Edgar Filing: AES CORP

10-K

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, 2015

-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 o No x

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, 2015, the last business day of the Registrant's most recently completed second fiscal quarter (based on the adjusted closing sale price of $12.88 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $8.79 billion.

The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, on February 18, 2016 was 659,733,335

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant's Proxy Statement for its 2016 annual meeting of stockholders are incorporated by reference in Parts II and III

THE AES CORPORATION FISCAL YEAR 2015 FORM 10-K

TABLE OF CONTENTS



Glossary of Terms	1
PART I	4
ITEM 1. BUSINESS	5
ITEM 1A. RISK FACTORS	55
ITEM 1B. UNRESOLVED STAFF COMMENTS	70
ITEM 2. PROPERTIES	70
ITEM 3. LEGAL PROCEEDINGS	70
ITEM 4. MINE SAFETY DISCLOSURES	75
PART II	76
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	76
ITEM 6. SELECTED FINANCIAL DATA	77
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	78
Overview of 2015 Results and Strategic Performance	78
Review of Consolidated Results of Operations	80
SBU Performance Analysis	85
Key Trends and Uncertainties	96
Capital Resources and Liquidity	99
Critical Accounting Policies and Estimates	113
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	116
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	120
Consolidated Balance Sheets	121
Consolidated Statements of Operations	122
Consolidated Statements of Comprehensive Income	123
Consolidated Statements of Changes in Equity	124
Consolidated Statements of Cash Flows	125
Note 1 - General and Summary of Significant Accounting Policies	126
Note 2 - Inventory	136
Note 3 - Property, Plant and Equipment	136
Note 4 - Fair Value	137
Note 5 - Investments in Marketable Securities	141
Note 6 - Derivative Instruments and Hedging Activities	141
Note 7 - Financing Receivables	143
Note 8 - Investments in and Advances to Affiliates	144
Note 9 - Other Non-Operating Expense	146
Note 10 - Goodwill and Other Intangible Assets	147
Note 11 - Regulatory Assets and Liabilities	149
Note 12 - Debt	150
Note 13 - Commitments	153
Note 14 - Contingencies	154
Note 15 - Benefit Plans	155
Note 16 - Equity	158
Note 17 - Segment and Geographic Information	161
Note 18 - Share-Based Compensation	163
Note 19 - Redeemable Stock of Subsidiaries	166
Note 20 - Other Income and Expense	167
Note 21 - Asset Impairment Expense	167
Note 22 - Income Taxes	169
Note 23 - Discontinued Operations	171
Note 24 - Dispositions and Held-For-Sale Businesses	172
Note 25 - Acquisitions	173
Note 26 - Earnings Per Share	173
Note 27 - Risks and Uncertainties	174
Note 28 - Related Party Transactions	176
Note 29 - Selected Quarterly Financial Data (Unaudited)	176
Note 30 - Subsequent Events	177
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	178
ITEM 9A. CONTROLS AND PROCEDURES	178
ITEM 9B. OTHER INFORMATION	179
PART III	180
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	180
ITEM 11. EXECUTIVE COMPENSATION	180
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	180
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE	181
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES	181
PART IV - ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	182
SIGNATURES	185

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
BOT Company	AES-VCM Mong Duong Power Company Limited
BTA	Best Technology Available
CAA	United States Clean Air Act
CAMMESA	Wholesale Electric Market Administrator in Argentina
CCGT	Combined Cycle Gas Turbine
CDEC	Economic Load Dispatch Center
CDI	Brazilian equivalent to LIBOR
CDPQ	La Caisse de depot et placement du Quebec
CDEEE	Dominican Corporation of State Electrical Companies
CEO	Chief Executive Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980 (also known as "Superfund")
CESCO	Central Electricity Supply Company of Orissa Ltd.
CFB	Circulating Fluidized Bed Boiler
CFE	Federal Commission of Electricity
CND	National Dispatch Center
CNE	National Energy Commission
COD	Commercial Operation Date
COFINS	Contribuição para o Financiamento da Seguridade Social
CO₂	Carbon Dioxide
COSO	Committee of Sponsoring Organizations of the Treadway Commission
CP	Capacity Performance
CPCN	Certificate of Public Convenience and Necessity
CPI	United States Consumer Price Index
CRES	Competitive Retail Electric Service
CSAPR	Cross-State Air Pollution Rule
CWA	U.S. Clean Water Act
DG Comp	Directorate-General for Competition of the European Commission
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
DP&L	The Dayton Power & Light Company
DPL	DPL Inc.
DPLE	DPL Energy, LLC, a wholly-owned subsidiary of DPL (renamed AES Ohio Generation, LLC effective 2/1/2016)
DPLER	DPL Energy Resources, Inc.
DPP	Dominican Power Partners
EBITDA	Earnings before Interest, Taxes, Depreciation & Amortization
ECCRA	Environmental Compliance Cost Recovery Adjustment
EGCO Group	Electricity Generating Public Company Limited
ELV	Emission Limit Values
EMIR	European Market Infrastructure Regulation
EOOD	Single person private limited liability company in Bulgaria
EPA	United States Environmental Protection Agency
EPC	Engineering, Procurement, and Construction
EPIRA	Electric Power Industry Reform Act of 2001
ERC	Energy Regulatory Commission
ESO	Electricity System Operator
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
EWG	Exempt Wholesale Generators
FAC	Fuel Adjustment Charges
FASB	Financial Accounting Standards Board
FCA	Federal Court of Appeals
FERC	Federal Energy Regulatory Commission
FONINVEMEM	Fund for the Investment Needed to Increase the Supply of Electricity in the Wholesale Market
FPA	Federal Power Act
FX	Foreign Exchange
G&A	General and Administrative
GAAP	Generally Accepted Accounting Principles in the United States
GEL	General Electricity Law
GHG	Greenhouse Gas
GNPIPD	Gross National Product - Implicit Price Deflator
GSA	Gas Supply Agreement
GWh	Gigawatt Hours
HLBV	Hypothetical Liquidation Book Value
HTA	Heads of Terms Agreement
ICC	International Chamber of Commerce
ICM	Industrial and Commerce Ministry
IDEM	Indiana Department of Environmental Management
IED	Industrial Emission Directive
IFC	International Finance Corporation
IOA	Investment Obligation Agreement
IPALCO	IPALCO Enterprises, Inc.
IPL	Indiana, Indianapolis Power & Light Company
IPP	Independent Power Producers
IRT	Annual Tariff Adjustment in Brazil
ISO	Independent System Operator
IURC	Indiana Utility Regulatory Commission
KPI	Key Performance Indicator
kWh	Kilowatt Hours
LIBOR	London Inter Bank Offered Rate
LNG	Liquefied Natural Gas
MACT	Maximum Achievable Control Technology
MATS	Mercury and Air Toxics Standards
MISO	Midcontinent Independent System Operator, Inc.
MME	Ministry of Mines and Energy
MRE	Energy Reallocation Mechanism
MW	Megawatts
MWh	Megawatt Hours
NCI	Noncontrolling Interest
NCRE	Non-conventional Renewable Energy
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
NSR	New Source Review
NYISO	New York Independent System Operator, Inc.
NYSE	New York Stock Exchange
O&M	Operations and Maintenance
ONS	National System Operator
OPGC	Odisha Power Generation Corporation, Ltd.
Parent Company	The AES Corporation
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
PRP	Potentially Responsible Parties
PSU	Performance Stock Unit
PUCO	The Public Utilities Commission of Ohio
PURPA	Public Utility Regulatory Policies Act
QF	Qualifying Facility
RCOA	Retail Competition & Open Access
RGGI	Regional Greenhouse Gas Initiative
RMRR	Routine Maintenance, Repair and Replacement
ROE	Return on Equity
RPM	Reliability Pricing Model
RSU	Restricted Stock Unit
RTO	Regional Transmission Organization
SADI	Argentine Interconnected System
SAIDI	System Average Interruption Duration Index
SAIFI	System Average Interruption Frequency Index
SBU	Strategic Business Unit
SCE	Southern California Edison
SEC	United States Securities and Exchange Commission
SEM	Single Electricity Market
SEN	National Power System
SEWRC	Bulgaria's State Energy and Water Regulatory Commission
SIC	Central Interconnected Electricity System
SIE	Superintendence of Electricity
SIN	National Interconnected System
SING	Northern Interconnected Electricity System
SIP	State Implementation Plan
SNE	National Secretary of Energy
SO₂	Sulfur Dioxide
SPP	Southwest Power Pool Electric Energy Network
SSO	Standard Service Offer
SSR	Service Stability Rider
TA	Transportation Agreement
TECONS	Term Convertible Preferred Securities
TIPRA	Tax Increase Prevention and Reconciliation Act of 2005
TNP	Transitional National Plan
TSR	Total Shareholder Return
UPME	Mining and Energetic Planning Unit
U.S.	United States
VAT	Value Added Tax
VIE	Variable Interest Entity
Vinacomin	Vietnam National Coal-Mineral Industries Holding Corporation Ltd.
WACC	Weighted Average Cost of Capital
WECC	Western Electric Coordinating Council
WESM	Wholesale Electricity Spot Market

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

Overview

We were incorporated in 1981 and are a diversified power generation and utility company organized into six market-oriented SBUs: US (United States), Andes (Chile, Colombia, and Argentina), Brazil, MCAC (Mexico, Central America and Caribbean), Europe, and Asia.

Item 1.—Business is an outline of our strategy and our businesses by SBU, including key financial drivers. Additional items that may have an impact on our businesses are discussed in Item 1A.—Risk Factors and Item 3.—Legal Proceedings.

Business Lines & SBUs — Within our six SBUs mentioned above, we have two lines of business. The first business line is generation, where we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. The second business line is utilities, where we own and/or operate utilities to generate or purchase, distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market. For each SBU, the following table summarizes our generation and utility businesses by capacity, number of facilities, utility customers and utility GWh sold.



SBU	Business Line	Generation Capacity (Gross MW)		Generation Facilities	Utility Customers	Utility GWh	Utility Businesses
US —	Generation	5,604		18
	Utilities	6,524		16	1.0 million	34,797	2
Andes —	Generation	8,141		33
Brazil —	Generation	3,298		13
	Utilities				8.2 million	56,861	2
MCAC —	Generation	3,239		16
	Utilities				1.3 million	3,754	4
Europe —	Generation	6,781		12
Asia —	Generation	2,290		3
		35,876	⁽¹⁾	111	10.5 million	95,412	8


⁽¹⁾	26,912 proportional MW. Proportional MW is equal to gross MW of a generation facility multiplied by AES' equity ownership percentage in such facility.

Strategy

In September 2011, we implemented a new strategy to maximize value for our shareholders and over the last four years we have made significant progress towards our goals by executing on the following pillars:

•

Reducing Complexity. By exiting businesses and markets where we do not have a competitive advantage, we have simplified our portfolio and reduced risk. Over the past four years, we have sold assets to generate $3.4 billion in equity proceeds for AES, decreasing the total number of countries where we have operations from 28 to 17. We exited Sri Lanka early in 2016, by selling our generation business, Kelanitissa, for $18 million. We exited several of these markets, including Ukraine, Turkey and Africa, at opportune times, as risks for these businesses have increased since the sales, which we believe would have adversely impacted the valuations of such businesses. In 2015, we announced or closed $787 million in asset sales proceeds.

•

Leveraging Our Platforms. We are focusing our growth on platform expansions in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns. We currently have 5,620 MW under construction. These projects represent $7 billion in total capital expenditures, with 85% of AES' $1.2 billion in equity already funded, and we expect the majority of these projects to come on-line through 2018. In 2015, we brought on-line five projects for a total of 1,484 MW. This capacity includes the 1,240 MW coal-fired Mong Duong 2 facility in Vietnam, which we completed six months early and under budget.

•

Performance Excellence. We strive to be a low-cost manager of a portfolio of international energy assets and to derive synergies and scale from our businesses. In 2011, we set a goal to reduce our G&A expenses by $200 million by 2015, and in 2014, we achieved these reductions one year early. We recently launched a $150 million cost reduction and revenue enhancement initiative. This initiative will include overhead reductions, procurement efficiencies and operational improvements. We expect to achieve at least $50 million in savings in 2016, ramping up to $150 million, including modest revenue enhancements, in 2018.

•

Expanding Access to Capital. We have raised $2.5 billion in proceeds to AES by building strategic partnerships at the project and business level. Through these partnerships, we aim to optimize our risk-adjusted returns in our existing businesses and growth projects. By selling down portions of certain businesses, we can adjust our global exposure to commodity, fuel, country and macroeconomic risks. Partial sell-downs of our assets can serve to highlight the value of businesses in our portfolio.

•

Allocating Capital in a Disciplined Manner. Our top priority is to maximize risk-adjusted returns to our shareholders, which we achieve by investing our discretionary cash and recycling the capital we receive from asset sales and strategic partnerships. To that end, since September 2011 we have repurchased $1.5 billion of our shares and benefited from a low interest rate environment, by transacting on $24 billion in debt deals at the Parent and our subsidiaries. These debt transactions represent $14 billion in refinancing and $10 billion in new financing, and we extended the maturities on $3.4 billion in Parent debt.

Note: Investments in subsidiaries excludes $2.3 billion investment in DPL.

Most recently, we increased our quarterly dividend by 10% to $0.11 per share beginning in the first quarter of 2016. This dividend increase reflects our expectation that we will maintain 10% annual growth in our dividend.

Generation

We currently own and/or operate a generation portfolio of 29,352 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, fixed-cost management, sourcing 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 7 years.

In contract sales, our generation businesses recover variable costs including fuel and variable O&M costs, either through direct or indexation-based contractual pass-throughs or tolling arrangements. When the contract does not include a fuel pass-through, we typically hedge fuel costs or enter into fuel supply agreements for a similar contract period (see discussion 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, including debt and return on capital invested. Although our project debt may consist of both fixed and floating rate debt, we typically hedge a significant portion of our exposure to variable interest rates. For foreign exchange, we generally structure the revenue of the business to match the currency of the debt and fixed costs. 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 and Short-Term Sales — Many of the markets in which we operate include regulated capacity markets. These capacity markets are intended to provide additional revenue based upon availability without reliance on the energy margin from the merit order dispatch. Capacity markets are typically priced based on the cost of a new entrant and the system capacity relative to the desired level of reserve margin (generation available in excess of peak demand). Our generating facilities selling in the short-term markets typically receive capacity payments based on their availability in the market. Our most significant capacity revenues are earned by our generation capacity in Ohio and Northern Ireland.

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

Fuel Costs — For our thermal generation plants, fuel is a significant component of our total cost of generation. For contract sales, we often enter into fuel supply agreements to match the contract period, or we may hedge our fuel costs. Some

of our contracts have periodic adjustments for changes in fuel cost indices. In those cases, we have fuel supply agreements with shorter terms to match those adjustments. For certain projects, we have tolling arrangements where the power offtaker is responsible for the supply and cost of fuel to our plants.

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

34% 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 our generation plants are fueled by natural gas. Generally, we use gas from local suppliers in each market. A few exceptions to this are AES Gener in Chile, where we purchase imported gas from third parties, and our plants in the Dominican Republic, where we import LNG to utilize in the local market.

28% of our generation plants are fueled by renewables, including hydro, wind and energy storage, which do not have significant fuel costs.

5% 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 8,145 MW (4,237 proportional MW) of renewable generation, including hydro, wind, energy storage, solar, biomass and landfill gas.

Seasonality, Weather Variations and Economic Activity — Our generation businesses are affected by seasonal weather patterns throughout the year and, therefore, operating margin is not generated evenly by month 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. See Item 7.—Management's Discussion and Analysis—Key Trends and Uncertainties of this Form 10-K for further details of the impact of dry hydrological conditions. In competitive markets for power, local economic activity can also have an impact on power demand and short-term prices for power.

Fixed-Cost Management — In our businesses with long-term contracts, the majority of the fixed operating and maintenance 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' eight utility businesses distribute power to 10.5 million people in three countries. AES' two utilities in the U.S. also include generation capacity totaling 6,524 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.

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 a wheeling and other non-bypassable fees, which are fees to the distribution company for use of its distribution system.

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

Seasonality, Weather Variations and Economic Activity — Our utility businesses are affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses 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, such as 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.

Environmental Matters

We are subject to various international, federal, state, and local regulations in all of our markets. These regulations govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity.

We are also subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, suspension or revocation of permits and/or facility shutdowns. See later in Item 1.—Business—Environmental and Land-Use Regulations for further regulatory and environmental discussion.

SBUs

All SBUs include generation facilities and three include utility businesses. The Company measures the operating performance of its SBUs using Adjusted PTC and Proportional Free Cash Flow, both of which are non-GAAP measures (see definitions below).

AES' primary sources of Revenue, Operating Margin, Adjusted PTC and Proportional Free Cash Flow are from generation and utility businesses. The Adjusted PTC and Proportional Free Cash Flow by SBU for the year ended December 31, 2015 are shown below. The percentages for Adjusted PTC are the contribution by each SBU to the gross metric, i.e., the total Adjusted PTC by SBU, before deductions for Corporate. See Item 8.—Financial Statements and Supplementary Data of this Form 10-K for reconciliation.

In 2015, approximately 80% of Adjusted PTC and Proportional Free Cash Flow was contributed by our businesses in the Americas — including the US, Andes, Brazil and MCAC SBUs.

We define Adjusted PTC as pretax income from continuing operations attributable to AES excluding gains or losses due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt. Adjusted PTC in each SBU includes the effect of intercompany transactions with other SBUs other than interest and charges for certain management services.

We define Proportional Free Cash Flow as cash flows from operating activities excluding capital expenditures related to service concession assets, less maintenance and non-recoverable environmental capital costs, adjusted for the estimated impact of noncontrolling interests. Proportional Free Cash Flow in each SBU includes the effect of intercompany transactions with other SBUs except for interest, tax sharing, charges for management fees and transfer pricing.

Our Organization and Segments

The segment reporting structure uses the Company's management reporting structure as its foundation to reflect how the Company manages the business internally and is organized by geographic regions which provide better socio-political-economic understanding of our business. The management reporting structure is organized along six SBUs — US, Andes, Brazil, MCAC, Europe, and Asia — which are led by our SBU Presidents.

Corporate and Other — For financial reporting purposes, the Company's corporate activities are reported within "Corporate and Other" because they do not require separate disclosure under segment reporting accounting guidance. "Corporate and Other" also includes costs related to corporate overhead which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 17—Segment and Geographic Information included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion of the Company's segment structure (including information on revenue from external customers, Adjusted PTC—a non-GAAP measure, Proportional Free Cash Flow—a non-GAAP measure, and total assets by segment) used for financial reporting purposes.

The following describes our businesses within our six SBUs:

US SBU

Our US SBU has 18 generation facilities and two integrated utilities in the United States. Our U.S. operations accounted for the following proportions of consolidated AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow, and AES Proportional Free Cash Flow (a non-GAAP measure):



US SBU ⁽¹⁾	2015		2014		2013
% of AES Operating Margin	22	%	23	%	21	%
% of AES Adjusted PTC (a non-GAAP measure)	23	%	24	%	24	%
% of AES Operating Cash Flow	34	%	37	%	28	%
% of AES Proportional Free Cash Flow (a non-GAAP measure)	36	%	46	%	37	%

⁽¹⁾ Percentages reflect the contributions by our US SBU before deductions for Corporate.

The following table provides highlights of our US operations:



Generation Capacity		12,128 gross MW (11,260 proportional MW)
Generation Facilities		19 (1 under construction)
Key Generation Businesses		Southland, Hawaii and US Wind
Utilities Penetration		1,002,000 customers (31,112 GWh)
Utility Businesses		2 integrated utilities (includes 18 generation plants, 4 under construction)
Key Utility Businesses		IPL and DPL

Operating installed capacity of our US SBU totals 12,128 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. Presented in the table below is a list of our U.S. generation facilities:



Business	Location	Fuel	Gross MW	AES Equity Ownership (% Rounded)		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
Southland—Alamitos	U.S.-CA	Gas	2,075	100	%	1998	2018	Southern California Edison
Southland—Redondo Beach	U.S.-CA	Gas	1,392	100	%	1998	2018	Southern California Edison
Southland—Huntington Beach	U.S.-CA	Gas	474	100	%	1998	2018	Southern California Edison
Shady Point	U.S.-OK	Coal	360	100	%	1991	2018	Oklahoma Gas & Electric
Buffalo Gap II^(1),(2)	U.S.-TX	Wind	233	100	%	2007	2017	Direct Energy
Hawaii	U.S.-HI	Coal	206	100	%	1992	2022	Hawaiian Electric Co.
Warrior Run	U.S.-MD	Coal	205	100	%	2000	2030	First Energy
Buffalo Gap III⁽¹⁾	U.S.-TX	Wind	170	100	%	2008
Buffalo Gap I⁽¹⁾	U.S.-TX	Wind	121	100	%	2006	2021	Direct Energy
Laurel Mountain	U.S.-WV	Wind	98	100	%	2011
Mountain View I & II⁽¹⁾	U.S.-CA	Wind	67	100	%	2008	2021	Southern California Edison
Distributed PV - Commercial⁽³⁾	U.S.-Various	Solar	56	80%-97%		2009-2015	2029-2041	Utility, Municipality, Education, Non-Profit
Mountain View IV	U.S.-CA	Wind	49	100	%	2012	2032	Southern California Edison
Tehachapi	U.S.-CA	Wind	35	100	%	2006	2016	Southern California Edison
Laurel Mountain ES	U.S.-WV	Energy Storage	32	100	%	2011
Tait ES	U.S.-OH	Energy Storage	20	100	%	2013
Distributed PV - Residential⁽³⁾	U.S.-Various	Solar	9	95	%	2012-2015	2037-2040	Residential
Advancion Applications Center	U.S.-PA	Energy Storage	2	100	%	2013
			5,604


⁽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 12/31/15.

Under construction — The following table lists our plants under construction in the US SBU:

Business

Location

Fuel

Gross MW

AES Equity Interest (% Rounded)

Expected Date of Commercial Operations

IPL MATS ⁽¹⁾

U.S.-IN

Coal

1,713

1H 2016

Eagle Valley CCGT ⁽¹⁾

U.S.-IN

Gas

671

1H 2017

Harding Street Units 5-7 ⁽¹⁾

U.S.-IN

Gas

630

1H 2016

Harding Street ES ⁽¹⁾

U.S.-IN

Energy Storage

1H 2016

Warrior Run ES

U.S.-MD

Energy Storage

100

1H 2016

US Total

3,044

⁽¹⁾

In the first quarter of 2015, La Caisse de depot et placement du Quebec ("CDPQ") invested $247 million for a 15% interest in AES US Investments, Inc. (AES US Investments), a subsidiary of AES that owns IPALCO Enterprises, Inc. ("IPALCO"). In the second quarter of 2015, CDPQ invested an additional $214 million and we expect CDPQ to invest an additional $134 million in IPALCO by 2016. After completion of this investment, CDPQ's direct and indirect interests in IPALCO will total 30%, AES will own 85% of AES US Investments, and AES US Investments will own 82.35% of IPALCO.

Presented below are our U.S. utilities and their generation facilities:



Business	Location	Approximate Number of Customers Served as of 12/31/2015	GWh Sold in 2015	Fuel	Gross MW	AES Equity Interest (% Rounded)		Year Acquired or Began Operation
DPL⁽¹⁾	U.S.-OH	517,000	16,714	Coal/Gas/Oil	3,066	100	%	2011
IPL⁽²⁾	U.S.-IN	485,000	14,398	Coal/Gas/Oil	3,458	75	%	2001
		1,002,000	31,112		6,524

⁽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. DPL Energy, LLC plants: Tait Units 4-7 and Montpelier Units 1-4.

⁽²⁾

In the first quarter of 2015, CDPQ invested $247 million for a 15% interest in AES US Investments, Inc. (AES US Investments), a subsidiary of AES that owns IPALCO. In the second quarter of 2015, CDPQ invested an additional $214 million and we expect CDPQ to invest an additional $134 million in IPALCO by 2016. After completion of this investment, CDPQ's direct and indirect interests in IPALCO will total 30%, AES will own 85% of AES US Investments, and AES US Investments will own 82.35% of IPALCO. IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg.

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 485,000 retail customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL has an exclusive right to provide electric service to those customers. IPL's service area covers about 528 square miles with an estimated population of approximately 934,000. IPL owns and operates four generating stations. Two of the generating stations are primarily coal-fired; however, one of these stations is in the process of being converted to natural gas and will be fully converted in 2016. The third station has a combination of units that use coal (baseload capacity), natural gas and/or oil (peaking capacity) for fuel to produce electricity. The fourth station is a small peaking station that uses gas-fired combustion turbine technology for the production of electricity. IPL's net electric generation capacity for winter is 3,233 MW and net summer capacity is 3,115 MW.

On December 15, 2014, the Company executed an agreement with CDPQ, a long-term institutional investor headquartered in Quebec, Canada. Pursuant to the agreement, CDPQ purchased 15% of AES US Investments, Inc. ("AES US Investments"), a wholly-owned subsidiary of AES that owns 100% of IPALCO, for $247 million. This transaction closed on February 11, 2015. In addition, in April 2015, IPALCO received an equity capital contribution of $214 million from the issuance of 11,818,828 shares of common stock to CDPQ for funding needs primarily related to IPL's environmental construction program, which IPALCO then made the same investment in IPL. After the April investment, CDPQ's direct and indirect ownership interests in IPALCO totaled 25%. CDPQ has committed to approximately $134 million of additional investments in IPALCO through 2016, which will be used primarily to help fund existing environmental and replacement generation projects at IPL. Upon completion of these transactions, CDPQ's direct and indirect interests in IPALCO will total 30%, AES will own 85% of AES US Investments, and AES US Investment will own 82.35% of IPALCO. There will be no change in management or operational control of AES US Investments or IPALCO as a result of these transactions.

Market Structure — IPL is one of many transmission system owner 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 ECCRA. These components function somewhat independently of one another, but the overall structure of IPL's rates and charges would be subject to review at the time of any review of IPL's basic rates and charges. IPL's basic rates and charges were last adjusted in 1996; however, IPL filed a petition with the IURC on December 29, 2014 for authority to increase its basic rates and charges. IPL's proposed rate increase, filed as part of IPL's rebuttal testimony in this proceeding, is $63.3 million, or 5.2%. An order on this proceeding will likely be issued by the IURC early in 2016.

Environmental Matters — MATS — In April 2012, the EPA's rule to establish maximum achievable control technology standards for each hazardous air pollutant regulated under the CAA emitted from coal and oil-fired power plants, known as MATS, became effective. On August 14, 2013, the IURC approved IPL's MATS plan, which includes investing up to $511 million in the installation of new pollution control equipment on IPL's five largest baseload generating units. These coal-fired units are located at IPL's Petersburg and Harding Street generating stations. The IURC also approved IPL's request to recover operating and construction costs for this equipment, including a return, through a rate adjustment mechanism with certain stipulations. Funding for these capital expenditures is expected to be obtained from additional debt financing at IPL; equity contributions; borrowing capacity on IPL's committed credit facilities; and cash generated from operating activities.

Replacement Generation — IPL has several generating units that are expected to retire or refuel by 2017. These units are primarily coal-fired and represent 472 MW of net capacity in total. To replace this generation, IPL filed a petition and case-in-chief with the IURC in April 2013 seeking a CPCN to build a 550 to 725 MW CCGT at its Eagle Valley Station site in Indiana and to refuel Harding Street Station Units 5 and 6 from coal to natural gas (approximately 100 MW net capacity each). In May 2014, IPL received an order on the CPCN from the IURC authorizing the refueling project and granting approval to build a 644 to 685 MW CCGT at a total budget of $649 million. The current estimated cost of these projects is $632 million. IPL requested and was granted authority to accrue post in-service allowance for debt and equity funds used during construction, and to defer the recognition of depreciation expense of the CCGT and refueling project until such time that IPL is allowed to collect both a return and depreciation expense of the CCGT and refueling projects. The CCGT is expected to be placed into service in April 2017, and the refueling project is expected to be completed by early 2016. The costs to build and operate the CCGT and for the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after the assets have been placed in service. In October 2014, IPL filed a petition and case-in-chief with the IURC seeking a CPCN to refuel Harding Street Station Unit 7 from coal to natural gas (about 410 MW net capacity). On July 29, 2015 IPL received approval for this CPCN from the IURC. This conversion is part of IPL's overall wastewater compliance plan for its power plants and is expected to be completed in 2016 (as discussed in Environmental Wastewater Requirements below).

Environmental Wastewater Requirements — In August 2012, the IDEM issued NPDES permits to the IPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. In April 2013, IPL received an extension to the compliance deadline through September 2017 for IPL's Harding Street and Petersburg facilities through agreed orders with IDEM. IPL conducted studies to determine the operational changes and/or control equipment necessary to comply with the new limitations. On October 16, 2014, IPL filed its wastewater compliance plans with the IURC. On July 29, 2015, IPL received approval for a CPCN from the IURC to convert Unit 7 at the Harding Street Station from coal-fired to natural gas-fired, and also to install and operate wastewater treatment technologies at Harding Street Station and Petersburg Generation Station in southern Indiana. IPL plans to invest $326 million in these projects to help ensure compliance with the wastewater treatment requirements by 2017. Recovery of these costs is expected through an Indiana statute which allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next basic rate case proceeding; however, there can be no assurances that IPL would be successful in that regard.

Key Financial Drivers — IPL's financial results are driven primarily by retail demand and rate base growth. Retail demand is influenced by local macroeconomic conditions. In addition, weather, energy efficiency and wholesale prices could also impact financial results. IPL's rate base growth is influenced by the timely recovery of capital expenditures, as well as 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. Please see above for a description of our major construction projects.

DPL Inc. ("DPL")

Business Description — DPL is an energy holding company whose principal subsidiaries include DP&L, DPLE, and DPLER.

DP&L generates, transmits, distributes and sells electricity to approximately 517,000 customers in a 6,000 square mile area of West Central Ohio. DP&L, solely or through jointly owned facilities, owns 2,510 MW of generation capacity and numerous transmission facilities.

DPLE owns peaking generation units representing 556 MW located in Ohio and Indiana.

DPLER, a competitive retail marketer, sells retail electricity to more than 124,000 retail customers in Ohio and Illinois. Approximately 110,000 of these customers are also distribution customers of DP&L in Ohio. On January 1, 2016, DPL closed on the sale of DPLER to Interstate Gas Supply, Inc. (IGS).

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

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

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

The PJM CP auctions are held three years in advance for a period covering 12 months starting from June 1. Auctions for the period covering June 1, 2019 through May 30, 2020 are expected to take place in May 2016. Future auction results are dependent upon various factors including the demand and supply situation, capacity additions and retirements and any changes in the current auction rules related to bidding for demand response and energy efficiency resources in the capacity auctions. For DPL-owned generation, applicable capacity prices through the auction year 2018/19 are as follows:



Auction Year (June 01-May 31)	2018/19	2017/18	2016/17	2015/16	2014/15	2013/14
Capacity Clearing Price ($/MW-Day)	$165	$152	$134	$136	$126	$28

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



Year	2018	2017	2016	2015	2014
Computed Average Capacity Price ($/MW-Day)	$159	$145	$135	$132	$85

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

According to the terms of DP&L's RPM rider, a portion of the capacity revenue is credited to SSO customers primarily based on the load still being served to the SSO customers. However, with the transition to market, no amount will be credited beginning January 1, 2016.

Regulatory Framework — Retail Regulation — DP&L is subject to 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, those to reflect changes in fuel costs to generate electricity or purchased power prices, and the timely recovery of costs incurred to comply with alternative energy, renewables, energy efficiency, and economic development costs. These components function independently of one another, but the overall structure of DP&L's retail rates and charges are subject to the rules and regulations established by the PUCO.

Retail Rate Structure — 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 Electric Security Plan ("ESP") filing. DP&L's wholesale transmission rates are regulated by the FERC. DP&L's distribution rates are regulated by the PUCO and are established through a traditional cost-based rate-setting process. DP&L is permitted to recover its costs of providing distribution service as well as earn a regulated rate of return on assets, determined by the regulator, based on the utility's allowed regulated asset base, capital structure and cost of capital.

The terms and conditions of DP&L's current SSO are provided under the ESP filed in 2012 and approved by the PUCO order dated September 4, 2013 ("2012 ESP"). The 2012 ESP has been in effect since January 2014 and allows DP&L to collect a non-bypassable Service Stability Rider ("SSR") equal to $110 million per year from 2014 - 2016. It allowed for DP&L to recover its PJM-related transmission charges, alternative energy costs, fuel and purchased power costs, and established a SEET ("Significant Excessive Earnings Test") threshold of 12% ROE. It also 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. Beginning January 1, 2016 DP&L's SSO will be 100% sourced through the competitive bid. For calendar years 2012 - 2014, DP&L was subject to a SEET threshold and was required to apply general rules for calculating earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings during a given calendar year. Through the 2012 ESP, the PUCO established DP&L's ROE SEET threshold at 12%. On May 15, 2014, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2013. A stipulation was reached with the PUCO staff agreeing that DP&L did not exceed the SEET threshold for 2014. A hearing was held and the PUCO issued an order approving the SEET stipulation. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows.

On October 30, 2015 DP&L publicly announced its intent to file an application to increase its distribution rates at the PUCO. On November 30, 2015 DP&L filed its distribution rate case using a 12-month test year of June 1, 2015 to May 31, 2016 to measure revenue and expenses and a date certain of September 30, 2015 to measure its asset base. The Company is 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.

On February 22, 2016 DP&L filed an ESP that would be in effect beginning January 1, 2017. As part of this filing, DP&L is seeking a Reliable Electricity Rider for 10 years, based on the variance between the proposed revenue requirement and the actual revenues net of operating costs of the generation units. This plan establishes the terms and conditions for DP&L's Standard Service Offer (SSO) beginning June 1, 2017 to customers that do not choose a competitive retail electric supplier. In its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $10 million of regulatory assets. The plan also proposes a new Distribution Investment Rider 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. There can be no assurance that the ESP will be approved as filed or on a timely basis, and if the ESP is not approved on a timely basis or the final ESP provides for terms that are more adverse than those submitted in DP&L’s application, the Company's consolidated results of operations, financial condition and cash flows could be materially impacted.

Environmental Matters — In relation to MATS, 3,066 MW of DPL's generation capacity is largely compliant with MATS, and DPL does not expect to incur material capital expenditures to ensure compliance with MATS. For more information see Item 1.— United States Environmental and Land-Use Legislation and Regulations.

Key Financial Drivers — Although recent ESP and Generation Separation decisions provide some clarity on the underlying drivers through 2016, challenges remain for DPL beyond 2016 including the potential impacts of retail demand, weather, energy efficiency and wholesale prices on financial results. In addition, through 2016, DPL financial results are likely to be driven by many factors including, but not limited to, the following:


•	PJM capacity prices auctioned already


•	Non-bypassable revenue: $110 million in 2014 and 2015 and allowed to earn $110 million annually in 2016


•	Operational performance of generation facilities

Beyond 2016, DPL financial drivers include many factors, such as the following:


•	PJM capacity prices


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


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


•	DPL's ability to reduce its cost structure

See Item 1A.—Risk Factors for additional discussion on DPL.

Construction and Development — Planned construction additions primarily relate to new investments in and upgrades to DP&L's power plant equipment 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 $439 million in capital projects for the period 2016 through 2018 with 61% attributable to Transmission and Distribution. DPL's ability to complete capital projects and the reliability of future service will be affected by its financial condition, the availability of internal funds and the reasonable cost of external funds. 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 WECC, PJM, SPP and Hawaii. AES Southland, in the WECC, is our most significant generating business.

AES Southland

Business Description — In terms of aggregate installed capacity, AES Southland is one of the largest generation operators in California, with an installed 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 mid-2018. Under the Tolling Agreement, AES Southland's largest revenue driver is unit availability, as approximately 97% of its revenue comes from availability-related payments. Historically, AES Southland has generally met or exceeded its contractual availability requirements under the Tolling Agreement and may capture bonuses for exceeding availability requirements in peak periods.

The offtaker under the Tolling Agreement provides gas to the three facilities at no cost; therefore, AES Southland is not exposed to significant fuel price risk. AES Southland does, however, guarantee the efficiency of each unit so that any fuel consumed in excess of what would have been consumed had the guaranteed efficiency been achieved is paid for by AES Southland. Additionally, if the units operate at an efficiency better than the guaranteed efficiency, AES Southland gets credit for the gas that is not consumed. The business is also exposed to the cost of replacement power for a limited time period if any of the plants are dispatched by the offtaker and are not able to meet the required dispatch schedule for generation of electric energy.

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

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 unmatched operational flexibility, enabling the most

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 finalized in 2016 with construction expected to begin in 2017, 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.

Regulatory Framework — Environmental Matters — For a discussion of environmental regulatory matters affecting U.S. Generation, see Item 1.—United States Environmental and Land-Use Legislation and Regulations.

Key Financial Drivers — AES Southland's contractual availability is 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 and wind generating facilities, of which AES Hawaii and our U.S. wind generation business are the most significant.

Many of our U.S. generation plants provide baseload operations and are required to maintain a guaranteed level of availability. Any change in availability has a direct impact on financial performance. The plants are generally eligible for availability bonuses on an annual basis if they meet certain requirements. In addition to plant availability, fuel cost is a key business driver for some of our facilities.

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

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

US Wind — AES has 773 MW of wind capacity in the U.S., located in California, Texas and West Virginia. In July 2015, AES sold its interest in Armenia Mountain, a wind project located in Pennsylvania with an installed capacity of 101 MW. Typically, these facilities sell under long-term PPAs. AES financed most of these projects with tax equity structures. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in a net loss to AES consolidated results in periods in which the facilities report net income. These non cash net losses will be expected to reverse during the life of the facilities. Some of the wind projects are exposed to the volatility of energy prices and their revenue may change materially as energy prices fluctuate in their respective markets of operations.

Buffalo Gap is located in Texas and is comprised of three wind projects with an aggregate generation capacity of 524 MW. Each wind project operates its own PPA with the exception of Buffalo Gap III whose PPA expired in December 2015. The energy price of the entire production of Buffalo Gap I is guaranteed by a PPA expiring in 2021. The PPA of Buffalo Gap II guarantees the energy price of 80% of the installed capacity while the energy price for the remaining 20% is dictated by the prices in the ERCOT market. The PPA of Buffalo Gap II expires in December 2017. Once the PPAs expire, the entire installed capacity of Buffalo Gap will be exposed to the volatility of energy prices in the ERCOT market which could adversely affect revenues.

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

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

Market Structure — Coal is one of the primary fuels used by our U.S. generation facilities that has international prices set by market factors, although the price of the other primary fuel, 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 EWG 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.

Our businesses are subject to emission regulations, which may result in increased operating costs or the purchase of additional pollution control equipment if emission levels are exceeded. Our businesses periodically review their obligations for compliance with environmental laws, including site restoration and remediation. Because of the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued, if any. For a discussion of environmental laws and regulations affecting the U.S. business, see Item 1.—US 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 US 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

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.

Our Andes operations accounted for the following proportions of consolidated AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow, and AES Proportional Free Cash Flow (a non-GAAP measure):



Andes SBU ⁽¹⁾	2015		2014		2013
% of AES Operating Margin	22	%	19	%	17	%
% of AES Adjusted PTC (a non-GAAP measure)	30	%	23	%	19	%
% of AES Operating Cash Flow	18	%	16	%	11	%
% of AES Proportional Free Cash Flow (a non-GAAP measure)	14	%	13	%	10	%

⁽¹⁾ Percentages reflect the contributions by our Andes SBU before deductions for Corporate.

The following table provides highlights of our Andes operations:



Countries		Chile, Colombia and Argentina
Generation Capacity		8,141 gross MW (6,008 proportional MW)
Generation Facilities		38 (including 5 under construction)
Key Generation Businesses		AES Gener Chile, Chivor and AES Argentina

Operating installed capacity of our Andes SBU totals 8,141 MW, of which 44%, 44% and 12% is located in Argentina, Chile and Colombia, respectively. Presented in the table below is a list of our Andes SBU generation facilities:



Business	Location	Fuel	Gross MW	AES Equity Interest (% Rounded)		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
Chivor	Colombia	Hydro	1,000	67	%	2000	Short-term	Various
Colombia Subtotal			1,000
Electrica Santiago⁽¹⁾	Chile	Gas/Diesel	750	67	%	2000
Gener - SIC⁽²⁾	Chile	Hydro/Coal/Diesel/Biomass	692	67	%	2000	2020-2037	Various
Guacolda⁽³⁾	Chile	Coal/Pet Coke	760	33	%	2000	2017-2032	Various
Electrica Angamos	Chile	Coal	558	67	%	2011	2026-2037	Minera Escondida, Minera Spence, Quebrada Blanca
Gener - SING⁽⁴⁾	Chile	Coal/Pet Coke	277	67	%	2000	2016-2037	Minera Escondida, Codelco, SQM, Quebrada Blanca
Electrica Ventanas⁽⁵⁾	Chile	Coal	272	67	%	2010	2025	Gener
Electrica Campiche⁽⁶⁾	Chile	Coal	272	67	%	2013	2020	Gener
Electrica Angamos ES	Chile	Energy Storage	20	67	%	2011
Gener - Norgener ES (Los Andes)	Chile	Energy Storage	12	67	%	2009
Chile Subtotal			3,613
TermoAndes⁽⁷⁾	Argentina	Gas/Diesel	643	67	%	2000	Short-term	Various
AES Gener Subtotal			5,256
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
Los Caracoles⁽⁸⁾	Argentina	Hydro	125	—	%	2009	2019	Energia Provincial Sociedad del Estado (EPSE)
Cabra Corral	Argentina	Hydro	102	100	%	1995
Ullum	Argentina	Hydro	45	100	%	1996
Sarmiento	Argentina	Gas/Diesel	33	100	%	1996
El Tunal	Argentina	Hydro	10	100	%	1995
Argentina Subtotal			2,885
Andes Total			8,141


⁽¹⁾	Electrica Santiago plants: Nueva Renca, Renca, Los Vientos and Santa Lidia.


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


⁽³⁾	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%.


⁽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 (% Rounded)

Expected Year of Commercial Operations

Cochrane

Chile

Coal

532

2H 2016

Alto Maipo

Chile

Hydro

531

2H 2018/1H 2019

Andes Solar

Chile

Solar

1H 2016

Cochrane ES

Chile

Energy Storage

2H 2016

Chile Subtotal

1,104

Tunjita

Colombia

Hydro

1H 2016

Colombia Subtotal

Andes Total

1,124

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 3,581 MW, excluding energy storage and TermoAndes, and a market share of 17.7% as of December 31, 2015.

AES Gener owns a diversified generation portfolio in Chile in terms of geography, technology, customers and fuel source. AES Gener's installed capacity is located near the principal electricity consumption centers, including Santiago, Valparaiso and Antofagasta. AES Gener's diverse generation portfolio, composed of hydroelectric, coal, gas, diesel and biomass facilities, 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 spot market energy. AES Gener has experienced significant growth in recent years responding to market opportunities with the completion of nine generation projects totaling approximately 1,861 MW, including the 152 MW Unit 5 of Guacolda completed in December 2015, and increasing AES Gener's installed capacity by 55% from 2006 to 2015. Additionally, we are constructing an additional 1,104 MW, comprised of the 21 MW Andes Solar and 20 MW Cochrane Energy Storage in the SING, the 532 MW coal-fired Cochrane plant in the SING and the 531 MW Alto Maipo run-of-the-river hydroelectric plant in the SIC.

In Chile, we align AES Gener's contracts to reduce the risk and improve margins, contracting a significant portion of their baseload capacity, currently coal and hydroelectric, under long-term contracts with a diversified customer base, including both regulated and unregulated customers. AES Gener reserves its higher variable cost units as designated backup facilities, principally the diesel- and gas-fired units in Chile, for sales to the spot market during scarce system supply conditions, such as

dry hydrological conditions and plant outages. In Chile, sales on the spot market are made only to other generation companies that are members of the relevant CDEC at the system marginal cost.

AES Gener currently has long-term contracts, with average terms of 13 to 16 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 CPI, 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 CDEC 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 CNE in the semiannual node price report and indexed to the CPI and other relevant indices.

During November, 2015, AES successfully completed the sale of 4% interest in AES Gener S.A. through its direct shareholder Inversiones Cachagua S.p.A. ("Cachagua") through a private auction. The strategic rationale of this sale was to increase the liquidity of the AES Gener's Share and its exposure on international markets. As a result of this transaction AES now owns 66.7% of AES Gener.

Market Structure — Chile has two main power systems, largely as a result of its geographic shape and size. The SIC is the largest of these systems, with an installed capacity of 15,911 MW as of December 31, 2015. The SIC serves approximately 92% of the Chilean population, including the densely populated Santiago Metropolitan Region, and represents 74% of the country's electricity demand. The SING serves about 6% of the Chilean population, representing 25% of Chile's electricity consumption, and is mostly oriented toward mining companies.

In 2015, thermoelectric generation represented 62% of the total generation in Chile. In the SIC, thermoelectric generation represents 50% of installed capacity, required to fulfill demand not satisfied by hydroelectric output and is critical to guaranteeing reliable and dependable electricity supply under dry hydrological conditions. In the SING, which includes the Atacama Desert, the driest desert in the world, thermoelectric capacity represents 96% of installed capacity. The fuels used for generation, mainly coal, diesel and LNG, are indexed to international prices.

In the SIC, where hydroelectric plants represent a large part of the system's installed capacity, hydrological conditions largely influence plant dispatch and, therefore, spot market prices, given that river flow volumes, melting snow and initial water levels in reservoirs largely determine the dispatch of the system's hydroelectric and thermoelectric generation plants. Rainfall and snowfall occur in Chile principally in the southern cone winter season (June to August) and during the remainder of the year precipitation is scarce. When rain is abundant, energy produced by hydroelectric plants can amount to more than 70% of total generation. In 2015 hydroelectric generation represented 45% of total energy production.

Regulatory Framework — Electricity Regulation — The government entity that has primary responsibility for the Chilean electricity system is the Ministry of Energy, acting directly or through the CNE 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. Companies that are owners of a trunk transmission system, generally high voltage transmission lines with capacity of 220 Kv and higher (with bi-directional flows and relevant number of users), cannot participate in the generation or distribution segments.

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

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

Other Regulatory Considerations — In 2011, a regulation on air emission standards for thermoelectric power plants became effective. This regulation provides for stringent limits on emission of PM and gases produced by the combustion of solid and liquid fuels, particularly coal. For existing plants, including those currently under construction, the new limits for PM emissions went into effect at the end of 2013, and the new limits for SO₂, NO_x and mercury emission will begin to apply in mid-2016, except for those plants operating in zones declared saturated or latent zones (areas at risk of or affected by excessive air pollution), where these emission limits will become effective by June 2015. In 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, 2015, AES Gener has concluded investments of approximately $229 million in order to comply within the required time frame. Additionally, its equity method investee Guacolda started the installation of new equipment during 2013, spending approximately $185 million (Guacolda I, II and IV) as of December 31, 2015 with the remaining $37 million to be invested in 2016.

Chilean law requires every electricity generator to supply a certain portion of its total contractual obligations with NCREs. In October 2013, the NCRE law was amended, increasing the NCRE requirements. The law distinguishes between energy contracts executed before and after July 1, 2013. For contracts executed between August 31, 2007 and July 1, 2013, the NCRE requirement is equal to 5% in 2014 with annual contract increases of 0.5% until reaching 10% in 2024. The NCRE requirement for contracts executed after July 1, 2013 is equal to 5% in 2013, with annual increases of 1% thereafter until reaching 12% in 2020, and subsequently annual increases of 1.5% until it is equal to 20% in 2025. Generation companies are able to meet this requirement by developing their 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 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, regarding the emissions produced during year 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 discos do not have change of law clauses. According to its PPAs, the company is currently discussing the pass-through mechanism with each client. Additionally, new tax laws were enacted in February 2016 in Chile which will increase the statutory income tax rate for most of our Chilean businesses 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 allowed energy exportation to Argentina using the transmission line which connects the SING (Chilean Northern Grid) with the SADI (Argentine Grid). The AES transmission line has a capacity of approximately 600MW, but will be operated at 200 MW according to technical studies. AES Gener signed an agreement with CAMMESA and other generators (Gas Atacama and ECL) in order to export electricity to Argentina.

Key Financial Drivers — Hedge levels at Gener provide some certainty and clarity on the underlying financial drivers through 2016. However, some risks remain through 2016, including, but not limited to, the following:


•	Dry hydrology scenarios reduce hydro generation (See Item 7.—Key Trends and Uncertainties— Operational—Weather sensitivity for further discussion)


•	Forced outages may impact earnings


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


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


•	Tax policy changes

Beyond 2016, financial drivers include all of the above factors, but also:


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


•	Market price risk when re-contracting

Construction and Development — Since 2007, AES Gener has constructed and initiated commercial operations of approximately 1,830 MW of new capacity, representing a significant portion of the increase in installed capacity and investment in the SIC and SING during the period. In Chile, AES Gener has a 21 MW solar project with a scheduled COD in the first half of 2016 and the 532 MW Cochrane project in the SING, expected to begin operations in 2016. The Cochrane project has an adjacent 20 MW energy storage project, which is also scheduled to initiate operations in 2016.

Additionally, in the SIC, AES Gener initiated construction of the 531 MW two unit Alto Maipo run-of-river hydroelectric project in December 2013, adjacent to our existing Alfalfal power plant, located 50 km from Santiago. Alto Maipo is the largest project in construction in the SIC market and it includes 67 kilometers of tunnel works, 2 caverns, 17 km of transmission lines as part of the construction, and is 90% underground. Alto Maipo has three main contractors and covers three adjacent valleys in the Chilean Andes. As of today, the project employs 4,100 people and expects to reach a peak close to 4,500 in the second half of 2017. The project units are scheduled to reach commercial operation in the second half of 2018 and the first half of 2019.

Colombia

Business Description — Chivor, a subsidiary of AES Gener, owns a hydroelectric facility with installed capacity of 1,000 MW, located approximately 160 km east of Bogota. As of December 31, 2015, AES Gener's net power production in Colombia was 4,112 GWh. The installed capacity represents approximately 6.2% of system capacity as of December 31, 2015. The plant consists of eight 125 MW dam-based hydroelectric generating units in two separate sub-facilities. All of Chivor's installed capacity in Colombia is hydroelectric and is therefore dependent on the prevailing hydrological conditions in the region in which it operates. Hydrological conditions largely influence generation and the spot prices at which Chivor sells its non-contracted generation in Colombia.

Chivor's commercial strategy focuses a significant portion of the expected output under contracts, principally with distribution companies, in order to provide cash flow stability. These bilateral contracts with distribution companies are awarded in public bids and normally last from one to three years. The remaining generation is sold on the spot market to other generation and trading companies at the system marginal cost, allowing us to maximize the operating margin.

Additionally, Chivor receives reliability payments for the availability and reliability of Chivor's reservoir during periods of scarcity, such as adverse hydrological conditions. These payments, referred to as "reliability charge payments" are designed to compensate generation companies for the firm energy that they are capable of providing to the system during critical periods of low supply in order to prevent electricity shortages.

Market Structure — Electricity supply in Colombia is concentrated in one main system, the SIN. The SIN encompasses one-third of Colombia's territory, providing coverage to 96% of the country's population. The SIN's installed capacity totaled 16,221 MW as of December 31, 2015, comprised of 69.0% hydroelectric generation, 30.4% thermoelectric generation and 0.6% 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 2015, 68.2% of total energy demand was supplied by hydroelectric plants with the remaining supply from thermoelectric generation (31.0%) and cogeneration and self-generation power (0.8%). From 2003 to 2015, electricity demand in the SIN has grown at a compound annual growth rate of 3.1% and the UPME projects an average compound annual growth rate in electricity demand of 2.8% per year for the next ten years.

Regulatory Framework — Electricity Regulation — 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 and the regulations and technical standards issued by the CREG. Other government entities that play an important role in the electricity industry include the MME, which defines the government's policy for the energy sector; the Public Utility Superintendency of Colombia, which is in charge of overseeing and inspecting the utility companies; and the UPME, which is in charge of planning the expansion of the generation and transmission network.

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

Other Regulatory Considerations — In the past few years, Colombian authorities have discussed proposals to make certain regulatory changes, which have not been implemented as of December 2015. One proposal is to replace or complement the current public auction system in which each distribution company holds an auction for its specific requirements and subsequently executes bilateral contracts with generation or trading companies, with a centralized auction in which the market administrator purchases energy for all distribution companies. During 2015, regulators developed rules to implement Law 1715 passed in 2014 regarding the participation of renewables sources in the electric sector and the rules for negotiation of excess of energy from self-generators. Due to very high spot prices in the market, the regulator implemented a temporary "spot price cap"

equivalent to the 75% of the first step of rationing cost. At the end of 2015, CREG assigned new firm energy obligations for the next 3 years (2017-2019). Additionally, regulation for emergency energy situations, such as severe drought conditions, was introduced in 2014 with the objective of avoiding shortages and other negative economic impacts. For 2016, the most probable changes in regulation will relate to the AGC ancillary services market as well as a general revision of the reliability charge scheme.

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 (see Item 7.—Key Trends and Uncertainties—Operational—Weather sensitivity for further discussion). Hedge levels at Chivor provide certainty and clarity on the underlying financial drivers, hedging the net cash flows of Chivor, up to 90%. However, some risks remain beyond 2016. In addition to hydrology, through 2016, financial results are likely to be driven by many factors including, but not limited to, the following:


•	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

Beyond 2016, financial drivers include all of the above factors, but also:


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

Construction and Development — In Colombia, AES Gener is currently constructing the 20 MW Tunjita run-of-river hydroelectric project, which is scheduled to start operations in the first half of 2016.

Argentina

Business Description — As of December 31, 2015, AES Argentina operates 3,528 MW which represents 10.5% 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 62% thermoelectric and 38% hydroelectric capacity. All of the thermoelectric capacity has the capability to burn alternative fuels. Approximately 69% of the thermoelectric capacity can operate alternatively with natural gas or diesel oil, and the remaining 31% can operate alternatively with natural gas, fuel oil, or coal.

AES Argentina primarily sells its production to the wholesale electric market where prices are largely regulated. In 2015, approximately 93% of the energy was sold in the wholesale electric market and 7% was sold under contract, as a result of the Energy Plus sales made by TermoAndes. Market prices are determined in Argentine Pesos by CAMMESA, the wholesale electric market administrator.

All of the thermoelectric facilities not affected by the Resolution 95/2013, a regulation passed in March 2013 discussed below, including the portion of TermoAndes plant committed to Energy Plus Contracts, are able to use natural gas and receive gas supplied through contracts with Argentine producers. In recent years, gas supply restrictions in Argentina, particularly during the winter season, have affected some of the plants, such as the TermoAndes plant which is connected to the SING by a transmission line owned by AES Gener. The TermoAndes plant commenced operations in 2000, selling exclusively into the Chilean SING. In 2008, following requirements from the Argentine authorities, TermoAndes connected its two gas turbines to the SADI, while maintaining its steam turbine connected to the SING. However, since mid-December 2011, TermoAndes has been selling the plant's full capacity in the SADI. TermoAndes' electricity permit to export to the SING expired on January 31, 2013 and its potential renewal is being evaluated.

Market Structure — The SADI electricity market is managed by CAMMESA. As of December 31, 2015, the installed capacity of the SADI totaled 33,480 MW. In 2015, 64% of total energy demand was supplied by thermoelectric plants, 31% by hydroelectric plants and 6% from nuclear, wind and solar plants.

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

Regulatory Framework — Electricity Regulation — The Argentine regulatory framework divides the electricity sector into generation, transmission and distribution. The wholesale electric market is made up of generation companies, transmission companies, distribution companies and large customers who are allowed to buy and sell electricity. Generation companies can sell their output in the short-term market or to customers in the contract market. CAMMESA is responsible for dispatch coordination and determination of short-term prices. The Electricity National Regulatory Agency is in charge of regulating

public service activities and the Ministry of Federal Planning, Public Investment and Services, through the Energy Secretariat, regulates system dispatch and grants concessions or authorizations for sector activities.

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

On March 26, 2013, the Secretariat of Energy released Resolution 95/2013, which affects the remuneration of generators whose sales prices had been frozen since 2003. This new regulation, which modified the current regulatory framework for the electricity industry, is applicable to generation companies with certain exceptions. It defined a new compensation system based on compensating for fixed costs, non-fuel variable costs and an additional margin. Resolution 95/2013 converted the Argentine electric market towards an "average cost" compensation scheme, increasing revenues of generators that were not selling their production under the Energy Plus scheme or under energy supply contracts with CAMMESA. Resolution 95/2013 applied to all of AES Argentina's plants, excluding TermoAndes. Based on Note 2053 sent by the Ministry of Energy in March 2013, it was understood that TermoAndes' units were not affected by the Resolution since they sell under the Energy Plus scheme.

Thermal units must achieve an availability target which varies by technology in order to receive full fixed cost revenues. The availability of most of AES Argentina's units exceeds this market average. As a result of Resolution 95/2013, revenues to AES Argentina's thermal units increased, but the impact on hydroelectric units is dependent on hydrology. The new Resolution also established that all fuels, except coal, are to be provided by CAMMESA. Thermoelectric natural gas plants not affected by the Resolution, such as TermoAndes, are able to purchase gas directly from the producers for Energy Plus sales.

On May 20, 2014, the Argentine government passed Resolution No. 529/214 ("Resolution 529") which retroactively updated the prices of Resolution 95/2013 to February 1, 2014, changed target availability and added a remuneration for non-periodic maintenance. This renumeration is aimed to cover the expenses that the generator incurs when performing major maintenances in its units.

In the fourth quarter of 2014, the Argentine government passed a resolution to contribute outstanding Resolution 95 receivables into a trust in connection with AES Argentina's commitment to install additional capacity into the system. CAMMESA will finance the investment utilizing the outstanding receivables as a guarantee.

On July 10, 2015, the Argentine government passed Resolution No. 482/2015 ("Resolution 482") which retroactively updated the prices of Resolution 529/2014 to February 1, 2015, including the portion of TermoAndes plant energy generation not committed to Energy Plus Contracts, and created a new trust called "Recursos para las inversions del FONINVEMEM 2015-2018" in order to invest in new generation plants.

In December 2015, the new finance minister lifted foreign currency controls, allowing the peso to float under the administration of Argentinean Central Bank. The newly freed currency fell by more than 30%. Over the course of 2015, the Argentinean Peso devalued by approximately 50%. At December 31, 2015, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank. 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, the following:

•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)


•	Regulatory changes from new government (See Item 7.—Key Trends and Uncertainties—Macroeconomics— Argentina for further discussion)

Brazil SBU

Our Brazil SBU has generation and distribution businesses. Eletropaulo and Tietê are publicly listed companies in Brazil. AES has a 16% economic interest in Eletropaulo and a 24% economic interest in Tietê, and these businesses are consolidated in our financial statements as we maintain control over their operations. Our Brazil operations accounted for the following proportions of consolidated AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow, and AES Proportional Free Cash Flow (a non-GAAP measure):



Brazil SBU ⁽¹⁾	2015		2014		2013
% of AES Operating Margin	21	%	24	%	27	%
% of AES Adjusted PTC (a non-GAAP measure)	6	%	13	%	12	%
% of AES Operating Cash Flow	5	%	14	%	26	%
% of AES Proportional Free Cash Flow (a non-GAAP measure)	NM⁽²⁾		1	%	6	%

⁽¹⁾ Percentages reflect the contributions by our Brazil SBU before deductions for Corporate.

⁽²⁾ Not meaningful

The following table provides highlights of our Brazil operations:



Generation Capacity		3,298 gross MW (932 proportional MW)
Generation Facilities		13
Key Generation Businesses		Tietê and Uruguaiana
Utilities Penetration		8.2 million customers (56,861 GWh)
Utility Businesses		2
Key Utility Businesses		Eletropaulo and Sul

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, 2015, Tietê represents approximately 12% of the total generation capacity in the state of São Paulo and is the third largest private generator in Brazil. We also have another generation plant, AES Uruguaiana, located in southern Brazil with an installed capacity of 640 MW. Listed below are our Brazil SBU generation facilities:

Business

Location

Fuel

Gross MW

AES Equity Interest (% Rounded)

Year Acquired or Began Operation

Contract Expiration Date

Customer(s)

Tietê⁽¹⁾

Brazil

Hydro

2,658

1999

2029

Various

Uruguaiana

Brazil

Gas

640

2000

Brazil Total

3,298


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

Utilities — AES owns interests in two distribution businesses in Brazil, Eletropaulo and Sul. Eletropaulo operates in the metropolitan area of São Paulo and adjacent regions, distributing electricity to 24 municipalities in a total area of 4,526 km², covering a region of high demographic density and the largest concentration of GDP in the country. Serving approximately 20 million people and 6.9 million consumer units, Eletropaulo is the largest power distributor in Brazil, according to the 2012 ranking of the Brazilian Association of the Distributors of Electric Energy (Abradee).

Sul is responsible for supplying electricity to 118 municipalities of the metropolitan region of Porto Alegre on the border with Uruguay and Argentina. The service area covers 99,512 km², serving approximately 3.7 million people and 1.3 million consumer units.

Presented in the table below is a list of our Brazil SBU distribution facilities:



Business	Location	Approximate Number of Customers Served as of 12/31/2015	GWh Sold in 2015	AES Equity Interest (% Rounded)		Year Acquired
Eletropaulo	Brazil	6,852,690	47,357	16	%	1998
Sul	Brazil	1,308,224	9,504	100	%	1997
		8,160,914	56,861

The following map illustrates the location of our Brazil facilities:

Brazil Generation Businesses

Business Description — Tietê has a portfolio of 12 hydroelectric power plants with total installed capacity of 2,658 MW in the state of São Paulo. Tietê was privatized in 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 assured capacity, approximately 11,1194 GWh, to Eletropaulo under a long-term PPA, which expired in December 2015. The contract was price-adjusted annually for inflation, and as of December 31, 2015, the price was R$218/MWh. After the expiration of contract with Eletropaulo, Tietê's strategy is to contract most of its Assured Energy, as described in Regulatory Framework section below, in the free market 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 (3-5 years).

As of December 31, 2015, Tietê's contracted portfolio position is 95% and 88% with average prices of R$149/MWh and R$150/MWh for 2016 and 2017, respectively. As Brazil is mostly a hydro-based country with energy prices highly tied to the hydrological situation, the deterioration of the hydrology since the beginning of 2014 caused an increase in energy prices going forward. Tietê is closely monitoring and analyzing system supply conditions to support energy commercialization decisions. In 2015, 12 new contracts were signed at an average price of approximately R$154/MWh.Tietê's strategy is to contract most of its physical guarantee in the free market while the remaining portion provides flexibility to either protect against low hydrology or potentially capture higher spot prices in the future. As Brazil does not have a developed market with hedge and options instruments for the energy sector, Tietê does not assume any hedging strategy for its portfolio.

Under the concession agreement, Tietê has an obligation to increase its capacity by 15%. Tietê as well as other concessionaire generators have not yet met this requirement due to regulatory, environmental, hydrological and fuel constraints. Sao Paulo state does not have a good potential for wind power and also only a small remaining potential for hydro projects, directing the new increase in the state for thermal capacity. With the high complexity process to get an environmental license for coal projects, Tietê decided to fulfill obligation with gas-fired projects in line with Federal government plans. As Petrobras refuses to supply natural gas and to offer capacity in its pipelines and regasification terminals and there are no regulations for natural gas swaps in place, up to now, it is unfeasible to bring natural gas to AES Tietê. A legal case has been initiated by the State of São Paulo 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 in 2013 during February and March, in 2014 during March, April, and May, and in 2015 during February, Mach, April and May due to the short-term supply of LNG for the facility. Uruguaiana continues to work toward securing gas on a long-term basis.

Market Structure — Brazil has installed capacity of 140,272 MW, which is 65% hydroelectric, 21.6% thermal and 13.4% renewable (biomass and wind). Brazil's national grid is divided into four subsystems. Tietê is in the Southeast subsystem of the national grid, while Uruguaiana is in the South.

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

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

In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels, and a mechanism known as MRE was created to share hydrological risk across all hydro generators. If the hydro system generates less than total Assured Energy of the system, hydro generators may need to purchase energy in the short-term market to fulfill their contract obligations. When total hydro generation is higher than the total MRE Assured Energy, the surplus is proportionally shared among its participants and they are able to make extra revenue selling the excess energy on the spot market. The consequences of unfavorable hydrology are (i) thermal plants (more expensive to the system) being dispatched, (ii) lower hydropower generation with deficits in the MRE and (iii) high spot prices.

Due to lower than expected hydrology during 2014, from February to April the spot price was at the cap of R$822/MWh and the average spot price of 2014 was R$689/MWh. During October and November 2014, the ANEEL conducted a public hearing to define a new spot price cap, changing it from R$822/MWh to R$388/MWh from January 2015 until December 2015. The lower cap price resulted in a meaningful reduction on the expenses of the agents that were negatively exposed to the spot price in 2015. However, due to improved hydrology in the second half of 2015 spot prices were below the cap with the average price of R$287/MWh. For 2016, ANEEL has already defined the new spot price cap, changing it from R$388/MWh to R$423/MWh from January 2016 forward.

Key Financial Drivers — As the system is highly dependent on hydroelectric generation, Tietê and Uruguaiana (more likely to generate during low hydrology) are affected by the hydrology in the overall sector, as well as the availability of Tietê's plants and reliability of the Uruguaiana facility. The availability of gas for continued operations is a driver for Uruguaiana.

Through and beyond 2016, Tietê's financial results are likely to be driven by many factors including, but not limited to, the following:


•	Hydrology, impacting quantity of energy generated


•	Demand growth


•	Re-contracting price


•	Asset management and plant availability


•	Cost management


•	Ability to execute on its growth strategy

Through and beyond 2016, Uruguaiana's financial results are likely to be driven by many factors including, but not limited to, the following:


•	Arbitration settlement with YPF (see Item 3.—Legal Proceedings)


•	Secure long-term gas solution

Brazil Utility Businesses

Business Description — Eletropaulo distributes electricity to the greater São Paulo area, Brazil's main economic and financial center. Eletropaulo is the largest electric power distributor in Latin America in terms of both revenues and volume of energy distribution.

AES owns 16% of the economic interest in Eletropaulo, our partner, BNDES, owns 19% and the remaining shares are publicly held or held by government-related entities. AES is the controlling shareholder and manages and consolidates this business. Eletropaulo holds a 30-year concession that expires in 2028.

AES owns 100% of Sul. Sul distributes electricity in the metropolitan region of Porto Alegre up to the frontier with Uruguay and Argentina, respectively, in the municipalities of Santana do Livramento and Uruguaiana/São Borja at the extreme west of the state of Rio Grande do Sul. AES manages Sul under a 30-year concession expiring in 2027.

Regulatory Framework — In Brazil, ANEEL, a government agency, sets the tariff for each distribution company based on a Return on Asset Base methodology, which also benchmarks operational costs against other distribution companies.

The tariff charged to regulated customers consists of two elements: (i) pass-through of non-manageable costs under a determined methodology ("Parcel A"), including energy purchase costs, sector charges and transmission and distribution system expenses; and (ii) a manageable cost component ("Parcel B"), including operation and maintenance costs (defined by ANEEL), recovery of investments and a component for a return to the distributor. The return to distributors is calculated as the net asset base multiplied by the Regulatory WACC, which is set for all industry participants during each tariff reset cycle. The current Regulatory WACC for Eletropaulo, after tax, is 8.1%. This WACC is effective for three years and as such will be updated again in the next tariff review for Sul in April 2018.

Each year ANEEL reviews each distributor's tariff for an annual tariff adjustment. The annual tariff adjustments allow for pass-through of Parcel A costs and inflation impacts on Parcel B costs, adjusted for expected efficiency gains and quality performances. Distribution companies are required to contract between 100% and 105% of anticipated energy needs through the regulated auction market. If contracted levels fall below required levels distribution companies may be subject to limitations on the pass-through treatment of energy purchase costs as well as penalties. As the costs incurred on energy purchases by our distribution companies are passed through to customers with adjustments on a yearly basis, working capital will be sensitive to significant increases in energy prices. In order to reduce potential working capital needs, in February 2015, ANEEL opened two public hearings (i) to discuss an Extraordinary Tariff Review ("ETR") requested by distribution companies and ii) to discuss adjustments to a tariff flag mechanism that may change the tariff to customers on a monthly basis depending on energy prices. These items were approved by ANEEL and made effective on March 2, 2015. The ETR represented an average tariff increase of 32% in AES Eletropaulo and 39% at AES Sul. The tariff flag mechanism, a temporary measure in response to higher energy prices due to dry hydrological conditions, was improved by incorporating i) a higher tariff increase depending on the energy purchase costs and (ii) resources collected by the tariff flag being centralized in an account and shared among distribution companies in proportion to their respective involuntary exposure. Most recently, ANEEL approved the Annual Readjustment for AES Sul on April 14, 2015 representing an average tariff increase of 5.46%.

Every four to five years, ANEEL resets each distributor's tariff to incorporate the revised Regulatory WACC and determination of the distributor's net asset base. Eletropaulo's tariff reset occurs every four years and the next tariff reset will be in July 2019. Sul's tariff is reset every five years and the next tariff reset is expected in April 2018. The 4^th Tariff Reset for AES Eletropaulo occurred on July 4, 2015, representing an average tariff increase of 15.23%.

ANEEL challenged the parameters of a tariff reset for Eletropaulo implemented in July 2012 and retroactive to 2011. ANEEL asserted that during the period between 2007 and 2011, certain assets that were included in the regulatory asset base should not have been included and that Eletropaulo should refund customers for the return on the disputed assets earned during this period. On December 17, 2013, ANEEL determined, at the administrative level, that Eletropaulo should adjust the prior (2007-2011) regulatory asset base and refund customers in the amount of $269 million (R$630 million) over a period of up to four tariff processes beginning in July 2014. Eletropaulo filed for an administrative appeal requesting ANEEL to reconsider its decision and requested that the decision be suspended until the appeal process was completed. On January 28, 2014, ANEEL denied Eletropaulo's request to suspend the effects of the previous decision. On January 29, 2014, Eletropaulo requested and received from the Federal Court of Brazil an injunction for the suspension of the effects of ANEEL's previous decision. As ANEEL had confirmed the original decision and the related refund to customers, the injunction no longer became effective. The Company recognized a regulatory liability of approximately $269 million in the Company's 2013 fourth quarter results of operations since ANEEL had compelled the Company to refund customers. Eletropaulo started reimbursing customers in July 2014.

On December 18, 2014, the effects of the injunction were restored and on January 5, 2015, during a public hearing, ANEEL resolved to follow the legal decision. However, on January 7, 2015 ANEEL requested the suspension of the injunction. While the final legal decision has yet not been taken, ANEEL released a new tariff for Eletropaulo on January 8, 2015, not considering the reimbursement to customers, which is immediately effective. On June 30, 2015, ANEEL included in Eletropaulo's tariff reset the reimbursement of amounts previously refunded to customers from July 2014 through early January 2015. In addition to ANEEL's failure thus far to suspend the injunction through the appeals process in the Brazilian courts, the tariff reset resulted in management's reassessment of the probability of refunding customers these disputed amounts. The Company now considers it only reasonably possible that Eletropaulo will be required to refund these amounts to customers prior to the ultimate resolution of the pending court case. As a result, during the second quarter of 2015, the Company reversed the remaining regulatory liability for this contingency of $161 million. Eletropaulo believes it has meritorious arguments on this matter and will continue to pursue its objections to ANEEL's rulings vigorously, however there can be no assurance that Eletropaulo will prevail.

Key Financial Drivers — Through and beyond 2016, Eletropaulo's and Sul's financial results are likely to be driven by many factors including, but not limited to, the following:


•	Hydrology, impacting quantity of energy sold and energy purchased


•	Brazilian economic growth and tariff increases, impacting energy consumption growth, losses and delinquency (see Item 7.—Key Trends and Uncertainties—Macroeconomics—Brazil for further information)


•	Ability of both Eletropaulo and Sul to pass through costs via productivity gains


•	Capital structure optimization to reduce leverage and interest costs


•	Sul's fourth tariff cycle outcomes in April 2018


•	July 2012 regulatory asset base resolution


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

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

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 1.3 million customers as of December 31, 2015. MCAC operations accounted for the following proportions of consolidated AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow, and AES Proportional Free Cash Flow (a non-GAAP measure):



MCAC SBU ⁽¹⁾	2015		2014		2013
% of AES Operating Margin	19	%	18	%	17	%
% of AES Adjusted PTC (a non-GAAP measure)	20	%	19	%	19	%
% of AES Operating Cash Flow	28	%	16	%	17	%
% of AES Proportional Free Cash Flow (a non-GAAP measure)	30	%	20	%	23	%

⁽¹⁾ Percentages reflect the contributions by our MCAC SBU before deductions for Corporate.

The following table provides highlights of our MCAC SBU operations:



Countries		Dominican Republic, El Salvador, Mexico, Panama and Puerto Rico
Generation Capacity		3,239 gross MW (2,482 proportional MW)
Generation Facilities		17 (including 1 under construction)
Key Generation Businesses		Andres, Panama and TEG TEP
Utilities Penetration		1.3 million customers (3,754 GWh)
Utility Businesses		4
Key Utility Businesses		El Salvador

The table below lists our MCAC SBU facilities:



Business	Location	Fuel	Gross MW	AES Equity Interest (% Rounded)		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
Andres	Dominican Republic (DR)	Gas	319	90	%	2003	2018	Ede Este/Non-Regulated Users/Linea Clave
Itabo⁽¹⁾	DR	Coal/Gas	295	45	%	2000	2016	Ede Este/Ede Sur/Ede Norte/Quitpe
DPP (Los Mina)	DR	Gas	236	90	%	1996	2016	Ede Este
Dominican Republic Subtotal			850
AES Nejapa	El Salvador	Landfill Gas	6	100	%	2011	2035	CAESS
Moncagua	El Salvador	Solar	3	100	%	2015	2035	EEO
El Salvador Subtotal			9
Merida III	Mexico	Gas	505	55	%	2000	2025	Comision Federal de Electricidad
Termoelectrica del Golfo (TEG)	Mexico	Pet Coke	275	99	%	2007	2027	CEMEX
Termoelectrica del Penoles (TEP)	Mexico	Pet Coke	275	99	%	2007	2027	Penoles
Mexico Subtotal			1,055
Bayano	Panama	Hydro	260	49	%	1999	2030	Electra Noreste/Edemet/Edechi/Other
Changuinola	Panama	Hydro	223	90	%	2011	2030	AES Panama
Chiriqui-Esti	Panama	Hydro	120	49	%	2003	2030	Electra Noreste/Edemet/Edechi/Other
Estrella de Mar I	Panama	Heavy Fuel Oil	72	49	%	2015	2020	Electra Noreste/Edemet/Edechi/Other
Chiriqui-Los Valles	Panama	Hydro	54	49	%	1999	2030	Electra Noreste/Edemet/Edechi/Other
Chiriqui-La Estrella	Panama	Hydro	48	49	%	1999	2030	Electra Noreste/Edemet/Edechi/Other
Panama Subtotal			777
Puerto Rico	US-PR	Coal	524	100	%	2002	2027	Puerto Rico Electric Power Authority
Illumina	US-PR	Solar	24	100	%	2012
Puerto Rico Subtotal			548
MCAC Total			3,239


⁽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 (% Rounded)

Expected Year of Commercial Operations

DPP (Los Mina) Conversion

Dominican Republic

Gas

122

1H 2017

Dominican Republic Subtotal

122

MCAC Total

122

MCAC Utilities — Our distribution businesses are located in El Salvador and distribute power to 1.3 million people in the country. These businesses consist of four companies, each of which operates in defined service areas as described below:



Business	Location	Approximate Number of Customers Served as of 12/31/2015	Approximate GWh Sold in 2015	AES Equity Interest (% Rounded)		Year Acquired
CAESS	El Salvador	583,000	2,174	75	%	2000
CLESA	El Salvador	377,000	892	80	%	1998
DEUSEM	El Salvador	76,000	132	74	%	2000
EEO	El Salvador	290,000	556	89	%	2000
		1,326,000	3,754

The following map illustrates the location of our MCAC facilities:

MCAC Businesses

Dominican Republic

Business Description — AES Dominicana consists of three operating subsidiaries, Itabo, Andres and DPP. AES has 23% of the system capacity (850 MW) and supplies approximately 42% of energy demand through these generation facilities.

During 2014, AES entered into a strategic partnership with the Estrella and Linda Groups ("Estrella-Linda"), an investor group based in the Dominican Republic. Under this agreement, Estrella-Linda acquired an 8% non-controlling interest in AES' business in the Dominican Republic for $83 million and, in December 2015, exercised its first call option of additional 2% for$18 million, net of discount and transaction costs. Estrella-Linda has an additional option to increase up to 20% by the end of 2016. Estrella-Linda is a consortium of two leading Dominican industrial groups: Estrella and Grupo Linda. The two partners manage a diversified business portfolio, including construction services, cement, agribusiness, metalwork, plastics, textiles, paints, transportation, insurance and media.

Itabo is 45%-owned by AES, 5% by Estrella-Linda, 49.97% owned by FONPER, a government-owned utility and the remaining 0.03% is owned by employees. Itabo owns and operates two thermal power generation units with a total of 295 MW of installed capacity. Itabo's PPAs are with government-owned distribution companies and expire in 2016. Since the majority of distribution companies' long term PPAs are expiring in July 2016, the CDEEE is sponsoring a bidding process that is expected to be released and awarded during 2016 in order to secure supply and competitive pricing for actual and future distribution energy requirements. The existing business strategy is to secure approximately 75% to 85% 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.

In 2005, Andres entered into a contract to sell re-gasified LNG for further distribution to industrial users within the Dominican Republic using compression technology to transport it within the country. In January 2010, the first LNG truck

tanker loading terminal started operations. With this investment, AES is capturing demand from industrial and commercial customers.

Market Structure

Electricity Market — The Dominican Republic has one main interconnected system with approximately 3,742 MW of installed capacity, composed primarily of thermal generation (82%), hydroelectric power plants (16%) and wind plants (2%).

Natural Gas Market — The natural gas market in the Dominican Republic started developing in 2001 when AES entered into a long-term contract for LNG and constructed AES Dominicana's LNG regasification terminal.

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

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

The electricity tariff applicable to regulated customers is subject to regulation within the concessions of the distribution companies. Clients with demand above 1.0 MW are classified as unregulated customers and their tariffs are unregulated.

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

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

•

Spot prices are mainly driven by the fluctuations in commodity prices due to the dependency of the Dominican Republic on oil-based thermal generation. Since the fuel component is a pass-through cost under the PPAs, any variation in the oil prices will mainly impact the spot sales for both Andres and Itabo, which are expected to be net sellers in the upcoming years. Current contracting level for 2016 is close to 90%. Supply shortages in the near term (next 2 to 3 years) may provide opportunities for upside but new generation is expected to come online from 2018.


•	Additional sales derived from natural gas domestic demand are expected to continue providing an income stream and growth based on the entry of future projects and the fees from the infrastructure service.

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 in the first half of 2017. Based on the increased capacity, AES Dominicana executed a PPA for 270 MW for a 6.5 years term beginning on August 1, 2016.

Panama

Business Description — AES owns and operates 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 25% 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 on December 2018 reducing the total contracted capacity of the company from 496 MW to 430 MW. Another portion contracted through Estrella del Mar I will expire on June 2020, reducing the total contracted capacity to 350 MW until December 2030.

Market Structure — Panama's current total installed capacity is 3,068 MW, of which 56% is hydroelectric, 3% wind and the remaining 41% thermal generation from diesel, bunker fuel and coal.

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

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

The CND implements the economic dispatch of electricity in the wholesale market. The CND's objectives are to minimize the total cost of generation and maintain the reliability and security of the electric power system, taking into account the price of water, which determines the dispatch of hydro plants with reservoirs. Short-term power prices are determined on an hourly basis by the last dispatched generating unit.

In Panama, dry hydrological conditions remained during 2015 affecting the generation output from hydroelectric facilities as in the prior year. AES Panama had to purchase energy on the spot market to fulfill its contract obligations as its generation output was below contract levels. The drop in the commodities prices helped to reduce the replacement cost and the financial impact of spot purchases compared to the prior year. Despite the hydrology conditions, spot prices were down to $90/MWh from $217/MWh in 2014, impacting also the amount recognized through the 2014-2016 Government Compensation Agreement to only $5.8 million out of the $30 million for 2015. On March 31, 2014, the government of Panama agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70 MW reduction in contracted capacity for the period 2014-2016 by compensating AES Panama for spot purchases up to $40 million in 2014, $30 million in 2015 and $30 million in 2016.

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

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

Generators can only contract their firm capacity. Physical generation of energy is determined by the CND regardless of contractual arrangements.

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


•	Lower hydrology resulting in low generation and additional energy purchases to fulfill contracts, partially mitigated by additional generation from Estrella del Mar I, lower spot prices driven by the drop in commodities, and the compensation amount from the Government Compensation Agreement.

•

In addition to spot prices being driven by hydrology since Panama is highly dependent on hydro generation (~56%), the fluctuations in commodity prices, mainly oil prices, affect the thermal generation cost impacting the spot prices and the opportunity cost of water. In the event of low hydrology, high commodity prices will increase the business exposure and the cost of replacement power to back up our contractual commitment.


•	Constraints imposed by 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 2016 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 (January to 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. See Item 7.—Key Trends and Uncertainties—Operational—Sensitivity to Dry Hydrological Conditions for further information.

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, 2015, amounts capitalized include $7 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 CFE under a capacity and energy based long-term PPA through 2025. Additionally, the plant purchases natural gas and diesel fuel under a long-term contract, the cost of which is then passed through to CFE under the terms of the PPA.

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

Market Structure — Mexico has a single national electricity grid, the SEN, covering nearly all of Mexico's territory. Mexico has an installed capacity totaling 65 GW with a generation mix of 74% thermal, 19% hydroelectric and 7% other. Electricity consumption is split between the following end users: industrial (58%), residential (26%) and commercial and service (16%).

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


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


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


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


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

According to the new regulatory framework, new assets developed under the new framework or assets transferred to the new regime and in operation after the approval of the Electricity Law (August 2014) are eligible to participate in the new markets. Additionally, projects developed and operated under the Electric Public Service Law (self-supply framework) like TEG TEP, could choose to participate. Until the new framework is further analyzed, AES will continue operating under the same conditions. Merida III and TEG/TEP will continue providing power under long-term contracts and selling any excess or surplus energy produced to CFE.

Key Financial Drivers — Operational performance is the key business driver as the companies are fully contracted and better performance provides additional financial benefits including performance incentives and/or excess energy sales (in the case of TEG/TEP). The energy prices of TEG/TEP for the sales in excess over its long-term contracts are driven by the average production cost of CFE which is highly dependent on natural gas and oil. If the average production cost of CFE is higher than the cost of generating with pet coke, our businesses in Mexico will benefit provided that they are able to sell energy in excess of their PPAs.

Other MCAC Businesses

Puerto Rico

Business Description — AES Puerto Rico owns and operates a coal-fired cogeneration plant and a recently acquired solar plant of 524 MW and 24 MW, respectively, representing approximately 9% of the installed capacity in Puerto Rico. Both plants have long-term PPAs expiring in 2027 and 2032, respectively, with PREPA, a state-owned entity that supplies virtually all of the electric power consumed in Puerto Rico and generates, transmits and distributes electricity to 1.4 million customers. On April 29, 2015, AES completed the acquisition of 100% of the common stock of the solar plant, AES Illumina. Its results of operations have been included in AES' consolidated results of operations from the date of acquisition. See Item 7.—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for further discussion of the long-term PPA with PREPA. In addition, AES Puerto Rico has ongoing litigation regarding the disposal of ash in the Dominican Republic. See Item 3.—Legal Proceedings.

El Salvador

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 3,730 GWh of market energy purchases during 2015, or about 64% market share of the country's total energy purchases.

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" or "The Regulator"). The Regulator, 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 next five years (2013-2017).

Europe SBU

Our Europe SBU has generation facilities in five countries. Our European operations accounted for the following proportions of consolidated AES Operating Margin, AES Adjusted PTC (a non-GAAP measure), AES Operating Cash Flow, and AES Proportional Free Cash Flow (a non-GAAP measure):



Europe SBU ⁽¹⁾	2015		2014		2013
% of AES Operating Margin	11	%	13	%	13	%
% of AES Adjusted PTC (a non-GAAP measure)	15	%	19	%	19	%
% of AES Operating Cash Flow	14	%	13	%	15	%
% of AES Proportional Free Cash Flow (a non-GAAP measure)	15	%	14	%	18	%

⁽¹⁾ Percentages reflect the contributions by our Europe SBU before deductions for Corporate.

The following table provides highlights of our Europe operations:



Countries		Bulgaria, Jordan, Kazakhstan, Netherlands and United Kingdom
Generation Capacity		6,781gross MW (5,009 proportional MW)
Generation Facilities		12
Key Generation Businesses		Maritza, Kilroot, Ballylumford, and Kazakhstan

Operating installed capacity of our Europe SBU totaled 6,781 MW. Presented in the table below is a list of our Europe SBU generation facilities:



Business	Location	Fuel	Gross MW	AES Equity Interest (% Rounded)		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
Maritza	Bulgaria	Coal	690	100	%	2011	2026	Natsionalna Elektricheska
St. Nikola	Bulgaria	Wind	156	89	%	2010	2025	Natsionalna Elektricheska
Bulgaria Subtotal			846
Amman East	Jordan	Gas	380	37	%	2009	2033-2034	National Electric Power Company
IPP4	Jordan	Heavy Fuel Oil/Gas	247	60	%	2014	2039	National Electric Power Company
Jordan Subtotal			627
Ust-Kamenogorsk CHP	Kazakhstan	Coal	1,372	100	%	1997	Short-term	Various
Shulbinsk HPP⁽¹⁾	Kazakhstan	Hydro	702	—	%	1997	Short-term	Various
Ust-Kamenogorsk HPP⁽¹⁾	Kazakhstan	Hydro	331	—	%	1997	Short-term	Various
Sogrinsk CHP	Kazakhstan	Coal	345	100	%	1997	Short-term	Various
Kazakhstan Subtotal			2,750
Elsta⁽²⁾	Netherlands	Gas	630	50	%	1998	2018	Dow Benelux/Delta/Nutsbedrijven/ Essent Energy
Netherlands ES	Netherlands	Energy Storage	10	100	%	2015
Netherlands Subtotal			640
Ballylumford	United Kingdom	Gas	1,246	100	%	2010	2023	Power NI/Single Electricity Market (SEM)
Kilroot⁽³⁾	United Kingdom	Coal/Oil	662	99	%	1992		SEM
Kilroot ES	United Kingdom	Energy Storage	10	100	%	2015
United Kingdom Subtotal			1,918
Europe Total			6,781


⁽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 European 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 EU Industrial Emission Directive, which came into force in January 2016. Maritza's entire power output is contracted with NEK under a 15-year PPA expiring in 2026, capacity and energy based, with a fuel pass-though. The lignite and limestone are supplied under a 15-year fuel supply contract.

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 2015 was approximately 13.6 GW. Thermal generation, which is mostly coal-fired, and nuclear power plants account for 64% of the installed capacity.

Regulatory Framework — The electricity sector in Bulgaria operates under the Energy Act of 2004 that allows the sale of electricity to take place freely at negotiated prices, at regulated prices between parties or on the organized market. In 2015 the government of Bulgaria has made advances toward market liberalization and has engaged with the World Bank to develop a model for a fully liberalized electricity market in Bulgaria. The final report with recommendations from the World Bank is expected in May 2016. The Independent Bulgarian Energy Exchange started commercial operation of the power exchange on January 19, 2016 after successful test sessions were held in December 2015.

Our investments in Bulgaria rely on long-term PPAs with NEK, the state-owned electricity public supplier and energy trading company. NEK is facing some liquidity issues and has been delayed in making payments under the PPAs with Maritza and St. Nikola. In May and June 2014, SEWRC issued decisions precluding the ability of NEK to pass-through to the regulated market certain costs incurred by NEK pursuant to the PPA with Maritza, which impacted NEK's liquidity and its ability to make payments under the PPA. SEWRC also instructed NEK and Maritza to begin negotiating amendments to the PPA. Maritza has engaged in negotiations with NEK and other Bulgarian state bodies concerning these matters. In August 2015, the ninth amendment of Maritza's PPA was executed under which Maritza and NEK would reduce the capacity payment to Maritza under the PPA by 14% through the PPA Term, without impacting the energy price component. In exchange, NEK would pay Maritza its overdue receivables. The amendment will become effective upon full payment of the overdue receivables by NEK, which is expected in 2016. In 2014 SEWRC announced that it has asked the DG Comp to review NEK's respective PPAs with Maritza and a separate generator pursuant to European state aid rules, and to suspend the PPAs pending the completion of that review. DG Comp has not contacted Maritza about the SEWRC's request to date.

In March 2015, changes to the Energy Act were enacted. Changes included a limitation on electricity purchases from co-generators at preferential prices, the allocation of the proceeds from the sale of state CO₂ allowances to NEK, and an increase in the Regulator's independence through appointment of its members by the Parliament rather than by the Council of Ministers. In July 2015, additional measures were voted by the Parliament to complement the first measures taken in March 2015. An Electricity Security Fund was created to help NEK meet its obligations with energy producers, financed with a 5% contribution from all energy producers on their energy revenues as well as with proceeds from the sale of state CO₂ allowances. Maritza is able to pass-through this additional contribution to NEK since it falls under a change in law provision under the PPA. Following the Energy Act amendments on July 31, 2015 the regulator approved new regulated prices that led to 0.11% decrease for household electricity prices and increased the non-household prices between 0% and 20% for the various segments. On November 1, 2015 the regulator decreased the non-household prices 2.5% on average as result of the falling gas prices. All these actions are expected to improve NEK's liquidity. At this time, it is difficult to predict the impact of the political conditions and regulatory changes on our businesses in Bulgaria.

Maritza has experienced ongoing delays in the collection of outstanding receivables from NEK. As of December 31, 2015, Maritza had an outstanding receivables balance of $351 million including $44 million of current receivables, $82 million of receivables overdue by less than 90 days and $225 million of receivables overdue by more than 90 days. See Key Trends and Uncertainties—Macroeconomics and Political—Bulgaria in Item 7.—Management's Discussion and Analysis to this Form 10-K for further information.

NEK has failed to maintain a minimum rating pursuant to the Government Support Letter issued in 2005. As a result, the PPA could be terminated at the discretion of Maritza and the lenders. See Item 1A.—Risk Factors—We may not be able to enter into long-term contracts, which reduce volatility in our results of operations. As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.

Key Financial Drivers — Both businesses, Maritza and St. Nikola, operate under PPA contracts. For the duration of the PPA, the financial results are primarily driven by, but not limited to: the availability of the operating units; the level of wind resource for St. Nikola; and NEK's ability to meet the terms of the PPA contract.

United Kingdom

Business Description — AES' generation businesses in the United Kingdom operate in the Irish Single Electricity Market (SEM) for the businesses located in Northern Ireland (1,918 MW). During 2015, AES sold its interests in wind development pipelines of 115 MW in Scotland.

The Northern Ireland generation facilities consist of two plants within the Greater Belfast region. Our Kilroot plant is a 662 MW coal-fired plant with 10 MW of energy storage facility and our Ballylumford plant is a 1,246 MW gas-fired plant. These plants provide approximately 70% of the Northern Ireland installed capacity and 18% of the combined installed capacity for the island of Ireland.

Kilroot is a merchant plant that bids into the SEM market. Kilroot derives its value from the variable margin when scheduled in merit and the margin from constrained dispatch (when dispatched out of merit to support the system in relation to the wind generation, voltage and transmission constraints) and capacity payments paid through