ITEM 1. BUSINESS

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

Executive Summary

Incorporated in 1981, AES is a diversified power generation and utility company, providing affordable, sustainable energy through our diverse portfolio of thermal and renewable generation facilities as well as distribution businesses. Our vision is to be the world's leading sustainable power company by leveraging our unique electricity platforms and the knowledge of our people to provide the energy and infrastructure solutions our customers truly need. Our people share a passion to help meet the world's current and increasing energy needs, while providing communities and countries the opportunity for economic growth due to the availability of reliable, affordable electric power.

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

Additionally, we have been expanding our LNG infrastructure in Central America, where we are helping to displace oil-fired generation in favor of a cheaper and cleaner alternative. In the United States, at IPL, we recently completed a multi-year rate-base investment in environmental upgrades to our coal plants and are in the process of re-powering several units from coal to gas.

Strategic Priorities

We have made significant progress towards meeting our strategic goals to maximize value for our shareholders.

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Segments

We are organized into six market-oriented strategic business units ("SBUs"): US (United States), Andes (Chile, Colombia, and Argentina), Brazil , MCAC (Mexico, Central America and the Caribbean), Europe , and Asia — which are led by our SBU Presidents. Within our six SBUs, we have two lines of business. The first business line is generation, where we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. The second business line is utilities, where we own and/or operate utilities to generate or purchase, distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market.

The Company measures the operating performance of its SBUs using Adjusted PTC and Proportional Free Cash Flow, both of which are non-GAAP measures. The Adjusted PTC and Proportional Free Cash Flow by SBU for the year ended December 31, 2016 are shown below. The percentages for Adjusted PTC and Proportional Free Cash Flow are the contribution by each SBU to the gross metric, i.e., the total Adjusted PTC by SBU, before deductions for Corporate. See Item 7.— Management's Discussion and Analysis SBU Performance Analysis of this Form 10-K for reconciliation and definitions of Adjusted PTC and Proportional Free Cash Flow.

The following summarizes our businesses within our six SBUs.

Overview

Generation

We currently own and/or operate a generation portfolio of 30,379 MW, excluding the generation capabilities of our integrated utilities. Our generation fleet is diversified by fuel type. See discussion below under Fuel Costs .

Performance drivers of our generation businesses include types of electricity sales agreements, plant reliability and flexibility, fuel costs, seasonality, weather variations and economic activity, fixed-cost management, and competition.

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

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

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

Capacity Payments and Contract Sales — Most of our contract sales include a capacity payment that covers projected fixed costs of the plant, including fixed O&M expenses and a return on capital invested. In addition, most of our contracts require that the majority of the capacity payment be denominated in the currency matching our fixed costs. We generally structure our business to eliminate or reduce foreign exchange risk by matching the currency of revenue and expenses, including fixed costs and debt. Our project debt may consist of both fixed and floating rate debt for which we typically hedge a significant portion of our exposure. Some of our contracted businesses also receive a regulated market-based capacity payment, which is discussed in more detail in the Capacity Payments and Short-Term Sales section below.

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

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

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

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

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

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

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

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

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

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

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

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

Seasonality, Weather Variations and Economic Activity — Our generation businesses are affected by seasonal weather patterns throughout the year and, therefore, operating margin is not generated evenly by month during the year. Additionally, weather variations, including temperature, solar and wind resources, and hydrological conditions, may also have an impact on generation output at our renewable generation facilities. In competitive markets for power, local economic activity can also have an impact on power demand and short-term prices for power.

Fixed-Cost Management — In our businesses with long-term contracts, the majority of the fixed O&M costs are recovered through the capacity payment. However, for all generation businesses, managing fixed costs and reducing them over time is a driver of business performance.

Competition — For our businesses with medium- or long-term contracts, there is limited competition during the term of the contract. For short-term sales, plant dispatch and the price of electricity are determined by market competition and local dispatch and reliability rules.

Utilities

AES' seven utility businesses distribute power to 9.4 million people in three countries. AES' two utilities in the U.S. also include generation capacity totaling 6,314  MW. The utility businesses have a variety of structures, ranging from integrated utility to pure transmission and distribution businesses.

In general, our utilities sell electricity directly to end-users, such as homes and businesses, and bill customers directly. Key performance drivers for utilities include the regulated rate of return and tariff, seasonality, weather variations, economic activity, reliability of service and competition. Revenue from utilities is classified as regulated in the Consolidated Statements of Operations.

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

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

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

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

Seasonality, Weather Variations and Economic Activity — Our utility businesses are affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses are not generated evenly by month during the year. Additionally, weather variations may also have an impact based on the number of customers, temperature variances from normal conditions and customers' historic usage levels and patterns. The retail kWh sales, after adjustments for weather variations, are affected by changes in local economic activity, energy efficiency and distributed generation initiatives, as well as the number of retail customers.

Reliability of Service — Our utility businesses must meet certain reliability standards, such as duration and frequency of outages. Those standards may be specific with incentives or penalties for performance against these standards. In other cases, the standards are implicit and the utility must operate to meet customer expectations.

Competition — Our integrated utilities, IPL and DP&L, operate as the sole distributor of electricity within their respective jurisdictions. Our businesses own and operate all of the businesses and facilities necessary to generate, transmit and distribute electricity. Competition in the regulated electric business is primarily from the on-site generation for industrial customers; however, in Ohio, customers in our service territory have the ability to switch to alternative suppliers for their generation service. Our integrated utilities, particularly DP&L, are exposed to the volatility in wholesale prices to the extent our generating capacity exceeds the native load served under the regulated tariff and short-term contracts. See the full discussion under the US SBU.

At our pure transmission and distribution businesses, such as those in Brazil and El Salvador, we face relatively limited competition due to significant barriers to entry. At many of these businesses, large customers, as defined by the relevant regulator, have the option to both leave and return to regulated service.

Development and Construction

We develop and construct new generation facilities. For our utility businesses, new plants may be built in response to customer needs or to comply with regulatory developments and are developed subject to regulatory approval that permits recovery of our capital cost and a return on our investment. For our generation businesses, our priority for development is platform expansion opportunities, where we can add on to our existing facilities in our key platform markets where we have a competitive advantage. We make the decision to invest in new projects by evaluating the project returns and financial profile against a fair risk-adjusted return for the investment and against alternative uses of capital, including corporate debt repayment and share buybacks.

In some cases, we enter into long-term contracts for output from new facilities prior to commencing construction. To limit required equity contributions from The AES Corporation, we also seek non-recourse project debt financing and other sources of capital, including partners where it is commercially attractive. For construction, we typically contract with a third party to manage construction, although our construction management team supervises the construction work and tracks progress against the project's budget and the required safety, efficiency and productivity standards.

Segments

The segment reporting structure uses the Company's management reporting structure as its foundation to reflect how the Company manages the business internally. It is organized by geographic regions which provide a socio-political-economic understanding of our business. For financial reporting purposes, the Company's corporate activities are reported within "Corporate and Other" because they do not require separate disclosure. See Item 7.— Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 16 — Segment and Geographic Information included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further discussion of the Company's segment structure.

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

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

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

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

U.S. Businesses

U.S. Utilities

IPALCO

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

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

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

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

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

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

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

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

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

Construction and Development — IPL's construction program is composed of capital expenditures necessary for prudent utility operations and compliance with environmental laws and regulations, along with discretionary investments designed to replace aging equipment or improve overall performance. Refer to the section above for a description of our major construction projects.

DPL

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

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

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

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

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

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

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

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

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

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

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

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

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

SSO rates are subject to rules and regulations of the PUCO and are established based on DP&L's most recently approved ESP. DP&L's distribution rates are regulated by the PUCO and are established through a traditional cost-based rate-setting process. DP&L is permitted to recover its costs of providing distribution service as well as earn a regulated rate of return on assets, determined by the regulator, based on the utility's allowed regulated asset base, capital structure and cost of capital. DP&L's wholesale transmission rates are regulated by the FERC.

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

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

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

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

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

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

and Regulations .

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

Construction and Development — Planned construction additions primarily relate to new investments in and upgrades to DP&L's power plant equipment and transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors.

DPL is projecting to spend an estimated $414 million in capital projects for the period 2017 through 2019 with 65% attributable to Transmission and Distribution. DPL's ability to complete capital projects and the reliability of future service will be affected by its financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance these construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.

U.S. Generation

Business Description — In the U.S., we own a diversified generation portfolio in terms of geography, technology and fuel source. The principal markets and locations where we are engaged in the generation and supply of electricity (energy and capacity) are the Western Electric Coordinating Council, PJM, Southwest Power Pool Electric Energy Network and Hawaii. AES Southland, in the Western Electric Coordinating Council, is our most significant generating business.

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

AES Southland

Business Description — In terms of aggregate installed capacity, AES Southland is one of the largest generation operators in California, with an installed gross capacity of 3,941 MW, accounting for approximately 5% of the state's installed capacity and 17% of the peak demand of Southern California Edison. The three coastal power plants comprising AES Southland are in areas that are critical for local reliability and play an important role in integrating the increasing amounts of renewable generation resources in California.

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

Under the Tolling Agreement, the offtaker provides gas to the three facilities thus AES Southland is not exposed to significant fuel price risk. If the units operate better than the guaranteed efficiency, AES Southland gets credit for the gas that is not consumed. Conversely, AES Southland is responsible for the cost of fuel in excess of what would have been consumed had the guaranteed efficiency been achieved. The business is also exposed to replacement power costs for a limited period if dispatched by the offtaker and not able to meet the required generation.

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

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

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

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

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

Key Financial Drivers — AES Southland's contractual availability is the single most important driver of operations. Its units are generally required to achieve at least 86% availability in each contract year. AES Southland has historically met or exceeded its contractual availability.

Additional U.S. Generation Businesses

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

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

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

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

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

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

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

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

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

Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators as defined under EPAct 1992. These businesses, subject to approval of FERC, have the right to sell power at market-based rates, either directly to the wholesale market or to a third-party offtaker such as a power marketer or utility/industrial customer. Under the FPA and FERC's regulations, approval from FERC to sell wholesale power at market-based rates is generally dependent upon a showing to FERC that the seller lacks market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no opportunity for abusive transactions involving regulated affiliates of the seller. To prevent market manipulation, FERC requires sellers with market-based rate authority to file certain reports, including a triennial updated market power analysis for markets in which they control certain threshold amounts of generation.

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

Environmental Regulation — For a discussion of environmental laws and regulations affecting the U.S. business, see Item 1.— United States Environmental and Land-Use Legislation and Regulations .

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

turbulent wind, and reduced turbine outages. In addition, PJM and ERCOT power prices impact financial results for the wind projects that are operating without long-term contracts for all or some of their capacity.

Construction and Development — Planned capital projects include the AES Southland re-powering described above. In addition to the new construction projects, U.S. Generation performs capital projects related to major plant maintenance, repairs, and upgrades to be compliant with new environmental laws and regulations.

Andes SBU

Generation — Our Andes SBU has generation facilities in three countries — Chile, Colombia and Argentina. AES Gener, which owns all of our assets in Chile, Chivor in Colombia and TermoAndes in Argentina, as detailed below, is a publicly listed company in Chile. AES has a 66.7% ownership interest in AES Gener and this business is consolidated in our financial statements.

Operating installed capacity of our Andes SBU totals 9,308 MW, of which 44%, 45% and 11% is located in Argentina, Chile and Colombia, respectively. The following table lists our Andes SBU generation facilities:

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

The following map illustrates the location of our Andes facilities:

Andes Businesses

Chile

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

AES Gener owns a diversified generation portfolio in Chile in terms of geography, technology, customers and fuel source. AES Gener's installed capacity is located near the principal electricity consumption centers, including Santiago, Valparaiso and Antofagasta. AES Gener's portfolio is composed of hydroelectric, coal, gas, diesel, solar photovoltaic and biomass facilities, that allows the businesses to operate under a variety of market and hydrological conditions, manage AES Gener's contractual obligations with regulated and unregulated customers and, as required, provide backup energy to the spot market.