2013 Form 10-K

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
____________________________________
FORM 10-K
_____________________________________ 
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2013
-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 28, 2013, the last business day of the Registrant’s most recently completed second fiscal quarter (based on the closing sale price of $11.87 of the Registrant’s Common Stock, as reported by the New York Stock Exchange on such date) was approximately $7.36 billion.
The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, on February 18, 2014 was 723,927,523
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant’s Proxy Statement for its 2013 annual meeting of stockholders are incorporated by reference in Parts II and III
 




THE AES CORPORATION
FISCAL YEAR 2013 FORM 10-K
TABLE OF CONTENTS




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 term “The AES Corporation” and “Parent Company” refers 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” projects and our ability to finance, construct and begin operating our “greenfield” 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 Power Purchase Agreements (“PPA”), 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, low levels of wind or sunlight for our wind and solar businesses, and the occurrence of difficult hydrological conditions for our hydro-power plants, as well as hurricanes and other storms and disasters;
•
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;

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•
the success of our initiatives in other renewable energy projects, as well as greenhouse gas 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, whether with or without adequate compensation;
•
our ability to achieve expected rate increases in our Utility businesses;
•
changes in laws, rules and regulations affecting our international businesses;
•
changes in laws, rules and regulations affecting our North America business, including, but not limited to, regulations which may affect competition, the ability to recover net utility assets and other potential stranded costs by our utilities;
•
changes in law resulting from new local, state, federal or international energy legislation and changes in political or regulatory oversight or incentives affecting our wind business, our solar joint venture, our other renewables projects and our initiatives in greenhouse gas 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, greenhouse gas 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;
•
the performance of business and asset acquisitions, including our acquisition of DPL Inc., and our ability to successfully integrate and operate acquired businesses and assets, such as DPL, and effectively realize anticipated benefits; and
•
information security breaches.
These factors in addition to others described elsewhere in this Form 10-K, including those described under Item 1A.—Risk Factors, and in subsequent securities filings, should not be construed as a comprehensive listing of factors that could cause results to vary from our forward-looking information.
We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.


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ITEM 1.
BUSINESS
Overview
We are a diversified power generation and utility company organized into six market-oriented Strategic Business Units (“SBUs”): US (United States), Andes (Chile, Colombia, and Argentina), Brazil, MCAC (Mexico, Central America and Caribbean), EMEA (Europe, Middle East and Africa), and Asia. We were incorporated in 1981.
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.
Strategy
Our strategic plan intends to maximize the risk-adjusted value of our portfolio for shareholders through our efforts to execute upon the following objectives:
•
First, we are managing our portfolio of generation and utility businesses to create value for our stakeholders, including customers and shareholders, through safe, reliable, and sustainable operations and effective cost management.
•
Second, we are driving our business to manage capital more effectively and to increase the amount of discretionary cash available for deployment into debt repayment, growth investments, shareholder dividends, and share buybacks.
•
Third, we are realigning our geographic focus. To this end, we will continue to exit markets where we do not have a competitive advantage or where we are unable to earn a fair risk-adjusted return relative to monetization alternatives. In addition, we will focus our growth investments on platform expansions or opportunities to expand our existing operations.
•
Finally, we are working to reduce the cash flow and earnings volatility of our businesses by proactively managing our currency, commodity and political risk exposures, mostly through contractual and regulatory mechanisms, as well as commercial hedging activities. We also will continue to limit our risk by utilizing non-recourse project financing for the majority of our businesses.
Business Lines & Strategic Business Units
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.
SBU
Generation Capacity (Gross MW)
 
Generation Facilities
 
Utility Customers
 
Utility GWh
 
Utility Businesses
US
 
 
 
 
 
 
 
 
 
Generation
6,015

 
13

 
 
 
 
 
 
Utilities
6,934

 
18

 
1.2 million
 
35,595

 
2

Andes
 
 
 
 
 
 
 
 
 
Generation
8,075

 
33

 
 
 
 
 
 
Brazil
 
 
 
 
 
 
 
 
 
Generation
3,298

 
13

 
 
 
 
 
 
Utilities
 
 
 
 
8.0 million
 
55,190

 
2

MCAC
 
 
 
 
 
 
 
 
 
Generation
3,140

 
13

 
 
 
 
 
 
Utilities
 
 
 
 
1.3 million
 
3,655

 
4

EMEA
 
 
 
 
 
 
 
 
 
Generation
7,513

 
23

 
 
 
 
 
 
Utilities
936

 
11

 
1.0 million
 
3,569

 
1

Asia
 
 
 
 
 
 
 
 
 
Generation
1,248

 
3

 
 
 
 
 
 
 
37,159

(1) 
127

 
11.5 million
 
98,009

 
9

(1) 
29,609 proportional MW. Proportional MW is equal to gross MW times AES’ equity ownership percentage.

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Generation
We currently own and/or operate a generation portfolio of 29,289 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 operations and maintenance (“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 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 are 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.

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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.
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.
36% of our generation plants are fueled by natural gas. Generally, we use gas from local supplies 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 Liquefied Natural Gas (“LNG”) to utilize in the local market.
5% of our generation fleet utilizes oil, diesel and petroleum coke (“pet coke”) for fuel. Oil and diesel are sourced locally at prices linked to international markets, while pet coke is largely sourced from Mexico and the U.S. The remaining 29% of our portfolio is comprised mostly of hydro, wind and solar generation plants, and energy storage capacity, which do not have significant fuel costs.
Renewable Generation Facilities
We currently own and operate 9,216 MW (4,959 proportional MW) of renewable generation, including hydro, wind, energy storage, biomass and landfill gas. Additionally, in 2008, we formed a 50/50 joint venture with Riverstone to develop, own and operate solar installations. Since its launch, Silver Ridge Power has commenced commercial operations of 522 MW (261 Proportional MW) of solar projects in Bulgaria, France, Greece, India, Italy, Puerto Rico and Spain, and has 266 MW (133 Proportional MW) under construction.
Energy Storage
AES has more than 170 MW of battery-based grid resources in commercial operation today, primarily in the U.S. and Chile. By adding these energy storage solutions to existing platforms in its SBUs, AES is better serving its customers’ needs for reliability services.  AES is working to further develop its energy storage fleet by adding storage capabilities to projects in operation and construction and those in advanced development. One key market AES is exploring for energy storage development is California, where the Utilities Commission approved a target for procurement of approximately 1,300 MW of storage-based resources.
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.

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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’ 9 utility businesses distribute power to more than 11 million people in four countries. These businesses also include generation capacity totaling 7,870 MW (7,458 proportional MW). These 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, Indianapolis Power & Light Company (“IPL”). Components of the tariff that are directly passed through to the customer are usually adjusted through a summary regulatory process or an existing formula-based mechanism. In some regulatory regimes, customers with demand above an established level are unregulated and can choose to contract with other retail energy suppliers directly and pay a wheeling and other non-bypassable fees, which are fees to the distribution company for use of its distribution system.
The regulated tariff generally recognizes that our utility businesses should recover certain operating and fixed costs, as well as manage uncollectible amounts, quality of service and non-technical losses. Utilities therefore need to manage costs to the levels reflected in the tariff or risk non-recovery of costs or diminished returns.
Seasonality, Weather Variations and Economic Activity
Our utility businesses are affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses are not generated evenly by month during the year. Additionally, weather variations may also have an impact based on the number of customers, temperature variances from normal conditions and customers’ historic usage levels and patterns. The retail kilowatt hours (“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.

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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 The Dayton Power & Light Company (“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 of 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, can leave and choose to return to regulated service.
Development and Construction
We develop and construct new generation facilities. For our utility businesses, new plants may be built in response to customer needs or to comply with regulatory developments and are developed subject to regulatory approval that permits recovery of our capital cost and a return on our investment. For our generation businesses, our priority for development is platform expansion opportunities, where we can add on to our existing facilities in our key platform markets where we have a competitive advantage. We make the decision to invest in new projects by evaluating the project returns and financial profile against a fair risk-adjusted return for the investment and against alternative uses of capital, including corporate debt repayment and share buybacks.
In some cases, we enter into long-term contracts for output from new facilities prior to commencing construction. To limit required equity contributions from The AES Corporation, we also seek non-recourse project debt financing and other sources of capital, including partners where it is commercially attractive. For construction, we typically contract with a third party to manage construction, although our construction management team supervises the construction work and tracks progress against the project's budget and the required safety, efficiency and productivity standards.
Environmental Matters
We are subject to various international, federal, state, and local regulations in all of our markets. These regulations govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity.
We are also subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, suspension or revocation of permits and/or facility shutdowns. See later in Item 1.—Business — Environmental and Land Use Regulations for further regulatory and environmental discussion.
Strategic Business Units
All SBUs include generation facilities and four include utility businesses. The Company measures the operating performance of its SBUs using Adjusted Pre-Tax Contribution (“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 contribution to Adjusted PTC by SBU for the year ended December 31, 2013 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.

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In 2013, approximately 73% of Adjusted PTC was contributed by our businesses in the Americas - including the US, Andes, Brazil and MCAC SBUs. Asia and EMEA accounted for the remaining 27%.
We define Adjusted PTC as pre-tax 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) significant gains or losses due to dispositions and acquisitions of business interests, (d) significant 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 PTC in each SBU includes the effect of intercompany transactions with other SBUs other than interest and charges for certain management services.
Risks
We routinely encounter and address risks, some of which may cause our future results to be different, sometimes materially different, than we presently anticipate. The categories of risk we have identified in Item 1A.—Risk Factors of this Form 10-K include the following:
•
risks related to our high level of indebtedness;
•
risks associated with our ability to raise needed capital;
•
external risks associated with revenue and earnings volatility;
•
risks associated with our operations; and
•
risks associated with governmental regulation and laws.
The categories of risk identified above are discussed in greater detail in Item 1A.—Risk Factors of this Form 10-K. These risk factors should be read in conjunction with Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the Consolidated Financial Statements and related notes included elsewhere in this report.
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 strategic business units (“SBUs”) — led by our Chief Executive Officer (“CEO”). During the fourth quarter of 2013, in conjunction with finalization of its reporting structure, the Company revised its internal reporting to align more closely with its operations. As a result, the

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Company applied the accounting guidance for segment reporting and determined that its reportable segments are aligned with the six SBUs as below:
•
US SBU
•
Andes SBU
•
Brazil SBU
•
MCAC SBU
•
EMEA 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 17—Segment and Geographic Information included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion of the Company’s segment structure used for financial reporting purposes.
Silver Ridge Power and certain other unconsolidated businesses are accounted for using the equity method of accounting. Therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Consolidated Statements of Operations, not in revenue and operating margin.
“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 17—Segment 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.
The following describes our businesses within our six SBUs:
US SBU
Our US SBU has 14 generation facilities and two integrated utilities in the United States. Our US operations accounted for 21%, 20% and 10% of consolidated AES operating margin and 24%, 20% and 10% of consolidated AES adjusted PTC (a non-GAAP measure) in 2013, 2012 and 2011, respectively. The percentages shown are the contribution by our US SBU to gross operating margin and adjusted PTC before deductions for Corporate.
The following table provides highlights of our U.S. operations:
Generation Capacity
 
12,949 gross MW (12,949 proportional MW)
Utilities Penetration
 
1,170,000 customers (35,595 GWh)
Generation Facilities
 
14
Utility Businesses
 
2 integrated utilities (includes 18 generation plants)
Key Generation Businesses
 
Southland, Hawaii and US Wind
Key Utility Businesses
 
IPL and DPL

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Operating installed capacity of our US SBU totals 12,949 MW. IPL’s parent, IPALCO Enterprises, Inc., and DPL Inc. are SEC registrants, and as such, follow public filing requirements of the Securities Exchange Act of 1934. Set forth in the table below is a list of our U.S. generation businesses:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Ownership (Percent, Rounded)
 
Year Acquired or Began Operation
Southland—Alamitos
 
US—CA
 
Gas
 
2,075

 
100
%
 
1998
Southland—Redondo Beach
 
US—CA
 
Gas
 
1,392

 
100
%
 
1998
Southland—Huntington Beach
 
US—CA
 
Gas
 
474

 
100
%
 
1998
Shady Point
 
US—OK
 
Coal
 
360

 
100
%
 
1991
Buffalo Gap II(1)
 
US—TX
 
Wind
 
233

 
100
%
 
2007
Hawaii
 
US—HI
 
Coal
 
206

 
100
%
 
1992
Warrior Run
 
US—MD
 
Coal
 
205

 
100
%
 
2000
Buffalo Gap III(1)
 
US—TX
 
Wind
 
170

 
100
%
 
2008
Deepwater
 
US—TX
 
Pet Coke
 
160

 
100
%
 
1986
Beaver Valley
 
US—PA
 
Coal
 
132

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

 
100
%
 
2006
Armenia Mountain(1)
 
US—PA
 
Wind
 
101

 
100
%
 
2009
Laurel Mountain
 
US—WV
 
Wind
 
98

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

 
100
%
 
2008
Laurel Mountain ES(3)
 
US—WV
 
Energy Storage
 
64

 
100
%
 
2011
Mountain View IV
 
US—CA
 
Wind
 
49

 
100
%
 
2012
Tait ES(3)
 
US—OH
 
Energy Storage
 
40

 
100
%
 
2013
Tehachapi
 
US—CA
 
Wind
 
38

 
100
%
 
2006
Palm Springs
 
US—CA
 
Wind
 
30

 
100
%
 
2005
 
 
 
 
 
 
6,015

 
 
 
 
(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 Sheet.
(2)
AES operates these facilities located throughout the US through management or O&M agreements and owns no equity interest in these businesses.
(3) 
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 U.S. utilities and their generation facilities:
Business
 
Location
 
Approximate Number of Customers Served as of 12/31/2013
 
GWh Sold in 2013
 
AES Equity Interest (Percent, Rounded)
 
Year
Acquired
DPL
 
US—OH
 
693,000

 
19,561

 
100
%
 
2011
IPL
 
US—IN
 
477,000

 
16,034

 
100
%
 
2001
 
 
 
 
1,170,000

 
35,595

 
 
 
 
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (Percent, Rounded)
 
Year Acquired or Began Operation
DPL(1)
 
US—OH
 
Coal/Diesel/Solar
 
3,453

 
100
%
 
2011
IPL(2)
 
US—IN
 
Coal/Gas/Oil
 
3,481

 
100
%
 
2001
 
 
 
 
 
 
6,934

 
 
 
 
(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: Beckjord Unit 6, Conesville Unit 4, East Bend Unit 2, 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. DPLE Energy, LLC plants: Tait Units 4-7 and Montpelier Units 1-4.
(2) 
IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg.

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The following map illustrates the location of our U.S. 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 more than 470,000 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 919,000. 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 (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 3,272 MW and net summer capacity is 3,148 MW.
Market Structure. IPL is one of many transmission system owner members in the Midcontinent Independent System Operator, Inc. (“MISO”). MISO is a Regional Transmission Organization ("RTO"), which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. IPL offers the available electricity production of each of its generation assets into the MISO day-ahead and real-time markets. MISO operates on a merit order dispatch, considering transmission constraints and other reliability issues to meet the total demand in the MISO region.
Regulatory Framework
Retail Ratemaking. In addition to the regulations referred to below in “U.S. Regulatory Matters”, IPL is subject to regulation by the Indiana Utility Regulatory Commission (“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 Fuel Adjustment Charges (“FAC”), and for the timely recovery of costs incurred to comply with environmental laws and regulations referred to as Environmental Compliance Cost Recovery Adjustment

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(“ECCRA”). See Senate Bill 251 discussion under Other United States Environmental and Land Use Legislation and Regulations later in this section. 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.
Environmental Matters
Mercury and Air Toxics Standards (“MATS”). IPL has 2,623 MW of coal-fired generation, which is subject to MATS regulation. IPL plans to retire 472 MW (529 MW gross capacity) and install environmental upgrades on 2,125 MW (2,426 MW gross capacity). Most of IPL’s coal-fired capacity has acid gas scrubbers or comparable control technologies; however, there are other improvements to these control technologies that are necessary to achieve compliance. 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 from AES; borrowing capacity on IPL’s committed credit facilities; and cash generated from operating activities.

Replacement Generation. IPL has several generating units that we expect 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, in April 2013, IPL filed a petition and case-in-chief with the IURC seeking a Certificate of Public Convenience and Necessity (“CPCN”) to build a 550 to 725 MW combined cycle gas turbine (“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). The total estimated cost of these projects is $667 million. IPL is seeking 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 until such time that IPL is allowed to collect a return and depreciation expense on the CCGT. If approved, the CCGT is expected to be placed into service in April 2017 and the refueling project is expected to be complete by April 2016. For the refueling project, we are requesting timely recovery of 80% of the revenue requirement of these federally mandated costs under Senate Bill 251, and deferral of the remaining 20% until the resolution of a base rate case filed with the IURC. If Harding Street Units 5 and 6 are not refueled, they will likely need to be retired because it is currently not economical to install controls on those units to comply with MATS. If we receive approval for the CCGT, the costs to build and operate the equipment would not be recoverable by IPL until the resolution of a base rate case with the IURC. IPL expects to receive an order on this matter from the IURC in the second quarter of 2014.
National Pollution Discharge Elimination System (“NPDES”). On August 28, 2012, Indiana Department of Environmental Management (“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 is conducting studies to determine what operational changes and/or additional equipment will be required to comply with the new limitations. 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. See Water Discharges discussion under Other United States Environmental and Land Use Legislation and Regulations for further details of NPDES later in this section.
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.
DPL Inc. ("DPL")
Business Description. DPL is an energy holding company whose principal subsidiaries include DP&L, DPL Energy, LLC (“DPLE”), and DPL Energy Resources, Inc. (“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 partnerships, owns 2,897 MW of generation capacity and numerous transmission facilities.

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DPLE owns peaking generation units representing 556 MW located in Ohio and Indiana.
DPLER, a competitive retail marketer, sells retail electricity to more than 308,000 retail customers in Ohio and Illinois. Approximately 130,000 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 Competitive Retail Electric Service Provider (“CRES Provider”) or continue to purchase power from their local utility under Standard Service Offer (“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 will no longer be supplied by DP&L but will be provided by third parties through the competitive bid process. Ten percent of the SSO load will be sourced through competitive bid in 2014, 40% in 2015, 70% in 2016 and 100% in 2017. The Public Utilities Commission of Ohio (“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.
Overall power market prices, as well as government aggregation initiatives within DP&L’s service territory, have led or may lead to the entrance of additional competitors in its service territory. During the year ended December 31, 2013, approximately 42% of customers representing 67% of 2013’s overall energy usage (kWh) within DP&L’s service area had elected to obtain their supply service from CRES Providers. DPL’s subsidiary DPLER is a CRES Provider that has been marketing generation services to customers in Ohio and Illinois, both inside and outside DP&L's service territory. During 2013, DPLER accounted for approximately 5,874 million kWh (63%) and other CRES Providers accounted for about 3,471 million kWh (37%) of the total 9,345 million kWh supplied by CRES Providers within DP&L’s service territory. The volume supplied by DPLER represents 42% of DP&L’s total distribution volume during 2013. DPL currently cannot determine the extent to which customer switching to CRES Providers will occur in the future and the impact this will have on its operations, but any additional switching could have a material adverse effect on its future results of operations, financial condition and cash flows.
PJM Operations. DP&L is a member of the PJM Interconnection, LLC (“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 Federal Energy Regulatory Commission ("FERC"). The Reliability Pricing Model (“RPM”) is PJM’s capacity construct. The purpose of RPM is to enable PJM to obtain sufficient resources to reliably meet the needs of electric customers within the PJM footprint. PJM conducts an auction to establish the price by zone. DP&L’s capacity has been located in the rest of the RTO area of 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, 2017 through May 30, 2018 are expected to take place in May of 2014. 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 2016/17 are as follows:
Auction Year (June 01- May 31)
 
2016/17
 
2015/16
 
2014/15
 
2013/14
 
2012/13
 
2011/12
Capacity Clearing Price ($/MW-Day)
 
$59
 
$136
 
$126
 
$28
 
$16
 
$110
Capacity Cleared (MW)
 
3,125
 
3,099
 
3,455
 
3,283
 
3,609
 
3,666
On a calendar-year basis, capacity prices and annual capacity revenues earned or projected to be earned by DPL are as follows:
Year
 
2016
 
2015
 
2014
 
2013
 
2012
Computed Average Capacity Price ($/MW-Day)
 
$91
 
$132
 
$85
 
$23
 
$55
Computed Gross RPM Capacity Revenue ($ millions)
 
$104
 
$156
 
$107
 
$29
 
$75

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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 2013, 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 June 1, 2017.
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.
In 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 in September 2013 (the “ESP Order”), which states that DP&L’s next ESP begins January 1, 2014 and extends through May 31, 2017. DP&L’s prior rate structure remained in place until January 1, 2014. The primary provisions of the ESP Order are as follows:
•
DP&L to collect a non-bypassable Service Stability Rider (“SSR”) equal to $110 million per year for 2014 through 2016. DP&L has the opportunity to seek an additional $46 million through a five-month extension of the SSR, provided it meets certain regulatory filing obligations. Such obligations include, but are not limited to: (a) filing a divestiture plan with the PUCO by December 31, 2013 to separate DP&L’s generation assets from the utility; and (b) filing a distribution rate case no later than July 1, 2014;
•
DP&L must separate its generation assets no later than May 31, 2017 through a transfer of the assets to a DPL affiliate or a divestiture; and
•
DP&L must phase-in a competitive bidding structure with 10% of DP&L’s SSO load sourced through the competitive bid starting in January 2014, 40% in 2015, 70% in 2016 and 100% by June 2017.

On October 28, 2013, DP&L conducted its first competitive bidding process as required by the ESP, which resulted in an average clearing price of $49.32 per MWh for 10% of its SSO load for the delivery period January 1, 2014 through May 31, 2017. The competitive bidding process determined who will provide generation service for 10% of DP&L’s SSO for January 1, 2014 through May 31, 2017 load at this price. The net effect will be a lower operating margin in future years. The 2014 auction will determine who will provide generation service for an additional 30% of DP&L’s SSO load for January 1, 2015 through May 31, 2017; and the 2016 auction will determine who will provide generation service for an additional 30% for DP&L’s SSO load for January 1, 2016 through May 31, 2017. Future blended rates, beyond 2014, are dependent on the actual auction results that will take place on an annual basis.

DP&L filed a generation separation application at the end of December 2013, as required in its ESP order, with the PUCO and on February 25, 2013, filed a supplemental application.  In the supplemental application, DP&L reaffirmed its commitment to separate the generation assets on or before May 31, 2017.  DP&L continues to look at multiple options to effectuate the separation including the transfer to an unregulated affiliate or through a sale process.  Assuming a transfer to an affiliate, we have requested the ability for the DP&L to, among other things:  (a) maintain the greater of, (i) total debt of up to $750 million; or (ii) total debt equal to 75% of rate base; (b) transfer the assets at a fair market value; and (c) keep OVEC as part of the utility post separation.
Environmental Matters
In relation to MATS, 3,246 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. However, DP&L has 207 MW of generation capacity

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that is jointly-owned and expected to cease operations due to the inability to comply with the requirements under MATS. For more information see Other United States Environmental and Land Use Legislation and Regulations discussion later in this section.
Key Financial Drivers
Although the recent ESP decision provides 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: $73 million in 2013 and allowed to earn $110 million annually from 2014 through 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 and lower the amount of non-recourse debt at DPL
See Item 1A.—Risk Factors for additional discussion on DPL.
U.S. Generation
Business Description. In the U.S., we own a diversified generation portfolio in terms of geography, technology and fuel source. The principal markets where we are engaged in the generation and supply of electricity (energy and capacity) are the Western Electricity Coordinating Council (“WECC”), PJM, Southwest Power Pool Electric Energy Network (“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 6% 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 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.
Regulatory Framework
Environmental Matters.

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For a discussion of environmental regulatory matters affecting U.S. Generation, see “Environmental and Land Use Regulations” below.
Key Financial Drivers
AES Southland’s contractual availability is the single most important driver of operations. Its units are generally required to achieve at least 86% availability in each contract year; AES Southland has historically met or exceeded its contractual availability.
Additional U.S. Generation Businesses
Business Description. Additional businesses include thermal and wind generating facilities, of which AES Hawaii and our U.S. wind generation business are the most significant.
Many of our U.S. generation plants provide baseload operations and are required to maintain a guaranteed level of availability. Any change in availability has a direct impact on financial performance. The plants are generally eligible for availability bonuses on an annual basis if they meet certain requirements. In addition to plant availability, fuel cost is a key business driver for some of our facilities.
AES Hawaii. AES Hawaii receives a fuel payment from its offtaker, which is based on a fixed rate indexed to the Gross National Product – Implicit Price Deflator (“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 February 2015; the business could be subject to variability in coal pricing beginning in March 2015. To mitigate fuel risk beyond February 2015, AES Hawaii plans to seek additional fuel purchase commitments on favorable terms. However, if market prices rise and AES Hawaii is unable to procure coal supply on favorable terms, the financial performance of AES Hawaii could be materially and adversely affected.
U.S. Wind. AES has 1,039 MW of wind capacity in the U.S., primarily located in California, Texas and West Virginia. Typically, these facilities sell under long-term PPAs. AES financed most of these projects with tax-equity structures. AES manages the wind portfolio as part of its broader investments in the U.S., leveraging operational and commercial resources to supplement the experienced subject matter experts in the wind industry to achieve optimal results.
Market Structure. Two of the primary fuels used by our U.S. generation facilities, coal and pet coke, are commodities with international prices set by market factors, although the price of the third 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 U.S. with PPAs have mechanisms to recover fuel costs from the offtaker, including an energy payment that is partially based on the market price of coal. In addition, these businesses often have an opportunity to increase or decrease profitability from payments under their PPAs depending on such items as plant efficiency and availability, heat rate, ability to buy coal at lower costs through AES’ global sourcing program, and fuel flexibility. Revenue may change materially as prices in fuel markets fluctuate, but the variable margin or profitability should not be materially changed when market price fluctuations in fuel are borne by the offtaker.
Regulatory Framework. Several of our generation businesses in the United States, currently operate as Qualifying Facilities (“QFs”) as defined under the Public Utility Regulatory Policies Act (“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 must 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 Exempt Wholesale Generators (“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 Federal Power Act (“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

16



regulated affiliates of the seller. To prevent market manipulation, FERC requires sellers with market-based rate authority to file certain reports, including a triennial updated market power analysis for markets in which they control certain threshold amounts of generation.
Other Regulatory Matters
The U.S. wholesale electricity market consists of multiple distinct regional markets that are subject to both federal regulation, as implemented by the U.S. FERC, and regional regulation as defined by rules designed and implemented by the RTOs, non-profit corporations that operate the regional transmission grid and maintain organized markets for electricity. These rules for the most part govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity. See Item 1A.—Risk Factors for additional discussion on U.S. regulatory matters.
Our businesses are subject to emission regulations, which may result in increased operating costs or the purchase of additional pollution control equipment if emission levels are exceeded. Our businesses periodically review their obligations for compliance with environmental laws, including site restoration and remediation. Because of the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued, if any. For a discussion of environmental laws and regulations affecting the U.S. business, see Other United States Environmental and Land Use Legislation and Regulations later in this section. In April 2012, the EPA’s rule to establish maximum achievable control technology standards for each hazardous air pollutant regulated under the Clean Air Act (“CAA”) emitted from coal and oil-fired electric utilities, known as MATS became effective.
Andes SBU
Our Andes SBU has generation facilities in three countries — Chile, Colombia and Argentina. Our Andes operations accounted for 17%, 16% and 19% of consolidated AES Operating Margin and 19%, 18% and 29% of AES Adjusted PTC (a non-GAAP measure) in 2013, 2012 and 2011, respectively. The percentages shown are 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
 
8,075 gross MW (6,189 proportional MW)
Generation Facilities
 
37 (including 4 under construction)
Key Generation Businesses
 
AES Gener, Chivor and AES Argentina

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Operating installed capacity of our Andes SBU totals 8,075 MW, of which 44%, 43% and 13% 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 (Percent, Rounded)
 
Year Acquired or Began Operation
Chivor
 
Colombia
 
Hydro
 
1,000

 
71
%
 
2000
Colombia Subtotal
 
 
 
 
 
1,000

 
 
 
 
Gener(1)
 
Chile
 
Hydro/Coal/Diesel/Biomass
 
985

 
71
%
 
2000
Guacolda(2)
 
Chile
 
Coal/Pet Coke
 
608

 
35
%
 
2000
Electrica Angamos
 
Chile
 
Coal
 
545

 
71
%
 
2011
Electrica Santiago(3)
 
Chile
 
Gas/Diesel
 
479

 
71
%
 
2000
Norgener
 
Chile
 
Coal/Pet Coke
 
277

 
71
%
 
2000
Electrica Ventanas(4)
 
Chile
 
Coal
 
272

 
71
%
 
2010
Electrica Campiche(5)
 
Chile
 
Coal
 
272

 
71
%
 
2013
Electrica Angamos ES(6)
 
Chile
 
Energy Storage
 
40

 
71
%
 
2011
Gener - Norgener ES (Los Andes)(6)
 
Chile
 
Energy Storage
 
24

 
71
%
 
2009
Chile Subtotal
 
 
 
 
 
3,502

 
 
 
 
TermoAndes(7)
 
Argentina
 
Gas/Diesel
 
643

 
71
%
 
2000
AES Gener Subtotal
 
 
 
 
 
5,145

 
 
 
 
Alicura
 
Argentina
 
Hydro
 
1,050

 
100
%
 
2000
Paraná-GT
 
Argentina
 
Gas/Oil/Biodiesel
 
845

 
100
%
 
2001
San Nicolás
 
Argentina
 
Coal/Oil/Gas
 
675

 
100
%
 
1993
Los Caracoles(8)
 
Argentina
 
Hydro
 
125

 
—
%
 
2009
Cabra Corral
 
Argentina
 
Hydro
 
102

 
100
%
 
1995
Quebrada de Ullum(8)
 
Argentina
 
Hydro
 
45

 
—
%
 
2004
Ullum
 
Argentina
 
Hydro
 
45

 
100
%
 
1996
Sarmiento
 
Argentina
 
Gas/Diesel
 
33

 
100
%
 
1996
El Tunal
 
Argentina
 
Hydro
 
10

 
100
%
 
1995
Argentina Subtotal
 
 
 
 
 
2,930

 
 
 
 
Andes Total
 
 
 
 
 
8,075

 
 
 
 
(1)
Gener plants: Alfalfal, Laguna Verde, Laguna Verde Turbogas, Laja, Los Vientos, Maitenes, Queltehues, San Francisco de Mostazal, Santa Lidia, Ventanas and Volcán.
(2)
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.
(3)
Electrica Santiago plants: Nueva Renca and Renca.
(4)
Electrica Ventanas plant: Nueva Ventanas.
(5) 
Electrica Campiche plant: Ventanas IV.
(6) 
Energy Storage MW are power plant equivalent dispatchable resource, including supply and load capability.
(7)
TermoAndes is located in Argentina, but is connected to both the SING in Chile and the SADI in Argentina.
(8)
AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses.
Under construction
The following table lists our plants under construction in the Andes SBU: 
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (Percent, Rounded)
 
Expected Year of Commercial Operations
Gener - Cochrane
 
Chile
 
Energy Storage
 
40

 
42
%
 
2016
Gener - Cochrane
 
Chile
 
Coal
 
532

 
42
%
 
2016
Gener - Alto Maipo
 
Chile
 
Run-of-River Hydro
 
531

 
42
%
 
2018
Gener—Guacolda V
 
Chile
 
Coal
 
152

 
35
%
 
2015
Chile Subtotal
 
 
 
 
 
1,255

 
 
 
 
Chivor—Tunjita
 
Colombia
 
Hydro
 
20

 
71
%
 
2014
Colombia Subtotal
 
 
 
 
 
20

 
 
 
 
Andes Total
 
 
 
 
 
1,275

 
 
 
 


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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 Central Interconnected Electricity System (“SIC”) and Northern Interconnected Electricity System (“SING”). In terms of aggregate installed capacity, AES Gener is the second largest generation operator in Chile with an installed capacity of 4,081 MW, including TermoAndes and excluding energy storage, and a market share of 22% as of December 31, 2013.
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 back-up 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 2013. Additionally, we are constructing an additional 1,255 MW, comprised of 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, which includes both regulated and unregulated customers. AES Gener reserves its higher variable cost units as designated back-up 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 Economic Load Dispatch Center (“CDEC”) at the system marginal cost.
AES Gener currently has long-term contracts, with average terms of 13 and 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, which periodically adjust prices based on the generation

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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 statistical information regarding maintenance periods and water inflows in the case of hydroelectric plants. The capacity price is fixed by the National Energy Commission (“CNE”) in the semi annual 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 14,080 MW as of December 31, 2013. 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 2013, thermoelectric generation represented 71% of the total generation in Chile. In the SIC, thermoelectric generation represents 55% of installed capacity, is required to fulfill demand not satisfied by hydroelectric output, and is critical to guaranteeing reliable and dependable electricity supply under dry hydrological conditions. In the SING, which includes the Atacama Desert, the driest desert in the world, thermoelectric capacity represents 99.7% of installed capacity. The fuels used for generation, mainly coal, diesel and LNG, have 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 occurs 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 2013, hydroelectric generation represented 39% 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 amongst 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 particulate matter 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 particulate matter emissions went into effect at the end of 2013 and the new limits for SO2 (sulfur dioxide), NOx (nitrogen dioxide) 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

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(Ventanas I and II and Norgener I and II, constructed between 1964 and 1997) in 2012. As of December 31, 2013, AES Gener has invested approximately $155 million and expects the remaining $96 million will be invested in 2014, in order to comply within the required time frame. Additionally, its equity method investee Guacolda started the installation of new equipment during 2013, spending approximately $36 million (Guacolda I, II and IV) and the remaining $185 million will be invested between 2014 and 2016.
Chilean law requires every electricity generator to supply a certain portion of its total contractual obligations with non-conventional renewable energies (“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 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.
Key Financial Drivers
In Chile, AES Gener’s contracting strategy, determining both the amount of capacity to contract or leave uncommitted for spot market sales and the relevant pricing formulas including indexation, is important to our profitability. AES Gener aligns its contracts with its efficient generation capacity, contracting a significant portion of its efficient capacity under long-term contracts, while reserving its higher variable cost units for sales on the spot market. The performance of its generating assets, efficiency and availability, is also a critical part of its strategy in order to maximize contracted margins and avoid exposure to spot price volatility.
In the SIC, hydrological conditions are also an important financial driver, since they largely influence plant dispatch and, therefore, spot market prices. AES Gener becomes a short-term purchaser of electricity from other generation companies during rainy hydrological conditions, when spot market prices are at their lowest, and AES Gener’s spot sales of electricity generated by their back-up facilities increase in periods of low water conditions, when spot market prices are at their highest. Both extreme hydrological conditions provide AES Gener with improved earnings and cash flow.
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 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, which is scheduled to begin operations in the second half of 2015, and the 532 MW Cochrane project in the SING, which is 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, 2013, AES Gener’s net power production in Colombia was 3,373 GWh (5% 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 7% of system capacity as of December 31, 2013. 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.

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Additionally, Chivor receives reliability payments for the availability and reliability of Chivor’s reservoir during periods of scarcity, such as adverse hydrological conditions. These payments, referred to as “reliability charge payments” are designed to compensate generation companies for the firm energy that they are capable of providing to the system during critical periods of low supply in order to prevent electricity shortages.
Market Structure
Electricity supply in Colombia is concentrated in one main system, the National Interconnected System (“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 14,600 MW as of December 31, 2013, comprised of 67% hydroelectric generation, 32% thermoelectric generation and 1% other. The dominance of hydroelectric generation and the marked seasonal variations in Colombia’s hydrology result in price volatility in the short-term market. In 2013, 72% of total energy demand was supplied by hydroelectric plants with the remaining supply from thermoelectric generation (27%) and cogeneration and self-generation power (1%). From 2003 to 2013, electricity demand in the SIN has grown at a compound annual growth rate of 2.9% and the Mining and Energetic Planning Unit (“UPME”) projects an average compound annual growth rate in electricity demand of 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 Energy and Gas Regulation Commission (“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 2014. 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. Additionally, a proposal has been discussed that would allow authorities to dictate emergency energy situations, in cases such as severe drought conditions, in order to implement measures to prevent shortages and other negative economic impacts.
Key Financial Drivers
Hydrological conditions largely influence Chivor’s generation level. Maintaining the appropriate contract level, while working to maximize revenue, through sale of excess generation, is key to Chivor’s results of operations.
In Colombia, AES Gener is currently constructing the 20 MW Tunjita run-of-river hydroelectric project, which is scheduled to start operations in the second half of 2014.
Argentina
Our Business. As of December 31, 2013, AES Argentina operates 3,573 MW which represents 11% of the country’s total installed capacity. The installed capacity in the Argentine Interconnected System ("SADI") includes the TermoAndes plant, a subsidiary of AES Gener, which is connected both to the SADI and the Chilean SING. AES Argentina has a diversified generation portfolio of ten generation facilities, comprised of 62% thermoelectric and 38% hydroelectric capacity. All of the thermoelectric capacity has the capability to burn alternative fuels. Approximately 69% of the thermoelectric capacity can operate alternatively with natural gas or diesel oil and the remaining 31% can operate alternatively with natural gas or fuel oil.
AES Argentina sells its production to customers in the short-term market, where prices are largely regulated. In 2013, approximately 81% of the energy was sold in the short-term market and 19% was sold under contract, as a result of the Energy Plus sales made by TermoAndes. Short-term prices are determined in Argentine Pesos by the Wholesale Electric Market Administrator (“CAMMESA”) and have been frozen at approximately $120 Pesos per MWh for the past three years.

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All of the thermoelectric facilities have the ability 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, specifically 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 of 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 potential renewal is being evaluated.
Market Structure. The SADI electricity market is managed by CAMMESA. As of December 31, 2013, the installed capacity of the SADI totaled 31,399 MW. In 2013, 66% of total energy demand was supplied by thermoelectric plants, 29% by hydroelectric plants and 5% from nuclear, wind and solar plants.
Thermoelectric generation in the SADI is principally fueled by natural gas. However, since 2004, and 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. The wholesale electric market is administrated by CAMMESA, which 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 cancelation 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, while 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.
Additionally, under the resolution, the energy margin is divided into two components. One component of the margin is paid on a monthly basis, and the second component is held as a receivable, which will be contributed for future power projects to be defined by the authorities (similar to FONINVEMEM). The receivables component is lower than in previous regulations.

23



Key Financial Drivers
Potential changes in regulations, particularly changes related to the recognition of the coal-related cost of the San Nicolas plant or the Energy Plus framework, are key drivers for the Argentina business. The ability to contract sales with unregulated customers at TermoAndes and obtain the natural gas required to supply the contracts is another area of focus for the business. Macroeconomic conditions, foreign currency exchange rates, further regulatory changes, and AES Argentina's ability to collect on receivables, including FONINVEMEM and future receivables, impact operating performance and cash flow. Finally, hydrological conditions affect our plants' dispatch. See Item 7. — Key Trends and Uncertainties - Argentina for further discussion of Argentina.
Brazil SBU
Our Brazil SBU has generation and distribution facilities. Our Brazil operations accounted for 27%, 27% and 45% of consolidated AES Operating Margin and 12%, 16% and 23% of consolidated AES Adjusted PTC (a non-GAAP measure) in 2013, 2012 and 2011, respectively. The percentages shown are 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 because we control them.
The following table provides highlights of our Brazil operations:
Generation Capacity
 
3,298 gross MW (932 proportional MW)
Utilities Penetration
 
8.0 million customers (55,190 GWh)
Generation Facilities
 
13
Utility Businesses
 
2
Key Generation Businesses
 
Tietê and Uruguaiana
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. Tietê represents approximately 11%, as of December 31, 2013, 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 (Percent, Rounded)
 
Year Acquired or Began Operation
Tietê(1)
 
Brazil
 
Hydro
 
2,658

 
24
%
 
1999
Uruguaiana
 
Brazil
 
Gas
 
640

 
46
%
 
2000
Brazil Total
 
 
 
 
 
3,298

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

24



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 to 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 12/31/2013
 
GWh Sold in 2013
 
AES Equity Interest (Percent, Rounded)
 
Year Acquired
Eletropaulo
 
Brazil
 
6,682,000

 
46,216

 
16
%
 
1998
Sul
 
Brazil
 
1,270,000

 
8,974

 
100
%
 
1997
 
 
 
 
7,952,000

 
55,190

 
 
 
 
The following map illustrates the location of our Brazil facilities:
Brazil Generation Businesses
Business Description
Tietê is 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, our partner the Brazilian Development Bank (“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, 2013, the price was R$194/MWh.
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 commissioned in December 2000. AES manages and owns a 46% economic interest and the remaining is held by BNDES. The facility is located in the town of Uruguaiana in the state of Rio Grande do Sul. The plant’s operations were suspended in April 2009 due to unavailability of gas. The facility

25



operated on a short-term basis in February and March 2013 due to a short-term supply of LNG for the facility. Uruguaiana is working to secure gas on a long-term basis, to operate at the plant’s full capacity.
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 Ministry of Mines and Energy ("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 National System Operator (“ONS”) is responsible for coordinating and controlling the operation of the national grid. The ONS dispatches generators based on hydrological conditions, reservoir levels, electricity demand and the prices of fuel and thermal generation. Given the importance of hydro generation in the country, the ONS sometimes reduces dispatch of hydro facilities and increases dispatch of thermal facilities to protect reservoir levels in the system.
Hydrological risk is shared among hydroelectric generation plants through the Energy Reallocation Mechanism ("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.
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.
Tietê's PPA with Eletropaulo expires in December 2015. After that, Tietê’s strategy is to contract most of its Assured Energy 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. As of December 31, 2013, Tietê had contracted an average of 478 MW, or approximately 38%, of its Assured Energy for delivery in 2016. For Tietê's uncontracted Assured Energy available for delivery in 2016, Tietê expects 2016 prices in the range of R$ 115-R$ 130/MWh, prior to adjustments for inflation. Future prices could vary materially from this range, depending on the supply and demand for electricity, hydrological, and other market conditions.
Brazil Utility Businesses
Business Description
Eletropaulo distributes electricity to the Greater São Paulo area, Brazil’s main economic and financial center. Eletropaulo is the largest electric power distributor in Latin America in terms of both revenues and volume of energy distribution.
AES owns 16% of the economic interest of 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 owns 100% of Sul and manages this business under a 30-year concession expiring in 2027.
Regulatory Framework
In Brazil, ANEEL, a government agency, sets the tariff for each distribution company based on a Return on Asset Base methodology, which also benchmarks operational costs against other distribution companies.
The tariff charged to regulated customers consists of two elements: (i) pass through of non-manageable costs under a determined methodology (“Parcel A”), which includes energy purchase costs, sector charges and transmission and distribution system expenses; and (ii) a manageable cost component (“Parcel B”), which includes operation and maintenance costs (defined

26



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%.
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.

Eletropaulo Regulatory Asset Base Update. The Brazilian regulator (ANEEL) has challenged the parameters of a tariff reset for Eletropaulo, in which the Company has a 16% ownership interest, which was 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 that was 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 their 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. The injunction will remain in effect until ANEEL formally decides to reconsider their decision. If ANEEL were to confirm the original decision and the related refund to customers, the injunction would no longer be effective. The Company has recognized a regulatory liability of approximately $269 million in the Company’s fourth quarter results of operations since ANEEL has compelled the Company to refund customers beginning in July 2014. While Eletropaulo believes it has meritorious arguments on this matter and intends to pursue its objections to ANEEL’s rulings vigorously, the aforementioned rulings require Eletropaulo to refund customers beginning in July 2014, and therefore recognition of a regulatory liability is required. If Eletropaulo does prevail in the underlying case, Eletropaulo would seek recovery of the amounts refunded to customers, however there can be no assurance that Eletropaulo will prevail on the request for reconsideration by ANEEL or the underlying case.
Key Financial Drivers
Eletropaulo and Sul are affected by the demand for electricity, which is driven by economic activity, weather patterns and customers’ consumption behavior. Operating performance also is driven by the quality of service, efficient management of operating and maintenance costs, and 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, 2013. MCAC operations accounted for 17%, 16% and 13% of consolidated AES Operating Margin and 19%, 19% and 17% of consolidated AES Adjusted PTC (a non-GAAP measure) in 2013, 2012 and 2011, respectively. The percentages shown are the contribution by our MCAC SBU to gross Operating Margin and Adjusted PTC before deductions for Corporate.

27



 
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 (2,489 proportional MW)
Utilities Penetration
 
1.3 million customers (3,655 GWh)
Generation Facilities
 
13
Utility Businesses
 
4
Key Generation Businesses
 
Andres, Panama and TEG TEP
Key Utility Businesses
 
El Salvador
The total operating installed capacity of our MCAC SBU is distributed 34%, 27%, 22% and 17% in Mexico, Dominican Republic, Panama and Puerto Rico, respectively. The table below lists our MCAC SBU facilities:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (Percent, Rounded)
 
Year Acquired or Began Operation
Andres
 
Dominican Republic
 
Gas
 
319

 
100
%
 
2003
Itabo(1) 
 
Dominican Republic
 
Coal/Gas
 
295

 
50
%
 
2000
DPP (Los Mina)
 
Dominican Republic
 
Gas
 
236

 
100
%
 
1996
Dominican Republic Subtotal
 
 
 
 
 
850

 
 
 
 
AES Nejapa
 
El Salvador
 
Landfill Gas
 
6

 
100
%
 
2011
El Salvador Subtotal
 
 
 
 
 
6

 
 
 
 
Merida III
 
Mexico
 
Gas
 
505

 
55
%
 
2000
Termoelectrica del Golfo (TEG)
 
Mexico
 
Pet Coke
 
275

 
99
%
 
2007
Termoelectrica del Penoles (TEP)
 
Mexico
 
Pet Coke
 
275

 
99
%
 
2007
Mexico Subtotal
 
 
 
 
 
1,055

 
 
 
 
Bayano
 
Panama
 
Hydro
 
260

 
49
%
 
1999
Changuinola
 
Panama
 
Hydro
 
223

 
89
%
 
2011
Chiriqui—Esti
 
Panama
 
Hydro
 
120

 
49
%
 
2003
Chiriqui—Los Valles
 
Panama
 
Hydro
 
54

 
49
%
 
1999
Chiriqui—La Estrella
 
Panama
 
Hydro
 
48

 
49
%
 
1999
Panama Subtotal
 
 
 
 
 
705

 
 
 
 
Puerto Rico
 
US—PR
 
Coal
 
524

 
100
%
 
2002
Puerto Rico Subtotal
 
 
 
 
 
524

 
 
 
 
MCAC Total
 
 
 
 
 
3,140

 
 
 
 
(1) 
Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine).

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MCAC Utilities. Our distribution businesses are located in El Salvador and distribute power to 1.3 million people in the country. This business consists of 4 companies, each of which operates in defined service areas as described in the table below:
Business
 
Location
 
Approximate Number of Customers Served as of 12/31/2013
 
GWh Sold in 2013
 
AES Equity Interest (Percent, Rounded)
 
Year Acquired
CAESS
 
El Salvador
 
567,000

 
2,142

 
75
%
 
2000
CLESA
 
El Salvador
 
354,000

 
864

 
64
%
 
1998
DEUSEM
 
El Salvador
 
72,000

 
123

 
74
%
 
2000
EEO
 
El Salvador
 
277,000

 
526

 
89
%
 
2000
 
 
 
 
1,270,000

 
3,655

 
 
 
 
The following map illustrates the location of our MCAC facilities:
MCAC Businesses
Dominican Republic
Business Description. AES Dominicana consists of its operating subsidiaries Itabo, Andres and Dominican Power Partners (“DPP”). AES has 23% of the system capacity (850 MW) and supplies approximately 40% of energy demand through its three generation facilities.
Itabo is 50%-owned by AES, 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 295 MW of installed capacity in total. Itabo's PPAs are with government-owned distribution companies and expire in 2016.
Andres and DPP are both wholly-owned subsidiaries of AES. Andres has a combined cycle gas turbine and generation capacity of 319 MW and the only LNG import facility, with 160,000 cubic meters of storage capacity, in the country. 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 expensive fuel oil-based generation.

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In 2005, Andres entered into a contract to sell re-gasified LNG for further distribution to industrial users within the Dominican Republic, using compression technology to transport it within the country. In January 2010, the first LNG truck tanker loading terminal started operations. With this investment, AES is capturing demand from industrial and commercial customers.
Market Structure
Electricity Market. The Dominican Republic has one main interconnected system with approximately 3,700 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 developed 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 General Electricity Law (“GEL”).
Two main agencies are responsible for monitoring and ensuring compliance with the GEL. The National Energy Commission (“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. The Superintendence of Electricity’s (“SIE”) main responsibilities include monitoring and supervising compliance with legal provisions and rules and 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 1.2 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 concession: 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 Industrial and Commerce Ministry (“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
Key drivers of financial results are plant reliability, the competitively-priced LNG contract, ancillary service revenues, and spot prices.
In addition, the financial weakness of the three state-owned distribution companies is due to low collection rates, high levels of non-technical losses and the delay in payments for the electricity supplied by generators. At times when outstanding balances have accumulated, AES Dominicana has accepted payment through other means, such as government bonds, in order to reduce their outstanding receiveables. There can be no guarantee that alternative collection methodologies will always be an avenue available for payment options. See Item 7. Capital Resources and Liquidity — Long-Term Receivables and Note 7. Financing Receivables for further discussion of receivables in the Dominican Republic.
Panama
Business Description. AES owns and operates five hydroelectric plants, representing 705 MW of installed capacity, or 30% 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.
Market Structure. Panama’s current total installed capacity is 2,341 MW, of which 60% is hydroelectric and the remaining 40% is fueled by 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 the Electric Law 6 enacted in 1997.

30



Generators can enter into long-term PPAs with distributors or unregulated consumers. In addition, generators can enter into alternative supply contracts with each other. Outside of the PPA market, generators may buy and sell energy in the short-term market.
The National Dispatch Center (“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.
Regulatory Framework. The National Secretary of Energy (“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 National Authority of Public Services (“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
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; 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.
Mexico
Business Description. AES owns installed capacity of 1,055 MW 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 coal-fired plants, located in San Luis Potosi, supply power to their offtakers under long-term PPAs that have a 90% availability guarantee. TEG and TEP secure their fuel (pet coke) under a long-term contract.
Merida is a combined-cycle gas turbine (“CCGT”), located in Merida, on Mexico’s Yucatan peninsula. Merida sells power to the Federal Commission of Electricity (“CFE”) under a capacity- and energy-based long-term PPA through 2025. Additionally, the plant purchases natural gas and diesel fuel under a long-term contract, the cost of which is then passed through to CFE under the terms of the PPA.
Market Structure
Mexico has a single national electricity grid, the National Power System (“SEN”), covering nearly all of Mexico’s territory. Mexico has an installed capacity totaling 53 GW with a generation mix of 62% thermal, 22% hydroelectric and 16% other. Electricity consumption is split between the following end users: industrial (59%), residential (26%) and commercial and service (15%).
Regulatory Framework
The CFE, which is mandated by the Mexican Constitution, is the state-owned electric monopoly, which 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.
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

31



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.
Key Financial Drivers
Plant availability is the largest single performance driver of this business. Additionally, AES’ Mexican businesses benefit from the wholesale price margin versus pet coke costs for any sales greater than the guaranteed output.
Other MCAC Businesses
Puerto Rico
AES Puerto Rico is a 524 MW coal-fired cogeneration plant utilizing Circulating Fluidized Bed Boiler (“CFB”) technology, representing approximately 14% of the installed capacity in Puerto Rico. The plant has a long-term PPA with the Puerto Rico Electric Power Authority (“PREPA”), a state-owned entity that supplies virtually all of the electric power consumed in the Commonwealth and generates, transmits and distributes electricity to 1.5 million customers.
El Salvador
AES is the majority owner of four of the five distribution companies operating in El Salvador. The distribution companies are operated by AES on an integrated basis under a single management team. AES El Salvador’s territory covers 80% of the country. AES El Salvador accounted for 3,655 GWh of market energy purchases during 2013, or about 63% market share of the country’s total market 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).
EMEA SBU
Our EMEA SBU has generation facilities in eight countries and a distribution utility in one country. Our EMEA operations accounted for 13%, 14% and 10% of AES consolidated Operating Margin and 19%, 18% and 15% of AES consolidated Adjusted PTC (a non-GAAP measure) in 2013, 2012 and 2011, respectively. The percentages shown are the contribution by our EMEA SBU to gross Operating Margin and Adjusted PTC before deductions for Corporate.
The following table provides highlights of our EMEA operations:
Countries
 
Bulgaria, Cameroon, Jordan, Kazakhstan, Netherlands, Nigeria, Turkey and United Kingdom
Generation Capacity
 
8,449 gross MW (6,089 proportional MW)
Utilities Penetration
 
1 million customers (3,569 GWh)
Generation Facilities
 
24 (including 1 under construction)
Utility Business
 
1
Key Generation Businesses
 
Maritza, Kilroot, Ballylumford, and Kazakhstan
Operating installed capacity of our EMEA SBU totaled 8,449 MW, of which 32%, 24% and 15% is located in Kazakhstan, United Kingdom and Cameroon, respectively. Set forth in the table below is a list of our EMEA SBU generation facilities:

32



Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (Percent, Rounded)
 
Year Acquired or Began Operation
Maritza
 
Bulgaria
 
Coal
 
690

 
100
%
 
2011
St. Nikola
 
Bulgaria
 
Wind
 
156

 
89
%
 
2010
Bulgaria Subtotal
 
 
 
 
 
846

 
 
 
 
Kribi(1)
 
Cameroon
 
Gas
 
216

 
56
%
 
2013
Dibamba(1)
 
Cameroon
 
Heavy Fuel Oil
 
86

 
56
%
 
2009
Cameroon Subtotal
 
 
 
 
 
302

 
 
 
 
Amman East
 
Jordan
 
Gas
 
380

 
37
%
 
2009
Jordan Subtotal
 
 
 
 
 
380

 
 
 
 
Ust—Kamenogorsk CHP
 
Kazakhstan
 
Coal
 
1,354

 
100
%
 
1997
Shulbinsk HPP(2)
 
Kazakhstan
 
Hydro
 
702

 
—
%
 
1997
Ust—Kamenogorsk HPP(2)
 
Kazakhstan
 
Hydro
 
331

 
—
%
 
1997
Sogrinsk CHP
 
Kazakhstan
 
Coal
 
301

 
100
%
 
1997
Kazakhstan Subtotal
 
 
 
 
 
2,688

 
 
 
 
Elsta(3) 
 
Netherlands
 
Gas
 
630

 
50
%
 
1998
Netherlands Subtotal
 
 
 
 
 
630

 
 
 
 
Ebute
 
Nigeria
 
Gas
 
294

 
95
%
 
2001
Nigeria Subtotal
 
 
 
 
 
294

 
 
 
 
Kocaeli(3),(4)
 
Turkey
 
Gas
 
158

 
50
%
 
2011
Bursa(3),(4) 
 
Turkey
 
Gas
 
156

 
50
%
 
2011
Kepezkaya(3),(4)
 
Turkey
 
Hydro
 
28

 
50
%
 
2010
Kumkoy(3),(4)
 
Turkey
 
Hydro
 
18

 
50
%
 
2011
Damlapinar(3),(4)
 
Turkey
 
Hydro
 
16

 
50
%
 
2010
Istanbul (Koc University)(3),(4)
 
Turkey
 
Gas
 
2

 
50
%
 
2011
Turkey Subtotal
 
 
 
 
 
378

 
 
 
 
Ballylumford
 
United Kingdom
 
Gas
 
1,246

 
100
%
 
2010
Kilroot(5)
 
United Kingdom
 
Coal/Oil
 
662

 
99
%
 
1992
Drone Hill
 
United Kingdom
 
Wind
 
29

 
100
%
 
2012
North Rhins
 
United Kingdom
 
Wind
 
22

 
100
%
 
2010
Sixpenny Wood
 
United Kingdom
 
Wind
 
20

 
100
%
 
2013
Yelvertoft
 
United Kingdom
 
Wind
 
16

 
100
%
 
2013
United Kingdom Subtotal
 
 
 
 
 
1,995

 
 
 
 
EMEA Total
 
 
 
 
 
7,513

 
 
 
 
(1)
These businesses met the held-for-sale criteria on November 7, 2013. The earnings from these businesses are reported as part of discontinued operations. See Note 23 — Discontinued Operations and Held-for-Sale Businesses included in Item 8. — Financial Statements and Supplementary Data of this Form 10-K for further information.
(2) 
AES operates these facilities under concession agreements until 2017.
(3) 
Unconsolidated entities, the results of operations of which are reflected in Equity in Earnings of Affiliates.
(4) 
Joint Venture with Koc Holding.
(5) 
Includes Kilroot Open Cycle Gas Turbine (“OCGT”).
Under construction
The following table lists our plants under construction in the EMEA SBU: 
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (Percent, Rounded)
 
Expected Year of Commercial Operation
IPP4 Jordan
 
Jordan
 
Heavy Fuel Oil
 
247

 
60
%
 
2014
Jordan Subtotal
 
 
 
 
 
247

 
 
 
 
EMEA Total
 
 
 
 
 
247

 
 
 
 
Set forth below is a list of our EMEA utility businesses:
Business
 
Location
 
Approximate Number of Customers Served as of 12/31/2012
 
GWh Sold in 2012
 
AES Equity Interest (Percent, Rounded)
 
Year Acquired
Sonel
 
Cameroon
 
816,000

 
3,569

 
56
%
 
2001
Cameroon Subtotal
 
 
 
816,000

 
3,569

 
 
 
 
EMEA Total
 
 
 
816,000

 
3,569

 
 
 
 

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Set forth below is information on the generation facilities of Sonel:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (Percent, Rounded)
 
Year Acquired or Began Operation
Sonel(1) 
 
Cameroon
 
Hydro/Diesel/Heavy Fuel Oil
 
936

 
56
%
 
2001
(1) 
Sonel plants: Bafoussam, Bassa, Djamboutou, Edéa, Lagdo, Limbé, Logbaba I, Logbaba II, Oyomabang I, Oyomabang II, Song Loulou, and other small remote network units. These businesses met the held-for-sale criteria on November 7, 2013. The earnings from these businesses are reported as part of discontinued operations. See Note 23 — Discontinued Operations and Held-for-Sale Businesses included in Item 8. — Financial Statements and Supplementary Data of this Form 10-K for further information.
The following map illustrates the location of our EMEA facilities:
 
EMEA 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 Natsionala Elektricheska Kompania (“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% 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.
Market Structure
The maximum market capacity in 2013 was approximately 13.6 GW. Thermal generation, which is mostly coal-fired, and nuclear power plants account for 64% of installed capacity.
Regulatory Framework
The electricity sector in Bulgaria operates under the Energy Act 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.

34




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. The key financial challenges for NEK include a regulated price that did not fully recover current and prior periods costs, higher than expected costs related to renewable energy resources, and non-recovery of NEK costs for balancing the electricity system.

In addition, parliamentary elections were held in May 2013 after the prior government was forced out by social unrest, partly related to protests over the perception of high energy prices. Energy legislation was amended by the new government in 2013 and new tariffs became effective in January 2014, which are intended to re-balance the energy system and strengthen NEK’s financial position. 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 on-going 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. Through January 2014, NEK has made payments according to the terms of the agreement. As of December 31, 2013, Maritza had an outstanding receivables balance of $91 million, including $70 million of receivables overdue by less than 90 days and $21 million of current receivables. In addition, Maritza had a balance of $60 million of receivables, which are not yet due under the November 2013 agreement. See Key Trends and Uncertainties, Macroeconomics, Bulgaria in Item 7—Management Discussion and Analysis to this Form 10-K for further information.

The restructuring of NEK is one of the requirements to complete the liberalization of Bulgaria’s electricity system under the European Union's 3rd energy liberalization package. During the fourth quarter of 2013, Maritza was formally approached by NEK with a request to consent to a proposed NEK restructuring, which contemplates a full unbundling of Electricity System Operator (ESO) from NEK and a transfer of the transmission grid from NEK to ESO. In February 2014, the NEK restructuring was implemented after approval by the regulatory authorities. Maritza and its lenders are analyzing the NEK restructuring and its impact on NEK’s financial condition and liquidity.

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 is lower, the PPA could be terminated at the discretion of Maritza and the lenders which triggers a cross default under the project debt agreements. See Item 1A - Risk Factors - “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations.” As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.
Key Financial Drivers
Plant availability is the largest single performance driver of this business. Another key driver is NEK's ability to meet the terms of the existing long-term PPA.
United Kingdom
Business Description
AES’ generation businesses in the United Kingdom operate in two different markets – the Irish Single Electricity Market (“SEM”) for the businesses located in Northern Ireland (1,908 MW) and the UK wholesale electricity market for the businesses located in Scotland and England (87 MW).
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.

35



Ballylumford is partially contracted (600 MW) under a PPA with Northern Ireland Electricity (“NIE”) that ends in 2018, with an extension at the offtaker’s option through 2023, with the remaining capacity bid into the SEM market. One of the Ballylumford stations of 540 MW does not meet the standards of the EU Industrial Emission Directive discussed below, which will most likely result in closing at the end of 2015, unless further investment is committed. 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 which means costs of operation are recovered from the market.
The Scotland and England businesses consist of four wind generation facilities totaling 87 MW. A further wind development pipeline of approximately 250 MW has been submitted for permitting consents. The operating wind projects sell their power to licensed suppliers in the United Kingdom market under long-term PPAs for the full output, generating half of the revenues from the United Kingdom wholesale electricity market and half from green certificates.
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 is 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.
Regulatory Framework
Electricity Regulation. The SEM is an energy market, which was established in 2007 and is completely distinct from the United Kingdom power market. It 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 Industrial Emission Directive (“IED”) that establishes the emission limit values (“ELVs”) 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.
The IED provides for two options that may be implemented by the EU member states – Transitional National Plan (“TNP”) or Limited Life Time Derogation. 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 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 Limited Life Time Derogation will allow plants to run between 2016 and 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 2013, favorable commodity pricing is supportive of this investment and we will be exploring the range of technical solutions available in early 2014. An investment of approximately $24 million is required.
Key Financial Drivers
For our business in the SEM market the key drivers are availability and commodity prices (gas and coal), and regulatory changes. The contracted plants’ financial results are influenced by availability.
In the United Kingdom, part of our revenue stream is indexed to short-term electricity market prices, which are largely influenced by delivered gas prices.
The future value of the Northern Ireland businesses will depend on gas price volatility and any alterations to the SEM market structure and payment mechanism.

36



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 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 20,442 MW, of which 16,008 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, means that coal prices 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.
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 Ministry of Industry and New Technology (“MINT”) for the period 2009-2015 for each of the thirteen groups of generators. These groups were determined by the MINT based on a number of factors including type of plant and fuel used.
In July 2012, Kazakhstan enacted various amendments to its Electricity Law. Among the amendments was a requirement for all profits generated by electricity producers during the years 2013-2015 to be reinvested. Accordingly, the business will be unable to pay dividends for the period 2013-2015. Under the amended Electricity Law, electricity producers must, on an annual basis, enter into investment obligation agreements (“IOAs”) with the MINT detailing their annual investment obligations. 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 MINT has the right to reject submitted IOA proposals. An electricity producer without an IOA executed by the MINT may not charge tariffs exceeding its incremental cost of production, excluding depreciation. On December 20, 2012, the MINT executed IOA 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 (DAREM). Tariffs can either be for one-year or multi-year periods.
Key Financial Drivers
The main business drivers are plant availability, tariff caps set by MINT, signing of IOA, approval of heat tariffs by the Regulator, and weather conditions.
Other EMEA Businesses
In Nigeria, we own the 294 MW gas-fired Ebute power plant. The plant operates under a capacity-based PPA contract with the state-owned entity Power Holding Company of Nigeria (“PHCN”), which expires in November 2014. Earnings are driven primarily by capacity payments paid under the PPA. It sells power generated by a nine unit barge-mounted gas turbine

37



system, with fuel currently supplied by the offtaker. However, due to the ongoing PHCN privatization process, in the future, Ebute will have to source its own fuel, although with the ability to pass some or all of its cost through the tariff.
In Turkey, we currently own in partnership with Koc Holding, 378 MW of hydroelectric and gas-fired plants. The Turkey hydro businesses fall under the renewable feed-in tariff, while the gas assets are dispatched in the market. Our businesses in Turkey are operated under a joint venture structure; they are reported as equity in earnings of affiliates.
In Jordan we have a controlling interest in Amman East, a 380 MW oil/gas-fired plant fully contracted with the national utility under a 25-year PPA. We consolidate the results of this business in our operations. We also have a 247 MW oil-fired peaker under construction in Jordan. The project is similar in structure with Amman East and is fully contracted with the national utility under a 25-year PPA.
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.
In Cameroon we are involved in the generation, transmission, distribution and sale of electricity through AES Sonel, an integrated utility, and two Independent Power Producers (IPP).
We own 56% of AES Sonel with the remaining 44% held by the Republic of Cameroon. AES Sonel is the only electricity provider in Cameroon. It is regulated by the Agence de Régulation de Secteur d’Electricité (ARSEL). AES Sonel operates and maintains 936 MW of generation, two interconnected transmission networks and distributes electricity to more than 800,000 primarily residential customers. AES Sonel operates under a 20-year concession agreement that was signed in July 2001. Electricity demand has increased at an average annual rate of 6.6%, since 2010. Growth is expected to continue especially in the residential segment.
In addition, AES is part owner and sole operator of two IPPs in Cameroon: Dibamba Power Development Company (“DPDC”), with an 86 MW heavy fuel oil plant, and Kribi Power Development Company (“KPDC”), with a 216 MW gas/light fuel oil plant. DPDC and KPDC have the same ownership structure; 56% AES and 44% Republic of Cameroon. Contracts at KPDC and DPDC are primarily capacity-based with Government protections. DPDC has a 20-year tolling agreement with AES Sonel and KPDC has a 20-year PPA with AES Sonel and a 20-year gas supply agreement with the Government-owned Societe Nationale des Hydrocarbures (“SNH”).
AES has 1,238 MW of generation in Cameroon—almost 100% of the country’s total capacity; of which 60% is hydroelectric, 18% gas, 16% heavy fuel oil, and 6% diesel.
In September 2013, AES entered into an agreement for the sale of its holding in Cameroon. See Note 23 - Discontinued Operations and Held-for-Sale Businesses included in Item 8. - Financial Statements and Supplementary Information included in this Form 10-K for further information.
Asia SBU
Our Asia SBU has generation facilities in four countries. Our Asia operations accounted for 5%, 7% and 4% of AES consolidated Operating Margin and 8%, 10% and 6% of AES consolidated Adjusted PTC (a non-GAAP measure) in 2013, 2012 and 2011, respectively. The percentages shown are the contribution by our Asia SBU to gross Operating Margin and Adjusted PTC before deductions for Corporate.

38



The following table provides highlights of our Asia operations:
Countries
 
India, Philippines, Sri Lanka and Vietnam
Generation Capacity
 
1,248 gross MW (964 proportional MW)
Generation Facilities
 
4 (including 1 under construction)
Key Businesses
 
Masinloc, OPGC and Mong Duong II
Operating installed capacity of our Asia SBU totals 1,248 MW, of which 53%, 34% and 13% located in the Philippines, India and Sri Lanka respectively. Set forth below in the table is a list of our Asia SBU generation facilities:
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (Percent, Rounded)
 
Year Acquired or Began Operation
OPGC(1)
 
India
 
Coal
 
420

 
49
%
 
1998
India Subtotal
 
 
 
 
 
420

 
 
 
 
Masinloc
 
Philippines
 
Coal
 
660

 
92
%
 
2008
Philippines Subtotal
 
 
 
 
 
660

 
 
 
 
Kelanitissa
 
Sri Lanka
 
Diesel
 
168

 
90
%
 
2003
Sri Lanka Subtotal
 
 
 
 
 
168

 
 
 
 
Asia Total
 
 
 
 
 
1,248

 
 
 
 
(1)
Unconsolidated entities for which the results of operations are reflected in Equity in Earnings of Affiliates.
Under construction
Business
 
Location
 
Fuel
 
Gross MW
 
AES Equity Interest (Percent, Rounded)
 
Expected Year of Commercial Operation
Mong Duong II
 
Vietnam
 
Coal
 
1,240

 
51
%
 
2015
The following map illustrates the location of our Asia facilities:
Asia Businesses
Philippines
Business Description. In April 2008, AES acquired the 660 MW Masinloc coal-fired power plant, located in Luzon. Subsequent to the acquisition, AES performed a substantial rehabilitation program that was completed in 2010, resulting in improvements in reliability, environmental emissions, and plant safety performance. Generating capacity was improved from 433 MW at acquisition to 630 MW, and plant availability increased from 74% at acquisition to current 89%.
More than 90% of Masinloc’s peak capacity and variable margin are contracted through medium-to long-term bilateral contracts primarily with Meralco, several electric cooperatives and industrial customers.

39



Market Structure
The Philippine power market is divided into three grids representing the country’s three major island groups — Luzon, Visayas and Mindanao. Luzon (which includes Manila and is the country’s largest island) is interconnected with Visayas and represents 88% of the total demand of both regions. Luzon and Visayas together have an installed capacity of 13,905 MW.
There is diversity in the mix of the Luzon - Visayas generation, with coal accounting for 37%, natural gas for 20%, hydroelectric for 18%, geothermal generation for 9%, and the remaining 16% from other generating plants (such as wind, biomass, blended, and oil) which are either dispatched by the system operator only during system emergencies or dispatched by the market during peak demand.
The primary customers for electricity are private distribution utilities, electric cooperatives, and to a lesser extent large industrial customers. Approximately 90% - 95% of the system’s total energy requirement is being sold/purchased through medium (3-5 years) to long (6-10 years) term bilateral contracts. Both medium and long term bilateral contracts have a renewal extension clause. The remaining 5% - 10% of energy is sold through the Wholesale Electricity Spot Market (“WESM”), which is the real time, bid-based and hourly market for energy where the sellers and the buyers adjust their differences between their production/demand and their contractual commitments.
Regulatory Framework
Electricity Regulation. The Philippines has divided its power sector into generation, transmission, distribution and supply under the Electric Power Industry Reform Act of 2001 (“EPIRA”). The EPIRA primarily aims to increase private sector participation in the power sector and to privatize the Government’s generation and transmission assets. Generation and supply are open and competitive sectors, while transmission and distribution are regulated sectors. Sale of power is conducted primarily through medium-term bilateral contracts between generation companies and customers specifying the volume, price and conditions for the sale of energy and capacity, which are approved by the Energy Regulatory Commission (“ERC”). Power is traded in the WESM which operates under a gross pool, central dispatch and net settlement protocols. Parties to bilateral contracts settle their transactions outside of the WESM and distribution companies or electricity cooperatives buy their imbalance (i.e., power requirements not covered by bilateral contracts) from the WESM. Distribution utilities and electric cooperatives are allowed to pass on to their end-users the ERC-approved bilateral contract rates, including WESM purchases.
Other Regulatory Considerations. EPIRA established the Retail Competition and Open Access (“RC&OA”) under which Retail Electricity Suppliers, who are duly licensed by the ERC, may supply directly to Contestable Customers (end-users with an average demand of at least 1,000 kW), with distribution companies or electricity cooperatives providing non-discriminatory wire services. The ERC has issued a joint statement with DOE declaring December 26, 2012 as the commencement date of the RC&OA. The period from December 26, 2012 to June 25, 2013 was deemed the transition period with full implementation occurring on June 26, 2013.
Environmental Regulation
The Renewable Energy Act of 2008 was enacted in December 2008 to promote non-conventional renewable energy sources, such as solar, wind, small hydroelectric and biomass energies. The law requires electric power participants to initially source 10% of their supply from eligible renewable energy resources. The initial requirement of 10% is preliminary, as the National Renewable Energy Board has not set the final figure. If the regulations are implemented, our businesses in the Philippines could be affected by requirements requiring all generators to supply a portion of their generation from renewable energy resources.
Key Financial Drivers
The key drivers of the business are Masinloc’s availability, system reliability, demand growth, and reserve margins.
Other Asia Businesses
India
Business Description
Our generation business in India consists of the 420 MW coal-fired Odisha Power Generation Corporation (“OPGC”) located in the state of Odisha. AES acquired 49% of OPGC in 1998, with the remaining 51% owned by the state. Saurashtra is a 100% owned 39 MW wind plant located in the state of Gujarat, which commenced operations in early 2012. In September 2013 AES entered into an agreement for the sale of Saurashtra.

40




OPGC has a 30-year PPA with GRIDCO Limited, a state utility, expiring in 2026. The PPA is comprised of a capacity payment based on fixed parameters and a variable component comprised of fuel costs, where actual fuel costs are a pass-through. OPGC is an unconsolidated entity and results are reported in Equity in Earnings of Affiliates.

AES has one coal-fired project under development with a total capacity of 1,320 MW, which is an expansion of our existing OPGC business. The project is expected to start construction in 2014 and begin operations in 2018.
Vietnam
Business Description
The Mong Duong II power project is a 1,240 MW plant being constructed under a Build, Operate and Transfer (“BOT”) agreement in Quang Ninh province of Vietnam. The project is currently the largest private sector power project in the country. AES-VCM Mong Duong Power Company Limited (“the BOT Company”), a limited liability joint venture established by the affiliates of AES (51%), Posco Energy Corporation (30%) and China Investment Corporation (19%). The BOT Company has a PPA term of 25 years with Vietnam Electricity (“EVN”). At the end of the term of the PPA, the BOT Company will be transferred to the Vietnamese Government in accordance with the BOT contract. Upon reaching commercial operations, EVN will have exclusive rights on the facility’s entire capacity and energy. Vietnam National Coal-Mineral Industries Group (“Vinacomin”), a stated-owned entity, is the project’s coal supplier under a 25-year coal supply agreement.
The tariff has two components: Capacity charge and the foreign component of Operation and Maintenance Charge (“O&M”), which are paid in U.S. Dollars and the local component of O&M and fuel charge which are paid in Vietnam Dong. In addition, the U.S. Dollar and Vietnam Dong component of O&M are linked to a published Consumer Price Index of the U.S. and Vietnam respectively. Fuel costs in general are pass-through elements in the fuel charge.
The project is currently under construction and is scheduled to commence operations in the second half of 2015.
Financial Data by Country
The table below presents information, by country, about our consolidated operations for each of the three years ended December 31, 2013, 2012 and 2011, respectively, and property, plant and equipment as of December 31, 2013 and 2012, respectively. Revenue is recognized in the country in which it is earned and assets are reflected in the country in which they are located. 

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Revenue
 
Property, Plant & Equipment, net
 
 
2013
 
2012
 
2011
 
2013
 
2012
 
 
(in millions)
United States(1)
 
$
3,630

 
$
3,736

 
$
2,088

 
$
7,523

 
$
7,540

Non-U.S.:
 
 
 
 
 
 
 
 
 
 
Brazil(2)
 
5,015

 
5,788

 
6,640

 
5,293

 
5,756

Chile
 
1,569

 
1,679

 
1,608

 
3,312

 
2,993

El Salvador
 
860

 
854

 
755

 
292

 
284

Dominican Republic
 
832

 
761

 
674

 
689

 
670

United Kingdom
 
558

 
505

 
587

 
603

 
578

Argentina(3)
 
545

 
857

 
979

 
256

 
278

Colombia
 
523

 
453

 
365

 
412

 
383

Philippines
 
497

 
559

 
480

 
776

 
800

Mexico
 
440

 
397

 
404

 
748

 
759

Bulgaria(4)
 
422

 
369

 
251

 
1,606

 
1,606

Puerto Rico
 
328

 
293

 
298

 
562

 
570

Panama
 
250

 
266

 
189

 
1,028

 
1,069

Kazakhstan
 
156

 
151

 
145

 
183

 
141

Jordan
 
142

 
121

 
124

 
439

 
222

Sri Lanka
 
53

 
169

 
140

 
7

 
8

Spain
 
—

 
119

 
258

 
—

 
—

Cameroon(5)
 
—

 
—

 
—

 
—

 
—

Ukraine(6)
 
—

 
—

 
—

 
—

 
—

Hungary(7)
 
—

 
—

 
—

 
—

 
—

Vietnam
 
—

 
—

 
—

 
1,296

 
887

Other Non-U.S. (8)
 
71

 
87

 
113

 
87

 
91

Total Non-U.S.
 
12,261

 
13,428

 
14,010

 
17,589

 
17,095

Total
 
$
15,891

 
$
17,164

 
$
16,098

 
$
25,112

 
$
24,635


(1)
Excludes revenue of $23 million, $63 million and $396 million for the years ended December 31, 2013, 2012 and 2011, respectively, and property, plant and equipment of $69 million and $123 million as of December 31, 2013 and 2012, respectively, related to Condon, Mid-West Wind, Eastern Energy, Thames, Red Oak and Ironwood which were reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets. Additionally property, plant and equipment excludes $25 million as of December 31, 2012 related to wind turbines which were reflected as assets held for sale in the accompanying Consolidated Balance Sheets.
(2)
Excludes revenue of $124 million for the year ended December 31, 2011 related to Brazil Telecom which was reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
(3)
Excludes revenue of $102 million for the year ended December 31, 2011 related to our Argentina distribution businesses which were reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
(4)
Our wind project in Maritza started operations in June 2011.
(5)
Excludes revenue of $474 million, $457 million and $386 million for the years ended December 31, 2013, 2012 and 2011, respectively, and property, plant and equipment of $1,100 million and $992 million as of December 31, 2013 and 2012 respectively, related to Dibamba, Kribi and Sonel which were reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.
(6)
Excludes revenue of $187 million, $491 million and $418 million for the years ended December 31, 2013, 2012 and 2011, respectively, and property, plant and equipment of $112 million at December 31, 2012 related to Kievoblenergo and Rivnooblenergo which were reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.
(7)
Excludes revenue of $18 million and $219 million for the years ended December 31, 2012 and 2011, respectively, related to Borsod, Tiszapalkonya and Tisza II, which were reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations.
(8)
Excludes revenue of $6 million, $11 million and $18 million for the years ended December 31, 2013, 2012 and 2011, respectively, and property, plant and equipment of $19 million and $54 million as of December 31, 2013 and 2012, respectively, related to Saurashtra, Poland wind and carbon reduction projects, which were reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.
Environmental and Land Use Regulations
The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts), and certain air

42



emissions, such as SO2, NOX, particulate matter, mercury and other hazardous air pollutants. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our United States or international subsidiaries, and our consolidated results of operations. For further information about these risks, see Item 1A.—Risk Factors, “Our businesses are subject to stringent environmental laws and regulations,” “Our businesses are subject to enforcement initiatives from environmental regulatory agencies,” and “Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows” in this Form 10-K. For a discussion of the laws and regulations of individual countries within each SBU where our subsidiaries operate, see discussion within Item 1. of this Form 10-K under the applicable SBUs.
Many of the countries in which the Company does business also have laws and regulations relating to the siting, construction, permitting, ownership, operation, modification, repair and decommissioning of, and power sales from, electric power generation or distribution assets. In addition, international projects funded by the International Finance Corporation, the private sector lending arm of the World Bank, or many other international lenders are subject to World Bank environmental standards or similar standards, which tend to be more stringent than local country standards. The Company often has used advanced generation technologies in order to minimize environmental impacts, such as circulating fluidized bed (“CFB”) boilers and advanced gas turbines, and environmental control devices such as flue gas desulphurization for SO2 emissions and selective catalytic reduction for NOX emissions.
Environmental laws and regulations affecting electric power generation and distribution facilities are complex, change frequently and have become more stringent over time. The Company has incurred and will continue to incur capital costs and other expenditures to comply with these environmental laws and regulations. See Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Environmental Capital Expenditures in this Form 10-K for more detail. The Company and its subsidiaries may be required to make significant capital or other expenditures to comply with these regulations. There can be no assurance that the businesses operated by the subsidiaries of the Company will be able to recover any of these compliance costs from their counterparties or customers such that the Company’s consolidated results of operations, financial condition and cash flows would not be materially affected.
Various licenses, permits and approvals are required for our operations. Failure to comply with permits or approvals, or with environmental laws, can result in fines, penalties, capital expenditures, interruptions or changes to our operations. Certain subsidiaries of the Company are subject to litigation or regulatory action relating to environmental permits or approvals. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation and regulatory action, including a Notice of Violation (“NOV”) issued by the United States Environmental Protection Agency ("EPA") against IPL concerning new source review and prevention of significant deterioration issues under the United States Clean Air Act ("CAA").
United States Environmental and Land Use Legislation and Regulations
In the United States the CAA and various state laws and regulations regulate emissions of air pollutants, including SO2, NOX, particulate matter (“PM”), mercury and other hazardous air pollutants (“HAPs”). Certain applicable rules are discussed in further detail below.
CAIR and CSAPR. The EPA promulgated the “Clean Air Interstate Rule” (“CAIR”) on March 10, 2005, which required allowance surrender for SO2 and NOX emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR contemplated two implementation phases. The first phase was to begin in 2009 and 2010 for NOX and SO2, respectively. A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015. To implement the required emission reductions for this rule, the states were to establish emission allowance based “cap-and-trade” programs. CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the EPA.
In response to the D.C. Circuit’s opinion, on July 7, 2011, the EPA issued a new rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). The CSAPR was scheduled to go into force on January 1, 2012 and would have required significant reductions in SO2 and NOX emissions from power plants in many states in which subsidiaries of the Company operate. Once fully implemented, the rule would have required additional SO2 emission reductions of 73% and additional NOX reductions of 54% from 2005 levels.
Many states, utilities and other affected parties filed petitions for review, challenging the CSAPR before the D.C. Circuit. On August 21, 2012, a three-judge panel of the D.C. Circuit vacated the CSAPR and required EPA to continue administering CAIR pending the promulgation of a valid replacement to the CSAPR. In June 2013, the U.S. Supreme Court granted a petition

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to review the D.C. Circuit’s decision vacating CSAPR. Oral argument was held on December 10, 2013 and a decision is expected in the next several months. We cannot predict the U.S. Supreme Court's actions and it is difficult to predict what steps would follow any ruling. If the U.S. Supreme Court were to reverse the D.C. Circuit, there remain numerous challenges to the CSAPR that must be addressed, some of which could again result in delay or invalidation of the CSAPR. Further, it is difficult to predict what the EPA will do in response to any decision. EPA has announced plans to propose a transport rule for NOX emissions that would address ozone in October 2014. This rule would be based on a more stringent ozone standard than was the original CSAPR. Also, many of the areas that were projected to be in non-attainment for both ozone and PM2.5 are now in attainment, calling into question the basis for the original CSAPR. Nonetheless, the Company anticipates an increase in capital costs and other expenditures and the operational restrictions that would be required to comply with a reinstated CSAPR or with replacement rules addressing transport of NOX and SO2. At this time, we cannot predict the impact that such rules would have on the Company; they could have a material impact on the Company's business, financial condition and results of operations.
MATS. The EPA is obligated under Section 112 of the CAA to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, hydrogen chloride, hydrogen fluoride, and nickel species, among other substances, from coal and oil-fired power plants. In connection with such rule, the CAA requires the EPA to establish Maximum Achievable Control Technology (“MACT”). MACT is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. Pursuant to Section 112 of the CAA, the EPA promulgated a final rule on December 16, 2011, called the Mercury Air Toxics Standards (“MATS”) establishing National Emissions Standards for Hazardous Air Pollutants (“NESHAP”) from coal and oil-fired electric utility steam generating units. These emission standards reflect the EPA’s application of MATS standards for each pollutant regulated under the rule. The rule requires all coal-fired power plants to comply with the applicable MATS standards within three years, with the possibility of obtaining an additional year, if needed, to complete the installation of necessary controls. To comply with the rule, many coal-fired power plants may need to install additional control technology to control acid gases, mercury or particulate matter, or they may need to repower with an alternate fuel or retire operations. Most of the Company’s United States coal-fired plants operated by the Company’s subsidiaries have scrubbers or comparable control technologies designed to remove SO2 and which also remove some acid gases. However, there are other improvements to such control technologies that may be needed even at these plants to assure compliance with the MATS standards. Older coal-fired facilities that do not currently have a SO2 scrubber installed are particularly at risk. For a discussion of the deactivation and planned deactivation of certain units owned or partially owned by IPL and DP&L as a result of existing and expected environmental regulations, including MATS, see "— Unit Retirement and Replacement Generation" below.
IPL estimates additional expenditures related to the MATS rule for environmental controls for its baseload generating units to be approximately $511 million through 2016, excluding demolition costs. In August 2013, the Indiana Utility Regulatory Commission (“IURC”) approved IPL’s MATS petition and request for a Certificate of Public Convenience and Necessity for this amount (including supplemental testimony). These filings detail the installations of new pollution control equipment that IPL plans to add to its five largest baseload generating units. The IURC also approved, with certain stipulations, IPL’s request to recover through its environmental rate adjustment mechanism all operating and capital expenditures (including a return) related to compliance. Recovery of these costs is through an Indiana statute that allows for 100% recovery of qualifying costs through a rate adjustment mechanism. As part of its Order, the IURC stipulated that if IPL’s Harding Street unit is retired before IPL has fully depreciated the new controls (which have a 20-year depreciable life), IPL shall not continue to collect depreciation expense on the clean energy projects included in the MATS Order for that unit. IPL management is currently evaluating the impact of this recent Order.
Several lawsuits challenging the MATS rule have been filed and consolidated into a single proceeding before the United States Court of Appeals for the District of Columbia Circuit. Oral argument was held on the challenges on December 10, 2013 and a decision on the challenges is anticipated in the next several months. We cannot predict the outcome of this litigation.
New Source Review. The new source review (“NSR”) requirements under the CAA impose certain requirements on major emission sources, such as electric generating stations, if changes are made to the sources that result in a significant increase in air emissions. Certain projects, including power plant modifications, are excluded from these NSR requirements, if they meet the routine maintenance, repair and replacement (“RMRR”) exclusion of the CAA. There is ongoing uncertainty, and significant litigation, regarding which projects fall within the RMRR exclusion. The EPA has pursued a coordinated compliance and enforcement strategy to address NSR compliance issues at the nation’s coal-fired power plants. The strategy has included both the filing of suits against power plant owners and the issuance of Notices of Violation (“NOVs”) to a number of power plant owners alleging NSR violations. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation and regulatory action, including a NOV issued by the EPA against IPL concerning NSR and prevention of significant deterioration issues under the CAA.
DP&L’s Stuart Station and Hutchings Station have received NOVs from the EPA alleging that certain activities undertaken in the past are outside the scope of the RMRR exclusion. Additionally, generation units partially owned by DP&L

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but operated by other utilities have received such NOVs relating to equipment repairs or replacements alleged to be outside the RMRR exclusion. The NOVs issued to DP&L-operated plants have not been pursued through litigation by the EPA.
If NSR requirements were imposed on any of the power plants owned by the Company's subsidiaries, the results could have a material adverse impact on the Company’s business, financial condition and results of operations. In connection with the imposition of any such NSR requirements on our U.S. utilities, DP&L and IPL, the utilities would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that they would be successful in that regard.
Regional Haze Rule. In July 1999, the EPA published the “Regional Haze Rule” to reduce haze and protect visibility in designated federal areas. On June 15, 2005, the EPA proposed amendments to the Regional Haze Rule that set guidelines for determining “best available retrofit technology” (“BART”) at affected plants and how to demonstrate "reasonable progress" towards eliminating man-made haze by 2064. The amendment to the Regional Haze Rule required states to consider five factors when establishing BART for sources, including the availability of emission controls, the cost of the controls and the effect of reducing emission on visibility in Class I areas (including wilderness areas, national parks and similar areas). The statute requires compliance within five years after the EPA approves the relevant state implementation plan (“SIP”) or issues a federal implementation plan, although individual states may impose more stringent compliance schedules.
The EPA had previously determined that states included in the CAIR or CSAPR would not be required to make source-specific BART determinations for BART-affected electric generating units, reasoning that the emissions reductions required by these rules were "better than BART." Some environmental groups challenged these determinations. On December 2, 2011, the EPA published a notice that it entered a consent decree with several environmental groups that requires the EPA to review and take final action on regional haze requirements for more than 40 states and territories, including those states that are subject to CAIR or CSAPR. That requirement has been held in abeyance pending the outcome of the U.S. Supreme Court ruling on the CSAPR.
Greenhouse Gas Emissions. In July 2013, President Obama announced plans to use executive orders to reduce greenhouse gas ("GHG") emissions and related climate change measures. In particular, the President directed the EPA to initiate rulemakings to set new source performance standards (“NSPS”) for fossil fuel-fired electric generating units pursuant to Section 111(b) of the CAA. The President also directed the EPA to begin a process pursuant to Section 111(d) of the CAA under which the states and the EPA would seek to achieve reductions in GHG emissions from existing fossil fuel-fired electric generating units through the establishment of existing source performance standards (“ESPS”).
The EPA proposed the NSPS for new electric generating units on January 8, 2014. The proposed NSPS would establish CO2 standards of 1100 lbs/MWh for newly constructed coal-fueled electric generating plant, which reflects the partial capture and storage of CO2 emissions from the plant. The NSPS also would impose standards of 1000 lbs/MWh for large natural gas combined cycle (“NGCC”) facilities and 1100 lbs/MWh for smaller and peaking NGCC facilities. These standards would apply to any electric generating unit with construction commencing after January 8, 2014. The comment period for this rule will run through March 10, 2014. The Company cannot predict whether these standards will be changed prior to the rule becoming final but the NSPS could have an impact on the Company’s plans to construct and/or reconstruct electric generating units in some locations.
The EPA also has announced plans to issue regulations designed to achieve GHG emissions reductions from existing electric generating units. The EPA plans to propose a rule requiring states to submit to EPA a plan for establishing GHG performance standards for coal- and gas-fired electric generating units in June 2014. The EPA also will issue guidelines to the states regarding the process for setting the performance standards, including how to determine the “best system of emission reduction,” which is to be the basis for setting the performance standards. The EPA will take comment on the proposed rule and guidelines and has stated its intention to finalize the rule in June 2015. The EPA has stated that it expects the states to submit plans for implementing the existing source performance standards by June 2016. At this time, the Company cannot predict whether this rule will have a material impact on the Company or its subsidiaries.
Water Discharges. The Company’s facilities are subject to a variety of rules governing water discharges. In particular, the Company’s U.S. facilities are subject to the U.S. Clean Water Act Section 316(b) rule issued by the EPA which seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the “Best Technology Available” (“BTA”) for cooling water intake structures. The EPA published a proposed rule establishing requirements under 316(b) regulations on April 20, 2011. The proposal establishes BTA requirements regarding impingement standards with respect to aquatic organisms for all facilities that withdraw above 2 million gallons per day of water from certain bodies of water and utilize at least 25% of the withdrawn water for cooling purposes. To meet these BTA requirements, as currently proposed, cooling water intake structures associated with once through cooling processes will need modifications of existing traveling screens that protect aquatic organisms and will need to add a fish return and handling system for each cooling system.

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Existing closed cycle cooling facilities may require upgrades to water intake structure systems. The proposal would also require comprehensive site-specific studies during the permitting process and may require closed-cycle cooling systems in order to meet BTA entrainment standards.
Under a consent decree filed in the U.S. District Court for the Southern District of New York, the EPA was required to issue a final rule by January 14, 2014; however, the EPA has not yet issued such final rule. Until such regulations are final, the EPA has instructed state regulatory agencies to use their best professional judgment in determining how to evaluate what constitutes BTA for protecting fish and other aquatic organisms from cooling water intake structures. Certain states in which the Company operates power generation facilities have been delegated authority and are moving forward to issue National Pollutant Discharge Elimination System (“NPDES”) permits with best technology available determinations in the absence of any final rule from the EPA. On September 27, 2010, the California Office of Administrative Law approved a policy adopted by the California State Water Resources Control Board with respect to power plant cooling water intake structures that withdraw from coastal and estuarine waters. This policy became effective on October 1, 2010, and establishes technology-based standards to implement Section 316(b) of the U.S. Clean Water Act in NPDES permits that withdraw from coastal and estuarine waters in California. At this time, it is contemplated that the Company’s Redondo Beach, Huntington Beach and Alamitos power plants in California (collectively, “AES Southland”) will need to have in place BTA by December 31, 2020, or repower the facilities. On April 1, 2011, AES Southland filed an Implementation Plan with the State Water Resources Control Board that indicated its intent to repower the facilities in a phased approach, with the final units being in compliance by 2024. The State Water Resources Board is currently reviewing the implementation plans and has requested additional information to assist with its evaluation. Power plants will be required to comply with the more stringent of state or federal requirements. At present, the Company cannot predict the final requirements under the EPA Section 316(b) regulation, but the Company anticipates compliance costs could have a material impact on our consolidated financial condition or results of operations.
On January 7, 2013, the Ohio EPA issued an NPDES permit for J.M. Stuart Station. The primary issues involve the temperature and thermal discharges from the Station including the point at which the water quality standards are applied, i.e., whether water quality standards apply at the point where the Station discharge canal discharges into the Ohio River, or whether, as the EPA alleges, the discharge canal is an extension of Little Three Mile Creek and the water quality standards apply at the point where water enters the discharge canal. In addition, there are a number of other water-related permit requirements established with respect to metals and other materials contained in the discharges from the Station. The NPDES permit establishes interim standards related to the thermal discharge for 54 months that are comparable to current levels of discharge by Stuart Station. Permanent standards for both temperature and overall thermal discharges are established as of 55 months after the permit is effective, except that an additional transitional period of approximately 22 months is allowed if compliance with the permanent standards is to be achieved through a plan of construction and various milestones on the construction schedule are met. DP&L is still analyzing the NPDES permit, but it is believed that there is a strong potential that compliance will require capital expenses that are material to DP&L. The cost of compliance and the timing of such costs is uncertain and may vary considerably depending on a compliance plan that would need to be developed, the type of capital projects that may be necessary, and the uncertainties that may arise in the likely event that permits and approvals from other governmental entities would likely be required to construct and operate any such capital project. DP&L has appealed various aspects of the final permit to the Environmental Review Appeals Commission. The outcome of such appeal is uncertain.
On August 28, 2012, the Indiana Department of Environmental Management ("IDEM") issued NPDES permits to the IPL Petersburg, Harding Street and Eagle Valley generating stations, which became effective in October 2012. NPDES permits regulate specific industrial waste water and storm water discharges to the waters of Indiana under Sections 402 and 405 of the U.S. Clean Water Act. These permits set new levels of acceptable metal effluent water discharge, as well as monitoring and other requirements designed to protect aquatic life, with full compliance required by October 2015. As part of an agreed order with IDEM in April 2013, IPL received a two-year extension of the required compliance date, through September 2017. IPL is conducting studies to determine what operational changes and/or additional equipment will be required to comply with the new limitation. In developing its compliance plans, IPL must make assumptions about the outcomes of future federal rulemaking with respect to coal combustion byproducts, cooling water intake and waste water effluents. In light of the uncertainties at this time, we cannot predict the impact of these regulations on our consolidated results of operations, cash flows, or financial condition, but it is expected to be material to IPL. Recovery of these costs is expected through an Indiana statute, which allows for 80% recovery of qualifying costs through a rate adjustment mechanism and the remainder through a base rate case proceeding; however, there can be no assurances that IPL would be successful in that regard.
In April 2013, the EPA announced proposed rules to reduce toxic pollutants discharged into waterways by power plants. The proposed rules are intended to update the existing technology-based rules for controlling the discharge of pollutants from various waste streams associated with steam electric generating facilities. The proposed rules identify four preferred options for controlling the discharge of these pollutants, and EPA believes that over half of existing power plants will comply with these rules, if they become final, without incurring costs. However, it is too early to determine whether the impacts of this rule, if and

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when it becomes final, will materially impact the Company or its subsidiaries. EPA is required to finalize these rules by May 2014.