five market-oriented SBUs: US (United States), Andes (Chile, Colombia, and Argentina), Brazil, MCAC (Mexico, Central America, and the Caribbean), and Eurasia (Europe and Asia) — which are led by our SBU Presidents. The Eurasia SBU resulted from the merger of the Europe and Asia SBUs in Q3 2017, in order to leverage scale. Within our five SBUs, we have two lines of business. The first business line is generation, where we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. The second business line is utilities, where we own and/or operate utilities to generate or purchase, distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market.
The Company measures the operating performance of its SBUs using Adjusted PTC and Consolidated Free Cash Flow ("Free Cash Flow"), both non-GAAP measures. The Adjusted PTC and Free Cash Flow by SBU for the year ended December 31, 2017 are shown below. The percentages for Adjusted PTC and Free Cash Flow are the contribution by each SBU to the gross metric, i.e., the total Adjusted PTC by SBU, before deductions for Corporate. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis of this Form 10-K for reconciliation and definitions of Adjusted PTC and Free Cash Flow.
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The following summarizes our businesses within our five SBUs.

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Overview
Generation
We currently own and/or operate a generation portfolio of 34,905 MW, including our integrated 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, fuel costs, seasonality, weather variations and economic activity, fixed-cost management, and competition.
Contract Sales — Most 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"). Our medium-term contract sales have terms of 2 to 5 years, while our long-term contracts have terms of more than 5 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 under Fuel Costs). These contracts are intended to reduce exposure to the volatility of fuel 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 in Contract Sales — Most of our contract sales include a capacity payment that covers projected fixed costs of the plant, including fixed O&M expenses, and a return on capital invested. In addition, most of our contracts require that the majority of the capacity payment be denominated in the currency matching our fixed costs. We generally structure our business to eliminate or reduce foreign exchange risk by matching the currency of revenue and expenses, including fixed costs and debt. Our project debt may consist of both fixed and floating rate debt for which we typically hedge a significant portion of our exposure. Some of our contracted businesses also receive a regulated market-based capacity payment, which is discussed in more detail in the Capacity Payments and Short-Term Sales sections 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 average terms of less than 2 years, including spot sales, directly in the short-term market or 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.
Capacity Payments — Many of the markets in which we operate include regulated capacity markets. These capacity markets are intended to provide additional revenue based upon availability without reliance on the energy margin from the merit order dispatch. Capacity markets are typically priced based on the cost of a new entrant and the system capacity relative to the desired level of reserve margin (generation available in excess of peak demand). Our generating facilities selling in the short-term markets typically receive capacity payments based on their availability in the market. Our most significant capacity revenues are earned by our generation capacity in Ohio and Northern Ireland.
Plant Reliability and Flexibility — Our contract and short-term sales provide incentives to our generation plants to optimally manage availability, operating efficiency and flexibility. Capacity payments under contract sales are frequently tied to meeting minimum standards. In short-term sales, our plants must be reliable and flexible to capture peak market prices and to maximize market-based revenues. In addition, our flexibility allows us to capture ancillary service revenue while meeting local market needs.
Fuel Costs — For our thermal generation plants, fuel is a significant component of our total cost of generation. For contract sales, we often enter into fuel supply agreements to match the contract period, or we may hedge our

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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 Risk in this Form 10-K.
37% of the capacity of our generation plants are fueled by natural gas. Generally, we use gas from local suppliers in each market. A few exceptions to this are AES Gener in Chile, where we purchase imported gas from third parties, and our plants in the Dominican Republic, where we import LNG to utilize in the local market.
33% 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.
26% of the capacity of our generation plants are fueled by renewables, including hydro, solar, wind, energy storage, biomass and landfill gas, which do not have significant fuel costs.
4% of the capacity of our generation fleet utilizes pet coke, diesel 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.
Seasonality, Weather Variations and Economic Activity — Our generation businesses are affected by seasonal weather patterns and, therefore, operating margin is not generated evenly throughout the year. Additionally, weather variations, including temperature, solar and wind resources, and hydrological conditions, may also have an impact on generation output at our renewable generation facilities. In competitive markets for power, local economic activity can also have an impact on power demand and short-term prices for power.
Fixed-Cost Management In our businesses with long-term contracts, the majority of the fixed O&M costs are recovered through the capacity payment. However, for all generation businesses, managing fixed costs and reducing them over time is a driver of business performance.
Competition — For our businesses with medium- or long-term contracts, there is limited competition during the term of the contract. For short-term sales, plant dispatch and the price of electricity are determined by market competition and local dispatch and reliability rules.
Utilities
AES' six utility businesses distribute power to 2.4 million people in two countries. AES' two utilities in the U.S. also include generation capacity totaling 5,373 MW. Our utility businesses consist of IPL (an integrated utility), DPL, including DP&L (transmission and distribution) and AES Ohio Generation (generation), 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 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 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 usage level and may include a pass-through 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, to the customer. Components of the tariff that are directly passed through to the

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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 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 and, therefore, operating margin is not generated evenly throughout 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. Retail 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 explicit, with defined performance incentives or penalties, or implicit, where the utility must operate to meet customer expectations.
Competition — Our integrated utility, IPL, and our regulated utility DP&L, operate as the sole distributors of electricity within their respective jurisdictions. IPL owns and operates 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 electric business is primarily from the on-site generation for industrial customers. 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. See the full discussion under the US SBU.
At our distribution business in El Salvador, we face relatively limited competition due to significant barriers to entry. At many of these businesses, large customers, as defined by the relevant regulator, have the option to both leave and return to regulated service.
Development and Construction
We develop and construct new generation facilities. For our utility business, new plants may be built or existing plants retrofitted in response to customer needs or to comply with regulatory developments. 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. We typically contract with a third party to manage construction, although our construction management team supervises the construction work and tracks progress against the project's budget and the required safety, efficiency and productivity standards.
Segments
The segment reporting structure uses the Company's management reporting structure as its foundation to reflect how the Company manages the business internally. It is organized by geographic regions which provide a socio-political-economic understanding of our business. For financial reporting purposes, the Company's corporate activities are reported within "Corporate and Other" because they do not require separate disclosure. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 15Segment 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.

13




US SBU
Our US SBU has 18 generation facilities and two utilities in the United States.
Generation — Operating installed capacity of our US SBU totals 12,371 MW. IPL's parent, IPALCO Enterprises, Inc., and DPL Inc. are SEC registrants, and as such, follow public filing requirements of the Securities Exchange Act of 1934. The following table lists our US SBU generation facilities:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest
 
Year Acquired or Began Operation
 
Contract Expiration Date
 
Customer(s)
Southland—Alamitos
 
US-CA
 
Gas
 
2,075

 
100
%
 
1998
 
2019-2020
 
Southern California Edison
Southland—Redondo Beach
 
US-CA
 
Gas
 
1,392

 
100
%
 
1998
 
2018
 
Southern California Edison
sPower (1)(2)
 
US-Various
 
Solar
 
1,245

 
50
%
 
2017
 
2028-2046
 
Various
Southland—Huntington Beach
 
US-CA
 
Gas
 
474

 
100
%
 
1998
 
2019-2020
 
Southern California Edison
Shady Point
 
US-OK
 
Coal
 
360

 
100
%
 
1991
 
2018
 
Oklahoma Gas & Electric
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 (2)
 
US-Various
 
Wind
 
142

 
50
%
 
2017
 
2036
 
Various
Distributed PV - Commercial & Utility (3)
 
US-Various
 
Solar
 
126

 
100
%
 
2015-2017
 
2029-2042
 
Utility, Municipality, Education, Non-Profit
Buffalo Gap I (3)
 
US-TX
 
Wind
 
119

 
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
Laurel Mountain ES
 
US-WV
 
Energy Storage
 
27

 
100
%
 
2011
 

 

Warrior Run ES
 
US-MD
 
Energy Storage
 
10

 
100
%
 
2016
 

 

Advancion Applications Center
 
US-PA
 
Energy Storage
 
2

 
100
%
 
2013
 

 

 
 
 
 
 
 
6,998

 
 
 
 
 
 
 
 
_____________________________
(1) 
sPower solar MW shown in Direct Current.
(2) 
Unconsolidated entity, accounted for as an equity affiliate.
(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.
Under construction — The following table lists our plants under construction in the US SBU: 
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest
 
Expected Date of Commercial Operations
Eagle Valley CCGT
 
US-IN
 
Gas
 
671

 
70
%
 
1H 2018
Distributed PV - Commercial
 
US-Various
 
Solar
 
27

 
100
%
 
1H-2H 2018
Lawai
 
US-HI
 
Solar/Energy Storage
 
48

 
100
%
 
1H 2019
Southland Re-powering
 
US-CA
 
Gas
 
1,284

 
100
%
 
1H 2020
Alamitos Energy Center
 
US-CA
 
Energy Storage
 
100

 
100
%
 
1H 2021
 
 
 
 
 
 
2,130

 
 
 
 
Utilities — The following table lists our U.S. utilities and their generation facilities:
Business
 
Location
 
Approximate Number of Customers Served as of 12/31/2017
 
GWh Sold in 2017
 
Fuel
 
Gross MW
 
AES Equity Interest
 
Year Acquired or Began Operation
DPL (1)
 
US-OH
 
521,000

 
14,771

 
Coal/Gas/Diesel/Solar
 
2,125

 
100
%
 
2011
IPL (2)
 
US-IN
 
490,000

 
13,484

 
Coal/Gas/Oil
 
3,248

 
70
%
 
2001
 
 
 
 
1,011,000

 
28,255

 
 
 
5,373

 
 
 
 
_____________________________
(1) 
As of December 31, 2017, DPL's subsidiary AES Ohio Generation, LLC owned the following plants (the Peaker Assets): Tait Units 1-7 and diesels, Yankee Street, Yankee Solar, Monument, Montpelier, Hutchings and Sidney. AES Ohio Generation jointly-owned the following plants: Conesville Unit 4, Killen and Stuart. DPL subsidiary DP&L also owned a 4.9% equity ownership in OVEC, an electric generating company. OVEC has two plants in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of approximately 2,109 MW. DP&L’s share of this generation is approximately 103 MW. AES’ share of the AES Ohio Generation jointly-owned plants, Conesville Unit 4, Stuart and Killen, represents 1,152 MW.
(2) 
CDPQ owns direct and indirect interests in IPALCO which total approximately 30%. AES owns 85% of AES US Investments and AES US Investments owns 82.35% of IPALCO. IPL plants: Georgetown, Harding Street, Petersburg and Eagle Valley (new CCGT currently under construction). 3.2 MW of IPL total is considered a transmission asset.

14




The following map illustrates the location of our U.S. facilities:
usmapitem1v3a03.jpg
U.S. Businesses
U.S. Utilities
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 power 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. MISO 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.
Business Description — IPL is engaged primarily in generating, transmitting, distributing and selling electric energy to 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 941,000. IPL owns and operates four generating stations all within the state of Indiana. IPL’s largest generating station, Petersburg, is coal-fired. The second largest, Harding Street, is natural gas-fired and uses natural gas and fuel oil to power combustion turbines. In addition, IPL operates a 20 MW battery-based energy storage unit at this location. The third, Eagle Valley, retired its coal-fired units in April 2016

15




and the new CCGT is expected to be completed in the first half of 2018 with installed capacity of 671 MW. The fourth, Georgetown, is a small peaking station that uses natural gas to power combustion turbines.
In December 2017, IPL filed an updated petition with the IURC requesting an increase to its basic rates and charges primarily to recover the cost of the new CCGT at Eagle Valley. The requested increase is proposed to coincide with the completion of the CCGT, which is expected in the first half of 2018. IPL’s proposed increase was $125 million annually, or 9%. In February 2018, IPL filed an update to the petition to reflect the newly enacted U.S. tax law, which reduced the revenue increase IPL is seeking to $97 million, or 7%. An order on this proceeding will likely be issued by the IURC by the first quarter of 2019.
Environmental Regulation — For information on compliance with 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, generating unit availability, outage costs and, to a lesser extent, wholesale prices. In addition, IPL's financial results are likely to be driven by many factors, including, but not limited to:
Rate case outcomes
Timely completion of major construction projects and recovery of capital expenditures through base rate growth
Passage of new legislation or implementation of or changes in regulations
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.
DPL
Regulatory Framework and Market Structure — DPL is an energy holding company whose principal subsidiaries include DP&L and AES Ohio Generation, LLC, both of which operate in Ohio. Electric customers within Ohio are permitted to purchase power under contract from a CRES Provider or from their local utility under SSO rates. The SSO generation supply is provided by third parties through a competitive bid process. Ohio utilities have the exclusive right to provide transmission and distribution services in their state certified territories.
DP&L is regulated 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. The PUCO maintains jurisdiction over the delivery of electricity, SSO, and other retail electric services.
While Ohio 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 through a competitive bid process for the supply of power to SSO customers. DP&L's distribution rates are regulated by the PUCO and are established through a traditional cost-based rate-setting process. DP&L is permitted to recover its costs of providing distribution service as well as earn a regulated rate of return on assets, determined by the regulator, based on the utility's allowed regulated asset base, capital structure and cost of capital. DP&L's rates include various adjustment mechanisms including, but not limited to, the timely recovery of costs incurred to comply with alternative energy, renewables, energy efficiency, and economic development costs. DP&L's wholesale transmission rates are regulated by the FERC.
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.
As a member of PJM, AES Ohio Generation is subject to charges and costs associated with PJM operations as approved by the FERC. The capacity construct of PJM operates under the Capacity Performance ("CP") program, which offers capacity revenues combined with penalties for non-performance or under-performance during certain periods identified as "capacity performance hours." This linkage between non- or under-performance during specific hours means that a generation unit that is generally performing well on an annual basis, may incur substantial penalties if it happens to be unavailable for service during some capacity performance hours. Similarly, a generation unit that is generally performing poorly on an annual basis may avoid such penalties if its outages happen to occur only during hours that are not capacity performance hours. An annual “stop-loss” provision exists that limits the size of penalties to 150% of the net cost of new entry, which is a value computed by PJM. This level is

16




likely to be larger than the capacity price established under the CP program, so that there is potential that participation in the CP program could result in capacity penalties that exceed capacity revenues. The purpose of the 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.
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 electric service on behalf of residential, commercial, industrial and governmental customers.
In October 2017, the PUCO approved DP&L's most recent ESP. The agreement establishes a six year settlement, an updated framework to provide retail services including rate structures, non-bypassable charges, and other specific rate recovery true-up mechanisms. The settlement also establishes a three-year non-bypassable distribution modernization rider designed to collect $105 million in revenue per year which could be extended by PUCO for an additional two years.
In October 2017, DP&L transferred its interest in its coal-fired and certain other generating units to AES Ohio Generation. AES Ohio Generation, solely or through jointly-owned facilities, owns coal-fired and peaking generation units representing 2,125 MW located in Ohio and Indiana. AES Ohio Generation sells all of its energy and capacity into the wholesale market.
In January 2017, Stuart Unit 1 failed and was retired. In March 2017 it was decided to retire the Stuart coal-fired and diesel-fired generating units and Killen coal-fired generating unit and combustion turbine on or before June 1, 2018. In December 2017, AES Ohio Generation sold its undivided interests in Zimmer and Miami Fort, and entered into an agreement to sell its 973 MW of peaking capacity.
Environmental Regulation — For information on compliance with environmental regulations see Item 1.United States Environmental and Land-Use Legislation and Regulations.
Key Financial Drivers — DPL's financial results are primarily driven by retail demand, weather, energy efficiency, generating unit availability, outage costs, and wholesale prices. In addition, DPL financial results are likely to be driven by many factors, including, but not limited to:
PJM capacity prices
Outcome of DP&L's pending distribution rate case
Recovery in the power market, particularly as it relates to an expansion in dark spreads
DPL's ability to reduce its cost structure
Construction and Development — Planned construction additions primarily relate to new investments in and upgrades to DPL's power plant equipment and 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.
DPL is projecting to spend an estimated $359 million in capital projects for the period 2018 through 2020 with 94% 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. We expect to finance these construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.
U.S. Generation
Business Description — In the U.S., we own a diversified generation portfolio in terms of geography, technology and fuel source. The principal markets and locations where we are engaged in the generation and supply of electricity (energy and capacity) are the Western Electric Coordinating Council, PJM, Southwest Power Pool Electric Energy Network and Hawaii. AES Southland, in the Western Electric Coordinating Council, is our most significant generating business.
Many of our U.S. generation plants provide baseload operations and are required to maintain a guaranteed level of availability. Any change in availability has a direct impact on financial performance. The plants are generally eligible for availability bonuses on an annual basis if they meet certain requirements. In addition to plant availability, fuel cost is a key business driver for some of our facilities.

17




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 of SCE. 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.
All of AES Southland's capacity is contracted through a long-term agreement (the “Tolling Agreement”), expiring on May 31, 2018. In 2017, the California Public Utilities Commission approved the Resource Adequacy Purchase Agreements (the “RAPAs”) between the SCE and AES Huntington Beach, LLC and AES Alamitos, LLC for the period of June 1, 2018 through 2020, and the SCE and AES Redondo Beach for the period of June 1, 2018 through December 31, 2018. Under the RAPAs, the generating stations will only provide resource adequacy capacity, and have no obligation to produce or sell any energy to SCE. However, the generating stations may bid energy into the California ISO markets.
Under the current Tolling Agreement, approximately 98% of AES Southland's revenue comes from availability. Historically, AES Southland has generally met or exceeded its contractual availability requirements under the Tolling Agreement and may capture bonuses for exceeding availability requirements in peak periods.
Under the Tolling Agreement, the offtaker provides gas to the three facilities thus AES Southland is not exposed to significant fuel price risk. If the units operate better than the guaranteed efficiency, AES Southland gets credit for the gas that is not consumed. Conversely, AES Southland is responsible for the cost of fuel in excess of what would have been consumed had the guaranteed efficiency been achieved. The business is also exposed to replacement power costs for a limited period if dispatched by the offtaker and not able to meet the required generation.
Environmental Regulation — For a discussion of environmental regulatory matters affecting U.S. Generation, see Item 1.United States Environmental and Land-Use Legislation and Regulations.
Re-powering — In November 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. Under the contracts, all capacity will be sold 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 natural gas and charging electricity.
In April 2017, the California Energy Commission unanimously approved the licenses for the new combined cycle projects at AES Alamitos and AES Huntington Beach. In June 2017, AES closed the financing of $2.0 billion, funded with a combination of non-recourse debt and AES equity. The construction of this new capacity started during 2017 and commercial operation of the gas-fired capacity is expected in 2020 and the energy storage capacity in 2021.
Key Financial Drivers — AES Southland's contractual availability is the single most important driver 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.
Additional U.S. Generation Businesses
Regulatory Framework and Market Structure — For the non-renewable businesses, coal and natural gas are used as the primary fuels. Coal prices are set by market factors internationally, while natural gas is generally set domestically. Price variations for these fuels can change the composition of generation costs and energy prices in our generation businesses.
Many of these generation businesses have entered into long-term PPAs with utilities or other offtakers. Some businesses with PPAs have mechanisms to recover fuel costs from the offtaker, including an energy payment partially based on the market price of fuel. 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.
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 to purchase power from QFs at the utility's avoided cost (i.e., the likely costs for

18




both energy and capital investment that would have been incurred by the purchasing utility if that utility had to provide its own generating capacity or purchase it from another source). To be a QF, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility's total energy output and meet certain efficiency standards. To be a QF, a small power production facility must generally use a renewable resource as its energy input and meet certain size criteria.
Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators as defined under 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 Federal 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.
The U.S. wholesale electricity market consists of multiple distinct regional markets that are subject to both federal regulation, as implemented by the 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.
Business Description — Additional businesses include thermal, wind, and solar generating facilities, of which our U.S. Renewables businesses and AES Hawaii are the most significant.
U.S. Renewables
sPower owns and/or operates more than 150 utility and distributed electrical generation systems across the U.S., actively buying, developing, constructing and operating renewable assets in the United States.
AES Distributed Energy develops, constructs and sells electricity generated by photovoltaic solar energy systems to public sector, utility, and non-profit entities through PPAs.
Excluding sPower wind plants, AES has 734 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., leveraging operational and commercial resources to supplement the experienced subject matter experts in the renewable industry to achieve optimal results. A portion of U.S. Solar projects and the majority of wind projects have been financed with tax equity structures. Under these tax equity structures, the tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in variability to earnings attributable to AES compared to the earnings reported at the facilities.
AES Hawaii
AES Hawaii receives a fuel payment from its offtaker under a PPA expiring in 2022, which is based on a fixed rate indexed to the Gross National Product — Implicit Price Deflator. Since the fuel payment is not directly linked to market prices for fuel, the risk arising from fluctuations in market prices for coal is borne by AES Hawaii.
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.
Environmental Regulation — For a discussion of environmental laws and regulations affecting the U.S. business, see Item 1.—United States Environmental and Land-Use Legislation and Regulations.
Key Financial Drivers — U.S. thermal 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

19




addition, major maintenance requiring units to be off-line is performed during periods when power demand is typically lower. The financial results of U.S. Wind are primarily driven by increased production due to faster and less 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. Tax reform enacted December 22, 2017 will change the taxation of U.S. Generation’s operations beginning in 2018. 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 project, U.S. Generation performs capital projects related to major plant maintenance, repairs and upgrades to be compliant with new environmental laws and regulations.
Andes SBU
Generation — Our Andes SBU has generation facilities in three countries — Chile, Colombia and Argentina. AES Gener, which owns all of our assets in Chile, Chivor in Colombia and TermoAndes in Argentina, as detailed below, is a publicly listed company in Chile. AES has a 66.7% ownership interest in AES Gener and this business is consolidated in our financial statements.
Operating installed capacity of our Andes SBU totals 9,326 MW, of which 44%, 45% and 11% are located in Argentina, Chile and Colombia, respectively. The following table lists our Andes SBU generation facilities:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest
 
Year Acquired or Began Operation
 
Contract Expiration Date
 
Customer(s)
Chivor
 
Colombia
 
Hydro
 
1,000

 
67
%
 
2000
 
Short-term
 
Various
Tunjita
 
Colombia
 
Hydro
 
20

 
67
%
 
2016
 
 
 
 
Colombia Subtotal
 
 
 
 
 
1,020

 
 
 
 
 
 
 
 
Guacolda (1)
 
Chile
 
Coal
 
760

 
33
%
 
2000
 
2018-2032
 
Various
Electrica Santiago (2)
 
Chile
 
Gas/Diesel
 
750

 
67
%
 
2000
 

 

Gener-SIC (3)
 
Chile
 
Hydro/Coal/Diesel/Biomass
 
690

 
67
%
 
2000
 
2020-2037
 
Various
Electrica Angamos
 
Chile
 
Coal
 
558

 
67
%
 
2011
 
2026-2037
 
Minera Escondida, Minera Spence, Quebrada Blanca
Cochrane
 
Chile
 
Coal
 
550

 
40
%
 
2016
 
2030-2034
 
SQM, Sierra Gorda, Quebrada Blanca
Gener-SING (4)
 
Chile
 
Coal
 
277

 
67
%
 
2000
 
2018-2037
 
Minera Escondida, Codelco, SQM, Quebrada Blanca
Electrica Ventanas (5)
 
Chile
 
Coal
 
272

 
67
%
 
2010
 
2025
 
Gener
Electrica Campiche (6)
 
Chile
 
Coal
 
272

 
67
%
 
2013
 
2020
 
Gener
Andes Solar
 
Chile
 
Solar
 
21

 
67
%
 
2016
 
2037
 
Quebrada Blanca
Cochrane ES
 
Chile
 
Energy Storage
 
20

 
40
%
 
2016
 
 
 
 
Electrica Angamos ES
 
Chile
 
Energy Storage
 
20

 
67
%
 
2011
 

 

Norgener ES (Los Andes)
 
Chile
 
Energy Storage
 
12

 
67
%
 
2009
 

 

Chile Subtotal
 
 
 
 
 
4,202

 
 
 
 
 
 
 
 
TermoAndes (7)
 
Argentina
 
Gas/Diesel
 
643

 
67
%
 
2000
 
Short-term
 
Various
AES Gener Subtotal
 
 
 
 
 
5,865

 
 
 
 
 
 
 
 
Alicura
 
Argentina
 
Hydro
 
1,050

 
100
%
 
2000
 
2017
 
Various
Paraná-GT
 
Argentina
 
Gas/Diesel
 
845

 
100
%
 
2001
 

 

San Nicolás
 
Argentina
 
Coal/Gas/Oil
 
675

 
100
%
 
1993
 

 

Guillermo Brown (8)
 
Argentina
 
Gas/Diesel
 
576

 
%
 
2016
 
 
 
 
Los Caracoles (8)
 
Argentina
 
Hydro
 
125

 
%
 
2009
 
2019
 
Energia Provincial Sociedad del Estado (EPSE)
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
 
 
 
 
 
3,461

 
 
 
 
 
 
 
 
 
 
 
 
 
 
9,326

 
 
 
 
 
 
 
 
_____________________________
(1) 
Guacolda plants: Guacolda 1, 2, 3, 4, and 5 are unconsolidated entities 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%.
(2) 
Electrica Santiago plants: Nueva Renca, Renca, Los Vientos and Santa Lidia. AES Gener announced the sale of this business in December 2017.
(3) 
Gener-SIC plants: Alfalfal, Laguna Verde, Laguna Verde Turbogas, Laja, Maitenes, Queltehues, Ventanas 1, Ventanas 2 and Volcán.
(4) 
Gener-SING plants: Norgener 1 and Norgener 2.
(5) 
Electrica Ventanas plant: Ventanas 3.

20




(6) 
Electrica Campiche plant: Ventanas 4.
(7) 
TermoAndes is located in Argentina, but is connected to both the SING in Chile and the SADI in Argentina.
(8) 
AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses.
Under construction — The following table lists our plants under construction in the Andes SBU: 
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest
 
Expected Date of Commercial Operations
Alto Maipo
 
Chile
 
Hydro
 
531

 
62
%
 
1H 2019 (1)
_____________________________
(1)  
The following map illustrates the location of our Andes facilities:
andesmapitem1a01.jpg
Andes Businesses
Chile
Regulatory Framework and Market Structure — Chile has operated a single power market, managed by CISEN, since November 2017. Previously, Chile had two main power systems, the SIC and SING, largely as a result of its geographic shape and size. The SIC served approximately 92% of the Chilean population, including the densely populated Santiago Metropolitan Region, representing 75% of the country's electricity demand. The SING, which mainly supplied mining companies, served about 6% of the Chilean population, representing 25% of Chile's electricity demand.
CISEN coordinates all generation and transmission companies previously in the SIC and SING. CISEN minimizes the operating costs of the electricity system, while maximizing service quality and reliability requirements. CISEN 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 SIC, thermoelectric generation is 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 the majority of installed capacity as hydroelectric generation is not feasible. The

21




fuels used for thermoelectric generation, mainly coal, diesel and LNG, are indexed to international prices. In 2017, the generation installed capacity in the Chilean market was composed primarily of the following:
 
 
SIC
 
SING
 
CISEN
Thermoelectric
 
44%
 
84%
 
54%
Hydroelectric
 
38%
 
 
29%
Solar
 
8%
 
11%
 
9%
Wind
 
7%
 
3%
 
6%
Other
 
3%
 
2%
 
2%
In the SIC, where hydroelectric plants represent a large part of the system's installed capacity, hydrological conditions influence reservoir water levels and largely determine the dispatch of the system's hydroelectric and thermoelectric generation plants and, therefore, influence spot market prices. Precipitation in Chile occurs principally in the southern cone mostly from June to August, and is scarce during the remainder of the year. During 2017 spot prices were also affected by a 14% increase in installed renewable energy capacity, totaling 564 MW, bringing total installed capacity to 4,719 MW.
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. The electricity sector is divided into three segments: generation, transmission and distribution. Generally, generation and transmission growth is subject to market competition, while transmission operation and distribution are subject to price regulation. 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 2 MW. Customers with connected capacity between 0.5 MW and 2.0 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 contract. 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 CISEN. AES Gener is the second largest generation operator in Chile with installed capacity of 4,150 MW, excluding energy storage and TermoAndes, and a market share of approximately 18% as of December 31, 2017.
AES Gener owns a diversified generation portfolio in Chile in terms of geography, technology, customers and fuel source. AES Gener's installed capacity is 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 and gas fired) 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 CISEN 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 both fixed and variable payments which are indexed to the CPI and the international price of coal. In some cases, the contracts include pass-through of fuel and regulatory costs, including changes in law.
In addition to energy payments, AES Gener also receives capacity payments to remain available during periods of peak demand. CISEN 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.
The Chilean government allows the export of energy generated from plants in the SING to Argentina utilizing transmission lines owned by AES Gener.
Environmental Regulation — During 2016, the Environmental Ministry updated the Atmospheric

22




Decontamination Plans for the Santiago, Ventanas and Huasco regions. Our plants in these regions — Nueva Renca, Ventanas and Guacolda — are evaluating operational improvements and additional investments to comply with the new requirements. As of December 31, 2017, the regulator did not issue the decree that provides the framework and time line for these investments.
Chilean law requires every electricity generator to supply a certain portion of its total contractual obligations with NCREs. Generation companies are able to meet this requirement by constructing 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 utilizing AES Gener's solar and biomass power plants and by purchasing NCREs from other generation companies. AES Gener has also sold and contracted certain water rights to companies to construct small hydro projects to ensure longer term NCRE compliance. 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 "change of law" clauses allowing the Company to pass the green tax costs to customers. Distribution PPAs originating from the SIC do not allow for the pass through of these costs; however, the costs can be passed through to unregulated customers. The Company is currently discussing the pass-through mechanism with each distribution customer.
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 strengthening regulations on thermal generation assets
Market price risk when re-contracting
Construction and Development — AES Gener continues to advance the construction of the 531 MW Alto Maipo run-of-the-river hydroelectric plant. Alto Maipo is the largest project in construction in the SIC market. When completed, it will include 74 km of tunnel works, two caverns, 17 km of transmission lines as part of the construction, and is 90% underground. Alto Maipo has two main contractors and covers three adjacent valleys in the Chilean Andes. The project currently employs approximately 4,500 people. 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 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 (70%) and thermal (29%), totaled 16,782 MW as of December 31, 2017. The marked seasonal variations in Colombia's hydrology result in price volatility in the short-term market. In 2017, 87% 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. The distinct activities of the electricity sector are governed by Colombian laws and the CREG. Other government entities have a role in the electricity industry, including the Ministry of Mines and Energy, which defines the government's policy for the energy sector; the Public Utility Superintendency of Colombia, which is in charge of overseeing utility companies; and the Mining and Energetic Planning Unit, which is in charge of expansion of the generation and transmission network.
The generation sector is organized on a competitive basis with companies selling their generation in the wholesale market at the short-term price or under bilateral contracts with other participants, including distribution companies, generators and traders, and unregulated customers at freely negotiated prices. The National Dispatch Center dispatches generators in merit order based on bid offers in order to ensure that demand will be satisfied by the lowest cost combination of available generating units.

23




The Colombian government and regulatory entity carried out various studies to improve the market. As a result, resolutions were issued in 2017 capping spot prices to reflect the true value of thermal plants; allowing small scale self-generation and distributed generation the option to sell excess energy to the grid; and a proposal to change the methodology for determining capacity payments for existing plants based on a new auction with the objective of reducing the reliability charges.
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, both located approximately 160 km east of Bogota. AES Chivor’s installed capacity accounted for approximately 6% of system capacity by the end of 2017. 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 reduce margin volatility by selling a significant portion of expected generation by bidding in public auctions for one to three year contracts, mainly with distribution companies. The remaining generation is sold on the spot market to other generation and trading companies at the system marginal cost. Additionally, AES Chivor receives reliability payments to maintain plant availability during periods of power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.
Key Financial Drivers — Hydrological conditions largely influence Chivor's generation abilities. Maintaining the appropriate contract level, while maximizing revenue through the sale of excess generation, is key to Chivor's results of operations. Hedge levels at Chivor limit volatility in the underlying financial drivers. In addition to hydrology, financial results are driven by many factors, including, but not limited to:
Forced outages
Fluctuations of the Colombian peso
Exposure to the spot market
Argentina
Regulatory Framework and Market Structure — Argentina has one main power system, the SADI, which serves 96% of the country. As of December 31, 2017, the installed capacity of the SADI totaled 36,505 MW. The SADI's installed capacity is composed primarily of thermoelectric generation (63%) and hydroelectric generation (32%).
Thermoelectric generation in the SADI is primarily natural gas. However, natural gas shortages in winter (June to August), lead to 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 spot market prices. Precipitation in Argentina occurs principally in the southern cone mostly from June to August.
Regulatory Framework — The Argentine regulatory framework divides the electricity sector into generation, transmission and distribution. The wholesale electric market is made up of generation companies, transmission companies, distribution companies and large customers who are 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 Ministry of Energy and Mining, through the Energy Secretariat, 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. In these cases, 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 fuels, except coal, are to be provided by CAMMESA. Thermoelectric natural gas plants, such as TermoAndes, are not subject to CAMMESA fuel purchases and are able to purchase gas directly from the producers.
Argentina’s new administration continues introducing regulatory improvements with the intention to normalize the energy sector. Among others, Resolution 19/2017 was enacted to set higher tariffs, denominated in USD, for energy and capacity prices. The Resolution also ceased non-cash retention of margins. 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 2017, the government has continued increasing residential and industrial tariffs in order to reduce the system deficit aiming to have all subsidies removed by the end of 2019.
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

24




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-K for further discussion of receivables in Argentina.
Business Description — As of December 31, 2017, AES Argentina operates 4,104 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 SING markets. AES Argentina has a diversified generation portfolio.
AES Argentina primarily sells its energy in the wholesale electric market where prices are largely regulated. In 2017, approximately 93% of the energy was sold in the wholesale electric market and 7% was sold under contract, as a result of contract sales made by TermoAndes.
All thermoelectric facilities not subject to fuel procurement from CAMMESA, including the portion of TermoAndes plant committed to Energy Plus contracts, are able to use natural gas and receive gas supplied from Argentine sources. In recent years, gas supply restrictions in Argentina, particularly during the winter season, have affected the operation of certain plants, such as the TermoAndes plant.
Since December 2015, foreign currency controls were lifted, allowing the Argentine peso to float under the administration of Argentinian Central Bank. Over the course of 2017, the Argentine peso devalued by approximately 17%.
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, to be effective on January 1, 2018. This tax reform will reduce the statutory corporate tax rate of companies from 35% to 30% in 2018 and 2019, and 25% from 2020 onward. The law also eliminates the Equalization Tax on the distribution of earnings generated after January 1, 2018. The Equalization Tax is to be replaced with a withholding tax on dividends at the rate of 7% for 2018 and 2019, and 13% from 2020 onward.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
Forced outages
Exposure to fluctuations of the Argentine peso
Changes in hydrology
Timely collection of FONINVEMEM installment and outstanding receivables (See Note 6.—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion)
Gas prices for contracted generation (Energy Plus)
Brazil SBU
Our Brazil SBU operates three generation businesses. Tietê is a publicly listed company in Brazil. AES controls and consolidates Tietê through its 24% economic interest.
Generation — Operating installed capacity of our three generation businesses totals 3,684 MW. The following table lists our Brazil SBU generation facilities:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest
 
Year Acquired or Began Operation
 
Contract Expiration Date
 
Customer(s)
Tietê (1)
 
Brazil
 
Hydro
 
2,658

 
24
%
 
1999
 
2029
 
Various
Alto Sertão II
 
Brazil
 
Wind
 
386

 
24
%
 
2017
 
2033-2035
 
 
Tietê Subtotal
 
 
 
 
 
3,044

 
 
 
 
 
 
 
 
Uruguaiana
 
Brazil
 
Gas
 
640

 
46
%
 
2000
 

 

 
 
 
 
 
 
3,684

 
 
 
 
 
 
 
 
_____________________________
(1) 
Tietê plants: 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).

25




The following map illustrates the location of our Brazil facilities:
brazilmapitem1a01.jpg
Brazil Businesses
Brazil Utility
Business Description — Eletropaulo distributes electricity to the greater São Paulo area, Brazil's main economic and financial center. Eletropaulo holds a 30-year concession that expires in 2028. AES owns 17% of the economic interest in Eletropaulo. In November 2017, Eletropaulo converted its preferred shares into ordinary shares and transitioned the listing of those shares into 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 and accounted for its ownership interest as an equity method investment. In December 2017, all the criteria were met for Eletropaulo to be classified as a discontinued operation.
Brazil Generation
Regulatory Framework and Market Structure — In Brazil, the Ministry of Mines and Energy determines the maximum amount of energy a plant can sell, called a 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.
The ONS is responsible for managing the operation of the national grid. The ONS dispatches generators based on hydrological conditions, reservoir levels, electricity demand, fuel prices and thermal generation availability. The consequences of unfavorable hydrology are (i) thermal plants become more expensive to dispatch in the system, (ii) the need for hydro plants to purchase energy in the spot market to fulfill their contractual obligations and (iii) high spot prices. Given the importance of hydro generation in the country, the ONS sometimes reduces dispatch of hydro facilities and increases dispatch of thermal facilities to maintain reservoir levels in the system.

26




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.
Brazil has installed capacity of 156,436 MW, which is primarily hydroelectric (64%) and thermal (17%).
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 operates 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's strategy is 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.
Under the concession agreement, Tietê is required to increase its capacity in the state of São Paulo by 15% (or 400 MW). In 2017, Tietê acquired two solar plants and was successful in a bid to develop a third solar project in the state of São Paulo, totaling 75% of the obligation. These assets are not subject to return at the end of the concession. Also 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. Alto Sertão II is subject to 20-year PPAs expiring between 2033 and 2035. Through its ownership of Tietê, AES owns a 24% economic interest in Alto Sertão II.
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 or 2017. AES has evaluated several alternatives to bring gas supply on a competitive basis to Uruguaiana. One of the challenges is the capacity restrictions on the Argentinean pipeline, 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
Ability to execute on its growth strategy
Construction and Development — As part of the initiative to pursue opportunities in renewable generation, Tietê has invested in three special purpose entities slated to construct photovoltaic power plants with a total projected capacity of 91 MW, subject to 20-year PPAs. Commercial operation is expected by the end of 2018.
MCAC SBU
Our MCAC SBU has a portfolio of distribution businesses and generation facilities, including renewable energy, in five countries, with a total capacity of 3,381 MW and distribution networks serving 1.4 million customers as of December 31, 2017.

27




Generation — The following table lists our MCAC SBU generation facilities:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest
 
Year Acquired or Began Operation
 
Contract Expiration Date
 
Customer(s)
DPP (Los Mina)
 
Dominican Republic
 
Gas
 
358

 
85
%
 
1996
 
2022
 
CDEEE
Andres
 
Dominican Republic
 
Gas
 
319

 
85
%
 
2003
 
2022
 
Ede Norte/Ede Este/Ede Sur/Non-Regulated Users
Itabo (1) 
 
Dominican Republic
 
Coal
 
295

 
43
%
 
2000
 
2022
 
Ede Norte/Ede Este/Ede Sur
Andres ES
 
Dominican Republic
 
Energy Storage
 
10

 
85
%
 
2017
 
 
 
 
Los Mina DPP ES
 
Dominican Republic
 
Energy Storage
 
10

 
85
%
 
2017
 
 
 
 
Dominican Republic Subtotal
 
 
 
 
 
992

 
 
 
 
 
 
 
 
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

 
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

 
 
 
 
 
 
 
 
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
Ilumina
 
US-PR
 
Solar
 
24

 
100
%
 
2012
 
2032
 
Puerto Rico Electric Power Authority
Puerto Rico Subtotal
 
 
 
 
 
548

 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,381

 
 
 
 
 
 
 
 
_____________________________
(1) 
Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine).
Under construction — The following table lists our plants under construction in the MCAC SBU: 
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest
 
Expected Date of Commercial Operations
Bosforo
 
El Salvador
 
Solar
 
30

 
100
%
 
1H-2H 2018
Colón
 
Panama
 
Gas
 
380

 
50
%
 
2H 2018
 
 
 
 
 
 
410

 
 
 
 
Utilities — Our distribution businesses are located in El Salvador and distribute power to 1.4 million people in the country. These businesses consist of four companies, each of which operates in defined service areas. The following table lists our MCAC utilities:
Business
 
Location
 
Approximate Number of Customers Served as of 12/31/2017
 
GWh Sold in 2017
 
AES Equity Interest
 
Year Acquired or Began Operation
CAESS
 
El Salvador
 
599,000

 
2,213

 
75
%
 
2000
CLESA
 
El Salvador
 
398,000

 
898

 
80
%
 
1998
DEUSEM
 
El Salvador
 
80,000

 
133

 
74
%
 
2000
EEO
 
El Salvador
 
307,000

 
577

 
89
%
 
2000
 
 
 
 
1,384,000

 
3,821

 
 
 
 

28




The following map illustrates the location of our MCAC facilities:
mcacmapitem1a01.jpg
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. In addition, they monitor behavior in the electric 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 3,692 MW of installed capacity, composed primarily of thermal (79%), hydroelectric (17%) and wind (4%) 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 46% of energy demand via these generation facilities. 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. Itabo's PPAs with government-owned distribution companies expired in July 2016. The

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Dominican Corporation of State Electrical Companies sponsored a bidding process, which was awarded in April 2017 for a total of 196 MW of installed capacity and secured supply and competitive pricing for actual and future distribution energy requirements.
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. Both Andres and Los Mina have in aggregate 697 MW of installed capacity, of which 625 MW is mostly contracted until 2022 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 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 2018.
Additional sales derived from domestic natural gas demand are expected to continue providing income and growth based on the entry of future projects and the fees from the infrastructure service.
El Salvador
Regulatory Framework and Market Structure — El Salvador 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 get affordable rates. The energy sector is governed by the General Electricity Law which defines 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 ("SIGET") regulates the market and sets consumer prices. SIGET, jointly with the distribution companies in El Salvador, completed the tariff reset process in December 2017 and developed the tariff calculation applicable from 2018 until 2022.
El Salvador has a national electric grid which interconnects with Guatemala and Honduras. The sector has approximately 1,882 MW of installed capacity, composed primarily of thermal (40%), hydroelectric (29%), geothermal (11%), biomass (13%), solar (5%) and other renewable (2%) generation plants/farms.
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 77% of the country and accounted for 4,124 GWh of the wholesale market energy purchases during 2017, or about 65% 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 100 MW solar farm with an estimated cost of $158 million. 10 MW of the project are under construction and expected to become operational during the first half of 2018. The energy produced by this project will be contracted directly by AES' utilities in El Salvador.
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

30




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 2,983 MW, composed primarily of hydroelectric (57%) and thermal (38%) generation.
Business Description — AES owns and operates five hydroelectric plants and one thermoelectric power plant, Estrella del Mar I, representing 705 MW and 72 MW of hydro and thermal capacity, respectively and 26% 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 low inflows from January through May, AES Panama may purchase energy in the short-term market to cover contractual obligations. During the remainder of the year, energy generation is generally in excess of contractual commitments, excess generation is sold on the short-term market.
A portion of the PPAs with distribution companies will expire in December 2018, reducing the total contracted capacity in Panama from 496 MW to 430 MW. Another portion contracted through Estrella del Mar I will expire in June 2020, reducing the total contracted capacity to 350 MW through December 2030.
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, 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.
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. As of December 31, 2017, amounts capitalized include $666 million recorded in construction-in-progress and the project is scheduled to initiate operations in the second half of 2018.
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.

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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 Federal Electricity Commission ("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.
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, expects to begin construction in the first half of 2018.
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.
Changes in the Locational Marginal Price and the Transmission High Tension Tariff.
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 Commission ("PREC") is the main regulatory body. The commission 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 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. 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.
Eurasia SBU
Generation — Our Eurasia SBU has generation facilities in seven countries. Operating installed capacity totaled 6,143 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.
India Subtotal
 
 
 
 
 
420

 
 
 
 
 
 
 
 
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

 
 
 
 
 
 
 
 
Elsta (1)(2) 
 
Netherlands
 
Gas
 
630

 
50
%
 
1998
 
2018
 
Dow Benelux/Delta/Nutsbedrijven/Essent Energy
Netherlands ES
 
Netherlands
 
Energy Storage
 
10

 
100
%
 
2015
 
 
 
 
Netherlands Subtotal
 
 
 
 
 
640

 
 
 
 
 
 
 
 
Masinloc (3)
 
Philippines
 
Coal
 
630

 
51
%
 
2008
 
Mid- and long-term
 
Various
Masinloc ES (3)
 
Philippines
 
Energy Storage
 
10

 
51
%
 
2016
 
 
 
 
Philippines Subtotal
 
 
 
 
 
640

 
 
 
 
 
 
 
 
Ballylumford
 
United Kingdom
 
Gas
 
1,015

 
100
%
 
2010
 
2023
 
Power NI/Single Electricity Market (SEM)
Kilroot (4)
 
United Kingdom
 
Coal/Oil
 
701

 
99
%
 
1992
 
 
 
Single Electricity Market (SEM)
Kilroot ES
 
United Kingdom
 
Energy Storage
 
10

 
100
%
 
2015
 
 
 
 
United Kingdom Subtotal
 
 
 
 
 
1,726

 
 
 
 
 
 
 
 
Mong Duong 2
 
Vietnam
 
Coal
 
1,240

 
51
%
 
2015
 
2040
 
EVN
Vietnam Subtotal
 
 
 
 
 
1,240

 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,143

 
 
 
 
 
 
 
 
_____________________________
(1) 
Unconsolidated entity, the results of operations of which are reflected in Equity in Earnings of Affiliates.
(2) 
Plant will be sold upon expiration of the PPA in September 2018.
(3) 
Announced the sale of this business in December 2017.
(4) 
Includes Kilroot Open Cycle Gas Turbine.
Under construction — The following table lists our plants under construction in the Eurasia SBU: 
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest
 
Expected Date of Commercial Operations
OPGC 2 (1)
 
India
 
Coal
 
1,320

 
49
%
 
2H 2018
Delhi ES
 
India
 
Energy Storage
 
10

 
50
%
 
2H 2018
 
 
 
 
 
 
1,330

(2) 
 
 
_____________________________
(1) 
Unconsolidated entity, accounted for as an equity affiliate.
(2) 
In December 2017, AES announced the sale of Masinloc. As such, 335 MW under construction at Masinloc 2 has been excluded from this table.

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The following map illustrates the location of our Eurasia facilities:
eurasiamapitem1a02.jpg
Eurasia 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 at bilaterally negotiated prices in an open market or on the day-ahead IBEX market. In March 2017, IBEX introduced an intra-day market platform. In addition, IBEX launched a platform for trading long-term contracts in Q4 2016. Effective January 1, 2018 all electricity outside regulated quotas may only be traded via the IBEX platform. Bulgaria is working with the European Commission and the World Bank 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, a stable regulatory environment, universal access to the grid, and numerous cross-border connections in neighboring countries. In addition, it plays an important role in the energy balance on the Balkan region.
Bulgaria has 13 GW of installed capacity enabling the country to meet and exceed domestic demand and export energy. Installed capacity is 39% coal-fired and 16% nuclear.
Business Description — Our Maritza plant is a 690 MW lignite fuel thermal power plant commissioned in June 2011. Maritza's entire power output is contracted with NEK under a 15-year PPA, expiring in May 2026.
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. Its entire power output is contracted with NEK under a 15-year PPA expiring in March 2025.
Our plants in Bulgaria operate under long-term PPAs with NEK, which has previously experienced liquidity issues. In April 2016, NEK paid Maritza its overdue receivables in exchange for amending the PPA and reducing the capacity payment to Maritza by 14% through the remaining PPA term. Maritza has experienced timely collection of outstanding receivables from NEK since May 2016. However, NEK's liquidity position remains subject to political conditions and regulatory changes in Bulgaria.
The DG Comp is reviewing NEK’s PPA with Maritza pursuant to the European Commission’s state aid rules.

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Maritza believes that its PPA is legal and 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.
Key Financial Drivers Both businesses, Maritza and St. Nikola, operate under PPA contracts. For the duration of the PPA, financial results are driven by many factors, including, but not limited to:
Regulatory changes to the Bulgaria power market
Results of the DG Comp review
The availability of the operating units
The level of wind resources for St. Nikola
NEK's ability to meet the payment terms of the PPA contract
United Kingdom
Regulatory Framework and Market Structure — The electricity sector in Northern Ireland is operated by the SEM. It is based on a gross mandatory pool within which all generators with 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.
In addition, the SEM has a capacity payment mechanism to ensure that sufficient generating capacity is offered to the market. The capacity payment is derived from a regulated Euro-based capacity payment pool, established a year ahead by the regulatory authority. Capacity payments are based on the expected availability of a unit and are subject to volatility due to seasonal influences, demand, and the actual generation available over each trading period. In the second quarter of 2018 regulatory authorities are expected to update the market framework to reflect the integration of the SEM day-ahead and intra-day markets with EU energy markets, introduce a new competitive capacity auction, and revise arrangements for system services to incentivize flexibility. The market will be renamed I-SEM (Integrated Single Electricity Market) to reflect these changes.
Northern Ireland's power sector is supported by a diverse generation mix, a stable regulatory environment, universal access to the grid, and connections between Northern and Southern Ireland and the UK. Installed capacity in the SEM is 49% gas fired and 26% from renewable sources, resulting in sensitivity to gas prices relative to order of merit. SEM has also set a target of 40% renewable generation by 2020.
Business Description — AES has two generation plants in the United Kingdom, both of which are located in Northern Ireland within the Greater Belfast region. Kilroot is a 701 MW coal-fired merchant plant, with an additional 10 MW of energy storage, that bids into the I-SEM. Kilroot's coal fired units failed to clear in the first I-SEM capacity auction process. Consequently, AES announced its intent to shut down the coal units on or before May 31, 2018, pending the results of an assessment by the regulator to determine the long term needs of the Northern Ireland power grid. Ballylumford is a 1,015 MW gas-fired plant, of which 600 MW is contracted under a PPA with Power NI Power Procurement Business expiring in 2023. The 415 MW remaining capacity is bid into the SEM market, with 310 MW subject to a supplemental Local Reserve Services Agreement with the system operator. One of Ballylumford's B-station units failed to clear the aforementioned I-SEM capacity auction; as a result, AES intends to retire that unit at the end of December 2018.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
Regulatory changes to the market structure and payment mechanisms
Investments to maintain compliance with European Union environmental legislation
Availability of the operating units and order of merit
Commodity prices (gas, coal and CO2) and sufficient market liquidity to hedge prices in the short-term
Electricity demand in the SEM (including impact of wind generation)
Kazakhstan
Regulatory Framework and Market Structure — The Kazakhstan government has grouped generators into fifteen groups based on a number of factors, including plant type and fuel used. Each group has a fixed tariff-cap level and all generators must sell electricity at or below their respective tariff-cap levels.
Business Description — AES operated four plants with a total capacity of 2,776 MW. Our two hydroelectric plants, representing 1,033 MW, were operated under a concession agreement until early October 2017, when the plants were transferred back to the Republic of Kazakhstan. The remaining 1,743 MW coal-fired capacity was sold in the second quarter of 2017.

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Jordan
Regulatory framework and market structure — The Jordan electricity transmission market is a single-buyer model with the state owned NEPCO responsible for transmission. NEPCO generally enters into long term power purchase agreements with IPP's to fulfill energy procurement requests from distribution utilities. The sector is prioritizing renewable energy development, with 2,200 MW of renewable energy installed capacity expected by year 2020, 700 MW of which was already connected to the grid.
Business Description — In Jordan, AES has a 37% controlling interest in Amman East, a 381 MW oil/gas-fired plant fully contracted with the national utility under a 25-year PPA expiring in 2033, and a 36% controlling interest in the IPP4 plant, a 250 MW oil/gas-fired peaker plant which commenced operations in July 2014, fully contracted with the national utility until 2039. We consolidate the results in our operations as we have controlling interest in these businesses.
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. Construction of the plant has not begun, but is expected to be completed mid-2019 to coincide with the start of a PPA to provide energy to NEPCO through 2038.
India
Regulatory framework and Market Structure — The power sector is largely dominated by state and central government-owned generation and distribution utilities. Electricity is generally sold to state utilities under long-term PPAs. The tariffs are fixed on yearly basis by the Electricity Regulatory Commissions of the Centre and the State(s) or determined through competitive bidding process. Orissa Electricity Regulatory Commission ("OERC") regulates the electricity purchase and procurement process for the Distribution Licensees, including the price at which the electricity from generating companies shall be procured for supply within the state of Orissa. OERC also facilitates interstate transmission and wheeling of electricity. OERC is guided by the National Electricity Policy, National Electricity Plan and Tariff Policy issued by the Government of India.
The power sector in India is composed of coal, gas, hydroelectric, renewable and nuclear energy. Total installed capacity as of December 31, 2017 was 331 GW, of which 66% is thermal generation. Renewable energy is adding capacity at a rapid pace and currently represents 18% of the total installed capacity.
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. OPGC is an unconsolidated entity and results are reported as Net equity in earnings of affiliates on our Consolidated Statements of Operations.
Construction and Development — AES has one 1,320 MW coal-fired project under construction and expected to begin operations by the end of 2018. As of December 31, 2017, total capitalized costs at the project level were $1.1 billion. Currently, 50% of the expansion capacity, or 660 MW, is contracted with GRIDCO for a period of 25 years. The remaining 50% of the generation capacity is proposed to be offered to GRIDCO under a new PPA.
Environmental Regulation — The Ministry of Environment, Forest and Climate Change in India amended the Environment (Protection) Rules with stricter emission limits for thermal power plants via their notification issued in December 2015. All existing plants installed before December 31, 2003 are required to meet revised emission limits within two years and any new thermal power plants that will be operational from January 1, 2017 are required to operate with the revised emission limits. As a result of this amendment, FGD systems need to be installed in the existing OPGC units to comply with the new SO2 emissions requirements, and new design options modifications to the schedule of the expansion project have been evaluated. As these amendments will require substantial investment to meet the revised environmental guidelines across the public and private power sectors in India, amendments and implementation time lines are still under review by the Ministry of Power, Government of India. 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 GRIDCO tariff 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

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Philippines
Regulatory Framework and market structure — The Philippines' power sector is divided into generation, transmission, distribution and supply. Generation and supply are open and competitive sectors, while transmission and distribution are regulated sectors. The ERC is an independent regulatory body performing administrative and other functions for the electric industry.
The Philippine power market is divided into three grids representing the three major island groups, Luzon, Visayas and Mindanao. Luzon, which includes Manila, the country's largest island, has limited interconnection with Visayas, and represents 86% of the total demand of both regions. Luzon and Visayas together have an installed capacity of approximately 18 GW. For Luzon, the largest generation sources are 50% coal and 29% natural gas.
The sale of power is conducted primarily through medium- or long-term bilateral contracts between generation companies and distribution utilities which are approved by the ERC. Distribution utilities and electric cooperatives are allowed to pass on to their end-users the bilateral contract rates, including WESM purchases, as approved by the ERC.
Business Description — The Masinloc plant is a 630 MW gross coal-fired plant located in Zambales, Philippines, is interconnected to the Luzon Grid, and is 51% owned by AES. More than 95% of Masinloc's current peak capacity is contracted through bilateral contracts. 430 MW is contracted with Meralco, the largest distribution company in the Philippines, under a PPA expiring in 2019. Following an ERC Order limiting power supply agreement extensions to one year, a supplemental PPA extending the contract with Meralco an additional three years was submitted for approval with the ERC. Masinloc's remaining contracts on existing units expire between 2018 and 2026. Masinloc has been granted a retail electricity supplier license from the ERC and currently markets power to contestable customers. Unlike Masinloc's contracts with distribution utilities, it's contract with contestable customers do not require ERC approval to be implemented. On December 17, 2017, the Company entered into an agreement to sell its Masinloc business. Closing is expected during the first half of 2018 subject to certain regulatory approvals.
Construction and Development — AES is constructing a 335 MW gross unit expansion to the Masinloc plant. The total capitalized cost as of December 31, 2017 is $394 million. The expansion unit is included in the Masinloc facilities to be sold as announced in December. The sale is expected to close in the first half of 2018.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
Operating performance of the facility
Demand from contracted customers
Whole sale electricity price in the market
Vietnam
Regulatory Framework and Market Structure — The Ministry of Industry and Trade is primarily responsible for formulating a program to restructure the power industry, developing the electricity market, and promulgating electricity market regulations. The fuel supply is owned by the government through Vinacomin, a state owned entity, and Petro Vietnam.
The Vietnam power market is divided into three regions (North, Central and South), with total installed capacity of approximately 45 GW. The fuel mix in Vietnam is composed primarily of hydropower at 35% and coal at 37%. EVN, the national utility, owns 57% of installed generation capacity.
The government is in the process of realigning EVN-owned companies into three different independent operations in order to create a competitive power market. A competitive electricity market has already been established. A pilot competitive wholesale electricity market has been developed, and will be implemented over the next five years. The retail market will undergo similar reforms after 2022. 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.
Business Description — Mong Duong II is a 1,240 MW gross coal-fired plant located in Quang Ninh Province of Vietnam and was constructed under a BOT service concession agreement expiring in 2040. This is the first and largest coal-fired BOT plant using pulverized coal fired boiler technology in Vietnam. The BOT company has a PPA with EVN and a Coal Supply Agreement with Vinacomin both expiring in 2040.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to, the operating performance and availability of the facility.

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Financial Data by Country
See the table with our consolidated operations for each of the three years ended December 31, 2017, 2016 and 2015, and property, plant and equipment as of December 31, 2017 and 2016, by country, in Note 15Segment 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 FactorsOur businesses are subject to stringent environmental laws and regulations; Our businesses are subject to enforcement initiatives from environmental regulatory agencies; and Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows 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 combined 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 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. 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 required significant reductions in SO2 and NOX emissions from power plants in many states in which subsidiaries of the Company operate. The Company is required to comply with the CSAPR in several states, including Ohio, Indiana, Oklahoma and Maryland. The CSAPR is implemented, in part, through a market-based program under which compliance may be achievable

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through the acquisition and use of emissions allowances created by the EPA. 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 2017 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, but it could be material if certain facilities will need to purchase additional allowances based on reduced allocations.
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. 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 of suits against power plant owners and the issuance of NOVs to a number of power plant owners alleging NSR violations. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation and regulatory action, including a NOV issued by the EPA against IPL concerning NSR and prevention of significant deterioration issues under the CAA.
In 2000, Stuart Station received an NOV from the EPA alleging that certain activities undertaken in the past are outside the scope of the RMRR exclusion. Hutchings Station also received such an NOV in 2009. Additionally, generation units partially owned by AES 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 AES-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" toward 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 requires 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 published a final rule affirming the continued validity of the EPA's previous determination allowing states to rely on the CSAPR to satisfy BART requirements. 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 and states must submit regional haze plans for this second implementation period in 2021, to continue to demonstrate reasonable progress towards reducing visibility impairment in Class I areas. States may need to require additional emissions controls for visibility impairing pollutants, including on BART sources, during the second implementation period. We currently cannot predict the impact of this second implementation period, if any, on any of our Company’s U.S. subsidiaries.
National Ambient Air Quality Standards ("NAAQS") — Under the CAA, the EPA sets NAAQS for six principal pollutants considered harmful to public health and the environment, including ozone, particulate matter, NOx and SO2, which result from coal combustion.  Areas meeting the NAAQS are designated "attainment areas" while those that do not meet the NAAQS are considered "nonattainment areas." Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS, which may include imposing operating limits on individual plants. The EPA is required to review NAAQS at five-year intervals.

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Based on the current and potential future ambient 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 attain 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 its final rule establishing reduced SO2 limits for IPL facilities in accordance with a new one-hour standard of 75 parts per billion, for the areas in which IPL's Harding Street, Petersburg, and Eagle Valley Generating Stations operate. The compliance date for these requirements was January 1, 2017. No impact is expected for Eagle Valley or Harding Street Generating Stations because these facilities ceased coal combustion prior to the compliance date. However, improvements to the existing FGD systems at IPL’s Petersburg station were required to meet the emission limits imposed by the rule. On April 26, 2017, 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 a subsequent rate case. The approved capital cost of the NAAQS SO2 compliance plan is approximately $29 million.
Greenhouse Gas Emissions — In January 2011, the EPA began regulating GHG emissions from certain stationary sources pursuant to two CAA programs: the Title V Operating Permit program and the preconstruction permitting program for certain new construction or major modifications, known as the PSD. Obligations relating to Title V permits include record-keeping and monitoring requirements. Sources subject to PSD can be required to implement BACT. If future modifications to our U.S.-based businesses' sources become subject to PSD for other pollutants, it may trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHG and has now proposed NSPS for modified and reconstructed units (see below) that will serve as a floor (maximum emission rate) for future BACT requirements. Individual states must 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 could be material.
On October 23, 2015, the EPA's rule establishing NSPS for new electric generating units became effective. The NSPS establish 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 natural gas combined cycle 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 22, 2015, the EPA's final CO2 emission rules for existing power plants under Clean Air Act Section 111(d) (called the CPP) also became effective. The CPP provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates that must be achieved starting in 2030. Under the CPP, states are required to meet state-wide emission rate standards or equivalent mass-based standards, with the goal being a 32% reduction in total U.S. power sector emissions from 2005 levels by 2030. The CPP requires states to submit, by 2016, implementation plans to meet the standards or a request for an extension to 2018. If a state fails to develop and submit an approvable implementation plan, the EPA will finalize a federal plan for that state. The full impact of the CPP would depend on the following:
whether and how the states in which the Company's U.S. businesses operate respond to the CPP;
whether the states adopt an emissions trading regime and, if so, which trading regime;
how other states respond to the CPP, which will affect the size and robustness of any emissions trading market; and
how other companies may respond in the face of increased carbon costs.
Several states and industry groups challenged the NSPS for CO2 in the D.C. Circuit. Pursuant to a court order issued in August 2017, the litigation is being held in indefinite abeyance pending further court order.

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In addition, several states and industry groups filed petitions in the D.C. Circuit challenging the CPP and requested a stay of the rule while the challenge was considered. The D.C. Circuit denied the stay and granted requests to consider the challenges on an expedited basis. On February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the CPP pending resolution of challenges to the rule. On March 28, 2017, the EPA filed a motion in the D.C. Circuit to hold the challenges to both the CPP and the GHG NSPS in abeyance in light of an Executive Order signed the same day. On April 28, 2017, the D.C. Circuit issued orders holding the challenges to both rules in abeyance for 60 days, with subsequent extensions granted by the court. The most recent extension of the CPP litigation was set to expire in January 2018 but, on January 10, 2018, the EPA filed a status report requesting that the court continue to hold the case in abeyance pending the conclusion of further rulemaking on the CPP. 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. Some states and environmental groups have opposed EPA’s most recent request to continue to hold the CPP appeals in abeyance and the D.C. Circuit has not yet acted upon EPA’s request.
By order of the U.S. Supreme Court, the CPP has been stayed pending resolution of the challenges to the rule. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, could be material. The GHG NSPS remains in effect at this time, and, absent further action from the EPA that rescinds or substantively revises the NSPS, it could impact any Company plans to construct and/or modify or reconstruct electric generating units in some locations, which may have a material impact on our business, financial condition or results of operations.
The Company will likely not know the answers to the above questions regarding the CPP until later in 2018 or potentially 2019. As the first compliance period would not end until 2025, and because we cannot predict whether the CPP will survive the legal challenges or be repealed or replaced through rulemaking, it is too soon to determine the CPP's potential impact on our business, operations or financial condition, but any such impact could be material.
Cooling Water Intake — The Company's facilities are subject to a variety of rules governing water use and discharge. In particular, the Company's U.S. facilities are subject to the CWA Section 316(b) rule issued by the EPA that seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the BTA for cooling water intake structures. On August 15, 2014, the EPA published its final standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other industrial facilities. These standards require 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 what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. This decision-making process would include public input as part of permit renewal or permit modification. It is possible this process could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility to increase generation capacity are required to reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards for entrainment. It is not yet possible to predict the total impacts of this recent final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.
AES Southland's current plan is to comply with the California State Water Resources Board's ("SWRCB") Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling ("OTC Policy") by shutting down and permanently retiring all existing generating units at AES Alamitos, AES Huntington Beach and AES Redondo Beach that utilize OTC by December 31, 2020, the compliance date included in the OTC Policy. New air-cooled combined cycle gas turbine generators and battery energy storage systems will be constructed at the AES Alamitos and AES Huntington Beach generating stations, and there is currently no plan to replace the OTC generating units at the AES Redondo Beach generating station. The execution of the implementation 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 generating units at AES Alamitos and AES Huntington Beach. The SWRCB is currently reviewing the implementation plan and latest information on OTC generating unit retirement dates and new generation availability to evaluate the impact on electrical system reliability, which could result in the extension of OTC compliance dates for specific units. The Company’s California subsidiaries have signed 20-year term power purchase agreements with Southern California

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Edison for the new generating capacity which 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 are 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 been filed and consolidated in the U.S. Court of Appeals for the Second Circuit, although implementation of the rule has not been stayed while the challenges proceed. The Company anticipates once-through cooling and CWA Section 316(b) compliance regulations and costs would 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 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 determined whether it had 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. On January 22, 2018, the U.S. Supreme Court decided that challenges to the rule must be reviewed in U.S. district courts and remanded the case to the U.S. Court of Appeals for the Sixth Circuit with instructions to dismiss the case for lack of jurisdiction. That action would lift the nationwide stay of the rule, leaving the stay in place only for those 13 states addressed in the order issued by the U.S. District Court for the District of North Dakota. On January 31, 2018, the EPA and the U.S. Army Corps of Engineers announced a rule that will delay the effective date of the "Waters of the U.S." rule by two years from the date the rule is published in the Federal Register. On June 27, 2017, the EPA proposed a rule that would rescind the “Waters of the U.S.” rule and re-codify the definition of “Waters of the United States” that existed prior to 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 U.S.” rule is ultimately implemented in its current or substantially similar form and survives the legal challenges, it could 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. under the CWA. On January 7, 2013, the Ohio Environmental Protection Agency issued an NPDES permit for J.M. Stuart Station, which included a compliance schedule for performing a study to justify an alternate thermal limitation or take undefined measures to meet certain temperature limits. On February 1, 2013, DPL appealed various aspects of the final permit. As a result of DPL’s decision to retire Stuart generating station, we do not expect a material impact.
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. These permits set new water quality-based effluent discharge limits for the Harding Street and Petersburg facilities, as well as monitoring and other requirements designed to protect aquatic life, with full compliance required by October 2015. The extended compliance deadline was September 29, 2017 for IPL's Harding Street and Petersburg facilities through agreed orders with IDEM. 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. The required compliance time lines for existing sources was to be established between November 1, 2018 and December 31, 2023. On September 18, 2017, the EPA published a final rule delaying certain compliance

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dates of the ELG rule for two years while it administratively reconsiders the rule. IPL has installed a dry bottom ash handling system in response to the CCR rule described below 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 still evaluating the effects of the rule on our other U.S. businesses, we anticipate that the implementation of its 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 pollutant Selenium in fresh water. NPDES permits may be updated to include 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 challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material. IPL would seek recovery of these capital expenditures; however, there is no guarantee it would be successful in this regard.
Waste Management — In the course of operations, the Company's facilities generate solid and liquid waste materials requiring eventual disposal or processing. With the exception of coal combustion residuals ("CCR"), the wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. CCR, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at some of our coal-fired power generation plant sites using engineered, permitted landfills. Waste materials generated at our electric power and distribution facilities may include asbestos, CCR, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree and land clearing wastes and polychlorinated 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, and may impose closure and/or corrective action requirements for existing CCR landfills and impoundments under certain specified conditions. The primary enforcement mechanisms under this regulation would be actions commenced by the states and private lawsuits. On December 16, 2016, President Obama signed into law the Water Infrastructure Improvements for the Nation Act ("WIN Act"), which 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. On September 13, 2017, the EPA indicated that it would reconsider certain provisions of the CCR Rule in response to two petitions it received to reconsider the final rule. On November 7, 2017, the EPA requested that legal challenges be held in abeyance and certain provisions of the rule be remanded without vacatur. It is too early to determine whether the results of the groundwater monitoring data or the outcome of CCR litigation or a potential CCR Remand Rule may have a material impact on our business, financial condition or results of operations.
The existing ash ponds at IPL's Petersburg Station do not meet certain structural stability requirements set forth in the CCR rule. IDEM has extended IPL's deadline to comply with the requirements or cease use of the ash ponds to April 11, 2018.
Comprehensive Environmental Response, Compensation and Liability Act of 1980 This act, also know as "Superfund," may be the source of claims against certain of the Company's U.S. subsidiaries from time to time. There is ongoing litigation at a site known as the South Dayton Landfill where a group of companies already recognized as potentially responsible parties have sued DP&L and other unrelated entities seeking a contribution toward the costs of assessment and remediation. DP&L is actively opposing such claims. In 2003, DP&L received notice that the EPA considers DP&L to be a potentially responsible party at the Tremont City landfill Superfund site. The EPA has taken no further action with respect to DP&L since 2003 regarding the Tremont City landfill. The Company is unable to determine whether there will be any liability, or the size of any liability that may ultimately be assessed against DP&L at these two sites, but any such liability could be material to DP&L.
Unit Retirement and Replacement Generation — In addition to the five oil-fired peaking units IPL retired in the second quarter of 2013, the four coal-fired units at Eagle Valley were retired in April 2016. To replace this generation, IPL received approval from the IURC in May 2014 to build a 644 to 685 MW CCGT at its Eagle Valley Station site in Indiana and refuel its Harding Street Station Units 5 and 6 from coal to natural gas (approximately 100 MW net capacity each) with a total budget of $655 million. The current estimated cost of these projects is $655 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. The costs to

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build and operate the CCGT and the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after construction is completed. The CCGT is expected to be completed in the first half of 2018, and the refueling project was completed in December 2015.
For a discussion of the retirement of AES Southland's OTC generating units due to U.S. cooling water intake regulations, please see — Cooling Water Intake, above.
International Environmental Regulations
For a discussion of the material environmental regulations applicable to the Company's businesses located outside of the U.S., see Environmental Regulation under the discussion of the various countries in which the Company's subsidiaries operate in Business—Our Organization and Segments, above.
Customers
We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2017 total revenue. In our generation business, we own and/or operate power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. Our utilities sell to end-user customers in the residential, commercial, industrial and governmental sectors in a defined service area.
Executive Officers
The following individuals are our executive officers:
Bernerd Da Santos, 54 years old, was appointed Chief Operating Officer and Executive Vice President in December 2017. Previously, Mr. Da Santos held several positions at the Company, including Chief Operating Officer and Senior Vice President (2014 - 2017), Chief Financial Officer, Global Finance Operations (2012-2014), Chief Financial Officer of Global Utilities (2011-2012), Chief Financial Officer of Latin America and Africa (2009-2011), Chief Financial Officer of Latin America (2007-2009), Managing Director of Finance for Latin America (2005-2007) and VP and Controller of 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, Companhia de Alumbrado Electrico de San Salvador ("CAESS"), Empresa Electrica de Oriente ("EEO"), Companhia de Alumbrado Electrico de Santa Ana, and Indianapolis Power & Light. Mr. Da Santos holds a bachelor's degree with Cum Laude distinction in Business Administration and Public Administration from Universidad José Maria Vargas, a bachelor's degree with Cum Laude distinction in Business Management and Finance, and an MBA with Cum Laude distinction from Universidad José Maria Vargas.
Paul L. Freedman, 47 years old, has been Senior Vice President and General Counsel since February 2018. Prior to assuming his current position, Mr. Freedman served as Chief of Staff to the CEO 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 2010-2011 and Counsel 2007 to 2010. Mr. Freedman is a member of the boards of IPALCO, AES U.S. Investments, DP&L and Fluence. He is also an alternate Director at AES Gener. 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, 60 years old, has been President, CEO and a member of our Board of Directors since September 2011 and is Chairman of the Strategy and Investment Committee of the Board. Prior to assuming his current position, Mr. Gluski served as EVP and Chief Operating Officer ("COO") of the Company since March 2007. Prior to becoming the COO of AES, Mr. Gluski was EVP 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, CEO of La Electricidad de Caracas ("EDC") from 2002 to 2003 and CEO of AES Gener (Chile) in 2001. Prior to joining AES in 2000, Mr. Gluski was EVP and Chief Financial Officer ("CFO") of EDC, EVP of Banco de Venezuela (Grupo Santander), Vice President ("VP") for Santander Investment, and EVP and CFO of CANTV (subsidiary of GTE). Mr. Gluski has also worked with the International Monetary Fund in the Treasury and Latin American Departments and served as Director General of the Ministry of Finance of Venezuela. From 2013-2016, Mr. Gluski served on President Obama's Export Council. Mr. Gluski is a member of the Board of Waste Management and AES Gener in Chile. Mr. Gluski is also Chairman of the Americas Society/Council of the Americas, and Director of the Edison Electric 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.
Tish Mendoza, 42 years old, is Chief Human Resources Officer and Senior Vice President, Global Human Resources and Internal Communications since 2015. Prior to assuming her current position, Ms. Mendoza was the

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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, 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 Leadership and Human Resource Management, and a bachelor's degree in Business Administration and Human Resources.
Thomas M. O'Flynn, 57 years old, has served as EVP and CFO of the Company since September 2012. Previously, Mr. O'Flynn served as Senior Advisor to the Private Equity Group of Blackstone, an investment and advisory group and held this position from 2010 to 2012. During this period, Mr. O'Flynn also served as COO and CFO of Transmission Developers, Inc., a Blackstone-controlled company that develops innovative power transmission projects in an environmentally responsible manner. From 2001 to 2009, he served as the CFO of PSEG, a New Jersey-based merchant power and utility company. He also served as President of PSEG Energy Holdings from 2007 to 2009. From 1986 to 2001, Mr. O'Flynn was in the Global Power 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. Mr. O'Flynn is the chairman of IPALCO, AES U.S. Investments and FTP Power, LLC. Mr. O'Flynn previously served as a member of the Boards of DP&L and its parent company, DPL, Inc. from February 2013 through February 2015 and served on the Board of Silver Ridge Power, a joint venture between AES and Riverstone Holdings LLC from September 2012 through July 2014. He is also currently on the Board of Directors of the New Jersey Performing Arts Center and was the inaugural Chairman of the Institute for Sustainability and Energy at Northwestern University, of which he is still an active Board member. Mr. O'Flynn has a BA in Economics from Northwestern University and an MBA in Finance from the University of Chicago.
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 19, 2017.
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

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operations, including those discussed in Item 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.
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;
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
We have a significant amount of debt, a large percentage of which is secured, which could adversely affect our business and the ability to fulfill our obligations.
As of December 31, 2017, we had approximately $20 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 available for future secured debt or credit support and reduces our flexibility in operating 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 our vulnerability to general adverse industry and economic conditions, including but not limited to adverse changes in foreign exchange rates and commodity prices;
reducing the availability of cash flow to fund other corporate purposes and grow our business;