Edgar Filing: AES CORP

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, 2016

-OR-



¨	TRANSITION REPORT FILED PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	COMMISSION FILE NUMBER 1-12291

THE AES CORPORATION

(Exact name of registrant as specified in its charter)



Delaware		54 1163725
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
4300 Wilson Boulevard Arlington, Virginia		22203
(Address of principal executive offices)		(Zip Code)
Registrant's telephone number, including area code: (703) 522-1315
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share		New York Stock Exchange
AES Trust III, $3.375 Trust Convertible Preferred Securities		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes 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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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, 2016, the last business day of the Registrant's most recently completed second fiscal quarter (based on the adjusted closing sale price of $12.48 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $8.22 billion.

The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, on February 17, 2017 was 659,183,208

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant's Proxy Statement for its 2017 annual meeting of stockholders are incorporated by reference in Parts II and III

THE AES CORPORATION FISCAL YEAR 2016 FORM 10-K

TABLE OF CONTENTS



Glossary of Terms	1
PART I	4
ITEM 1. BUSINESS	6
ITEM 1A. RISK FACTORS	57
ITEM 1B. UNRESOLVED STAFF COMMENTS	73
ITEM 2. PROPERTIES	73
ITEM 3. LEGAL PROCEEDINGS	73
ITEM 4. MINE SAFETY DISCLOSURES	77
PART II	78
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	78
ITEM 6. SELECTED FINANCIAL DATA	79
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	80
Executive Summary	80
Overview of 2016 Results and Strategic Performance	81
Review of Consolidated Results of Operations	82
SBU Performance Analysis	89
Key Trends and Uncertainties	103
Capital Resources and Liquidity	104
Critical Accounting Policies and Estimates	118
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	122
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	125
Consolidated Balance Sheets	126
Consolidated Statements of Operations	127
Consolidated Statements of Comprehensive Income	128
Consolidated Statements of Changes in Equity	129
Consolidated Statements of Cash Flows	130
Note 1 - General and Summary of Significant Accounting Policies	131
Note 2 - Inventory	142
Note 3 - Property, Plant and Equipment	142
Note 4 - Fair Value	143
Note 5 - Derivative Instruments and Hedging Activities	148
Note 6 - Financing Receivables	149
Note 7 - Investments in and Advances to Affiliates	151
Note 8 - Other Non-Operating Expense	152
Note 9 - Goodwill and Other Intangible Assets	152
Note 10 - Regulatory Assets and Liabilities	154
Note 11 - Debt	155
Note 12 - Commitments	158
Note 13 - Contingencies	159
Note 14 - Benefit Plans	161
Note 15 - Equity	164
Note 16 - Segment and Geographic Information	167
Note 17 - Share-Based Compensation	169
Note 18 - Redeemable Stock of Subsidiaries	172
Note 19 - Other Income and Expense	174
Note 20 - Asset Impairment Expense	174
Note 21 - Income Taxes	176
Note 22 - Discontinued Operations	179
Note 23 - Dispositions	181
Note 24 - Acquisitions	182
Note 25 - Earnings Per Share	182
Note 26 - Risks and Uncertainties	182
Note 27 - Related Party Transactions	184
Note 28 - Selected Quarterly Financial Data (Unaudited)	184
Note 29 - Subsequent Events	185
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	186
ITEM 9A. CONTROLS AND PROCEDURES	186
ITEM 9B. OTHER INFORMATION	187
PART III	188
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	188
ITEM 11. EXECUTIVE COMPENSATION	188
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	188
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE	189
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES	189
PART IV - ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	190
SIGNATURES	193

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:



Adjusted EPS	Adjusted Earnings Per Share, a non-GAAP measure
Adjusted PTC	Adjusted Pretax Contribution, a non-GAAP measure of operating performance
AES	The Parent Company and its subsidiaries and affiliates
AFUDC	Allowance for Funds Used During Construction
ANEEL	Brazilian National Electric Energy Agency
AOCL	Accumulated Other Comprehensive Loss
ASC	Accounting Standards Codification
ASEP	National Authority of Public Services
BACT	Best Available Control Technology
BART	Best Available Retrofit Technology
BNDES	Brazilian Development Bank
BOT	Build, Operate and Transfer
BTA	Best Technology Available
CAA	United States Clean Air Act
CAMMESA	Wholesale Electric Market Administrator in Argentina
CCGT	Combined Cycle Gas Turbine
CDI	Brazilian equivalent to LIBOR
CDPQ	La Caisse de depot et placement du Quebec
CEO	Chief Executive Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980 (a.k.a. "Superfund")
CFB	Circulating Fluidized Bed Boiler
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
CPCN	Certificate of Public Convenience and Necessity
CPP	Clean Power Plan
CRES	Competitive Retail Electric Service
CSAPR	Cross-State Air Pollution Rule
CWA	U.S. Clean Water Act
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
DP&L	The Dayton Power & Light Company
DPL	DPL Inc.
DPLE	DPL Energy, LLC, a wholly-owned subsidiary of DPL (renamed AES Ohio Generation, LLC effective 2/1/2016)
DPLER	DPL Energy Resources, Inc.
DPP	Dominican Power Partners
EBITDA	Earnings before Interest, Taxes, Depreciation & Amortization
EMIR	European Market Infrastructure Regulation
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
FAC	Fuel Adjustment Charges
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
IDEM	Indiana Department of Environmental Management
IFC	International Finance Corporation
IPALCO	IPALCO Enterprises, Inc.
IPL	Indiana, Indianapolis Power & Light Company
IPP	Independent Power Producers
ISO	Independent System Operator
IURC	Indiana Utility Regulatory Commission
kWh	Kilowatt Hours
LIBOR	London Inter Bank Offered Rate
LNG	Liquefied Natural Gas
MATS	Mercury and Air Toxics Standards
MISO	Midcontinent Independent System Operator, Inc.
MW	Megawatts
MWh	Megawatt Hours
NCI	Noncontrolling Interest
NEK	Natsionalna Elektricheska Kompania (state-owned electricity public supplier in Bulgaria)
NERC	North American Electric Reliability Corporation
NGCC	Natural Gas Combined Cycle
NOV	Notice of Violation
NO_X	Nitrogen Dioxide
NPDES	National Pollutant Discharge Elimination System
NSPS	New Source Performance Standards
NYISO	New York Independent System Operator, Inc.
NYSE	New York Stock Exchange
O&M	Operations and Maintenance
OPGC	Odisha Power Generation Corporation, Ltd.
Parent Company	The AES Corporation
PCB	Polychlorinated biphenyl
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
PSA	Power Supply Agreement
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
RPM	Reliability Pricing Model
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
TA	Transportation Agreement
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.
WACC	Weighted Average Cost of Capital

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, as well as GHG emissions reduction 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;


•	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 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


•	information security breaches.

These factors in addition to others described elsewhere in this Form 10-K, including those described under Item 1A.—Risk Factors, and in subsequent securities filings, should not be construed as a comprehensive listing of factors that could cause results to vary from our forward-looking information.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.

ITEM 1. BUSINESS

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 diversified power generation and utility company, providing affordable, sustainable energy through our diverse portfolio of thermal and renewable generation facilities as well as distribution businesses. Our vision is to be the world's leading sustainable power company by leveraging our unique electricity platforms and the knowledge of our people to provide the energy and infrastructure solutions our customers truly 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.

Future growth across our company will be heavily weighted towards less carbon-intensive wind, solar and gas generation. Growth in renewables not only provides an opportunity for direct investments in wind and solar generation, but also presents significant potential for energy storage. We are a leader in lithium ion, battery-based energy storage, with more than 400 MW in operation, under construction or in advanced development across seven countries. We believe lithium ion-based energy storage will play a critical role in an increasingly renewables-based generation mix. With our technological experience, presence in key markets and channel sales partnerships, we are positioned to capitalize on this rapidly growing market.

Additionally, we have been expanding our LNG infrastructure in Central America, where we are helping to displace oil-fired generation in favor of a cheaper and cleaner alternative. In the United States, at IPL, we recently 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.

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 2016, brought on-line nine projects for a total of 2,976 MW
●	3,389 MW currently under construction
	○	Represents $6.4 billion in total capital expenditures
	○	Majority of AES’ $1.1 billion in equity already funded
	○	Expected to come on-line through 2019
●	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
	○	Sold assets to generate $3.6 billion in equity proceeds
	○	Decreased total number of countries where we have operations from 28 to 17
●	In 2016, announced or closed $510 million in equity proceeds from sales or sell-downs of six businesses



Performance Excellence
Striving to be the low-cost manager of a portfolio of assets and deriving synergies and scale from our businesses
●	In 2015, launched a $150 million cost reduction and revenue enhancement initiative
	○	Includes overhead reductions, procurement efficiencies and operational improvements
	○	Achieved $50 million in savings in 2016 and expect to ramp up to a total of $150 million in 2018



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 2016, we generated substantial cash by executing on our strategy, which we allocated in line with our capital allocation framework

	○	Used $312 million to prepay and refinance Parent Company debt
	○	Returned $369 million to shareholders through share repurchases and quarterly dividends
		■	Increased our quarterly dividend by 9.1% to $0.12 per share beginning in the first quarter of 2017
	○	Invested $394 million in our subsidiaries

_____________________________


⁽¹⁾	Investments in subsidiaries excludes $2.2 billion investment in DPL.

Segments

We are organized into six market-oriented strategic business units ("SBUs"): US (United States), Andes (Chile, Colombia, and Argentina), Brazil, MCAC (Mexico, Central America and the Caribbean), Europe, and Asia — which are led by our SBU Presidents. Within our six 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 Proportional Free Cash Flow, both of which are non-GAAP measures. The Adjusted PTC and Proportional Free Cash Flow by SBU for the year ended December 31, 2016 are shown below. The percentages for Adjusted PTC and Proportional Free Cash Flow are the contribution by each SBU to the gross metric, i.e., the total Adjusted PTC by SBU, before deductions for Corporate. See Item 7.—Management's Discussion and Analysis SBU Performance Analysis of this Form 10-K for reconciliation and definitions of Adjusted PTC and Proportional Free Cash Flow.

The following summarizes our businesses within our six SBUs.

Overview

Generation

We currently own and/or operate a generation portfolio of 30,379 MW, excluding the generation capabilities of our integrated utilities. 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.

Electricity Sales Contracts — Our generation businesses sell electricity under medium- or long-term contracts ("contract sales") or under short-term agreements in competitive markets ("short-term sales").

Contract Sales — Most of our generation fleet sells electricity under contracts. Our medium-term contract sales have a term of 2 to 5 years, while our long-term contracts have a term of more than 5 years. Across our portfolio, the average remaining contract term is 6 years.

In contract sales, our generation businesses recover variable costs including fuel and variable O&M costs, either through direct or indexation-based contractual pass-throughs or tolling arrangements. When the contract does not include a fuel pass-through, we typically hedge fuel costs or enter into fuel supply agreements for a similar contract period (see discussion under the Fuel Costs section below). These contracts are intended to reduce exposure to the volatility of fuel prices and electricity prices by linking the business's revenues and costs. These contracts also help us to fund a significant portion of the total capital cost of the project through long-term non-recourse project-level financing.

Capacity Payments and 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 section below.

Thus, these contracts, or other related commercial arrangements, significantly mitigate our exposure to changes in power and fuel prices, currency fluctuations and changes in interest rates. In addition, these contracts generally provide for a recovery of our fixed operating expenses and a return on our investment, as long as we operate the plant to the reliability and efficiency standards required in the contract.

Short-Term Sales — Our other generation businesses sell power and ancillary services under short-term contracts with an average term of less than 2 years, including spot sales, directly in the short-term market, or, in some cases, at regulated prices. The short-term markets are typically administered by a system operator to coordinate dispatch. Short-term markets generally operate on merit order dispatch, where the least expensive generation facilities, based upon variable cost or bid price, are dispatched first and the most expensive facilities are dispatched last. The short-term price is typically set at the marginal cost of energy or bid price (the cost of the last plant required to meet system demand). As a result, the cash flows and earnings associated with these businesses are more sensitive to fluctuations in the market price for electricity. In addition, many of these wholesale markets include markets for ancillary services to support the reliable operation of the transmission system. Across our portfolio, we provide a wide array of ancillary services, including voltage support, frequency regulation and spinning reserves.

In certain markets, such as Argentina and Kazakhstan, a regulator establishes the prices for electricity and fuel and adjusts them periodically for inflation, changes in fuel prices and other factors. In these cases, our businesses are particularly sensitive to changes in regulation.

Capacity Payments — Many of the markets in which we operate include regulated capacity markets. These capacity markets are intended to provide additional revenue based upon availability without reliance on the energy margin from the merit order dispatch. Capacity markets are typically priced based on the cost of a new entrant and the system capacity relative to the desired level of reserve margin (generation available in excess of peak demand). Our generating facilities selling in the short-term markets typically receive capacity payments based on their availability in the market. Our most significant capacity revenues are earned by our generation capacity in Ohio and Northern Ireland.

Plant Reliability and Flexibility — Our contract and short-term sales provide incentives to our generation plants to optimally manage availability, operating efficiency and flexibility. Capacity payments under contract sales are frequently tied to meeting minimum standards. In short-term sales, our plants must be reliable and flexible to capture peak market prices and to maximize market-based revenues. In addition, our flexibility allows us to capture ancillary service revenue while meeting local market needs.

Fuel Costs — For our thermal generation plants, fuel is a significant component of our total cost of generation. For contract sales, we often enter into fuel supply agreements to match the contract period, or we may hedge our fuel costs. Some of our contracts have periodic adjustments for changes in fuel cost indices. In those cases, we have fuel supply agreements with shorter terms to match those adjustments. For certain projects, we have tolling arrangements where the power offtaker is responsible for the supply and cost of fuel to our plants.

In short-term sales, we sell power at market prices that are generally reflective of the market cost of fuel at the time, and thus procure fuel supply on a short-term basis, generally designed to match up with our market sales profile. Since fuel price is often the primary determinant for power prices, the economics of projects with short-term sales are often subject to volatility of relative fuel prices. For further information regarding commodity price risk please see Item 7A.—Quantitative and Qualitative Disclosures about Market Risk in this Form 10-K.

34% of the capacity of our generation fleet is coal-fired. In the U.S., most of our plants are supplied from domestic coal. At our non-U.S. generation plants, and at our plant in Hawaii, we source coal internationally. Across our fleet, we utilize our global sourcing program to maximize the purchasing power of our fuel procurement.

33% of the capacity of our generation plants are fueled by natural gas. Generally, we use gas from local suppliers in each market. A few exceptions to this are AES Gener in Chile, where we purchase imported gas from third parties, and our plants in the Dominican Republic, where we import LNG to utilize in the local market.

27% of the capacity of our generation plants are fueled by renewables, including hydro, wind and energy storage, which do not have significant fuel costs.

6% of the capacity of our generation fleet utilizes oil, diesel and petroleum coke ("pet coke") for fuel. Oil and diesel are sourced locally at prices linked to international markets, while pet coke is largely sourced from Mexico and the U.S.

Renewable Generation Facilities — We currently own and operate 8,228 MW (4,293 proportional MW) of renewable generation, including hydro, wind, energy storage, solar, biomass and landfill gas.

Seasonality, Weather Variations and Economic Activity — Our generation businesses are affected by seasonal weather patterns throughout the year and, therefore, operating margin is not generated evenly by month during 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' seven utility businesses distribute power to 9.4 million people in three countries. AES' two utilities in the U.S. also include generation capacity totaling 6,314 MW. The utility businesses have a variety of structures, ranging from integrated utility to pure transmission and distribution businesses.

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 in the Consolidated Statements of Operations.

Regulated Rate of Return and Tariff — In exchange for the exclusive right to sell or distribute electricity in a franchise area, our utility businesses are subject to government regulation. This regulation sets the prices ("tariffs") that our utilities are allowed to charge retail customers for electricity and establishes service standards that we are required to meet.

Our utilities are generally permitted to earn a regulated rate of return on assets, determined by the regulator based on the utility's allowed regulatory asset base, capital structure and cost of capital. The asset base on which the utility is permitted a return is determined by the regulator and is based on the amount of assets that are considered used and useful in serving customers. Both the allowed return and the asset base are important components of the utility's earning power. The allowed rate of return and operating expenses deemed reasonable by the regulator are recovered through the regulated tariff that the utility charges to its customers.

The tariff may be reviewed and reset by the regulator from time to time depending on local regulations, or the utility may seek a change in its tariffs. The tariff is generally based upon a certain usage level and may include a pass-through to the customer of costs that are not controlled by the utility, such as the costs of fuel (in the case of integrated utilities) and/or the costs of purchased energy. In addition to fuel and purchased energy, other types of costs may be passed through to customers via an existing mechanism, such as certain environmental expenditures that are covered under an environmental tracker at our utility in Indiana, IPL. Components of the tariff that are directly passed through to the customer are usually adjusted through a summary regulatory process or an existing formula-based mechanism. In some regulatory regimes, customers with demand above an established level are unregulated and can choose to contract with other retail energy suppliers directly and pay wheeling and other non-bypassable fees, which are fees to the distribution company for use of its distribution system.

The regulated tariff generally recognizes that our utility businesses should recover certain operating and fixed costs, as well as manage uncollectible amounts, quality of service and non-technical losses. Utilities, therefore, need to manage costs to the levels reflected in the tariff, or risk non-recovery of costs or diminished returns.

Seasonality, Weather Variations and Economic Activity — Our utility businesses are affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses are not generated evenly by month during the year. Additionally, weather variations may also have an impact based on the number of customers, temperature variances from normal conditions and customers' historic usage levels and patterns. The retail kWh 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 specific with incentives or penalties for performance against these standards. In other cases, the standards are implicit and the utility must operate to meet customer expectations.

Competition — Our integrated utilities, IPL and DP&L, operate as the sole distributor of electricity within their respective jurisdictions. Our businesses own and operate all of the businesses and facilities necessary to generate, transmit and distribute electricity. Competition in the regulated electric business is primarily from the on-site generation for industrial customers; however, in Ohio, customers in our service territory have the ability to switch to alternative suppliers for their generation service. Our integrated utilities, particularly DP&L, are 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 pure transmission and distribution businesses, such as those in Brazil and 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 businesses, new plants may be built in response to customer needs or to comply with regulatory developments and are developed subject to regulatory approval that permits recovery of our capital cost and a return on our investment. For our generation businesses, our priority for development is platform expansion opportunities, where we can add on to our existing facilities in our key platform markets where we have a competitive advantage. We make the decision to invest in new projects by evaluating the project returns and financial profile against a fair risk-adjusted return for the investment and against alternative uses of capital, including corporate debt repayment and share buybacks.

In some cases, we enter into long-term contracts for output from new facilities prior to commencing construction. To limit required equity contributions from The AES Corporation, we also seek non-recourse project debt financing and other sources of capital, including partners where it is commercially attractive. For construction, 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 16—Segment and Geographic Information included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion of the Company's segment structure.

US SBU

Our US SBU has 18 generation facilities and two integrated utilities in the United States.

Generation — Operating installed capacity of our US SBU totals 11,929 MW. IPL's parent, IPALCO Enterprises, Inc., and DPL Inc. are voluntary 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	U.S.-CA	Gas	2,075	100	%	1998	2018	Southern California Edison
Southland—Redondo Beach	U.S.-CA	Gas	1,392	100	%	1998	2018	Southern California Edison
Southland—Huntington Beach	U.S.-CA	Gas	474	100	%	1998	2018	Southern California Edison
Shady Point	U.S.-OK	Coal	360	100	%	1991	2018	Oklahoma Gas & Electric
Buffalo Gap II ^(1),(2)	U.S.-TX	Wind	233	100	%	2007	2017	Direct Energy
Hawaii	U.S.-HI	Coal	206	100	%	1992	2022	Hawaiian Electric Co.
Warrior Run	U.S.-MD	Coal	205	100	%	2000	2030	First Energy
Buffalo Gap III ⁽¹⁾	U.S.-TX	Wind	170	100	%	2008
Buffalo Gap I ⁽¹⁾	U.S.-TX	Wind	119	100	%	2006	2021	Direct Energy
Laurel Mountain	U.S.-WV	Wind	98	100	%	2011
Distributed PV - Commercial & Utility ^{(1) (3)}	U.S.-Various	Solar	89	100	%	2015-2016	2029-2042	Utility, Municipality, Education, Non-Profit
Mountain View I & II	U.S.-CA	Wind	67	100	%	2008	2021	Southern California Edison
Mountain View IV	U.S.-CA	Wind	49	100	%	2012	2032	Southern California Edison
Laurel Mountain ES	U.S.-WV	Energy Storage	32	100	%	2011
Tait ES	U.S.-OH	Energy Storage	20	100	%	2013
Distributed PV - Residential ^{(1) (3)}	U.S.-Various	Solar	14	100	%	2015	2037-2040	Residential
Warrior Run ES	U.S.-MD	Energy Storage	10	100	%	2016
Advancion Applications Center	U.S.-PA	Energy Storage	2	100	%	2013
			5,615

_____________________________


⁽¹⁾	AES owns these assets together with third-party tax equity investors with variable ownership interests. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes, that vary over the life of the projects. The proceeds from the issuance of tax equity are recorded as noncontrolling interest in the Company's Consolidated Balance Sheets.


⁽²⁾	Power Purchase Agreement with Direct Energy is for 80% of annual expected energy output.


⁽³⁾	AES operates these facilities located throughout the U.S. through management or O&M agreements as of December 31, 2016.

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

U.S.-IN

Gas

671

1H 2018

Distributed PV - Commercial

U.S.-Various

Solar

100

1H 2017

681

Utilities — The following table lists our U.S. utilities and their generation facilities:



Business	Location	Approximate Number of Customers Served as of 12/31/2016	GWh Sold in 2016	Fuel	Gross MW	AES Equity Interest		Year Acquired or Began Operation
DPL ⁽¹⁾	U.S.-OH	519,000	16,757	Coal/Gas/Oil	3,066	100	%	2011
IPL ⁽²⁾	U.S.-IN	490,000	14,186	Coal/Gas/Oil	3,248	70	%	2001
		1,009,000	30,943		6,314

_____________________________

⁽¹⁾

DPL subsidiary DP&L has the following plants: Tait Units 1-3 and diesels, Yankee Street, Yankee Solar, Monument and Sidney. DP&L jointly owned plants: Conesville Unit 4, Killen, Miami Fort Units 7 & 8, Stuart and Zimmer. In addition to the above, DP&L also owns a 4.9% equity ownership in OVEC ("Ohio Valley Electric Corporation"), an electric generating company. OVEC has two plants in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of

approximately 2,109 MW. DP&L's share of this generation capacity is approximately 103 MW. AES Ohio Generation, LLC plants: Tait Units 4-7 and Montpelier Units 1-4.


⁽²⁾	CDPQ owns direct and indirect interests in IPALCO which total 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.

The following map illustrates the location of our U.S. facilities:

U.S. Businesses

U.S. Utilities

IPALCO

Business Description — IPALCO owns all of the outstanding common stock of IPL. IPL is engaged primarily in generating, transmitting, distributing and selling electric energy to approximately 490,000 retail customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL has an exclusive right to provide electric service to those customers. IPL's service area covers about 528 square miles with an estimated population of approximately 939,000. IPL owns and operates four generating stations. IPL’s largest generating station, Petersburg, is coal-fired. The second largest station, Harding Street, has converted its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines. The third, Eagle Valley, retired its coal-fired units in April 2016 and their CCGT is expected to be completed in the first half of 2018. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of December 31, 2016, IPL's net electric generation capacity for winter is 2,993 MW and net summer capacity is 2,878 MW.

Market Structure — IPL is one of many transmission system owner members in the MISO. MISO is a RTO, which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. IPL offers the available electricity production of each of its generation assets into the MISO day-ahead and real-time markets. MISO operates on a merit order dispatch, considering transmission constraints and other reliability issues to meet the total demand in the MISO region.

Regulatory Framework - Retail Ratemaking — In addition to the regulations referred to below in Other Regulatory Matters, IPL is subject to regulation by the IURC with respect to IPL's services and facilities; retail rates and charges; the issuance of long-term securities; and certain other matters. The regulatory power of the IURC over IPL's business is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions. IPL's tariff rates for electric service to retail customers consist of basic rates and charges,

which are set and approved by the IURC after public hearings. The IURC gives consideration to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. In addition, IPL's rates include various adjustment mechanisms including, but not limited to: (i) a rider to reflect changes in fuel and purchased power costs to meet IPL's retail load requirements, referred to as the FAC, and (ii) a rider for the timely recovery of costs incurred to comply with environmental laws and regulations referred to as the Environmental Compliance Cost Recovery Adjustment. These components function somewhat independently of one another, but the overall structure of IPL's rates and charges would be subject to review at the time of any review of IPL's basic rates and charges.

In March 2016, the IURC issued an order authorizing IPL to increase its basic rates and charges by approximately $31 million annually. On December 22, 2016, IPL filed a petition with the IURC for authority to increase its basic rates and charges, primarily to recover the cost of the new Eagle Valley CCGT. The Eagle Valley CCGT was previously expected to be completed in the first half of 2017, but is now expected to be completed in the first half of 2018. To address this change, on February 24, 2017, IPL filed a motion to withdraw the case without prejudice or alternatively amend the petition at a later date. No assurances can be given as to the timing or outcome of this proceeding.

Environmental Regulation — For information on compliance with environmental regulations see Item 1.—United States Environmental and Land-Use Legislation and Regulations.

Replacement Generation — IPL has several generating units that have been recently retired or refueled. These units were primarily coal-fired and represented 472 MW of net capacity in total. To replace this generation, IPL has approval to build a 644 to 685 MW CCGT at its Eagle Valley Station site in Indiana and refuel its Harding Street Station Units 5 and 6 from coal to natural gas (approximately 100 MW net capacity each) with a total budget of $649 million. The current estimated cost of these projects is $632 million. IPL was granted authority to accrue post in-service allowance for debt and equity funds used during construction, and to defer the recognition of depreciation expense of the CCGT and refueling project. These costs to build and operate the CCGT and the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after the assets have been placed in service. The CCGT is expected to be completed in the first half of 2018, and the refueling project was completed in December 2015.

In July 2015 IPL received approval from the IURC for a CPN to refuel the Harding Street Station Unit 7 from coal to natural gas (about 410 MW net capacity). The Harding Street Station Unit 7 conversion was completed in the second quarter of 2016.

Key Financial Drivers — IPL's financial results are driven primarily by retail demand, weather, energy efficiency and wholesale prices. In addition, IPL's financial results are likely to be driven by many factors including but not limited to:


•	rate case outcomes


•	the timely recovery of capital expenditures through base rate growth


•	the passage of new legislation or implementation of 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. Refer to the section above for a description of our major construction projects.

DPL

Business Description — DPL is an energy holding company whose principal subsidiaries include DP&L and AES Ohio Generation, LLC.

DP&L generates, transmits, distributes and sells electricity to approximately 519,000 customers in a 6,000 square mile area of West Central Ohio. DP&L, solely or through jointly owned facilities, owns 2,510 MW of generation capacity and numerous transmission facilities.

AES Ohio Generation, LLC owns peaking generation units representing 556 MW located in Ohio and Indiana.

On January 1, 2016, DPL closed on the sale of DPLER to Interstate Gas Supply, Inc. DPLER, a competitive retail marketer, sold retail electricity to more than 124,000 retail customers in Ohio and Illinois while owned by DPL. Approximately 110,000 of those customers were also distribution customers of DP&L in Ohio.

Market Structure — Since January 2001, electric customers within Ohio have been permitted to choose to purchase power under a contract with a CRES Provider or to continue to purchase power from their local utility

under SSO rates established by the tariff. DP&L and other Ohio utilities continue to have the exclusive right to provide delivery service in their state certified territories, and DP&L has the obligation to provide retail generation service to customers that did not choose an alternative supplier. Beginning in 2014, a portion of the SSO generation supply was no longer supplied by DP&L, but was provided by third parties through a competitive bid process. A total of 10%, 60% and 100% of the SSO load was sourced through competitive bid in 2014, 2015 and 2016, respectively. The PUCO maintains jurisdiction over DP&L's delivery of electricity, SSO and other retail electric services. The PUCO has issued extensive rules on how and when a customer can switch generation suppliers, how the local utility will interact with CRES Providers and customers, including for billing and collection purposes, and which elements of a utility's rates are "bypassable" (i.e., avoided by a customer that elects a CRES Provider) and which elements are "non-bypassable" (i.e., charged to all customers receiving a distribution service irrespective of what entity provides the retail generation service).

DP&L is a member of PJM. The PJM RTO operates the transmission systems owned by utilities operating in all or parts of Pennsylvania, New Jersey, Maryland, Delaware, D.C., Virginia, Ohio, West Virginia, Kentucky, North Carolina, Tennessee, Indiana and Illinois. PJM has an integrated planning process to identify potential needs for additional transmission to be built to avoid future reliability problems. PJM also runs the day-ahead and real-time energy markets, ancillary services market and forward capacity market for its members.

As a member of PJM, DP&L is also subject to charges and costs associated with PJM operations as approved by the FERC. Prior to 2015, the RPM was PJM's capacity construct. In 2015, PJM implemented a new CP program, replacing the RPM model. The CP program offers the potential for higher capacity revenues, combined with substantially increased penalties for non-performance or under-performance during certain periods identified as "capacity performance hours." This linkage between non- or under-performance during specific hours means that a generation unit that is generally performing well on an annual basis, may incur substantial penalties if it happens to be unavailable for service during some capacity performance hours. Similarly, a generation unit that is generally performing poorly on an annual basis may avoid such penalties if its outages happen to occur only during hours that are not capacity performance hours. An annual “stop-loss” provision exists that limits the size of penalties to 150% of the net cost of new entry, which is a value computed by PJM. This level is likely to be larger than the capacity price established under the CP program, so that there is potential that participation in the CP program could result in capacity penalties that exceed capacity revenues. The purpose of the RPM and CP Program is to enable PJM to obtain sufficient resources to reliably meet the needs of electric customers within the PJM footprint. PJM conducts an auction to establish the price by zone.

The PJM CP auctions are held three years in advance for a period covering 12 months starting from June 1. Auctions for the period covering June 1, 2020 through May 30, 2021 are expected to take place in May 2017. Future auction results are dependent upon various factors including the demand and supply situation, capacity additions and retirements and any changes in the current auction rules related to bidding for demand response and energy efficiency resources in the capacity auctions. For DPL-owned generation, applicable capacity prices through the auction year 2019/20 are as follows:



Auction Year (June 01-May 31)	2019/20	2018/19	2017/18	2016/17	2015/16	2014/15
Capacity Clearing Price ($/MW-Day)	$100	$165	$152	$134	$136	$126

The computed average capacity prices by calendar year are as follows:



Year	2019	2018	2017	2016	2015
Computed Average Capacity Price ($/MW-Day)	$127	$159	$145	$135	$132

The above tables reflect the capacity prices after the transitional auctions discussed earlier. Substantially all of DP&L's capacity cleared in the CP auction. The results of these auctions could have a significant effect on DP&L's revenues in the future.

Regulatory Framework - Retail Regulation and Rate Structure — DP&L is subject to regulation by the PUCO, for its distribution services and facilities, retail rates and charges, reliability of service, compliance with renewable energy portfolio, energy efficiency program requirements and certain other matters. DP&L's rates for electric service to retail customers consist of basic rates and charges that are set and approved by the PUCO after public hearings. In addition, DP&L's rates include various adjustment mechanisms including, but not limited to, the timely recovery of costs incurred to comply with alternative energy, renewables, energy efficiency, and economic development costs. These components function independently of one another, but the overall structure of DP&L's retail rates and charges are subject to the rules and regulations established by the PUCO.

Since Ohio is deregulated, and allows customers to choose retail generation providers, DP&L is required to provide retail generation service at SSO rates to any customer that has not signed a contract with a CRES provider.

SSO rates are subject to rules and regulations of the PUCO and are established based on DP&L's most recently approved ESP. 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 wholesale transmission rates are regulated by the FERC.

Although it had been in effect since January 2014, on June 20, 2016, the Supreme Court of Ohio ("Court") issued an opinion in the appeal of DP&L’s ESP (ESP 2) that had been approved by the PUCO for the years 2014-2016 and which, among other matters, permitted DP&L to collect a non-bypassable Service Stability Rider equal to $110 million per year from 2014-2016 and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. DP&L's own generation was phased-out of supplying SSO service over the three year period and beginning January 1, 2016 DP&L's SSO was 100% sourced through the competitive bid. In the opinion, the Court stated that the PUCO’s approval of ESP 2 was reversed. In view of that reversal, DP&L filed a motion to withdraw ESP 2 and implement rates consistent with those in effect prior to 2014 (ESP 1). Those rates will be in effect until rates consistent with DP&L’s pending February 22, 2016 ESP (ESP 3) filing are approved and effective.

DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to recover $145 million per year for seven years supporting the alternative described in the original filing, named the Distribution Modernization Rider. This plan establishes the terms and conditions for DP&L's SSO beginning June 1, 2017 to customers that do not choose a competitive retail electric supplier. In its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $11 million of regulatory assets. The plan also proposes a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions from DP&L's energy efficiency programs, and certain environmental liabilities the Company may incur.

On January 30, 2017 DP&L, in conjunction with nine intervening parties, filed a settlement in the ESP 3 case, which is subject to PUCO approval. DP&L and the intervening parties agreed to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:


•	The establishment of a five-year Distribution Modernization Rider designed to collect $90 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure;


•	The establishment of a Distribution Investment Rider for distribution investments, with one component designed to collect $35 million in revenue per year to enable the implementation of smart grid and advanced metering, ending after the fifth year of the term of the ESP,


•	A commitment by the Company to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC);


•	A commitments to commence the sale process of our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants and;


•	A commitment to develop or procure wind and/or solar energy projects in Ohio,


•	Restrictions on DPL making dividend or tax sharing payments, various other riders, and competitive retail market enhancements.

A hearing on the stipulation has been scheduled for March 2017. A final decision by the PUCO is expected at the end of Q2 or early Q3 2017. If the PUCO agrees to the proposed settlement, the average residential customer in the DP&L service territory, using 1,000 kWh on DP&L's Standard Service Offer, can expect a monthly bill increase of $2.39. There can be no assurance that the ESP 3 stipulation will be approved as filed or on a timely basis, and if the final ESP provides for terms that are more adverse than those submitted in DP&L's stipulation, our results of operations, financial condition and cash flows could be materially impacted.

On November 30, 2015 DP&L filed an application to increase its distribution rate case using a 12-month test year of June 1, 2015 to May 31, 2016 to measure revenue and expenses and a date certain of September 30, 2015 to measure its asset base. The Company is seeking an increase to distribution revenues of $66 million per year. The Company has asked for recovery of certain regulatory assets as well as two new riders that would allow the Company to recover certain costs on an ongoing basis. It has proposed a modified straight-fixed variable rate design in an effort to decouple distribution revenues from electric sales. If approved as filed the rates are expected to have a total bill impact of approximately 4% on a typical residential customer.

Environmental Regulation — In relation to MATS, DPL does not expect to incur material capital expenditures to ensure compliance. For more information see Item 1.—United States Environmental and Land-Use Legislation

and Regulations.

Key Financial Drivers — DPL financial results are driven by retail demand, weather, energy efficiency and wholesale prices on financial results. 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 ESP 3 case, including the amount of non-bypassable revenue


•	Outcome of DP&L's pending distribution rate case


•	Operational performance of generation facilities


•	Recovery in the power market, particularly as it relates to an expansion in dark spreads


•	Sale or transfer to a DPL affiliate of DP&L generation assets


•	DPL's ability to reduce its cost structure

Construction and Development — Planned construction additions primarily relate to new investments in and upgrades to DP&L's power plant equipment 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 $414 million in capital projects for the period 2017 through 2019 with 65% attributable to Transmission and Distribution. DPL's ability to complete capital projects and the reliability of future service will be affected by its financial condition, the availability of internal funds and the reasonable cost of external funds. 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.

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 Southern California Edison. The three coastal power plants comprising AES Southland are in areas that are critical for local reliability and play an important role in integrating the increasing amounts of renewable generation resources in California.

Market Structure — All of AES Southland's capacity is contracted through a long-term agreement (the “Tolling Agreement”), which expires in May 31, 2018. A Resource Adequacy agreement has been executed that covers the period from June 1, 2018 through 2020, but it is still subject to approval from the California Public Utilities Commission. Under the current Tolling Agreement, AES Southland's largest revenue driver is unit availability, as approximately 98% of its revenue comes from availability-related payments. Historically, AES Southland has generally met or exceeded its contractual availability requirements under the Tolling Agreement and may capture bonuses for exceeding availability requirements in peak periods.

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.

AES Southland delivers electricity into the California ISO's market through its Tolling Agreement counterparty.

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 October 2014, AES Southland was awarded 20-year contracts by SCE to provide 1,284 MW of combined cycle gas-fired generation and 100 MW of interconnected battery-based energy storage. In addition to replacing older gas-fired plants with more efficient gas-fired capacity, SCE chose advanced energy storage as a cost effective way to ensure critical power system reliability. This new storage resource will provide operational flexibility, enabling the efficient dispatch of other generating plants, lowering cost and emissions and supporting the on-going addition of renewable power sources.

This new capacity will be built at the Company's existing power plant sites in Huntington Beach and Alamitos Beach. For the gas-fired capacity, financing agreements are expected to be completed in mid-2017 with construction expected to begin shortly thereafter, and commercial operation scheduled for 2020. For the energy storage capacity, commercial operation is scheduled for 2021.

AES is pursuing permits to build both the gas-fired and energy storage capacity and will complete the licensing process before financial close. The total cost for these projects is expected to be approximately $1.9 billion, which will be funded with a combination of non-recourse debt and AES equity.

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

Business Description — Additional businesses include thermal, wind, and solar generating facilities, of which AES Hawaii, our U.S. wind generation businesses and distributed solar are the most significant.


•	AES Hawaii — AES Hawaii receives a fuel payment from its offtaker under a PPA expiring in 2022, which is based on a fixed rate indexed to the Gross National Product - Implicit Price Deflator. Since the fuel payment is not directly linked to market prices for fuel, the risk arising from fluctuations in market prices for coal is borne by AES Hawaii.

To mitigate the risk from such fluctuations, AES Hawaii has entered into fixed-price coal purchase commitments that end in December 2018; the business could be subject to variability in coal pricing beginning in January 2019. To mitigate fuel risk beyond December 2018, AES Hawaii plans to seek additional fuel purchase commitments on favorable terms. However, if market prices rise and AES Hawaii is unable to procure coal supply on favorable terms, the financial performance of AES Hawaii could be materially and adversely affected.

•

U.S. Wind — AES has 736 MW of wind capacity in the U.S., located in California, Texas and West Virginia. Typically, these facilities sell under long-term PPAs. AES financed most of these projects with tax equity structures. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in a net loss to AES consolidated results in periods in which the facilities report net income. These non cash net losses will be expected to reverse during the life of the facilities. Some of the wind projects are exposed to the volatility of energy prices and their revenue may change materially as energy prices fluctuate in their respective markets of operations.

Buffalo Gap is located in Texas and is comprised of three wind projects with an aggregate generation capacity of 522 MW. Each wind project operates its own PPA with the exception of Buffalo Gap III. The energy price of the entire production of Buffalo Gap I is guaranteed by a PPA expiring in 2021. The PPA of Buffalo Gap II guarantees the energy price of 80% of the installed capacity while the energy price for the remaining 20% is dictated by the prices in the ERCOT market. The PPA of Buffalo Gap II expires in December 2017. Once the PPAs expire, the entire installed capacity of Buffalo Gap will be exposed to the volatility of energy prices in the ERCOT market which could adversely affect revenues.

Laurel Mountain is a wind project located in West Virginia with an installed capacity of 98 MW. Laurel Mountain does not operate under a long-term contract and sells its entire capacity and power generated into the PJM market. The volatility and fluctuations of energy prices in PJM have a direct impact in the results of Laurel Mountain.

AES manages the wind portfolio as part of its broader investments in the U.S., leveraging operational and commercial resources to supplement the experienced subject matter experts in the wind industry to achieve optimal results.

•

AES Distributed Energy — AES has 103 MW of solar capacity in the U.S., located across multiple states. Distributed Energy's Commercial and Utility division, which comprised 89 MW of solar capacity as of December 31, 2016, sells electricity generated by photovoltaic solar energy systems to public sector, utility, and non-profit entities through power purchase agreements. AES has added 33 MW of commercial and utility capacity in 2016. A majority of this new capacity has been financed with tax equity structures. Under these tax equity structures, the tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in a net loss to AES consolidated results in periods in which the facilities report net income. These non cash net losses will be expected to reverse during the life of the facilities.

AES manages the Distributed Energy portfolio as part of its broader investments in the U.S., leveraging operational and commercial resources to supplement the experienced subject matter experts in the solar industry to achieve optimal results.

Market Structure — For the non-renewable businesses included in our additional U.S. generation facilities, coal and natural gas are used as the primary fuels. Coal has prices that are set by market factors internationally while natural gas is generally set domestically. Price variations for these fuels can change the composition of generation costs and energy prices in our generation businesses, and the prices of these fuels have been subject to volatility in recent years.

Many of these generation businesses have entered into long-term PPAs with utilities or other offtakers. Some coal-fired power plant businesses in the U.S. with PPAs have mechanisms to recover fuel costs from the offtaker, including an energy payment that is partially based on the market price of coal. In addition, these businesses often have an opportunity to increase or decrease profitability from payments under their PPAs depending on such items as plant efficiency and availability, heat rate, ability to buy coal at lower costs through AES' global sourcing program and fuel flexibility. Revenue may change materially as prices in fuel markets fluctuate, but the variable margin or profitability should not be materially changed when market price fluctuations in fuel are borne by the offtaker.

Regulatory Framework — Several of our generation businesses in the U.S. currently operate as QFs as defined under the PURPA. These businesses entered into long-term contracts with electric utilities that had a mandatory obligation under PURPA requirements to purchase power from QFs at the utility's avoided cost (i.e., the likely costs for both energy and capital investment that would have been incurred by the purchasing utility if that utility had to provide its own generating capacity or purchase it from another source). To be a QF, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility's total energy output and meet certain efficiency standards. To be a QF, a small power production facility must generally use a renewable resource as its energy input and meet certain size criteria.

Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators as defined under 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 FPA and FERC's regulations, approval from FERC to sell wholesale power at market-based rates is generally dependent upon a showing to FERC that the seller lacks market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no opportunity for abusive transactions involving regulated affiliates of the seller. To prevent market manipulation, FERC requires sellers with market-based rate authority to file certain reports, including a triennial updated market power analysis for markets in which they control certain threshold amounts of generation.

Other Regulatory Matters — The U.S. wholesale electricity market consists of multiple distinct regional markets that are subject to both federal regulation, as implemented by the U.S. FERC, and regional regulation as defined by rules designed and implemented by the RTOs, non-profit corporations that operate the regional transmission grid and maintain organized markets for electricity. These rules for the most part govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity. See Item 1A.—Risk Factors for additional discussion on U.S. regulatory matters.

Environmental Regulation — 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. Generation's financial results are driven by fuel costs and outages. The Company has entered into long-term fuel contracts to mitigate the risks associated with fluctuating prices. In addition, major maintenance requiring units to be off-line is performed during periods when power demand is typically lower. The financial results of U.S. Wind are primarily driven by increased production due to faster and less

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.

Construction and Development — Planned capital projects include the AES Southland re-powering described above. In addition to the new construction projects, 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 9,308 MW, of which 44%, 45% and 11% is 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/Pet Coke	760	33	%	2000	2017-2032	Various
Electrica Santiago ⁽²⁾	Chile	Gas/Diesel	750	67	%	2000
Gener - SIC ⁽³⁾	Chile	Hydro/Coal/Diesel/Biomass	689	67	%	2000	2020-2037	Various
Electrica Angamos	Chile	Coal	558	67	%	2011	2026-2037	Minera Escondida, Minera Spence, Quebrada Blanca
Cochrane	Chile	Coal	532	40	%	2016	2030-2034	SQM, Sierra Gorda, Quebrada Blanca
Gener - SING ⁽⁴⁾	Chile	Coal/Pet Coke	277	67	%	2000	2017-2037	Minera Escondida, Codelco, SQM, Quebrada Blanca
Electrica Ventanas ⁽⁵⁾	Chile	Coal	272	67	%	2010	2025	Gener
Electrica Campiche ⁽⁶⁾	Chile	Coal	272	67	%	2013	2020	Gener
Andes Solar	Chile	Solar	21	67	%	2016	2037	Quebrada Blanca
Cochrane ES	Chile	Energy Storage	20	40	%	2016
Electrica Angamos ES	Chile	Energy Storage	20	67	%	2011
Gener - Norgener ES (Los Andes)	Chile	Energy Storage	12	67	%	2009
Chile Subtotal			4,183
TermoAndes ⁽⁷⁾	Argentina	Gas/Diesel	643	67	%	2000	Short-term	Various
AES Gener Subtotal			5,846
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	11	100	%	1995		Various
Argentina Subtotal			3,462
			9,308

_____________________________


⁽¹⁾	Guacolda plants: Guacolda 1, 2, 3, 4, and 5. Unconsolidated entities for which the results of operations are reflected in 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.


⁽³⁾	Gener — SIC plants: Alfalfal, Laguna Verde, Laguna Verde Turbogas, Laja, Maitenes, Queltehues, Ventanas 1, Ventanas 2 and Volcán.


⁽⁴⁾	Gener — SING plants: Norgener 1 and Norgener 2.


⁽⁵⁾	Electrica Ventanas plant: Ventanas 3.


⁽⁶⁾	Electrica Campiche plant: Ventanas 4.


⁽⁷⁾	TermoAndes is located in Argentina, but is connected to both the 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

1H 2019

Chile Subtotal

531

The following map illustrates the location of our Andes facilities:

Andes Businesses

Chile

Business Description — In Chile, through AES Gener, we are engaged in the generation and supply of electricity (energy and capacity) in the two principal markets: the SIC and SING. In terms of aggregate installed capacity, AES Gener is the second largest generation operator in Chile with a calculated installed capacity of 4,131 MW, excluding energy storage and TermoAndes, and a market share of approximately 18% as of December 31, 2016.

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 portfolio is composed of hydroelectric, coal, gas, diesel, solar photovoltaic and biomass facilities, that allows the businesses to operate under a variety of market and hydrological conditions, manage AES Gener's contractual obligations with regulated and unregulated customers and, as required, provide backup energy to the spot market.

AES Gener has experienced significant growth in recent years by responding to market opportunities. The company successfully completed a first expansion phase between 2007 and 2014 that added 6 new power plants totaling 1,677 MW. It continued to grow in Chile through its second expansion phase that will add 1,236 MW. As of the end of 2016, AES Gener has completed the construction of Guacolda Unit 5 (152 MW), Cochrane (532 MW) and Andes Solar (21 MW). Additionally, we continue to advance in the construction of the 531 MW Alto Maipo run-of-the-river hydroelectric plant in the SIC.

Our commercial policy in Chile aims to maximize margin while reducing cash flow volatility. In order to achieve this, we contract a significant portion of our baseload capacity, currently coal and hydroelectric, under long-term agreements with a diversified customer base, that includes both regulated and unregulated customers. Power plants that are not considered within our baseload capacity (higher variable cost units, mainly diesel and gas fired

units) operate during scarce system supply conditions, such as dry hydrological conditions and plant outages, selling their energy in the spot market. In Chile, sales on the spot market are made only to other generation companies (entities that are members of the Economic Load Dispatch Center - "CISEN") at the system marginal cost. In anticipation of the SIC and SING interconnection, the new Transmission Law created the CISEN, an entity that will merge both system operators into one.

AES Gener currently has long-term contracts, with an average remaining term of approximately 11 years, with regulated distribution companies and unregulated customers, such as mining and industrial companies. In general, these long-term contracts include both fixed and variable payments along with indexation mechanisms that periodically adjust prices based on the generation cost structure related to the United States Consumer Price Index, the international price of coal, and in some cases, with pass-through of fuel and regulatory costs, including changes in law.

In addition to energy payments, AES Gener also receives firm capacity payments for contributing to the system's ability to meet peak demand. These payments are added to the final electricity price paid by both unregulated and regulated customers. In each system, the CISEN annually determines the firm capacity amount allocated to each power plant. A plant's firm capacity is defined as the capacity that it can guarantee at peak hours during critical conditions, such as droughts, taking into account statistical information regarding maintenance periods and water inflows in the case of hydroelectric plants. The capacity price is fixed by the National Energy Commission in the semiannual node price report and indexed to the United States Consumer Price Index and other relevant indices.

Market Structure — Chile has two main power systems, largely as a result of its geographic shape and size. The SIC is the largest of these systems, with an installed capacity of 17,543 MW as of December 31, 2016. The SIC serves approximately 92% of the Chilean population, including the densely populated Santiago Metropolitan Region, and represents 75% of the country's electricity demand. The SING serves about 6% of the Chilean population, representing 25% of Chile's electricity consumption, and mainly supplies mining companies.

In 2016, thermoelectric generation represented 67% of the total generation in Chile. In the SIC, thermoelectric generation represents 48% of installed capacity, required to fulfill demand not satisfied by hydroelectric output and is critical to guaranteeing reliable and dependable electricity supply under dry hydrological conditions. In the SING, which includes the Atacama Desert, the driest desert in the world, thermoelectric capacity represents 92% of installed capacity. The fuels used for generation, mainly coal, diesel and LNG, are indexed to international prices.

In the SIC, where hydroelectric plants represent a large part of the system's installed capacity, hydrological conditions largely influence plant dispatch and, therefore, spot market prices, given that river inflows, snow melting and initial water levels in reservoirs largely determine the dispatch of the system's hydroelectric and thermoelectric generation plants. Rainfall and snowfall occur in Chile principally in the southern cone winter season (June to August) and during the remainder of the year precipitation is scarce. When rain is abundant, energy produced by hydroelectric plants can amount to more than 70% of total generation. In 2016 hydroelectric generation represented 36% of total energy production within the SIC, and 27% of the country’s total energy production.

Solar and wind installed capacity represents a small but growing part of the total capacity installed. In the SIC, solar accounts for 3% of the power generation and 7% of the system’s installed capacity while in the SING solar accounts for 4% of the power generation and 6% of the system’s capacity. As for wind, in the SIC, wind contributes with 4% of the power generation and 7% of the system’s capacity, while in the SING wind generation represents 1% of the power generation and with 2% of the system’s capacity.

Regulatory Framework — The government entity that has primary responsibility for the Chilean electricity system is the Ministry of Energy, acting directly or through the National Energy Commission and the Superintendency of Electricity and Fuels. The electricity sector is divided into three segments: generation, transmission and distribution. In general terms, generation and transmission expansion are subject to market competition, while transmission operation and distribution, are subject to price regulation. The transmission segment consists of companies that transmit the electricity produced by generation companies at high voltage. The individual and joint participation of companies operating in any other segment of the electricity sector cannot exceed 8% and 40%, respectively, of the total investment value of the national transmission system.

Companies in the SIC and the SING that own generation, transmission, sub-transmission or additional transmission facilities, as well as unregulated customers directly connected to transmission facilities, are coordinated through the CISEN, which minimizes the operating costs of the electricity system, while meeting all service quality and reliability requirements. The principal purpose of the CISEN is to ensure that the most efficient electricity generation available to meet demand is dispatched to customers. The CISEN dispatches plants in merit order based on their variable cost of production, allowing for electricity to be supplied at the lowest available cost.

All generators can commercialize energy through contracts with distribution companies for their regulated and unregulated customers or directly with unregulated customers. Unregulated customers are customers whose connected capacity is higher than 2MW. Customers with connected capacity between 0.5 MW and 2.0 MW can opt for a Regulated or Unregulated regime for a minimum period of four years. By law, both regulated and unregulated customers are required to purchase all of their electricity requirements under contract. Generators may also sell energy to other power generation companies on a short-term basis. Power generation companies may engage in contracted sales among themselves at negotiated prices outside the spot market. Electricity prices in Chile, under contract and on the spot market, are denominated in U.S. Dollars, although payments are made in Chilean Pesos.

In July 2016, modifications to the Transmission 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 year 2019 through 2034.

Environmental Regulation — In 2011, a regulation on air emission standards for thermoelectric power plants became effective. This regulation provides for stringent limits on emission of PM and gases produced by the combustion of solid and liquid fuels, particularly coal. For existing plants, including those currently under construction, the new limits for PM emissions went into effect at the end of 2013, and the new limits for SO₂, NO_x and mercury emission were in effect since mid-2016, except for those plants operating in zones declared saturated or latent zones (areas at risk of or affected by excessive air pollution), where these emission limits became effective in June 2015. In order to comply with the new emission standards, AES Gener initiated investments in Chile at its older coal facilities (Ventanas I and II and Norgener I and II, constructed between 1964 and 1997) in 2012. As of December 31, 2016, AES Gener has concluded investments of approximately $229 million in order to comply within the required time frame. Additionally, its equity method investee Guacolda started the installation of new emission control equipment during 2013, and concluded investments of approximately $209 million in order to comply within the required time frame.

On March 29, 2016, the Health Ministry enacted Supreme Decree N°43 (“DS 43”) ruling “Storage of Hazardous Materials”, modifying the current applicable rules. This regulation will become fully effective in March 2018 for structural improvements of currently authorized storage facilities. The estimated investment required to comply with DS 43 would be approximately $15 million.

During 2016, the Environmental Ministry worked on upgrading the Atmospheric Decontamination Plans for Santiago, Ventanas and Huasco areas, each of which, as of December 31, 2016, are currently under different stages of progress. Nueva Renca, Ventanas and Guacolda power plants may require an improvement of their operational practices and additional investments to meet the expected new requirements during the year following the enactment of the Decontamination Plan, which is expected for mid 2017.

Chilean law requires every electricity generator to supply a certain portion of its total contractual obligations with Non-conventional Renewable Energy ("NCREs"). In October 2013, the NCRE law was amended, increasing the NCRE requirements. The law distinguishes between energy contracts executed before and after July 1, 2013. For contracts executed between August 31, 2007 and July 1, 2013, the NCRE requirement is equal to 5% in 2014 with annual contract increases of 0.5% until reaching 10% in 2024. The NCRE requirement for contracts executed after July 1, 2013 is equal to 5% in 2013, with annual increases of 1% thereafter until reaching 12% in 2020, and subsequently annual increases of 1.5% until it is equal to 20% in 2025. Generation companies are able to meet this requirement by developing their own NCRE generation capacity (wind, solar, biomass, geothermal and small hydroelectric technology), purchasing NCREs from qualified generators or by paying the applicable fines for non-compliance. AES Gener currently fulfills the NCRE requirements by utilizing AES Gener's own solar and biomass power plants and by purchasing NCREs from other generation companies. It has sold certain water rights to companies that are developing small hydro projects, entering into power purchase agreements with these companies in order to promote development of these projects, while at the same time meeting the NCRE requirements. At present, AES Gener is in the process of negotiating additional NCRE supply contracts to meet the future requirements.

In September 2014 a new tax law was enacted. The new law introduces an emission tax, or "green tax", that assesses the emissions of PM, SO₂, NO_x and CO₂ produced for installations with an installed capacity over 50 MW. The first annual payment shall be made in April 2018 for emissions produced in 2017. In the case of CO₂, the tax will be equivalent to $5 per ton emitted. In the SING, all PPAs have "change of law" clauses, which would allow the company to transfer this cost to customers. In the SIC, costs can only be passed through to unregulated customers, as existing PPAs with distribution companies do not have change of law clauses. According to its PPAs, the company is currently discussing the pass-through mechanism with each client. Additionally, the new tax systems introduced by the new tax laws enacted in February 2016 will be effective from January 1, 2017 onwards. The statutory income tax rate for most of our Chilean businesses will increase from 25% to 25.5% in 2017 and to 27%

for 2018 and future years. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Income Taxes for further details of the impacts of these new laws.

In June 2015, the Chilean government published Decree N°7/2015, which allows the export of energy generated by plants not dispatched in the SING to Argentina using the transmission line connecting the SING with the SADI. This transmission line is owned by AES Gener and has a capacity of approximately 600 MW, but will be operated at 200 MW according to the government permit and related technical studies. AES Gener signed an agreement with CAMMESA and Chilean generators to export electricity to Argentina. In December 2016, Decree N° 7/2015 was amended to allow the export of energy generated by plants dispatched into the SING to Argentina. During 2016, energy exported to Argentina reached 102 GWh.

Key Financial Drivers — Hedge levels at Gener provide some certainty and clarity on the underlying financial drivers. In addition, financial results are likely to be driven by many factors including, but not limited to:


•	Dry hydrology scenarios reduce hydro generation


•	Forced outages may impact earnings


•	Changes in current regulatory rulings could alter the ability to pass through or recover certain costs


•	AES is exposed to the fluctuation of the Chilean peso, which may pose a risk to earnings; our hedging strategy reduces this risk, but some residual risk to earnings remains


•	Tax policy changes


•	Current legislation is trending towards promoting renewable energy and strengthening regulations on thermal generation assets, posing a risk to future coal margins


•	Market price risk when re-contracting

Construction and Development — Since 2007, AES Gener has constructed and commissioned approximately 2,400 MW of new capacity, representing a significant portion of the capacity increase in the SIC and SING during the period. During 2016, AES Gener achieved important milestones related to the construction of their projects:


•	Cochrane project began operations (Unit 2 on October 12 and Unit 1 on July 9) adding 532 MW to the SING.


•	Cochrane Energy Storage began operations in October 2016 adding 20 MW of batteries contributing to system stability in the SING.


•	Andes Solar with 21 MW began operations in May 2016

Additionally, in the SIC, we continue advancing in the construction of our Alto Maipo project, a 531 MW two unit run-of-river hydroelectric power plant, adjacent to our existing Alfalfal plant, located 50 km from Santiago. Alto Maipo is the largest project in construction in the SIC market and it includes 67 km of tunnel works, two caverns, 17 km of transmission lines as part of the construction, and is 90% underground. Alto Maipo has three main contractors and covers three adjacent valleys in the Chilean Andes. As of today, the project employs approximately 4,300 people and expects to reach a peak close to 4,500. The project units are scheduled to reach commercial operation in the first half of 2019.

We are expanding our business by evaluating opportunities in the desalination business line through two initiatives: i) brownfield projects, which take advantage of existing infrastructure in thermoelectric power plants (marine works, easy access to power, strategic location, permits, etc.), providing shorter development time lines and more competitive water tariffs to offtakers; and ii) greenfield projects, mainly for mining companies which either purchase industrial water through water purchase agreements, or either invite external companies to compete in a bidding process to develop a project under a build-own-operate-and-transfer scheme where the water facility along its pipeline is transferred to the mining operation at the end of a defined period. In Chile, most of the water demand comes from mining operations, either directly or indirectly (their service providers), hence negative outlooks in the mineral markets have translated in the postponement of most of the mining projects and their corresponding water demands.

Colombia

Business Description — We operate in Colombia through AES Chivor, a subsidiary of AES Gener, who owns a hydroelectric plant with an installed capacity of 1,000 MW, and Tunjita, a 20 MW run-of-river hydroelectric, both located approximately 160 km east of Bogota. As of December 31, 2016, AES Chivor's net power production in reached 4,373 GWh. AES Chivor’s installed capacity accounted for approximately 6.1% of system capacity by the end of the year. Chivor remains dependent on prevailing hydrological conditions in the region in which it operates. Hydrological conditions largely influence generation and the spot prices at which AES Chivor sells its non-

contracted generation in Colombia.

AES Chivor's commercial strategy aims to reduce margin volatility by selling a significant portion of the expected generation under short term contracts, mainly with distribution companies. These contracts are awarded in public auctions and normally last from one to three years. The remaining generation is sold on the spot market to other generation and trading companies at the system marginal cost, allowing us to maximize the operating margin. Additionally, AES Chivor receives reliability payments to compensate for the plant availability during periods of power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.

Market Structure — Electricity supply in Colombia is concentrated in one main system, the SIN which encompasses one-third of Colombia's territory, providing coverage to 97% of the country's population. The SIN's installed capacity totaled 16,690 MW as of December 31, 2016, comprised of 70% hydroelectric generation, 29% thermoelectric generation and 1% other. The dominance of hydroelectric generation and the marked seasonal variations in Colombia's hydrology result in price volatility in the short-term market. In 2016, 72% of total energy demand was supplied by hydroelectric plants with the remaining supply from thermoelectric generation of 27% and cogeneration and self-generation power of 1%. From 2003 to 2016, electricity demand in the SIN has grown at a compound annual growth rate of 2.9% and the Mining and Energetic Planning Unit projects an average compound annual growth rate in electricity demand of 3.0% per year for the next 10 years.

Regulatory Framework — Since 1994, the electricity sector in Colombia has operated 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 various laws as well as the regulations and technical standards issued by the CREG. Other government entities that play an important role in the electricity industry include the Ministry of Mines and Energy, which defines the government's policy for the energy sector; the Public Utility Superintendency of Colombia, which is in charge of overseeing and inspecting the utility companies; and the Mining and Energetic Planning Unit, which is in charge of planning the expansion of the generation and transmission network.

The generation sector is organized on a competitive basis with companies selling their generation in the wholesale market at the short-term price or under bilateral contracts with other participants, including distribution companies, generators and traders, and unregulated customers at freely negotiated prices. Generation companies must submit price bids and report the quantity of energy available on a daily basis. The National Dispatch Center dispatches generators in merit order based on bid offers in order to ensure that demand will be satisfied by the lowest cost combination of available generating units.

Regulatory Framework - Tax Regulation — On December 29, 2016, Law 1819 was enacted in Colombia, which introduced a tax reform with several changes in the Colombian tax system, and became effective on January 1, 2017. This tax reform reduced the statutory corporate tax rate of companies to 40% in 2017, 37% in 2018, and 33% in 2019 onwards. The law also created a new withholding tax on dividend distributions based on a tax rate of 5%, applicable on distribution of Colombian profits generated from the taxable year 2017 onwards.

Other Regulatory Considerations — After the phenomenon of El Niño put the energy supply at risk, regulatory agencies and the government have carried out various studies to make adjustments to the market. The subjects susceptible to revision include the following:


•	Adjustments to the scarcity price so that it reflects a true value of thermal plants that operate in periods of crisis.


•	A plan to implement an option to assign firm energy obligations without the need for reliability auctions but with obligation of signing energy contracts with non-regulated demand.


•	Possible participation of renewable plants in the market and its effect in the formation of prices and operation of the market.


•	The implementation of the standardized contract market, and


•	The possibility of entering into the intraday markets and markets of the previous day are still being considered.

Other topics that the regulator could analyze in 2017, but with a secondary priority are: An international interconnection scheme, review of the AGC market and analysis of other ancillary services, and possible modification of the current regulation for emergency situations.

Key Financial Drivers — Hydrological conditions largely influence Chivor's generation level. Maintaining the appropriate contract level, while working to maximize revenue, through sale of excess generation, is key to Chivor's results of operations Hedge levels at Chivor provide certainty and clarity on the underlying financial drivers, hedging the net cash flows of Chivor, up to 90%. In addition to hydrology financial results are likely to be driven by many factors including, but not limited to:


•	Forced outages may impact earnings


•	AES is exposed to fluctuation of the Colombian peso, which pose a risk to earnings; our hedging strategy reduces this risk, but some residual risk to earnings remains


•	Chivor has exposure to the spot market as hedge levels are lower in the future

Construction and Development — In Colombia, AES Gener completed the construction of the Tunjita project in June 2016 that added 20 MW of capacity to the Chivor plant.

Argentina

Business Description — As of December 31, 2016, AES Argentina operates 4,105 MW which represents 12% 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. AES Argentina has a diversified generation portfolio of ten generation facilities, comprised of 68% thermoelectric and 32% hydroelectric capacity. All of the thermoelectric capacity has the capability to burn alternative fuels. Approximately 76% of the thermoelectric capacity can operate with natural gas or diesel oil, and the remaining 24% can operate with natural gas, fuel oil, or coal.

AES Argentina primarily sells its production to the wholesale electric market where prices are largely regulated. In 2016, approximately 94% of the energy was sold in the wholesale electric market and 6% was sold under contract, as a result of the Energy Plus sales made by TermoAndes.

All of the thermoelectric facilities not affected by the Resolution 95/2013, a regulation passed in March 2013 discussed below, including the portion of TermoAndes plant committed to Energy Plus Contracts, are able to use natural gas and receive gas supplied through contracts with Argentine producers. In recent years, gas supply restrictions in Argentina, particularly during the winter season, have affected some of the plants, such as the TermoAndes plant. The TermoAndes plant commenced operations in 2000, selling exclusively into the Chilean SING. In 2008, following requirements from the Argentine authorities, TermoAndes connected its two gas turbines to the SADI, while maintaining its steam turbine connected to the SING. However, since December 2011, TermoAndes has been selling the plant's full capacity in the SADI.

Market Structure — The SADI electricity market is managed by CAMMESA. As of December 31, 2016, the installed capacity of the SADI totaled 33,901 MW. In 2016, 66% of total energy demand was supplied by thermoelectric plants, 26% by hydroelectric plants and 8% from nuclear, wind and solar plants.

Thermoelectric generation in the SADI is principally fueled by natural gas. However, since 2004 due to natural gas shortages, in addition to increasing electricity demand, the use of alternative fuels in thermoelectric generation, such as oil and coal, has increased. Given the importance of hydroelectric facilities in the SADI, hydrological conditions determining river flow volumes and initial water levels in reservoirs largely influence hydroelectric and thermoelectric plant dispatch. Rainfall occurs principally in the southern cone winter season (June to August).

Regulatory Framework — The Argentine regulatory framework divides the electricity sector into generation, transmission and distribution. The wholesale electric market is made up of generation companies, transmission companies, distribution companies and large customers who are allowed to buy and sell electricity. Generation companies can sell their output in the short-term market or to customers in the contract market. CAMMESA is responsible for dispatch coordination and determination of short-term prices. The Electricity National Regulatory Agency is in charge of regulating public service activities and the Ministry of Federal Planning, Public Investment and Services, through the Energy Secretariat, regulates system dispatch and grants concessions or authorizations for sector activities.

Since 2001, significant modifications have been made to the electricity regulatory framework. These modifications include the freezing of tariffs, the cancellation of inflation adjustment mechanisms and the introduction of a complex pricing system in the wholesale electric market, which have materially affected electricity generators, transporters and distributors, and generated substantial price differences within the market. Since 2004, as a result of energy market reforms and overdue accounts receivables owed by the government to generators operating in Argentina, AES Argentina contributed certain accounts receivables to fund the construction of new power plants under FONINVEMEM agreements. These receivables accrue interest and are collected in monthly installments over 10 years once the related plants begin operations. At this point, three funds have been created to construct three facilities. The three plants are operating and payments are being received. AES Argentina will receive a pro rata ownership interest in these newly built plants once the accounts receivables have been paid. See Item 7.—Capital Resources and Liquidity—Long-Term Receivables and Note 7—Financing Receivables for further discussion of receivables in Argentina.

In March 2013, the Secretariat of Energy released Resolution 95/2013, which affects the remuneration of generators whose sales prices had been frozen since 2003. This regulation is applicable to generation companies with certain exceptions. It defined a compensation system based on compensating for fixed costs, non-fuel variable costs and an additional margin. Resolution 95/2013 converted the Argentine electric market to an "average cost" compensation scheme.

Thermal units must achieve an availability target, which varies by technology, in order to receive full fixed cost revenues. The Resolution also established that all fuels, except coal, are to be provided by CAMMESA. Thermoelectric natural gas plants not affected by the Resolution, such as TermoAndes, are able to purchase gas directly from the producers for Energy Plus sales.

In May 2014, the Argentine government passed Resolution No. 529/214 ("Resolution 529") which retroactively updated the prices of Resolution 95/2013 to February 1, 2014, changed target availability and added a remuneration for non-periodic maintenance. This remuneration is aimed to cover the expenses that the generator incurs when performing major maintenances in its units. Since 2014, this resolution has been updated annually, the most recent of which was issued in March 2016.

On February 2, 2017, the Ministry of Energy issued Resolution 19/2017 establishing changes to the Energia Base price framework. Effective in February 2017, the framework will maintain the current tolling agreement structure, as fuels will continue to be sourced by CAMMESA. A key change will be introduced to the tariff structure which will now have prices set in USD and also eliminates all future non-cash retention of margins.

In December 2015, the finance minister lifted foreign currency controls, allowing the peso to float under the administration of Argentinean Central Bank. The newly freed currency fell by more than 30%. Over the course of 2016, the Argentinean Peso devalued by approximately 22%. At December 31, 2016, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank. See Note 7—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information on the long-term receivables. Further weakening of the Argentine Peso and local economic activity could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to the Parent Company, and the value of our assets.

Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to:

•Forced outages may impact earnings

•FX exposure to fluctuations of the Argentine Peso

•Hydrology


•	Timely collection of FONINVEMEM installment and outstanding receivables (See Note 7—Financing Receivables in Item 8.—Financial Statements and Supplementary Data for further discussion)

•Level of gas prices for contracted generation (Energy Plus)

Brazil SBU

Our Brazil SBU has generation and distribution businesses. Tietê and Eletropaulo are publicly listed companies in Brazil. AES has a 24% economic interest in Tietê and a 17% economic interest in Eletropaulo. These businesses are consolidated in our financial statements as we maintain control over their operations.

Generation — Operating installed capacity of our Brazil SBU totals 2,658 MW in AES Tietê plants, located in the state of São Paulo. As of December 31, 2016, Tietê represents approximately 10% of the total generation capacity in the state of São Paulo and is one of the largest generation companies in Brazil. We also have another generation plant, AES Uruguaiana, located in southern Brazil with an installed capacity of 640 MW. The following table lists our Brazil SBU generation facilities:



Business	Location	Fuel	Gross MW	AES Equity Interest		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
Tietê ⁽¹⁾	Brazil	Hydro	2,658	24	%	1999	2029	Various
Uruguaiana	Brazil	Gas	640	46	%	2000
			3,298

_____________________________


⁽¹⁾	Tietê plants with installed capacity: Água Vermelha (1,396 MW), Bariri (143 MW), Barra Bonita (141 MW), Caconde (80 MW), Euclides da Cunha (109 MW), Ibitinga (132 MW), Limoeiro (32 MW), Mogi-Guaçu (7 MW), Nova Avanhandava (347 MW), Promissão (264 MW), Sao Joaquim (3 MW) and Sao Jose (4 MW).

Utilities — Eletropaulo operates in the metropolitan area of São Paulo and adjacent regions, distributing electricity to 24 municipalities in a total area of 4,526 km², covering a region of high demographic density and the largest concentration of GDP in the country. Serving approximately 18 million people and 7 million consumer units,

Eletropaulo is the largest power distributor in Brazil, according to the 2015 ranking of the Brazilian Association of the Distributors of Electric Energy (Abradee). On October 31, 2016, the Company completed the sale of its wholly-owned subsidiary AES Sul, a distribution business in Brazil. The following table describes our Brazil utility:

Business

Location

Approximate Number of Customers Served as of 12/31/2016

GWh Sold in 2016

AES Equity Interest (% Rounded)

Year Acquired

Eletropaulo

Brazil

7,015,909

34,464

1998

The following map illustrates the location of our Brazil facilities:

Brazil Businesses

Brazil Utility

Business Description — Eletropaulo distributes electricity to the greater São Paulo area, Brazil's main economic and financial center. AES owns 17% of the economic interest in Eletropaulo, our partner, BNDES, owns 19% and the remaining shares are publicly held or held by government-related entities. On December 30, 2016 AES purchased par shares from BNDES and increased its participation in Eletropaulo from 16% to 17%. AES is the controlling shareholder and manages and consolidates this business. Eletropaulo holds a 30-year concession that expires in 2028. In December 2016, Eletropaulo underwent a corporate restructuring which is expected to, among other things, prepare for the listing of its shares on the Novo Mercado, a segment of the Brazilian stock exchange.

Regulatory Framework — In Brazil, ANEEL, a government agency, sets the tariff for each distribution company based on a return on asset base methodology, which also benchmarks operational costs against other distribution companies. The tariff charged to regulated customers consists of two elements: (i) pass-through of non-manageable costs under a determined methodology ("Parcel A"), including energy purchase costs, sector charges and transmission and distribution system expenses; and (ii) a manageable cost component ("Parcel B"), including operation and maintenance costs (defined by ANEEL), recovery of investments and a component for a return to the distributor. The return to distributors is calculated as the net asset base multiplied by the regulatory weighted-average cost of capital, which is set for all industry participants during each tariff reset cycle. The current regulatory weighted-average cost of capital for Eletropaulo, after tax, is 8.1%.

Each year ANEEL reviews each distributor's tariff for an annual tariff adjustment. The annual tariff adjustments allow for pass-through of Parcel A costs and inflation impacts on Parcel B costs, adjusted for expected efficiency gains and quality performances. Distribution companies are required to contract between 100% and 105% of anticipated energy needs through the regulated auction market. If contracted levels fall below required levels distribution companies may be subject to limitations on the pass-through treatment of energy purchase costs as well as penalties. As the costs incurred on energy purchases made by our distribution company are passed through

to customers with adjustments on a yearly basis, working capital can be sensitive to significant increases in energy prices. In order to reduce potential working capital needs, in 2015 ANEEL established the tariff flag mechanism, which allows temporary tariff changes to customers on a monthly basis depending on energy purchase prices. The resources collected by the tariff flag mechanism are centralized in an account and shared among distribution companies in proportion to their respective exposure to the spot market.

Every four years, ANEEL resets each distributor's tariff to incorporate the revised regulatory weighted-average cost of capital and determination of the distributor's net asset base as well as operational costs. Eletropaulo's tariff reset occurs every four years and the next tariff reset will be in July 2019. The 4^th Tariff Reset for AES Eletropaulo occurred on July 4, 2015, representing an average tariff increase of 15.23%.

Between the tariff reset periods, the regulator applies the annual adjustments. On July 4, 2016 ANEEL approved a negative tariff adjustment for Eletropaulo, mainly due to a decrease in energy purchase and sector charges costs. The average tariff decrease was 8.1%.

In 2013, ANEEL challenged the parameters of a tariff reset for Eletropaulo implemented in July 2012 and retroactive to 2011. ANEEL asserted that during the period between 2007 and 2011, certain assets that were included in the regulatory asset base should not have been included and that Eletropaulo should refund customers for the return on the disputed assets earned during this period. On December 17, 2013, ANEEL determined, at the administrative level, that Eletropaulo should adjust the prior 2007-2011 regulatory asset base and refund customers in the amount of $269 million over a period of up to four tariff processes beginning in July 2014. The Company recognized a regulatory liability of approximately $269 million in 2013, since ANEEL had compelled the Company to refund customers, and started reimbursing customers in July 2014. Eletropaulo filed for an administrative appeal requesting ANEEL to reconsider its decision and requested that the decision be suspended until the appeal process is completed. The injunction was granted and, although for a period was suspended, it has been restored and in effect since December 2014.

Given ANEEL's failure to suspend the injunction through the appeals process in the Brazilian courts thus far, the tariff reset resulted in management's reassessment of the probability of refunding customers these disputed amounts. Therefore, at this point, the Company considers it only reasonably possible that Eletropaulo will be required to refund these amounts to customers prior to the ultimate resolution of the pending court case. As a result, during 2015, the Company reversed the remaining regulatory liability for this contingency of $161 million. Eletropaulo believes it has meritorious arguments on this matter and will continue to pursue its objections to ANEEL's rulings vigorously, however there can be no assurance that Eletropaulo will prevail.

Key Financial Drivers — Eletropaulo's financial results is likely to be driven by many factors including, but not limited to:


•	Hydrology, impacting quantity of energy sold and energy purchased


•	Brazilian economic scenario and tariff increases, impacting energy consumption growth, losses and delinquency


•	Quality indicators recovery plan


•	Ability of Eletropaulo to pass through costs via productivity gains


•	Ability of Eletropaulo to solve involuntary exposure


•	Capital structure optimization to reduce leverage and interest costs


•	The CTEEP Eletrobrás case (see Item 3.—Legal Proceedings for further information)

Eletropaulo is affected by the demand for electricity, which is driven by economic activity, weather patterns and customers' consumption behavior. Operating performance is also driven by the quality of service, efficient management of operating and maintenance costs as well as the ability to control non-technical losses. Finally, annual tariff adjustments and periodic tariff resets by ANEEL impact results from operations.

Brazil Generation

Business Description — Tietê has a portfolio of 12 hydroelectric power plants with total installed capacity of 2,658 MW in the state of São Paulo. Tietê was privatized in 1999 under a 30-year concession expiring in 2029. AES owns a 24% economic interest in Tietê, our partner, the BNDES, owns 28% and the remaining shares are publicly held or held by government-related entities. AES is the controlling shareholder and manages and consolidates this business.

Tietê sold nearly 100% of its physical guarantee, approximately 11,194 GWh, to Eletropaulo under a long-term PPA, which expired in December 2015. The contract was price-adjusted annually for inflation, and as of December

31, 2015, the price was R$218/MWh. After the expiration of contract with Eletropaulo, Tietê's strategy is to contract most of its physical guarantee, as described in Regulatory Framework section below, and sell the remaining portion in the spot market. Tietê's strategy is reassessed from time to time according to changes in market conditions, hydrology and other factors. Tietê has been continuously selling its available energy from 2016 forward through medium-term bilateral contracts of three to five years.

As of December 31, 2016, Tietê's contracted portfolio position is 95% and 88% with average prices of R$157/MWh and R$159/MWh (inflation adjusted until December 2016) for 2016 and 2017, respectively. As Brazil is mostly a hydro-based country with energy prices highly tied to the hydrological situation, the deterioration of the hydrology since the beginning of 2014 caused an increase in energy prices going forward. Tietê is closely monitoring and analyzing system supply conditions to support energy commercialization decisions.

Under the concession agreement, Tietê has an obligation to increase its capacity by 15%. Tietê, as well as other concession generators, have not yet met this requirement due to regulatory, environmental, hydrological and fuel constraints. The state of São Paulo does not have a sufficient potential for wind power and only has a small remaining potential for hydro projects. As such, the capacity increases in the state will mostly be derived from thermal gas capacity projects. Due to the highly complex process to obtain an environmental license for coal projects, Tietê decided to fulfill its obligation with gas-fired projects in line with the federal government plans. Petrobras refuses to supply natural gas and to offer capacity in its pipelines and regasification terminals. Therefore, there are no regulations for natural gas swaps in place, and it is unfeasible to bring natural gas to AES Tietê. A legal case has been initiated by the state of São Paulo requiring the investment to be performed. Tietê is in the process of analyzing options to meet the obligation.

Uruguaiana is a 640 MW gas-fired combined cycle power plant located in the town of Uruguaiana in the state of Rio Grande do Sul, commissioned in December 2000. AES manages and has a 46% economic interest in the plant with the remaining interest held by BNDES. The plant's operations were suspended in April 2009 due to the unavailability of gas. 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. The plant operated on a short-term basis during February and March 2013, March through May 2014, and February through May 2015 due to the short-term supply of LNG for the facility. The plant did not operate in 2016. Uruguaiana continues to work toward securing gas on a long-term basis.

Market Structure — Brazil has installed capacity of 150,136 MW, which is 65% hydroelectric, 19% thermal and 16% renewable (biomass and wind). Brazil's national grid is divided into four subsystems. Tietê is in the Southeast and Uruguaiana is in the South subsystems of the national grid.

Regulatory Framework — In Brazil, the Ministry of Mines and Energy determines the maximum amount of energy that a plant can sell, called physical guarantee, which represents the long-term average expected energy production of the plant. Under current rules, physical guarantee can be sold to distribution companies through long-term regulated auctions or under unregulated bilateral contracts with large consumers or energy trading companies.

The National System Operator ("ONS") is responsible for coordinating and controlling the operation of the national grid. The ONS dispatches generators based on hydrological conditions, reservoir levels, electricity demand and the prices of fuel and thermal generation. Given the importance of hydro generation in the country, the ONS sometimes reduces dispatch of hydro facilities and increases dispatch of thermal facilities to protect reservoir levels in the system.

In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels. A mechanism known as the Energy Reallocation Mechanism ("MRE") was created to share hydrological risk across MRE hydro generators. If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may need to purchase energy in the short-term market to fulfill their contract obligations. When total hydro generation is higher than the total MRE physical guarantee, the surplus is proportionally shared among its participants and they are able to make extra revenue selling the excess energy on the spot market. The consequences of unfavorable hydrology are (i) thermal plants more expensive to the system being dispatched, (ii) lower hydropower generation with deficits in the MRE and (iii) high spot prices. ANEEL defines the spot price cap for electricity in the Brazilian market. The spot price caps as defined by ANEEL and average spot prices by calendar year are as follows (R$/MWh):



Year	2017	2016	2015	2014
Spot price cap as defined by ANEEL	534	423	388	822
Average spot rate		94	287	689

Key Financial Drivers — As the system is highly dependent on hydroelectric generation, Tietê and Uruguaiana are are affected by the hydrology in the overall sector. They are also affected by the availability of Tietê's plants and reliability of the Uruguaiana facility. The availability of gas is also a driver for continued operations at Uruguaiana. Tietê's financial results are likely to be driven by many factors including, but not limited to:


•	Hydrology, 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

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 3,239 MW and distribution networks serving 1.4 million customers as of December 31, 2016.

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)
Andres	Dominican Republic	Gas	319	90	%	2003	2018	Ede Este/Non-Regulated Users/Linea Clave
Itabo ⁽¹⁾	Dominican Republic	Coal/Gas	295	45	%	2000	2017	Ede Este/Ede Sur/Ede Norte
DPP (Los Mina)	Dominican Republic	Gas	236	90	%	1996	2022	CDEEE
Dominican Republic Subtotal			850
AES Nejapa	El Salvador	Landfill Gas	6	100	%	2011	2035	CAESS
Moncagua	El Salvador	Solar	3	100	%	2015	2035	EEO
El Salvador Subtotal			9
Merida III	Mexico	Gas	505	55	%	2000	2025	Comision Federal de Electricidad
Termoelectrica del Golfo (TEG)	Mexico	Pet Coke	275	99	%	2007	2027	CEMEX
Termoelectrica del Penoles (TEP)	Mexico	Pet Coke	275	99	%	2007	2027	Penoles
Mexico Subtotal			1,055
Bayano	Panama	Hydro	260	49	%	1999	2030	Electra Noreste/Edemet/Edechi/Other
Changuinola	Panama	Hydro	223	90	%	2011	2030	AES Panama
Chiriqui-Esti	Panama	Hydro	120	49	%	2003	2030	Electra Noreste/Edemet/Edechi/Other
Estrella de Mar I	Panama	Heavy Fuel Oil	72	49	%	2015	2020	Electra Noreste/Edemet/Edechi/Other
Chiriqui-Los Valles	Panama	Hydro	54	49	%	1999	2030	Electra Noreste/Edemet/Edechi/Other
Chiriqui-La Estrella	Panama	Hydro	48	49	%	1999	2030	Electra Noreste/Edemet/Edechi/Other
Panama Subtotal			777
Puerto Rico	US-PR	Coal	524	100	%	2002	2027	Puerto Rico Electric Power Authority
Illumina	US-PR	Solar	24	100	%	2012	2032	Puerto Rico Electric Power Authority
Puerto Rico Subtotal			548
			3,239

_____________________________


⁽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

DPP (Los Mina) Conversion

Dominican Republic

Gas

122

1H 2017

Dominican ES

Dominican Republic

Energy Storage

1H 2017

Dominican Republic Subtotal

142

Colón

Panama

Gas

380

1H 2018

Panama Subtotal

380

522

Utilities — Our distribution businesses are located in El Salvador and distribute power to 1.4 million people in the country. These businesses consist of four companies, each of which operates in defined service areas. The following table lists our MCAC utilities:



Business	Location	Approximate Number of Customers Served as of 12/31/2016	GWh Sold in 2016	AES Equity Interest		Year Acquired or Began Operation
CAESS	El Salvador	590,971	2,232	75	%	2000
CLESA	El Salvador	388,341	894	80	%	1998
DEUSEM	El Salvador	78,063	133	74	%	2000
EEO	El Salvador	298,026	576	89	%	2000
		1,355,401	3,835

The following map illustrates the location of our MCAC facilities:

MCAC Businesses

MCAC Utilities

El Salvador

Business Description — AES is the majority owner of four of the five distribution companies operating in El Salvador. The distribution companies are operated by AES on an integrated basis under a single management team. AES El Salvador's territory covers 77% of the country. AES El Salvador accounted for 4,151 GWh of market energy purchases during 2016, or about 63% market share of the country's total energy purchases.

MCAC Generation

Dominican Republic

Business Description — AES Dominicana consists of three operating subsidiaries, Itabo, Andres and DPP. AES has 24% of the system capacity of 850 MW and supplies approximately 37% of energy demand through these generation facilities. AES has a strategic partnership with the Estrella and Linda Groups ("Estrella-Linda"), an investor group based in the Dominican Republic. Estrella-Linda is a consortium of two leading Dominican industrial groups: Estrella and Grupo Linda. The two partners manage a diversified business portfolio, including construction services, cement, agribusiness, metalwork, plastics, textiles, paints, transportation, insurance and media.

Itabo is 45% owned by AES, 5% by Estrella-Linda, 49.97% owned by FONPER, a government-owned utility and the remaining 0.03% is owned by employees. 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 and thus two new short term contracts with Ede Sur and Ede Este were signed until new long term contracts take place. The Dominican Corporation of State Electrical Companies is sponsoring a bidding process, released in

August 2016, which is expected to be awarded in April 2017 in order to secure supply and competitive pricing for actual and future distribution energy requirements. The existing business strategy is to secure between 80% and 85% of the open position through new PPAs with distribution companies and large users. Price and PPA structure will be subject to the terms of the bidding process.

Andres and DPP are owned 90% by AES and 10% by Estrella-Linda. Andres has a combined cycle gas turbine and generation capacity of 319 MW as well as the only LNG import facility in the country, with 160,000 cubic meters of storage capacity. DPP (Los Mina) has two open cycle natural gas turbines and generation capacity of 236 MW. Both Andres and DPP have in aggregate 555 MW of installed capacity, of which 450 MW is mostly contracted until 2018 with government-owned distribution companies and large customers.

AES Dominicana has a long-term LNG purchase contract through 2023 for 33.6 trillion btu/year with a price linked to NYMEX Henry Hub. The LNG contract terms allow the diversion of the cargoes to various markets in Latin America. These plants capitalize on the competitively-priced LNG contract by selling power where the market is dominated by fuel oil-based generation. 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.

Market Structure - Electricity and Natural Gas — The Dominican Republic has one main interconnected system with approximately 3,553 MW of installed capacity, composed primarily of thermal generation (80%), hydroelectric power plants (17%) and wind plants (3%).

Regulatory Framework — The regulatory framework in the Dominican Republic consists of a decentralized industry including generation, transmission and distribution, where generation companies can earn revenue through short- and long-term PPAs, ancillary services and a competitive wholesale generation market. All electric companies (generators, transmission and distributors), are subject to and regulated by the General Electricity Law.

Two main agencies are responsible for monitoring and ensuring compliance with the General Electricity Law, the National Energy Commission and the Superintendence of Electricity. The National Energy Commission is in charge of drafting and coordinating the legal framework and regulatory legislation, proposing and adopting policies and procedures to assure best practices, drafting plans to ensure the proper functioning and development of the energy sector and promoting investment. The Superintendence of Electricity's main responsibilities include monitoring and supervising compliance with legal provisions and rules, monitoring compliance with the technical procedures governing generation, transmission, distribution and commercialization of electricity and supervising electric market behavior in order to avoid monopolistic practices.

The electricity tariff applicable to regulated customers is subject to regulation within the concessions of the distribution companies. Clients with demand above 1 MW are classified as unregulated customers and their tariffs are unregulated.

Fuels and hydrocarbons are regulated by a specific law which establishes prices to end customers and a tax on consumption of fossil fuels. For natural gas there are regulations related to the procedures to be followed to grant licenses and concessions: i) distribution, including loading, transportation and compression plants; ii) the installation and operation of natural gas stations, including consumers and potential modifications of existing facilities; and iii) conversion equipment suppliers for vehicles. The regulation is administered by the Industrial and Commerce Ministry who supervises commercial and industrial activities in the Dominican Republic as well as the fuels and natural gas commercialization to the end users.

Key Financial Drivers — Financial results are likely to be 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.

In addition, the financial weakness of the three state-owned distribution companies due to low collection rates and high levels of non-technical losses has led to delays in payments for the electricity supplied by generators. At times when outstanding receivable balances have accumulated, AES Dominicana has accepted payment through other means, such as government bonds, in order to reduce the balance. There can be no guarantee that alternative collection methodologies will always be an avenue available for payment options.

Construction and Development — DPP is converting its existing plant from open cycle to combined cycle. The project will recycle DPP's heat emissions and increase total power output by approximately 114 MW of gross capacity at an estimated cost of $260 million, fully financed with non-recourse debt. The EPC contract was signed on July 2, 2014, and the additional capacity is expected to become operational in the first half of 2017. Based on the increased capacity, AES Dominicana executed a PPA for 270 MW for a 6.5 year term beginning in 2017.

Panama

Business Description — AES owns and operates five hydroelectric plants and one thermoelectric power plant, Estrella del Mar I, which commenced operations in March 2015, representing 705 MW and 72 MW of hydro and thermal capacity respectively, for a total of 777 MW equivalent to 23% of the installed capacity in Panama. The majority of hydro sources in Panama are based on run-of-river technology, with the exception of the 260 MW Bayano plant.

A portion of the PPAs with distribution companies will expire in December 2018 reducing the total contracted capacity of the company from 496 MW to 430 MW. Another portion contracted through Estrella del Mar I will expire in June 2020, reducing the total contracted capacity to 350 MW until December 2030.

Market Structure — Panama's current total installed capacity is 3,350 MW, of which 52% is hydroelectric, 8% wind, 2% solar and the remaining 38% thermal generation from diesel, bunker fuel and coal.

The Panamanian power sector is composed of three distinct operating business units: generation, distribution and transmission, all of which are governed by Electric Law 6 enacted in 1997.

Generators can enter into long-term PPAs with distributors or unregulated consumers. In addition, generators can enter into alternative supply contracts with each other. Outside of the PPA market, generators may buy and sell energy in the short-term market.

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, taking into account the price of water, which determines the dispatch of hydro plants with reservoirs. Short-term power prices are determined on an hourly basis by the last dispatched generating unit.

In Panama, dry hydrological conditions remained until June 2016, due to the presence of the El Niño phenomenon, affecting the generation output from hydroelectric facilities compared to the prior year. AES Panama had to purchase energy on the spot market to fulfill its contract obligations as its generation output was below contract levels. The drop in the commodities prices helped to reduce the replacement cost and the financial impact of spot purchases compared to the prior year. Despite the hydrology conditions, spot prices were down to $60/MWh from $91/MWh in 2015, limiting the amount recognized through the 2014-2016 Government Compensation Agreement to $1 million out of the possible $30 million for 2016. On March 31, 2014, the government of Panama agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70 MW reduction in contracted capacity for the period 2014-2016 by compensating AES Panama for spot purchases above the contracted price of $82.45/MWh, up to $40 million in 2014, $30 million in 2015 and $30 million in 2016.

Regulatory Framework — The SNE has the responsibilities of planning, supervising and controlling policies of the energy sector within Panama. With these responsibilities, the SNE proposes laws and regulations to the executive agencies that promote the procurement of electrical energy, hydrocarbons and alternative energy for the country.

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

Generators can only contract up to their firm capacity. Physical generation of energy is determined by the National Dispatch Center regardless of contractual arrangements.

Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to:


•	In the event of low hydrology, high commodity prices will increase the business exposure and the cost of replacement power to fulfill our contractual commitments, partially mitigated by additional generation from Estrella del Mar I.


•	Fluctuations in commodity prices, mainly oil prices, affect the thermal generation cost impacting the spot prices and the opportunity cost of water.


•	Constraints imposed by the capacity of the transmission line connecting the west side of the country with the load center are expected to continue until the end of 2017 keeping surplus power trapped, particularly during the wet season.


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

Given that most of AES' portfolio is run-of-river, hydrological conditions have an important influence on its profitability. Variations in actual hydrology can result in excess or a short energy balance relative to our contract obligations. During the low inflow period of January through May, generation tends to be lower and AES Panama may purchase energy in the short-term market to cover contractual obligations. During the remainder of the year (June to December), generation tends to be higher and energy generated in excess of contract volumes is sold to the short-term market. In addition to hydrological conditions, commodity prices affect short-term electricity prices.

Construction and Development — Continuing with the strategy to reduce reliance on hydrology started with the acquisition of the power barge, Estrella del Mar I, in August 2015 AES executed a partnership agreement with Deeplight Corporation, a minority partner, with the purpose to construct, operate and maintain a natural gas power generation plant and a liquefied natural gas terminal, in order to purchase and sell energy and capacity as well as commercialize natural gas and other ancillary activities related to natural gas. As of December 31, 2016, amounts capitalized include $254 million recorded in Construction in Progress and the project is scheduled to initiate operations in the first half of 2018.

Mexico

Business Description — AES has 1,055 MW of installed capacity in Mexico, including the 550 MW Termoeléctrica del Golfo ("TEG") and Termoeléctrica Peñoles ("TEP") facilities and Merida III ("Merida"), a 505 MW generation facility.

The TEG and TEP pet coke-fired plants, located in San Luis Potosi, supply power to their offtakers under long-term PPAs expiring in 2027 with a 90% availability guarantee. TEG and TEP secure their fuel under a long-term contract.

Merida is a CCGT, located in Merida, on Mexico's Yucatan Peninsula. Merida sells power to the Federal Commission of Electricity ("CFE") under a capacity and energy based long-term PPA through 2025. Additionally, the plant purchases natural gas and diesel fuel under a long-term contract, the cost of which is then passed through to CFE under the terms of the PPA.

In line with AES' strategy of building strategic partnerships, on January 18, 2016 the 50/50 joint venture partnership agreement with Grupo BAL was fully executed. The joint venture will co-invest in power and related infrastructure projects in Mexico.

Market Structure — Mexico has a single national electricity grid, the National Power System, covering nearly all of Mexico's territory. Mexico has an installed capacity totaling 68 GW with a generation mix of 72% thermal, 18% hydroelectric and 10% other. Electricity consumption is split between the following end users: industrial of 58%, residential of 26% and commercial and service of 16%.

Regulatory Framework — Following the constitutional changes approved in December 2013, during 2014 and 2015 the Mexican government issued a package of secondary regulations, including the Electricity Law, and operational dispositions, with the objective to start the implementation of a new regulatory framework with the following characteristics:


•	The energy market liberalization in January 2016 through the implementation of: wholesale electricity market (day ahead and real time market), ancillary services, capacity, Clean Energy Certificates, and Financial Transmission Rights market.


•	CFE's, former state-owned electric monopoly, vertical and horizontal disintegration into different segments of the value chain: generation, transmission, distribution and commercialization.


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


•	Implementation of annual mid and long term auctions to secure supply for the regulated demand, establishing a PPA with CFE as the Basic Supplier.

According to the new regulatory framework, new assets developed under the new framework or assets transferred to the new regime and in operation after the approval of the Electricity Law (August 2014) are eligible to participate in the new markets. Additionally, projects developed and operated under the Electric Public Service Law

(self-supply framework) like TEG/TEP, could choose to participate. Until the new framework is further analyzed, AES will continue operating under the same conditions. Merida III and TEG/TEP will continue providing power under long-term contracts and selling any excess or surplus energy produced to CFE.

Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to:


•	Operational performance (as the companies are fully contracted and better performance provides additional financial benefits including performance incentives and/or excess energy sales (in the case of TEG/TEP).


•	The energy prices of TEG/TEP for the sales in excess over its long-term contracts are driven by the average production cost of CFE which is highly dependent on natural gas and oil.


•	If the average production cost of CFE is higher than the cost of generating with pet coke, our businesses in Mexico will benefit provided that they are able to sell energy in excess of their PPAs.

Puerto Rico

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, 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. See Item 7.—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for further discussion of the long-term PPA with PREPA.

El Salvador

Business Description — AES El Salvador also owns AES Nejapa, a 6 MW power plant generating electricity with methane gas from a landfill, fully contracted with CAESS. During 2015, AES El Salvador began operations of a AES Moncagua, a 2.5 MW solar facility located in the East of the country, which is fully contracted with EEO.

The sector is governed by the General Electricity Law and the general and specific orders are issued by Superintendencia General de Electricidad y Telecomunicacions ("SIGET"). SIGET, jointly with the distribution companies in El Salvador, completed the tariff reset process in December 2012 and defined the tariff calculation to be applicable for the five year period 2013-2017.

Europe SBU

Generation — Our Europe SBU has generation facilities in five countries. Operating installed capacity of our Europe SBU totaled 6,619 MW. The following table lists our Europe SBU generation facilities:



Business	Location	Fuel	Gross MW	AES Equity Interest		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
Maritza	Bulgaria	Coal	690	100	%	2011	2026	Natsionalna Elektricheska
St. Nikola	Bulgaria	Wind	156	89	%	2010	2025	Natsionalna Elektricheska
Bulgaria Subtotal			846
Amman East	Jordan	Gas	381	37	%	2009	2033-2034	National Electric Power Company
IPP4	Jordan	Heavy Fuel Oil/Gas	250	36	%	2014	2039	National Electric Power Company
Jordan Subtotal			631
Ust-Kamenogorsk CHP	Kazakhstan	Coal	1,398	100	%	1997	Short-term	Various
Shulbinsk HPP ⁽¹⁾	Kazakhstan	Hydro	702	—	%	1997	2020	Titanium Magnesium Kombiant
Sogrinsk CHP	Kazakhstan	Coal	345	100	%	1997	Short-term	Various
Ust-Kamenogorsk HPP ⁽¹⁾	Kazakhstan	Hydro	331	—	%	1997	2020	Titanium Magnesium Kombiant
Kazakhstan Subtotal			2,776
Elsta ⁽²⁾	Netherlands	Gas	630	50	%	1998	2018	Dow Benelux/Delta/Nutsbedrijven/Essent Energy
Netherlands ES	Netherlands	Energy Storage	10	100	%	2015
Netherlands Subtotal			640
Ballylumford	United Kingdom	Gas	1,015	100	%	2010	2023	Power NI/Single Electricity Market (SEM)
Kilroot ⁽³⁾	United Kingdom	Coal/Oil	701	99	%	1992		SEM
Kilroot ES	United Kingdom	Energy Storage	10	100	%	2015
United Kingdom Subtotal			1,726
			6,619

_____________________________


⁽¹⁾	AES operates these facilities under concession agreements until 2017.


⁽²⁾	Unconsolidated entity, the results of operations of which are reflected in Equity in Earnings of Affiliates.


⁽³⁾	Includes Kilroot Open Cycle Gas Turbine ("OCGT").

The following map illustrates the location of our Europe facilities:

Europe Businesses

Bulgaria

Business Description — Our Maritza plant is a 690 MW lignite fuel plant that was commissioned in June 2011. Maritza is fully compliant with the European Union Industrial Emission Directive, which became effective in January 2016. Maritza's entire power output is contracted with NEK under a 15-year PPA, capacity and energy based, with a fuel pass-though, expiring in 2026. The lignite and limestone are supplied under 15-year fuel supply contracts.

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.

Market Structure — The maximum market capacity in 2016 was approximately 13 GW. Thermal generation, which is mostly coal-fired, and nuclear power plants account for 61% of the installed capacity.

Regulatory Framework — The electricity sector in Bulgaria operates under the Energy Act of 2004 which allows the sale of electricity to take place freely at negotiated prices, at regulated prices between parties or on the organized market. In 2016 the government of Bulgaria made advances toward market liberalization and has engaged with the World Bank to develop a model for a fully liberalized electricity market in Bulgaria. The final report with recommendations from the World Bank was finalized in December 2016. The Independent Bulgarian Energy Exchange (IBEX) started commercial operation of the power exchange in January 2016 with the introduction of Day Ahead market platform. In September 2016, IBEX expanded its trading platform for bilateral forward contracts. The next step of the development of IBEX is the introduction of intra-day trading, which is expected in mid-2017.

Our investments in Bulgaria rely on long-term PPAs with NEK, the state-owned electricity public supplier and energy trading company. NEK had been facing some liquidity issues and had been delayed in making payments under the PPAs with Maritza and St. Nikola. In August 2015, the ninth amendment of Maritza's PPA was executed, under which Maritza and NEK agreed to reduce the capacity payment to Maritza by 14% through the PPA term without impacting the energy price component. In exchange, NEK paid Maritza its overdue receivables. The amendment became effective in April 2016 upon full payment of the overdue receivables by NEK. Maritza has experienced timely collection of outstanding receivables from NEK since May 2016.

The Directorate-General for Competition of the European Commission (“DG Comp”) continues to review NEK’s respective PPAs with Maritza and an unrelated generator pursuant to the European Commission’s state aid rules. Although no formal investigation has been launched by DG Comp, Maritza has met with the DG Comp case team and representatives of Bulgaria to discuss the agency’s review. Maritza expects that the parties will engage in

further discussions on the issues surrounding the review. At this time, we cannot predict the outcome of such discussions, nor can we predict how DG Comp might resolve its review if the anticipated discussions fail to result in an agreement concerning the review. Maritza believes that its PPA is legal and in compliance with all applicable laws, and it will take all actions necessary to protect its interests, whether through negotiated agreement or otherwise. However, there can be no assurances that this matter will be resolved favorably; if it is not, there could be a material adverse impact on Maritza’s and the Company’s respective financial statements.

In 2015, a number of measures were introduced to the regulation of the energy sector that significantly improved the liquidity of NEK. As a result, NEK is forecast to end the year 2016 with a $7 million net profit, more than a $102 million improvement over year 2015 and more than a $316 million improvement over year 2014. However, the financial situation of NEK remains subject to political conditions and regulatory changes in Bulgaria.

Key Financial Drivers — Both businesses, Maritza and St. Nikola, operate under PPA contracts. For the duration of the PPA, the financial results are primarily driven by, but not limited to:


•	the availability of the operating units


•	the level of wind resource for St. Nikola


•	NEK's ability to meet the terms of the PPA contract

United Kingdom

Business Description — AES' generation businesses in the United Kingdom are located in Northern Ireland and operate in the Irish SEM (1,726 MW). The Northern Ireland generation facilities consist of two plants within the Greater Belfast region. Our Kilroot plant is a 701 MW coal-fired plant with an additional 10 MW of energy storage facility and our Ballylumford plant is a 1,015 MW gas-fired plant. These plants provide approximately 62% of the Northern Ireland installed capacity and 16% of the combined installed capacity for the island of Ireland.

Kilroot is a merchant plant that bids into the SEM. the plant earns margin when scheduled in merit, out of merit, for capacity payments, and for ancillary services. Out of merit dispatch, through which costs are recovered, occurs when there are system constraints related to wind generation, voltage and transmission.

Ballylumford is partially contracted for 600 MW under a PPA with PPB that expires in 2023 with the remaining capacity bid into the SEM market. 310 MW of this merchant capacity has a supplemental Local Reserve Services Agreement ("LRSA") with the system operator. Ballylumford earns margin from availability payments received under the PPA, capacity payments offered through the SEM and revenues from the LRSA. Additionally, Ballylumford receives margin from out of merit dispatch through which the costs of operation are recovered as well as ancillary services.

Market Structure — The majority of the generation capacity in the SEM is represented by gas-fired power plants, which results in market sensitivity to gas prices. Wind generation capacity represents approximately 25% of the total generation capacity. The governments of Northern Ireland and the Republic of Ireland plan further increases in renewable energy sources. Market availability and liquidity of hedging products are weak, reflecting the limited size and immaturity of the market, the predominance of vertical integration and lack of forward pricing. There are essentially three products (baseload, mid-merit and peaking) which are traded between the generators and suppliers.

Regulatory Framework — The SEM is an energy market established in 2007 and is based on a gross mandatory pool within which all generators with a capacity higher than 10 MW must trade the physical delivery of power. Generators are centrally dispatched based on merit order and physical constraints of the system. The SEM structure is under review by the regulatory authorities with a new structure due to be introduced in the second quarter of 2018.

In addition, there is 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 declared availability of a unit and have a degree of volatility to reflect seasonal influences, demand and the actual out-turn of generation declared available over each trading period.

Environmental Regulation — In 2011, the European Commission adopted the Industrial Emission Directive ("IED") that establishes the Emission Limit Values ("ELV") for SO₂, NO_x and dust emissions effective January 1, 2016. Both Ballylumford and Kilroot are required to comply with the IED. The Ballylumford C Station is compliant without the need for investment. Both Ballylumford B Station and Kilroot required investment to be in compliance.

The IED provides for two options that may be implemented by the European Union member states other than compliance with the new ELV's the Transitional National Plan or Limited Life Time Derogation.

Kilroot has opted into the Transitional National Plan which allows the plant to operate between 2016-2020, being exempt from compliance with ELVs, but observing a ceiling set for maximum annual emissions that is based on the last 10 years average emissions and operating hours. Kilroot has invested approximately $10 million in Umbrella Selective Non Catalytic Reduction technology, which reduces the plant's NO_x emissions enabling the plant to increase its capacity factor within the ceiling of NO_x emissions and earn energy margin. The Transitional National Plan also established a UK wide NO_x trading scheme which Kilroot avails of as required. Further technical modifications are being evaluated which could make the plant fully compliant with the IED from 2020.

Without investment, the Ballylumford B station of 540 MW did not meet the standards of the IED. In 2014, AES secured a LRSA with the Transmission System Operator ("TSO") to refurbish two of the three units to be compliant with ELVs under IED, providing at least 250 MW of capacity from 2016 to 2018 with an option to extend to 2020 by the TSO. The project was executed in 2015 with an achieved combined gross output of 310 MW.

Key Financial Drivers — For our businesses in the SEM market, the financial results will be driven by, but not limited to, the following:


•	Regulatory changes to the market structure and payment mechanism


•	Availability of the operating units


•	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

Business Description — Our businesses account for approximately 6% of the total annual generation in Kazakhstan. Of the total capacity of 2,776 MW, 1,033 MW is hydroelectric and operates under a concession agreement until the beginning of October 2017 and 1,743 MW is coal-fired capacity which is owned outright. The thermal plants are designed to produce heat with electricity as a co- or by-product.

The Kazakhstan businesses act as merchant plants for electricity sales by entering into bilateral contracts directly with consumers for periods of generally no more than one year. There are limited opportunities for the plants to be in contracted status, as there is no central offtaker, and the few businesses that could take a whole plant's generation tend to have in-house generation capacity.

The hydroelectric plants are run-of-river and rely on river flow and precipitation, particularly snow. Due to the presence of a large multi-year storage dam upstream and a season minimum river flow rate agreement with Russia downstream, the plants are protected against significant downside risk to their volume in years with low precipitation. AES does not control water flow which impacts our generation.

Ust Kamenogorsk CHP provides heat to the city of Ust Kamenogorsk through the city heat network company (Ust Kamenogorsk Heat Nets). Ust Kamenogorsk CHP is their only source of supply.

Market Structure — The Kazakhstan electricity market totals approximately 21,307 MW, of which 17,504 MW is available. The bulk of the generating capacity in Kazakhstan is thermal with coal as the main fuel. As coal is abundantly available in Kazakhstan, most plants are designed to burn local coal. The geographical remoteness of Kazakhstan, in combination with its abundant resources, results in coal prices that are not reflective of world coal prices, current delivered cost is less than $12 per metric ton. In addition, the government closely monitors coal prices, due to their impact on the price of socially necessary heating and on electricity tariffs.

Regulatory Framework — All Kazakhstan generating companies sell electricity at or below their respective tariff-cap level. These tariff-cap levels have been fixed by the Kazakhstan government for the period 2009-2018 for each of the fifteen groups of generators. These groups were determined by the Ministry of Energy, based on a number of factors including plant type and fuel used.

In July 2012, Kazakhstan enacted an amendment to its Electricity Law requiring electricity producers to reinvest all profits generated during the years 2013-2015 as part of annual investment obligation agreements, thereby limiting the businesses ability to distribute dividends. These investment obligation agreements had to be equal to the sum of the planned annual depreciation and profit. Selection of investment projects was at the discretion of electricity producers, but the Ministry of Energy had the right to reject submitted proposals. An electricity producer without an investment obligation agreement executed by the Ministry of Energy was not allowed to charge tariffs exceeding its incremental cost of production, excluding depreciation.

In November 2015, Kazakhstan enacted amendments to its Electricity Law to eliminate the obligation for power plants to sign annual investment obligation agreements for 2016-2018, thereby allowing the businesses to distribute dividends. In addition, the amendment stated that a centrally organized capacity market will be established by 2019 and that the Kazakhstan government plans to prolong price cap regulation by fixing new caps on energy and capacity tariffs for each group of power plants.

Kazakhstan government has approved a renewable energy law which set feed-in tariffs for renewable energy and set a renewable energy target of 3% by 2020 and 10% by 2030. This renewable energy law imposes an obligation on all non-renewable power plants to purchase renewable energy at the renewable energy tariff and resell it to customers at their own, lower price cap level.

Heat production in Kazakhstan is also regulated as a natural monopoly. The heat tariffs are set on a cost-plus basis by making an application to the Committee of Natural Monopoly Regulation and Competition Protection, the regulator. Currently, tariffs are only for multi-year periods, but with some annual adjustments for fuel cost.

Key Financial Drivers — The financial results for assets in Kazakhstan are driven by many factors including, but not limited to:


•	Availability of the operating units;


•	Regulated electricity tariff-cap levels and heat tariff levels


•	Weather conditions,


•	Regulatory changes to the market structure and payment mechanism


•	Cost of coal and Kazakhstan currency exchange rate fluctuation.

Jordan

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 and a 36% controlling interest in the IPP4 plant in Jordan, a 250 MW oil/gas-fired peaker plant which commenced operations in July 2014, fully contracted with the national utility under a 25-year PPA. As we have controlling interest in these businesses, we consolidate the results in our operations.

Asia SBU

Generation — Our Asia SBU has generation facilities in three countries. Operating installed capacity totals 2,300 MW. The following table lists our Asia SBU generation facilities:



Business	Location	Fuel	Gross MW	AES Equity Interest		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
OPGC ⁽¹⁾	India	Coal	420	49	%	1998	2026	GRID Corporation Ltd.
India Subtotal			420
Masinloc	Philippines	Coal	630	51	%	2008	Mid and long-term	Various
Masinloc ES	Philippines	Energy Storage	10	51	%	2016
Philippines Subtotal			640
Mong Duong 2	Vietnam	Coal	1,240	51	%	2015	2040	EVN
Vietnam Subtotal			1,240
			2,300

_____________________________


⁽¹⁾	Unconsolidated entity for which the results of operations are reflected in Equity in Earnings of Affiliates.

Under construction