10-K 1 a2014form10-k.htm 10-K 2014 Form 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, 2014
-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, 2014, the last business day of the Registrant’s most recently completed second fiscal quarter (based on the adjusted closing sale price of $15.32 of the Registrant’s Common Stock, as reported by the New York Stock Exchange on such date) was approximately $10.17 billion.
The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, on February 18, 2015 was 702,634,251
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant’s Proxy Statement for its 2015 annual meeting of stockholders are incorporated by reference in Parts II and III
 





THE AES CORPORATION
FISCAL YEAR 2014 FORM 10-K
TABLE OF CONTENTS





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
ANEEL
Brazilian National Electric Energy Agency
APS
Attributed Profit System
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
CA
Commercial Availability
CAA
United States Clean Air Act
CAIR
Clean Air Interstate Rule
CAMMESA
Wholesale Electric Market Administrator in Argentina
CCB
Coal Combustion Byproducts
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
CEEE
Companhia Estadual de Energia
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
CO2
Carbon Dioxide
COSO
Committee of Sponsoring Organizations of the Treadway Commission
CPCN
Certificate of Public Convenience and Necessity
CPI
United States Consumer Price Index
CREG
Energy and Gas Regulation Commission
CRES
Competitive Retail Electric Service
CSAPR
Cross-State Air Pollution Rule
CVA
Credit Valuation Adjustment
CWA
U.S. Clean Water Act
DAREM
Kazakhstan regulator
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
DPLER
DPL Energy Resources, Inc.
DPP
Dominican Power Partners
ECCRA
Environmental Compliance Cost Recovery Adjustment
ED
East Kazakhstan Ecology Department
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

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ERC
Energy Regulatory Commission
ESO
Electricity System Operator
ESP
Electric Security Plan
ESP
Electric Service Plan
ESPS
Existing Source Performance Standards
EU ETS
European Union Greenhouse Gas Emission Trading Scheme
EURIBOR
Euro Inter Bank Offered Rate
EUSGU
Electric Utility Steam Generating Unit
EVN
Vietnam Electricity
EVP
Executive Vice President
EWG
Exempt Wholesale Generators
FAC
Fuel Adjustment Charges
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
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
HAP
Hazardous Air Pollutant
HLBV
Hypothetical Liquidation Book Value
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
MINT
Kazakhstan Ministry of Industry and New Technology
MISO
Midcontinent Independent System Operator, Inc.
MME
Ministry of Mines and Energy
MRE
Energy Reallocation Mechanism
MW
Megawatts
MWh
Megawatt Hours
NCRE
Non-conventional Renewable Energy
NEK
Natsionala Elektricheska Kompania (state-owned electricity public supplier in Bulgaria)
NERC
North American Electric Reliability Corporation
NESHAP
National Emissions Standards for Hazardous Air Pollutants
NGCC
Natural Gas Combined Cycle
NIE
Northern Ireland Electricity
NODA
Notice of Data Availability
NOV
Notice of Violation
NOX
Nitrogen Dioxide
NPDES
National Pollutant Discharge Elimination System

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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
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
RC&OA
Retail Competition and Open Access
RCRA
Resource Conservation and Recovery Act
RGGI
Regional Greenhouse Gas Initiative
RMRR
Routine Maintenance, Repair and Replacement
RPM
Reliability Pricing Model
RSU
Restricted Stock Unit
RTO
Regional Transmission Organization
SADI
Argentine Interconnected System
SAIDI
System Average Interruption Duration Index
SAIFI
System Average Interruption Frequency Index
SBU
Strategic Business Unit
SCE
Southern California Edison
SCJ
Superior Court of Justice
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
UTB
Unrecognized Tax Benefit
VIE
Variable Interest Entity
Vinacomin
Vietnam National Coal-Mineral Industries Group
WECC
Western Electric Coordinating Council
WESM
Wholesale Electricity Spot Market

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PART I
In this Annual Report the terms “AES,” “the Company,” “us,” or “we” refer to The AES Corporation and all of its subsidiaries and affiliates, collectively. The terms “The AES Corporation” and “Parent Company” refer only to the parent, publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates.
FORWARD-LOOKING INFORMATION
In this filing we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot assure you that they will prove to be correct.
Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:
the economic climate, particularly the state of the economy in the areas in which we operate, including the fact that the global economy faces considerable uncertainty for the foreseeable future, which further increases many of the risks discussed in this Form 10-K;
changes in inflation, demand for power, interest rates and foreign currency exchange rates, including our ability to hedge our interest rate and foreign currency risk;
changes in the price of electricity at which our generation businesses sell into the wholesale market and our utility businesses purchase to distribute to their customers, and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk;
changes in the prices and availability of coal, gas and other fuels (including our ability to have fuel transported to our facilities) and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk, and our ability to meet credit support requirements for fuel and power supply contracts;
changes in and access to the financial markets, particularly changes affecting the availability and cost of capital in order to refinance existing debt and finance capital expenditures, acquisitions, investments and other corporate purposes;
our ability to manage liquidity and comply with covenants under our recourse and non-recourse debt, including our ability to manage our significant liquidity needs and to comply with covenants under our senior secured credit facility and other existing financing obligations;
changes in our or any of our subsidiaries’ corporate credit ratings or the ratings of our or any of our subsidiaries’ debt securities or preferred stock, and changes in the rating agencies’ ratings criteria;
our ability to purchase and sell assets at attractive prices and on other attractive terms;
our ability to compete in markets where we do business;
our ability to manage our operational and maintenance costs, the performance and reliability of our generating plants, including our ability to reduce unscheduled down times;
our ability to locate and acquire attractive “greenfield” or “brownfield” projects and our ability to finance, construct and begin operating our “greenfield” or “brownfield” projects on schedule and within budget;
our ability to enter into long-term contracts, which limit volatility in our results of operations and cash flow, such as PPAs, fuel supply, and other agreements and to manage counterparty credit risks in these agreements;
variations in weather, especially mild winters and cooler summers in the areas in which we operate, the occurrence of difficult hydrological conditions for our hydropower plants, as well as hurricanes and other storms and disasters, and low levels of wind or sunlight for our wind and solar facilities;
our ability to meet our expectations in the development, construction, operation and performance of our new facilities, whether greenfield, brownfield or investments in the expansion of existing facilities;
the success of our initiatives in other renewable energy projects, 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;

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changes in laws, rules and regulations affecting our international businesses;
changes in laws, rules and regulations affecting our North America business, including, but not limited to, regulations which may affect competition, the ability to recover net utility assets and other potential stranded costs by our utilities;
changes in law resulting from new local, state, federal or international energy legislation and changes in political or regulatory oversight or incentives affecting our wind business and solar projects, our other renewables projects and our initiatives in GHG reductions and energy storage, including tax incentives;
changes in environmental laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, mercury, hazardous air pollutants and other substances, GHG legislation, regulation and/or treaties and coal ash regulation;
changes in tax laws 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 post retirement 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 (formerly EMEA), 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, as discussed 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.

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SBU
Generation Capacity (Gross MW)
 
Generation Facilities
 
Utility Customers
 
Utility GWh
 
Utility Businesses
US
 
 
 
 
 
 
 
 
 
Generation
5,825

 
12

 
 
 
 
 
 
Utilities
6,520

 
18

 
1.1 million
 
34,797

 
2

Andes
 
 
 
 
 
 
 
 
 
Generation
8,032

 
32

 
 
 
 
 
 
Brazil
 
 
 
 
 
 
 
 
 
Generation
3,298

 
13

 
 
 
 
 
 
Utilities
 
 
 
 
8.0 million
 
57,274

 
2

MCAC
 
 
 
 
 
 
 
 
 
Generation
3,140

 
13

 
 
 
 
 
 
Utilities
 
 
 
 
1.3 million
 
3,620

 
4

Europe
 
 
 
 
 
 
 
 
 
Generation
6,699

 
11

 
 
 
 
 
 
Asia
 
 
 
 
 
 
 
 
 
Generation
1,218

 
3

 
 
 
 
 
 
 
34,732

(1) 
102

 
10.4 million
 
95,691

 
8

(1) 
27,595 proportional MW. Proportional MW is equal to gross MW of a generation facility times AES’ equity ownership percentage in such facility.
Strategy
In 2011, we implemented a new strategy to maximize value for our shareholders and over the last three 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 three years, we have sold assets to generate $3.0 billion in equity proceeds for AES, decreasing the total number of countries where we have operations from 28 to 18. 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 2014, we raised $1.8 billion in asset sales proceeds and exited three countries.
Leveraging Our Platforms. We are focusing our growth on platform expansions, including adjacencies, in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns. We currently have 7,141 MW under construction — the most in AES' 34-year history. These projects represent $9 billion in total capital expenditures, with the majority of AES' $1.5 billion in equity already funded and we expect all of these projects to come on-line from 2015 through 2018. In 2014, we brought on-line the 247 MW heavy fuel oil-fired IPP4 power plant in Jordan and broke ground on six new construction projects, totaling 2,226 MW. Beyond the projects we currently have under construction, we will continue to advance select projects from our 12,000 MW development pipeline, including traditional power plants and adjacencies, such as energy storage. Adjacencies are smaller investments that add near-term growth and can be replicated across our portfolio. We are already successful - AES is the world leader in battery-based energy storage, with 228 MW (power plant equivalent dispatchable resource, including supply and load capability) in operation or under construction.
AES has the most comprehensive and accomplished fleet of battery-based energy storage in the world
U.S. Energy Information Administration (EIA) forecasts 28,000 MW of new renewable capacity in the next ten years and 82,000 MW of power plant retirements over the same period
Energy storage can serve as a replacement resource, to absorb renewable energy
AES Advancion is a complete battery-based grid resource offered to utility companies and renewable developers
Tailored to specific market needs in terms of power and duration
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. We have reduced our global general & administrative expenses ("G&A") by $200 million, achieving the goal we established in 2011 one year early.
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. In 2014, we brought in partners at four of our businesses:
CDPQ, a long-term institutional investor headquartered in Quebec, Canada, recently purchased direct and indirect interests in IPALCO, the Parent Company of IPL in Indiana, for $595 million.
At Guacolda in Chile, we brought in Global Infrastructure Partners to acquire a 50% stake by investing $728 million, which allowed us to improve operations, without changing our ownership stake.

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At Masinloc in the Philippines, Electricity Generating Company Limited ("EGCO"), a Thailand-based Independent Power Producer, took an indirect stake in the existing business, as well as potential expansion opportunities, for $443 million. AES and EGCO agreed to use the Masinloc platform as their exclusive vehicle for growth in the Philippines.
At AES Dominicana in the Dominican Republic, we sold a minority interest in the business to the Estrella and Linda Groups, for $84 million, valuing our assets in the country at $1.2 billion. Estrella and Linda Groups represents strong local players and will support our planned platform expansions, such as upgrading our DPP power plant in the Dominican Republic.
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 $985 million of our shares and benefited from a low interest rate environment, by transacting on $18 billion in debt deals at the Parent and our subsidiaries. These debt transactions represent $9 billion in refinancing and $9 billion in new financing and extended the maturities on $2.9 billion in Parent debt.
Note: Investments in Subsidiaries excludes $2.3 billion investment in DPL.
Most recently, we doubled our regular dividend, increasing the quarterly payment to $0.10 per share beginning in the first quarter of 2015. This dividend increase reflects our confidence in the predictability and growth of our cash flow.
Generation
We currently own and/or operate a generation portfolio of 28,212 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 Fuel Costs). These contracts are intended to reduce exposure to the volatility of fuel prices and electricity prices by linking the

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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.
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, 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 of this Form 10-K.
35% 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.

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30% of our generation fleet is coal-fired. In the United States, most of our plants are supplied from domestic coal. At our non-U.S. generation plants and at our plant in Hawaii, we source coal internationally. Across our fleet, we utilize our global sourcing program to maximize the purchasing power of our fuel procurement.
29% of our generation plants are fueled by renewables, including hydro, wind and energy storage, which do not have significant fuel costs.
6% 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 8,221 MW (4,364 proportional MW) of renewable generation, including hydro, wind, energy storage, 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 more than 10 million people in three countries. AES’ two utilities in the United States also include generation capacity totaling 6,520 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

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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.—BusinessEnvironmental and Land-Use Regulations for further regulatory and environmental discussion.

10




SBUs
All SBUs include generation facilities and three include utility businesses. The Company measures the operating performance of its SBUs using Adjusted PTC, a non-GAAP measure (see definition below).
AES’ primary sources of Revenue, Operating Margin and Adjusted PTC are from generation and utility businesses. The Adjusted PTC by SBU for the year ended December 31, 2014 is shown below. The percentages shown are the contribution by each SBU to gross Adjusted PTC, 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 2014, approximately 79% of Adjusted PTC was contributed by our businesses in the Americas —including the US, Andes, Brazil and MCAC SBUs. Asia and Europe accounted for the remaining 21%.
We define Adjusted PTC as pretax income from continuing operations attributable to AES excluding gains or losses of the consolidated entity 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 also includes net equity in earnings of affiliates on an after-tax basis, adjusted for the aforementioned items. Adjusted PTC in each SBU includes the effect of intercompany transactions with other SBUs other than interest and charges for certain management services.
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 — led by our Chief Executive Officer (“CEO”):
US SBU
Andes SBU
Brazil SBU
MCAC SBU
Europe SBU
Asia SBU
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. See Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 17Segment 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 used for financial reporting purposes.
“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 Note 17Segment and Geographic Information included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for information on revenue from external customers, Adjusted PTC (a non-GAAP measure) and total assets by segment.

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The following describes our businesses within our six SBUs:
US SBU
Our US SBU has 12 generation facilities and two integrated utilities in the United States. Our US operations accounted for 23%, 21% and 20% of consolidated AES operating margin and 24%, 24% and 20% of AES Adjusted PTC (a non-GAAP measure) in 2014, 2013 and 2012, respectively. The percentages reflect the contribution by our US SBU to gross operating margin and adjusted PTC before deductions for Corporate.
The following table provides highlights of our US operations:
Generation Capacity
 
12,345 gross MW (12,345 proportional MW)
Generation Facilities
 
15 (including 3 under construction)
Key Generation Businesses
 
Southland, Hawaii and US Wind
Utilities Penetration
 
1,125,000 customers (34,797 GWh)
Utility Businesses
 
2 integrated utilities (includes 18 generation plants)
Key Utility Businesses
 
IPL and DPL
Operating installed capacity of our US SBU totals 12,345 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. Set forth in the table below is a list of our US generation businesses:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Ownership (% Rounded)
 
Year Acquired or Began Operation
 
Contract Expiration Date
 
Customer(s)
Southland—Alamitos
 
US-CA
 
Gas
 
2,075

 
100
%
 
1998
 
2018
 
Southern California Edison
Southland—Redondo Beach
 
US-CA
 
Gas
 
1,392

 
100
%
 
1998
 
2018
 
Southern California Edison
Southland—Huntington Beach
 
US-CA
 
Gas
 
474

 
100
%
 
1998
 
2018
 
Southern California Edison
Shady Point
 
US-OK
 
Coal
 
360

 
100
%
 
1991
 
2018
 
Oklahoma Gas & Electric
Buffalo Gap II(1)
 
US-TX
 
Wind
 
233

 
100
%
 
2007
 
2017
 
Direct Energy
Hawaii
 
US-HI
 
Coal
 
206

 
100
%
 
1992
 
2022
 
Hawaiian Electric Co.
Warrior Run
 
US-MD
 
Coal
 
205

 
100
%
 
2000
 
2030
 
First Energy
Buffalo Gap III(1)
 
US-TX
 
Wind
 
170

 
100
%
 
2008
 
2015
 
Direct Energy
Beaver Valley
 
US-PA
 
Coal
 
132

 
100
%
 
1985
 
 
 
 
Buffalo Gap I(1)
 
US-TX
 
Wind
 
121

 
100
%
 
2006
 
2021
 
Direct Energy
Armenia Mountain(1)
 
US-PA
 
Wind
 
101

 
100
%
 
2009
 
2024
 
Delmarva & ODEC
Laurel Mountain
 
US-WV
 
Wind
 
98

 
100
%
 
2011
 
 
 
 
Mountain View I & II(1)
 
US-CA
 
Wind
 
67

 
100
%
 
2008
 
2021
 
Southern California Edison
Laurel Mountain ES(2)
 
US-WV
 
Energy Storage
 
64

 
100
%
 
2011
 
 
 
 
Mountain View IV
 
US-CA
 
Wind
 
49

 
100
%
 
2012
 
2032
 
Southern California Edison
Tait ES(2)
 
US-OH
 
Energy Storage
 
40

 
100
%
 
2013
 
 
 
 
Tehachapi
 
US-CA
 
Wind
 
38

 
100
%
 
2006
 
2015
 
Southern California Edison
 
 
 
 
 
 
5,825

 
 
 
 
 
 
 
 
(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) 
Energy Storage MW are power plant equivalent dispatchable resource, including supply and load capability.

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Under construction
The following table lists our plants under construction in the US SBU: 
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (Percent, Rounded)
 
Expected Date of Commercial Operations
IPL MATS
 
US-IN
 
Coal
 
2,400

 
100
%
 
1H 2016
Eagle Valley CCGT
 
US-IN
 
Gas
 
671

 
100
%
 
1H 2017
Warrior Run ES(1)
 
US-MD
 
Energy Storage
 
20

 
100
%
 
1H 2015
US Total
 
 
 
 
 
3,091

 
 
 
 
(1) 
Energy Storage MW are power plant equivalent dispatchable resource, including supply and load capability.    
Set forth in the tables below is a list of our US utilities and their generation facilities:
Business
 
Location
 
Approximate Number of Customers Served as of 12/31/2014
 
GWh Sold in 2014
 
AES Equity Interest (Percent, Rounded)
 
Year
Acquired
DPL
 
US-OH
 
644,000

 
18,763

 
100
%
 
2011
IPL
 
US-IN
 
481,000

 
16,034

 
100
%
 
2001
 
 
 
 
1,125,000

 
34,797

 
 
 
 
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (Percent, Rounded)
 
Year Acquired or Began Operation
DPL(1)
 
US-OH
 
Coal/Gas/Oil
 
3,066

 
100
%
 
2011
IPL(2)
 
US-IN
 
Coal/Gas/Oil
 
3,454

 
100
%
 
2001
 
 
 
 
 
 
6,520

 
 
 
 
(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, 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) 
IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg.
The following map illustrates the location of our US facilities:
US Businesses
US 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 480,000 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 a population of approximately 928,000. IPL owns and operates four generating stations. Two of the generating stations are primarily coal-fired. The third station has a combination of units that use coal

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(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 3,241 MW and net summer capacity is 3,123 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, CDPQ will invest approximately $349 million in IPALCO through 2016, in exchange for a 17.65% equity stake, funding existing growth and environmental 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 US. 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, those to reflect changes in fuel costs to generate electricity or purchased power prices, referred to as FAC, and 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 by approximately $67.8 million annually, or 5.6%. Hearings have begun on this proceeding and an order on this proceeding will likely be issued in the fourth quarter of 2015 with any rate change expected to become effective by early 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. Pursuant to an Indiana statute, 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 in the next few years. 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 (106 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 $626 million. IPL was granted authority to accrue post in-service allowance for debt and equity funds used during construction, and to defer the recognition of depreciation expense of the CCGT and refueling project until such time that IPL is allowed to collect a return. The CCGT is expected to be placed into service in April 2017, and the refueling project is expected to be completed in 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). This conversion is part of IPL’s overall wastewater compliance plan for its power plants (as discussed in Environmental Wastewater Requirements below).

14




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 as part of an agreed order with IDEM. IPL conducted studies to determine the operational changes and/or control equipment necessary in order to comply with the new limitations. On October 16, 2014, IPL filed its wastewater compliance plans with the IURC. IPL is seeking approval for a CPCN to install and operate wastewater treatment technologies at its Petersburg Plant and Harding Street Station, as well as for the refueling of Unit 7 at Harding Street. If approved, IPL will invest $332 million in these projects to ensure compliance with the wastewater treatment requirements by 2017. IPL cannot predict the impact of these regulations on IPL’s consolidated results of operations, cash flows, or financial condition, but it is expected to be material. 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 Environmental Matters 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 more than 515,000 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 260,000 retail customers in Ohio and Illinois. Approximately 131,000 of these customers are also distribution customers of DP&L in Ohio.
Market Structure
Customer Switching. Since January 2001, electric customers within Ohio have been permitted to choose to purchase power under a contract with a CRES Provider or continue to purchase power from their local utility under SSO rates established by tariff. DP&L and other Ohio utilities continue to have the exclusive right to provide delivery service in their state certified territories, and DP&L has the obligation to 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. Ten percent of the SSO load was sourced through competitive bid in 2014, and an additional 50% and 100% will be sourced in this manner in 2015 and 2016, respectively. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services. The PUCO has issued extensive rules on how and when a customer can switch generation suppliers, how the local utility will interact with CRES Providers and customers, including for billing and collection purposes, and which elements of a utility’s rates are “bypassable” (i.e., avoided by a customer that elects a CRES Provider) and which elements are “non-bypassable” (i.e., charged to all customers receiving a distribution service irrespective of what entity provides the retail generation service). Several communities in DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering retail generation service to their residences.
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. The RPM is PJM’s capacity construct. The purpose of the RPM is to enable PJM to obtain sufficient resources to reliably meet the needs of electric customers within the

15




PJM footprint. PJM conducts an auction to establish the price by zone. DP&L’s capacity is located in the remainder of the RTO area within PJM.
The PJM RPM auctions are held three years in advance for a period covering 12 months starting from June 1. Auctions for the period covering June 1, 2018 through May 30, 2019 are expected to take place in May 2015. 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 RPM capacity auctions. For DPL-owned generation, applicable capacity prices and capacity cleared for periods through the auction year 2017/18 are as follows:
Auction Year (June 01-May 31)
 
2017/18
 
2016/17
 
2015/16
 
2014/15
 
2013/14
 
2012/13
Capacity Clearing Price ($/MW-Day)
 
$120
 
$59
 
$136
 
$126
 
$28
 
$16
Capacity Cleared (MW)
 
2,960
 
2,957
 
2,923
 
3,277
 
3,283
 
3,609
On a calendar-year basis, capacity prices and annual capacity revenues earned or projected to be earned by DPL are as follows:
Year
 
2017
 
2016
 
2015
 
2014
 
2013
Computed Average Capacity Price ($/MW-Day)
 
$95
 
$91
 
$132
 
$85
 
$23
Computed Gross RPM Capacity Revenue ($ millions)
 
$103
 
$97
 
$147
 
$107
 
$29
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. Accordingly, in 2014, DP&L credited 29% of the RPM capacity revenue to SSO customers. However, with ongoing switching and transitioning to the market, the amount to be credited will decline each year until reaching zero by 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 to any customer that has not signed a contract with a CRES provider at SSO rates. SSO rates are subject to rules and regulations of the PUCO and are established based on an 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.
On October 5, 2012, DP&L filed an ESP with the PUCO to establish SSO rates that were to be in effect starting January 2013. An order was issued by the PUCO on September 4, 2013 and a correction to that order was issued on September 6, 2013 ("ESP Order"). After several rehearing requests the ESP Order was revised several times. Collectively, the ESP Orders state that DP&L’s current ESP began January 2014 and extends through May 31, 2017. The PUCO authorized DP&L to collect a non-bypassable SSR equal to $110 million per year for 2014 - 2016. The ESP Order also directed DP&L to divest its generation assets no later than January 1, 2017 and established DP&L’s Significantly Excessive Earnings Test ("SEET") threshold at a 12% ROE. Beginning in 2014, DP&L was no longer permitted to supply 100% of the generation service for SSO customers. Instead, the PUCO directed DP&L to phase in the competitive bidding structure with 10% of DP&L’s SSO load sourced through the competitive bid starting in 2014, 60% in 2015, and 100% by January 1, 2016. The ESP Order approved DP&L’s rate proposal to bifurcate its transmission charges into a non-bypassable component, Transmission Cost Recovery Rider - Nonbypassable ("TCRR-N") and a bypassable component, Transmission Cost Recovery Rider - Bypassable ("TCRR-B"). The ESP order also required DP&L to establish a $2.0 million per year shareholder funded economic development fund.
In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. After a period of comments and response, DP&L filed amended applications on February 25, 2014 and May 23, 2014. On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the time by which DP&L must separate its generation assets from its transmission and distribution assets to no later than January 1, 2017. On July 14, 2014, DP&L publicly announced its decision to retain DP&L’s generation assets but to maintain its plans to transfer the

16




assets to a separate affiliate of DPL in accordance with the PUCO orders by January 1, 2017. On September 17, 2014, the PUCO issued a Finding and Order which approved DP&L’s plan to separate its generation assets with minor modifications. These modifications denied DP&L’s request to defer costs associated with Ohio Valley Electric Corporation (which are not currently being recovered through existing rates) and ordered DP&L to transfer environmental liabilities with the generation assets.
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.
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 (as discussed above)
Non-bypassable revenue: $110 million in 2014 and allowed to earn $110 million annually in 2015 and 2016
Customer switching, competitive bidding and SSO rates (as discussed above)
Retail margins earned at DPLER
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 $437 million in capital projects for the period 2015 through 2017. 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.
US Generation
Business Description. In the US, we own a diversified generation portfolio in terms of geography, technology and fuel source. The principal markets 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, which expires in mid-2018 (the “Tolling Agreement”). Under the Tolling Agreement, AES Southland’s largest revenue driver is unit availability, as approximately 98% of its revenue comes from availability-related payments. Historically, AES Southland has generally met or exceeded its contractual availability requirements under the Tolling Agreement and may capture bonuses for exceeding availability requirements in peak periods.
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

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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 Independent System Operator’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, construction is expected to begin in 2017, and commercial operation is 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 US 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 US Generation Businesses
Business Description. Additional businesses include thermal and wind generating facilities, of which AES Hawaii and our US wind generation business are the most significant.
Many of our US 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, 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 2017; the business could be subject to variability in coal pricing beginning in January 2018. To mitigate fuel risk beyond December 2017, 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 877 MW of wind capacity in the US, located in California, Pennsylvania, Texas and West Virginia. Typically, these facilities sell under long-term PPAs. AES financed most of these projects with tax equity structures. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in a net loss to AES consolidated results in periods in which the facilities report net income. These non cash net losses will be expected to reverse during the life of the facilities. Some of the wind projects are exposed to the volatility of energy prices and their revenue may change materially as energy prices fluctuate in their respective markets of operations.
Buffalo Gap is located in Texas and is comprised of three wind projects with an aggregate generation capacity of 524 MW. Each wind project operates its own PPA. The energy price of the entire production of Buffalo Gap I is guaranteed by a

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PPA expiring in 2021. The PPAs of Buffalo Gap II and Buffalo Gap III guarantee 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 PPAs of Buffalo Gap II and Buffalo Gap III expire in December 2017 and December 2015, respectively. Once the PPAs expire, the entire installed capacity of Buffalo Gap will be exposed to the volatility of energy prices in the ERCOT market which could adversely affect revenues.
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 US, 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 US 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. Many of these generation businesses have entered into long-term PPAs with utilities or other offtakers. Some coal-fired power plant businesses in the US 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 United States 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 United States 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 US wholesale electricity market consists of multiple distinct regional markets that are subject to both federal regulation, as implemented by the US 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 US 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 US business, see Item1.—US Environmental and Land-Use Legislation and Regulations.
Key Financial Drivers
US 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

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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 and an energy storage project that will be adjacent to the existing Warrior Run coal plant located in Maryland. In addition to the new construction projects, US 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. Our Andes operations accounted for 19%, 17% and 16% of consolidated AES Operating Margin and 23%, 19% and 18% of AES Adjusted PTC (a non-GAAP measure) in 2014, 2013 and 2012, respectively. The percentages reflect the contribution by our Andes SBU to gross Operating Margin and Adjusted PTC before deductions for Corporate.
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 71% ownership interest in AES Gener and this business is consolidated in our financial statements.
The following table provides highlights of our Andes operations: 
Countries
 
Chile, Colombia and Argentina
Generation Capacity
 
8,032 gross MW (6,354 proportional MW)
Generation Facilities
 
38 (including 6 under construction)
Key Generation Businesses
 
AES Gener Chile, Chivor and AES Argentina

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Operating installed capacity of our Andes SBU totals 8,032 MW, of which 44%, 44% and 12% is located in Argentina, Chile and Colombia, respectively. Set forth 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

 
71
%
 
2000
 
Short-term
 
Various
Colombia Subtotal
 
 
 
 
 
1,000

 
 
 
 
 
 
 
 
Electrica Santiago(1)
 
Chile
 
Gas/Diesel
 
750

 
71
%
 
2000
 
 
 
 
Gener - SIC(2)
 
Chile
 
Hydro/Coal/Diesel/Biomass
 
716

 
71
%
 
2000
 
2015-2037
 
Various
Guacolda(3) (4)
 
Chile
 
Coal/Pet Coke
 
608

 
35
%
 
2000
 
2015-2032
 
Various
Electrica Angamos
 
Chile
 
Coal
 
545

 
71
%
 
2011
 
2026-2037
 
Minera Escondida, Minera Spence, Quebrada Blanca
Gener - SING(5)
 
Chile
 
Coal/Pet Coke
 
277

 
71
%
 
2000
 
2015-2037
 
Minera Escondida, Codelco, SQM, Quebrada Blanca
Electrica Ventanas(6)
 
Chile
 
Coal
 
272

 
71
%
 
2010
 
2025
 
Gener
Electrica Campiche(7)
 
Chile
 
Coal
 
272

 
71
%
 
2013
 
2020
 
Gener
Electrica Angamos ES(8)
 
Chile
 
Energy Storage
 
40

 
71
%
 
2011
 
 
 
 
Gener - Norgener ES (Los Andes)(8)
 
Chile
 
Energy Storage
 
24

 
71
%
 
2009
 
 
 
 
Chile Subtotal
 
 
 
 
 
3,504

 
 
 
 
 
 
 
 
TermoAndes(9)
 
Argentina
 
Gas/Diesel
 
643

 
71
%
 
2000
 
Short-term
 
Various
AES Gener Subtotal
 
 
 
 
 
5,147

 
 
 
 
 
 
 
 
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
 
2015
 
Various
Los Caracoles(10)
 
Argentina
 
Hydro
 
125

 
%
 
2009
 
2019
 
Energia Provincial Sociedad del Estado (EPSE)
Cabra Corral
 
Argentina
 
Hydro
 
102

 
100
%
 
1995
 
 
 
Various
Ullum
 
Argentina
 
Hydro
 
45

 
100
%
 
1996
 
 
 
Various
Sarmiento
 
Argentina
 
Gas/Diesel
 
33

 
100
%
 
1996
 
 
 
 
El Tunal
 
Argentina
 
Hydro
 
10

 
100
%
 
1995
 
 
 
Various
Argentina Subtotal
 
 
 
 
 
2,885

 
 
 
 
 
 
 
 
Andes Total
 
 
 
 
 
8,032

 
 
 
 
 
 
 
 
(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, San Francisco de Mostazal, Ventanas 1, Ventanas 2 and Volcán.
(3) 
Guacolda plants: Guacolda 1, Guacolda 2, Guacolda 3 and Guacolda 4. Unconsolidated entities for which the results of operations are reflected in Equity in Earnings of Affiliates.
(4) 
The Company’s ownership in Guacolda is held through AES Gener, a 71%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 35%.
(5) 
Gener - SING plants: Norgener 1 and Norgener 2.
(6) 
Electrica Ventanas plant: Nueva Ventanas.
(7) 
Electrica Campiche plant: Ventanas 4.
(8) 
Energy Storage MW are power plant equivalent dispatchable resource, including supply and load capability.
(9) 
TermoAndes is located in Argentina, but is connected to both the SING in Chile and the SADI in Argentina.
(10) 
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

 
42
%
 
2H 2016
Alto Maipo
 
Chile
 
Hydro
 
531

 
42
%
 
2H 2018
Guacolda V
 
Chile
 
Coal
 
152

 
35
%
 
2H 2015
Cochrane ES(1)
 
Chile
 
Energy Storage
 
40

 
42
%
 
2H 2016
Andes Solar
 
Chile
 
Solar
 
21

 
71
%
 
2H 2015
Chile Subtotal
 
 
 
 
 
1,276

 
 
 
 
Tunjita
 
Colombia
 
Hydro
 
20

 
71
%
 
1H 2015
Colombia Subtotal
 
 
 
 
 
20

 
 
 
 
Andes Total
 
 
 
 
 
1,296

 
 
 
 
(1) 
Energy Storage MW are power plant equivalent dispatchable resource, including supply and load capability.

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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 3,440 MW, excluding energy storage and TermoAndes, and a market share of 17.9% as of December 31, 2014.
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 to the SIC and SING. AES Gener has experienced significant growth in recent years responding to market opportunities with the completion of nine generation projects totaling approximately 1,700 MW and increasing AES Gener’s installed capacity by 49% from 2006 to 2014. Additionally, we are constructing an additional 1,276 MW, comprised of the 21 MW Andes Solar and 40 MW Cochrane Energy Storage in the SING, the 152 MW coal-fired Guacolda V in the SIC, 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 with their efficient generation capacity, 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 U.S. Consumer Price Index (“U.S. 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

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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 U.S. CPI and other relevant indices.
Market Structure. Chile has four 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 15,181 MW as of December 31, 2014. The SIC serves approximately 92% of the Chilean population, including the densely populated Santiago Metropolitan Region, and represents 75% of the country’s electricity demand. The SING serves about 6% of the Chilean population, representing 24% of Chile’s electricity consumption, and is mostly oriented toward mining companies.
In 2014, thermoelectric generation represented 64% of the total generation in Chile. In the SIC, thermoelectric generation represents 52% 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 95% 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 2014 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 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 100% of their electricity requirements under contract. Generators may also sell energy to other power generation companies on a short-term basis. Power generation companies may engage in contracted sales among themselves at negotiated prices outside the spot market. Electricity prices in Chile, under contract and on the spot market, are denominated in U.S. Dollars, although payments are made in Chilean Pesos.
Other Regulatory Considerations. In 2011, a regulation on air emission standards for thermoelectric power plants became effective. This regulation provides for stringent limits on emission of PM and gases produced by the combustion of solid and liquid fuels, particularly coal. For existing plants, including those currently under construction, the new limits for PM emissions went into effect at the end of 2013, and the new limits for SO2, NOx and mercury emission will begin to apply in mid-2016, except for those plants operating in zones declared saturated or latent zones (areas at risk of or affected by excessive air pollution), where these emission limits will become effective by June 2015. In 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, 2014, AES Gener has invested approximately $204 million and expects the remaining $48 million will be invested in 2015 in order to comply within the required time frame. Additionally, its equity method investee Guacolda started the installation of new equipment during 2013, as of December 31, 2014 spending approximately $114 million (Guacolda I, II and IV) and the remaining $107 million will be invested between 2015 and 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 6% in 2013, with annual increases of 1% thereafter until

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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 particulate material (PM), SO2, NOx and CO2 produced for installations with an installed capacity over 50 MW. This new tax will be in force from 2017. In the case of CO2, the tax will be equivalent to $5 per ton of CO2 emitted. AES Gener is currently assessing the impacts of the new tax and possible mitigation strategies.
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:
Availability of hydro generation: dry hydrology scenarios reduce hydro generation
Availability of generation: forced outages may impact earnings
Regulatory rulings: a change in current governmental rulings could alter the ability to pass through or recover certain costs
Foreign exchange: 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
Beyond 2016, financial drivers include all of the above factors, but also:
Generation margins: current legislation is trending towards rewarding renewable energy and penalizing coal assets, posing a risk to future coal margins
Construction and Development
Since 2007, AES Gener has constructed and initiated commercial operations of approximately 1,700 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 second half of 2015, two coal-fired projects under construction with gross capacity of 684 MW, 152 MW of which is represented by Guacolda V in the northern part of the SIC, scheduled to begin operations in the second half of 2015 and the 532 MW Cochrane project in the SING, expected to begin operations in 2016. The Cochrane project includes a 40 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. Alto Maipo is the largest permitted project in the SIC market and includes 67 kilometers of tunnel work as part of the construction. This project is scheduled to start operations in 2018 and is expected to represent approximately 4% of the energy demand in the SIC at that time.
Colombia
Business Description. As of December 31, 2014, AES Gener’s net power production in Colombia was 3,985 GWh (6% of the country’s total generation). Chivor, a subsidiary of AES Gener, owns a hydroelectric facility with installed capacity of 1,000 MW, located approximately 160 km east of Bogota. The installed capacity represents approximately 6.4% of system capacity as of December 31, 2014. 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 on selling between 75% and 85% of the annual 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.

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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 15,528 MW as of December 31, 2014, comprised of 69.3% hydroelectric generation, 29.8% thermoelectric generation and 0.9% 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 2014, 70.7% of total energy demand was supplied by hydroelectric plants with the remaining supply from thermoelectric generation (28.6%) and cogeneration and self-generation power (0.7%). From 2003 to 2014, electricity demand in the SIN has grown at a compound annual growth rate of 3% and the UPME projects an average compound annual growth rate in electricity demand of 2.3% 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 Ministry of Mines and Energy, which defines the government’s policy for the energy sector; the Public Utility Superintendency of Colombia, which is in charge of overseeing and inspecting the utility companies; and the UPME, 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 February 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 must develop 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. 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.
Key Financial Drivers
Hedge levels at Chivor provide a high degree of certainty and clarity on the underlying financial drivers through 2016, however, some risks remain beyond 2016.
Through 2016, financial results are likely to be driven by many factors including, but not limited to, the following:
Availability of generation: forced outages may impact earnings
Availability of hydro generation: dry hydrology scenarios reduce hydro generation
Foreign exchange: 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:
Spot market exposure: Chivor has exposure to the spot market as hedge levels are lower in the future
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.
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 2015.
Argentina
Business Description. As of December 31, 2014, AES Argentina operates 3,508 MW which represents 11% of the country’s total installed capacity. The installed capacity in the SADI includes the TermoAndes plant, a subsidiary of AES Gener, which is connected both to the SADI and the Chilean SING. AES Argentina has a diversified generation portfolio of ten generation facilities, comprised of 61% thermoelectric and 39% 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 or fuel oil.

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AES Argentina primarily sells its production to the wholesale electric market where prices are largely regulated. In 2014, 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 the CAMMESA.
All of the thermoelectric facilities not affected by the Resolution 95/2013, including TermoAndes, 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, 2014, the installed capacity of the SADI totaled 32,371 MW. In 2014, 63% 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, the wholesale electric market administrator, 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 under construction. 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 applies to all of AES Argentina’s plants, excluding TermoAndes. Based on Note 2053 sent by the Ministry of Energy in March 2013, it is understood that TermoAndes’ units are 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-

26




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 90 MW of capacity into the system. CAMMESA will finance the investment utilizing the outstanding receivables as a guarantee.
Key Financial Drivers
Financial results are likely to be driven by many factors including, but not limited to, the following:
Availability of generation - forced outages may impact earnings
Exposure to fluctuations of the Argentine peso
Hydrology
Lack of subsequent regulatory adjustments for cost increases
Timely collection of FONINVEMEM installment and outstanding receivables
Level of gas prices for contracted generation (Energy Plus)
Access to foreign exchange for imports
See Item 7.—Key Trends and UncertaintiesArgentina for further discussion of Argentina.
Brazil SBU
Our Brazil SBU has generation and distribution businesses. Our Brazil operations accounted for 24%, 27% and 27% of consolidated AES Operating Margin and 13%, 12% and 16% of consolidated AES Adjusted PTC (a non-GAAP measure) in 2014, 2013 and 2012, respectively. The percentages reflect the contribution by our Brazil SBU to gross operating margin and Adjusted PTC before deductions for Corporate.
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.
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
 
8.0 million customers (57,274 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, 2014, 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 the South of Brazil with an installed capacity of 640 MW.
Set forth in the table below is a list of our Brazil SBU generation facilities:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (% Rounded)
 
Year Acquired or Began Operation
 
Contract Expiration Date
 
Customer(s)
Tietê(1)
 
Brazil
 
Hydro
 
2,658

 
24
%
 
1999
 
2015
 
Eletropaulo
Uruguaiana
 
Brazil
 
Gas
 
640

 
46
%
 
2000
 
 
 
 
Brazil Total
 
 
 
 
 
3,298

 
 
 
 
 
 
 
 

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(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 20.1 million people and 6.7 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 3.5 million people and 1.3 million consumer units.
Set forth in the table below is a list of our Brazil SBU distribution facilities:
Business
 
Location
 
Approximate Number of Customers Served as of 12/31/2014
 
GWh Sold in 2014
 
AES Equity Interest (% Rounded)
 
Year Acquired
Eletropaulo
 
Brazil
 
6,682,000

 
47,583

 
16
%
 
1998
Sul
 
Brazil
 
1,270,000

 
9,691

 
100
%
 
1997
 
 
 
 
7,952,000

 
57,274

 
 
 
 
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 sells nearly 100% of its assured capacity, approximately 11,108 GWh, to Eletropaulo under a long-term PPA, which is expiring in December 2015. The contract is price-adjusted annually for inflation, and as of December 31, 2014, the price was R$206/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, 2014, Tietê's contracted portfolio position is 83% and 73% with average prices of R$132/MWh and R$133/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 in 2014 caused an increase in energy prices going forward. Tietê is closely monitoring and analyzing system supply conditions to support energy commercialization decisions. In 2014, 31 new contracts were signed at an average price of approximately R$147/MWh. Tietê's current view on energy prices for 2016 is in

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the range of R$245 - R$265/MWh, prior to adjustment for inflation, depending on the length of the contract (vs. R$125-R$135/MWh expectation in the beginning of 2014). 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 eventual Assured Energy reduction 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. Future prices could vary materially, depending on the supply and demand for electricity, hydrology and other market conditions.
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. 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 (February and March) and 2014 (March, April, and May) due to the short-term supply of LNG for the facility. Uruguaiana continues to work towards securing gas on a long-term basis.
Market Structure. Brazil has installed capacity of 123,973 MW, which is 74% hydroelectric, 16% thermal and 10% renewable (biomass and wind). Brazil's national grid is divided into four subsystems. Tietê sells into the Southeast subsystem of the national grid, while Uruguaiana sells into 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.
Hydrological risk is shared among hydroelectric generation plants through the MRE. 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 as well and they are able to make extra revenues selling the excess energy on the spot market.
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$690/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 forward. The lower cap price will result in a meaningful reduction on the expenses of the agents that are negatively exposed to the spot price in 2015. AES’ expectation for 2015 is that spot prices will be near the new regulatory cap of R$388/MWh and hydro power generators may purchase energy due to lower Assured Energy in the system as a result of unfavorable hydrological conditions. See Item 7. Key Trends and Uncertainties- Operational - Weather Sensitivity for further information.
Key Financial Drivers
As the system is highly dependent on hydroelectric generation, Tietê and Uruguaiana 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 sold
Re-contracting price
Asset management and plant availability
Cost management

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Ability to execute on its growth strategy
Through and beyond 2016, Uruguaiana 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 a 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, the ANEEL, a government agency, sets the tariff for each distribution company based on a Return on Asset Base methodology, which also benchmarks operational costs against other distribution companies.
The tariff charged to regulated customers consists of two elements: (i) pass-through of non-manageable costs under a determined methodology (“Parcel A”), including energy purchase costs, sector charges and transmission and distribution system expenses; and (ii) a manageable cost component (“Parcel B”), including operation and maintenance costs (defined by ANEEL), recovery of investments and a component for a return to the distributor. The return to distributors is calculated as the net asset base multiplied by the regulatory weighted-average cost of capital ("Regulatory WACC"), which is set for all industry participants during each tariff reset cycle. The current Regulatory WACC, after tax, is 7.5%. For the next tariff cycle which will be applied in July 2015 at Eletropaulo, the Regulatory WACC, after tax, will be 8.1%. This WACC will be updated again in three years before the next tariff review at 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.
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 2015. Sul’s tariff is reset every five years and the next tariff reset is expected in April 2018.
ANEEL has challenged the parameters of a tariff reset for Eletropaulo implemented in July 2012 and retroactive to 2011. ANEEL has asserted that during the period between 2007 and 2011, certain assets that were included in the regulatory asset base should not have been included and that Eletropaulo should refund customers for the return on the disputed assets earned during this period. On December 17, 2013, ANEEL determined, at the administrative level, that Eletropaulo should adjust the prior (2007-2011) regulatory asset base and refund customers in the amount of $269 million over a period of up to four tariff processes beginning in July 2014. 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.

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Key Financial Drivers
Through and beyond 2016, Eletropaulo and Sul 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
Eletropaulo's Fourth tariff cycle outcomes in July 2015
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).
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. In addition, Eletropaulo is involved in a dispute with Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) regarding a liability from the privatization of Eletropaulo. See Item 3.—Legal Proceedings for further discussion of this dispute. If Eletropaulo is found liable in the dispute, Eletropaulo's results from operations could be materially affected.
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 3,140 MW and distribution networks serving 1.3 million customers as of December 31, 2014. MCAC operations accounted for 18%, 17% and 16% of consolidated AES Operating Margin and 19%, 19% and 19% of consolidated AES Adjusted PTC (a non-GAAP measure) in 2014, 2013 and 2012, respectively. The percentages reflect the contribution by our MCAC SBU to gross Operating Margin and Adjusted PTC 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
 
3,140 gross MW (2,434 proportional MW)
Generation Facilities
 
14 (including 1 under construction)
Key Generation Businesses
 
Andres, Panama and TEG TEP
Utilities Penetration
 
1.3 million customers (3,620 GWh)
Utility Businesses
 
4
Key Utility Businesses
 
El Salvador

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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
 
Gas
 
319

 
92
%
 
2003
 
2018
 
Ede Este/Non-Regulated Users/Linea Clave
Itabo(1) 
 
Dominican Republic
 
Coal/Gas
 
295

 
46
%
 
2000
 
2016
 
Ede Este/Ede Sur/Ede Norte/Quitpe
DPP (Los Mina)
 
Dominican Republic
 
Gas
 
236

 
92
%
 
1996
 
2016
 
Ede Este
Dominican Republic Subtotal
 
 
 
 
 
850

 
 
 
 
 
 
 
 
AES Nejapa
 
El Salvador
 
Landfill Gas
 
6

 
100
%
 
2011
 
2035
 
CAESS
El Salvador Subtotal
 
 
 
 
 
6

 
 
 
 
 
 
 
 
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
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
 
 
 
 
 
705

 
 
 
 
 
 
 
 
Puerto Rico
 
US-PR
 
Coal
 
524

 
100
%
 
2002
 
2027
 
Puerto Rico Electric Power Authority
Puerto Rico Subtotal
 
 
 
 
 
524

 
 
 
 
 
 
 
 
MCAC Total
 
 
 
 
 
3,140

 
 
 
 
 
 
 
 
(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

 
92
%
 
1H 2017
Dominican Republic Subtotal
 
 
 
 
 
122

 
 
 
 
Estrella del Mar I
 
Panama
 
Fuel Oil
 
72

 
49
%
 
1H 2015
Panama Subtotal
 
 
 
 
 
72

 
 
 
 
MCAC Total
 
 
 
 
 
194

 
 
 
 
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 in the table below:
Business
 
Location
 
Approximate Number of Customers Served as of 12/31/2014
 
GWh Sold in 2014
 
AES Equity Interest (% Rounded)
 
Year Acquired
CAESS
 
El Salvador
 
576,000

 
2,108

 
75
%
 
2000
CLESA
 
El Salvador
 
365,000

 
865

 
80
%
 
1998
DEUSEM
 
El Salvador
 
74,000

 
125

 
74
%
 
2000
EEO
 
El Salvador
 
283,000

 
522

 
89
%
 
2000
 
 
 
 
1,298,000

 
3,620

 
 
 
 

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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 40% 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 $84 million with an 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 46%-owned by AES, 4% 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 MWs of installed capacity. Itabo's PPAs are with government-owned distribution companies and expire in 2016.
Andres and DPP are owned 92% by AES and 8% 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. This translates into a competitive advantage as we are currently purchasing LNG at prices lower than those on the international market. 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.
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 2015 in order to secure supply and competitive pricing for actual and future distribution energy requirements. The existing business strategy is to secure approximately 70% to 80% 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.

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Market Structure
Electricity Market. The Dominican Republic has one main interconnected system with approximately 3,700 MW of installed capacity, composed primarily of thermal generation (85%) and hydroelectric power plants (15%).
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 transportation and loading and compression plant; 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 2015 is close to 80%. 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.
New market rules for ancillary services enacted in 2014, particularly with regard to primary frequency regulation, reduced the revenues in the latter part of the 2014 and may impact future earnings
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 122 MW of gross capacity at an estimated cost of $275 million, fully financed with non-recourse debt. The EPC contract was signed on July 2, 2014, and the additional capacity is expected to become operational in the first quarter 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 representing 705 MWs of installed capacity, or 26% of the installed capacity in Panama. The majority of our capacity in Panama is run-of-river, with the exception of the 260 MW Bayano project.

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A portion of the distribution companies' PPAs will expire on December 2018 reducing the total contract capacity of the company from 424 MW to 350 MW and will remain at that level until December 2030.
Market Structure. Panama’s current total installed capacity is 2,759 MW, of which 56% is hydroelectric, 2% wind and the remaining 42% 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 in 2014 reduced generation output from hydroelectric facilities and increased spot prices for electricity. From March to June 2014, the government of Panama implemented certain energy saving measures designed to reduce demand for electricity during peak hours by approximately 300 MW, which contributed to water savings in the key hydroelectric dams and lower spot prices. AES Panama had to purchase energy on the spot market to fulfill its contract obligations as its generation output was below contract levels. 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 high spot prices for the additional energy purchased to fulfill contracts, partially mitigated by the compensation agreement with the government and the power barge which is expected to be operational in the first half of 2015
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
Spot prices are driven by hydrology since Panama is highly dependent on hydro generation (~56%), however, fluctuations in commodity prices, mainly oil prices, will affect the thermal generation cost impacting the spot prices and the opportunity cost of water
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 - Weather Sensitivity for further information.
Construction and Development.
Following the strategy to reduce reliance on hydrology, in September 2014 AES Panama acquired a a 72 MW gross capacity power barge for $27 million, financed with non-recourse debt. The barge arrived in Panama on September 25, 2014

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and is expected to become operational in the first half of 2015 with fuel to be supplied by Chevron. AES Panama executed a physical PPA for the supply of energy for a period of 5 years.
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.
Market Structure. Mexico has a single national electricity grid, the SEN, covering nearly all of Mexico’s territory. Mexico has an installed capacity totaling 54 GW with a generation mix of 74% thermal, 21% hydroelectric and 5% other. Electricity consumption is split between the following end users: industrial (58%), residential (26%) and commercial and service (16%).
Regulatory Framework
The CFE, mandated by the Mexican Constitution, is the state-owned electric monopoly that operates the national grid and generates electricity for the public. CFE regulates wholesale tariffs which are largely set by the marginal production cost of oil and gas-fired generation. The Mexican energy system is fully integrated under the sole responsibility of CFE. The Electric Public Service Law allows privately owned projects to produce electricity for self-supply application and/or IPP structures.
Under current regulatory framework, private parties are allowed to invest in certain activities in Mexico’s electric power market and obtain permits from the Ministry of Energy for: (i) generating power for self-supply; (ii) generating power through co-generation processes; (iii) generating power through independent production; (iv) small-scale production; and (v) importing and exporting electrical power. Permit holders are required to enter into PPAs with the CFE to sell all surplus power produced. Merida provides power exclusively to CFE under a long-term contract. TEG/TEP provides the majority of its output to two offtakers under long-term contracts and can sell any excess or surplus energy produced to CFE at a predetermined day-ahead price.
During 2014, the Mexican government promulgated the administrative regulations for the implementation of a new regulatory framework including the following aspects:
Electricity Reform: implementing a complete restructuring of the industry including permitting process, terms and conditions for transmission and distribution services and a wholesale electricity market, among others. Under the proposed reform, the CFE will be transformed into a Productive State Enterprise, including separation of the vertically-integrated monopoly into generation, transmission, distribution and marketing activities.
Regulations to the Geothermal Energy Law: setting forth details on terms and conditions of the permitting process and of the exploitation of the resources.
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 is a 524 MW coal-fired cogeneration plant utilizing CFB technology, representing approximately 9% of the installed capacity in Puerto Rico. The plant has a long-term PPA expiring in 2027 with the PREPA, a state-owned entity that supplies virtually all of the electric power consumed in Puerto Rico and generates, transmits and distributes electricity to 1.5 million customers. See Item 7. Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for further discussion of the long-term PPA with PREPA.
El Salvador
Business Description. AES 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

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territory covers 84% of the country. AES El Salvador accounted for 3,796 GWh of market energy purchases during 2014, or about 63% market share of the country’s total energy purchases.
The sector is governed by the General Electricity Law and the general and specific orders 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 13%, 13% and 14% of AES consolidated Operating Margin and 19%, 19% and 18% of AES consolidated Adjusted PTC (a non-GAAP measure) in 2014, 2013 and 2012, respectively. The percentages reflect the contribution by our Europe SBU to gross Operating Margin and Adjusted PTC before deductions for Corporate.
The following table provides highlights of our Europe operations:
Countries
 
Bulgaria, Jordan, Kazakhstan, Netherlands and United Kingdom
Generation Capacity
 
6,699 gross MW (4,989 proportional MW)
Generation Facilities
 
11
Key Generation Businesses
 
Maritza, Kilroot, Ballylumford, and Kazakhstan
Operating installed capacity of our Europe SBU totaled 6,699 MW. Set forth 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
 
247

 
60
%
 
2014
 
 
 
 
Jordan Subtotal
 
 
 
 
 
627

 
 
 
 
 
 
 
 
Ust-Kamenogorsk CHP
 
Kazakhstan
 
Coal
 
1,354

 
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
 
301

 
100
%
 
1997
 
Short-term
 
Various
Kazakhstan Subtotal
 
 
 
 
 
2,688

 
 
 
 
 
 
 
 
Elsta(2) 
 
Netherlands
 
Gas
 
630

 
50
%
 
1998
 
2018
 
Dow Benelux, Delta, Nutsbedrijven, Essent Energy
Netherlands Subtotal
 
 
 
 
 
630

 
 
 
 
 
 
 
 
Ballylumford
 
United Kingdom
 
Gas
 
1,246

 
100
%
 
2010
 
2023
 
Power NI and Single Electricity Market (SEM)
Kilroot(3)
 
United Kingdom
 
Coal/Oil
 
662

 
99
%
 
1992
 
 
 
SEM
United Kingdom Subtotal
 
 
 
 
 
1,908

 
 
 
 
 
 
 
 
Europe Total
 
 
 
 
 
6,699

 
 
 
 
 
 
 
 
(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”).

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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 the only coal-fired power plant in Bulgaria that is fully compliant with the EU Industrial Emission Directive, which comes into force in 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 2014 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 practice, an organized market for trading electricity has not yet evolved, so NEK remains the main wholesale buyer for power generated in Bulgaria.
Our investments in Bulgaria rely on long-term PPAs with NEK, the state-owned electricity public supplier and energy trading company. NEK is facing some liquidity issues and has been delayed in making payments under the PPAs with Maritza and St. Nikola. In May and June 2014, Bulgaria’s State Energy and Water Regulatory Commission (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 could further impact 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, including taking one of Maritza’s units out of the PPA and reducing the price of the remaining unit’s output by 30%. Maritza has filed appeals of these SEWRC decisions with the Supreme Administrative Court in Bulgaria. In November 2014, SEWRC issued a new decision withdrawing the specific PPA amendment conditions and replacing with instructions to start negotiations without conditions. In addition, SEWRC announced that it has asked the Directorate-General for Competition of the European Commission (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.
On July 24, 2014, the Bulgarian government formally resigned and the caretaker government was appointed by the President. Preliminary parliamentary elections were held on October 5, 2014. Eight political parties were elected and the biggest party, supported by another three, formed a coalition government. Meanwhile, the caretaker government requested and received the resignations of the former chairman and two commissioners of the Regulator. The new leadership approved an end-consumer energy price increase of approximately 10% effective October 1, 2014, which is expected to slightly improve NEK's liquidity. At this time, it is difficult to predict the impact of these political conditions and regulatory changes on our businesses in Bulgaria.
Maritza has experienced ongoing delays in the collection of outstanding receivables from NEK. In November 2013, Maritza and NEK signed an agreement to reschedule payments of the overdue balance as of the agreement date. By December

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2014, NEK has fulfilled its payment obligations under the agreement. On July 31, 2014, Maritza entered into a tripartite agreement with NEK and Mini Maritza Iztok EAD (MMI), our fuel supplier, which reduced Maritza's outstanding receivables from NEK by $17 million through an offset of payables due by Maritza to MMI. Additionally, NEK agreed to four additional monthly installments totaling $28 million to be paid equally from August to November 2014, which NEK made accordingly. As of December 31, 2014, Maritza had an outstanding receivables balance of $262 million including $57 million of current receivables, $75 million of receivables overdue by less than 90 days and $130 million of receivables overdue by more than 90 days. See Key Trends and Uncertainties, Macroeconomics, Bulgaria in Item 7—Management Discussion and Analysis to this Form 10-K for further information.
On February 18, 2014, Standard & Poor's lowered NEK's credit rating from BB- to B+ with a negative outlook. This credit rating is lower than the rating NEK had of BB upon the issuance of the Government Support Letter in 2005. Given the credit rating lowered, the PPA could be terminated at the discretion of Maritza and the lenders. Also, as a result of the restructuring, SEWRC revoked NEK's transmission license. These events trigger a cross default under the project debt agreements. See Item 1A.—Risk FactorsWe 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 following:
Availability of the operating units
Level of wind resource for St. Nikola
NEK’s ability to meet the terms of the PPA contract
United Kingdom
Business Description. AES’ generation businesses in the United Kingdom operate in the Irish SEM for the businesses located in Northern Ireland (1,908 MW). During 2014, AES sold its interests in four wind generation facilities totaling 87.5 MW located in Scotland and England which operated in the UK wholesale electricity market. AES is still continuing to develop a wind pipeline of approximately 250 MW in Scotland.
The Northern Ireland generation facilities consist of two plants within the Belfast region. Our Kilroot plant is a 662 MW coal-fired plant 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 capacity payments offered through the SEM Capacity Payment Mechanism, 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). In addition to the above, value is also secured from ancillary services.
Ballylumford is partially contracted for 600 MW under a PPA with NIE that expires in 2018, with an extension at the offtaker’s option through 2023, with the remaining capacity bid into the SEM market. The Ballylumford B station of 540 MW will not meet the standards of the EU Industrial Emission Directive following 2015. AES has secured a Local Reserve Services Agreement with the Transmission System Operator to refurbish two thermal units at the B station to provide at least 250 MW of capacity in the period 2016 to 2018 with an option to extend out to 2020. Ballylumford's key sources of revenue are availability payments received under the PPA and capacity payments offered through the SEM Capacity Payment Mechanism. Additionally, Ballylumford receives revenue from constrained dispatch through which the costs of operation are recovered from the market.
Market Structure. The majority of the generation capacity in the SEM is represented by gas-fired power plants, which results in market sensitivity to gas prices. Wind generation capacity represents approximately 18% of the total generation capacity. The governments of Northern Ireland and the Republic of Ireland plan further increases in renewables. Market availability and liquidity of hedging products are weak, reflecting the limited size and immaturity of the market, the predominance of vertical integration and lack of forward pricing. There are essentially three products (baseload, mid-merit and peaking) which are traded between the two largest generators and suppliers.

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Regulatory Framework
Electricity Regulation. The SEM is an energy market established in 2007 and is based on a gross mandatory pool within which all generators with a capacity higher than 10 MW must trade the physical delivery of power. Generators are dispatched based on merit order.
In addition, there is a capacity payment mechanism to ensure that sufficient generating capacity is offered to the market. The capacity payment is derived from a regulated Euro-based capacity payment pool, established a year ahead by the regulatory authority. Capacity payments are based on the declared availability of a unit and have a degree of volatility to reflect seasonal influences, demand and the actual out-turn of generation declared available over each trading period.
Environmental Regulation
The European Commission adopted in 2011 the IED that establishes the ELV for SO2, NOx and dust emissions to be complied with starting in 2016. This affects our Kilroot business which currently complies with the dust ELV, but for the SO2, and particularly NOx, significant investment will be required to be in compliance.
The IED provides for two options that may be implemented by the EU member states – TNP or Limited Life Time Derogation ("LLTD"). The TNP would allow the power plants to continue to operate between 2016-2020, being exempt from compliance with ELVs, but observing a ceiling set for maximum annual emissions that is established by looking at the last 10 years average emissions and operating hours. Under the TNP, power plants will have to implement investment plans that will ensure compliance by 2020. The LLTD will allow plants to run between 2016-2023, being exempt from the compliance with ELVs but for no more than 17,500 hours. Kilroot has elected the TNP as it gives the business significant operating flexibility without further investment. We are also reviewing the commercial positioning of the Kilroot business and the financial value that could be derived out of making the plant fully compliant with IED ELV’s post-2016. As of the end of 2014, favorable commodity pricing is supportive of this investment and we will be performance testing new low NOX technology in the second quarter of 2015. An investment of approximately $10 million is required to implement the TNP.
Key Financial Drivers
For our businesses in the SEM market, the financial results will be driven by, but not limited to, the following, and may change in 2017 due to regulatory changes to the market structure and payment mechanism:
Availability of the operating units
Commodity prices (gas, coal and CO2) and sufficient market liquidity to hedge prices in the short-term
Electricity demand in the SEM
Kazakhstan
Business Description. Our businesses account for approximately 4% of the total annual generation in Kazakhstan. Of the total capacity of 2,688 MW, 1,033 MW is hydroelectric and operates under a concession agreement until the beginning of October 2017 and 1,655 MW of coal-fired capacity is owned outright. The thermal plants are designed to produce heat with electricity as a co- or by-product.
The Kazakhstan businesses act as merchant plants for electricity sales by entering into bilateral contracts directly with consumers for periods of generally no more than one year. There are no opportunities for the plants to be in contracted status, as there is no central offtaker, and the few businesses that could take a whole plant’s generation tend to have in-house generation capacity. The 2012 amendments to the Electricity Law state that a centrally organized capacity market will be established by 2016, but the capacity offtaker still only signs annual contracts.
The hydroelectric plants are run-of-river and rely on river flow and precipitation, particularly snow. Due to the presence of a large multi-year storage dam upstream and a growing season minimum river flow rate agreement with Russia downstream, the plants are protected against significant downside risk to their volume in years with low precipitation. AES does not control water flow which impacts our generation.
Ust Kamenogorsk CHP provides heat to the city of Ust Kamenogorsk through the city heat network company (Ust Kamenogorsk Heat Nets). These sales could be considered as contracted, since Ust Kamenogorsk Heat Nets has no alternative suppliers.
Market Structure. The Kazakhstan electricity market totals approximately 20,591 MW, of which 17,108 MW is available. The bulk of the generating capacity in Kazakhstan is thermal with coal as the main fuel. As coal is abundantly available in Kazakhstan, most plants are designed to burn local coal. The geographical remoteness of Kazakhstan, in combination with its abundant resources, results in coal prices that are not reflective of world coal prices, current delivered cost is less than $24 per metric ton. In addition, the government closely monitors coal prices, due to their impact on the price of socially necessary heating and on electricity tariffs.

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Regulatory Framework
All Kazakhstan generating companies sell electricity at or below their respective tariff-cap level. These tariff-cap levels have been fixed by the Kazakhstan Government for the period 2009-2015 for each of the thirteen groups of generators. These groups were determined by the Ministry of Energy, previously Ministry of Industry and New Technologies, based on a number of factors including plant type and fuel used.
In July 2012, Kazakhstan enacted various amendments to its Electricity Law. Among the amendments was a requirement to reinvest all profits generated by electricity producers during the years 2013-2015. Accordingly, the business will be unable to pay dividends for the period 2013-2015. Under the amended Electricity Law, electricity producers must, on an annual basis, enter into IOAs with the Ministry of Energy. These annual IOAs must equal the sum of the upcoming year’s planned depreciation and profit. Selection of investment projects for the IOAs is at the discretion of electricity producers, but the Ministry of Energy has the right to reject submitted IOA proposals. An electricity producer without an IOA executed by the Ministry of Energy may not charge tariffs exceeding its incremental cost of production, excluding depreciation. In December 2014, the Ministry of Energy executed IOAs with all four AES generators in Kazakhstan, which allow revenue at the tariff-cap level, but all generated cash will need to be reinvested.
Heat production in Kazakhstan is also regulated as a natural monopoly. The heat tariffs are set on a cost-plus basis by making an application to the Regulator, the Committee of Natural Monopoly Regulation and Competition Protection). Currently, tariffs are only for multi-year periods, but with some annual adjustments for fuel cost.
Key Financial Drivers
The financial results for assets in Kazakhstan are driven by many factors including, but not limited to, the following, and may change in 2016 due to regulatory changes to the market structure and payment mechanism:
Availability of the operating units
Regulated electricity tariff-cap levels
Regulated heat tariff levels
Weather conditions
Other Europe Businesses
In Jordan, AES has a 37% controlling interest in Amman East, a 380 MW oil/gas-fired plant fully contracted with the national utility under a 25-year PPA. We also have a 60% controlling interest in the IPP4 plant in Jordan, a 247 MW oil-fired peaker plant fully contracted with the national utility under a 25-year PPA which commenced operations in July 2014. As we have controlling interest in these businesses, we consolidate the results in our operations.
In the Netherlands, we own 50% of the Elsta facility, a 630 MW gas-fired plant that supplies steam and electricity under long-term contracts ending in 2018. Elsta’s income is reported as Equity in Earnings of Affiliates in our consolidated results of operations.
In November 2014, AES sold its 95% ownership in a 294 MW gas-fired Ebute power plant in Nigeria to Cryex Energy Limited. The plant operated under a capacity-based PPA contract with the state-owned entity Power Holding Company of Nigeria (“PHCN”), which expired in November 2014. See Note 24Dispositions included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
In December 2014, AES sold its 49.62% ownership of 364 MW of hydroelectric and gas-fired plants in Turkey to its partner Koc Holdings. The Turkey hydro businesses were under the renewable feed-in tariff, while the gas assets were dispatched in the market. Our businesses in Turkey were operated under a joint venture structure and reported as Equity in Earnings of Affiliates. See Note 8Investments in and Advances to Affiliates included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Asia SBU
Our Asia SBU has generation facilities in four countries. Our Asia operations accounted for 2%, 5% and 7% of AES consolidated Operating Margin and 2%, 8% and 10% of AES consolidated Adjusted PTC (a non-GAAP measure) in 2014, 2013 and 2012, respectively. The percentages reflect the contribution by our Asia SBU to gross Operating Margin and Adjusted PTC before deductions for Corporate.

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The following table provides highlights of our Asia operations:
Countries
 
India, Philippines, Sri Lanka and Vietnam
Generation Capacity
 
1,218 gross MW (678 proportional MW)
Generation Facilities
 
5 (including 2 under construction)
Key Businesses
 
Masinloc, OPGC I and Mong Duong II
Operating installed capacity of our Asia SBU totals 1,218 MW. Set forth below in the table is a list of our Asia SBU generation facilities:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (% Rounded)
 
Year Acquired or Began Operation
 
Contract Expiration Date
 
Customer(s)
OPGC(1)
 
India
 
Coal
 
420

 
49
%
 
1998
 
2026
 
GRID Corporation Ltd.
India Subtotal
 
 
 
 
 
420

 
 
 
 
 
 
 
 
Masinloc
 
Philippines
 
Coal
 
630

 
51
%
 
2008
 
Mid and long-term
 
Various
Philippines Subtotal
 
 
 
 
 
630

 
 
 
 
 
 
 
 
Kelanitissa
 
Sri Lanka
 
Diesel
 
168

 
90
%
 
2003
 
2023
 
Ceylon Electricity Board
Sri Lanka Subtotal
 
 
 
 
 
168

 
 
 
 
 
 
 
 
Asia Total
 
 
 
 
 
1,218

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