Our US and Utilities SBU has 3747 generation facilities, two utilities in the United States, and four utilities in El Salvador.

The majority of projects under construction have executed long-term PPAs or, as applicable, have been assigned tariffs through a regulatory process.

The following map illustrates the locations of our US and Utilities facilities:

IPL'sAES Indiana's tariff rates for electric service to retail customers consist of basic rates and approved charges. In addition, IPL'sAES Indiana'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'sAES Indiana's retail load requirements, referred to as the Fuel Adjustment Charge, (ii) a rider for the timely recovery of costs incurred to comply with environmental laws and regulations, including a return, (iii) a rider to reflect changes in ongoing RTO costs, and (iii) a rider for the timely recovery of demand side management energy efficiency program costs, and (iv) riders for passing through to collect changes in capacity sales andcustomers wholesale sales margins and capacity sales above and below established annual benchmarks, referred to as the Capacity Adjustment(v) a rider for a return on, and Off-System Sales Margin Adjustment, respectively. Theseof, investments for eligible TDSIC improvements, and (vi) a rider for cost recovery, lost margin recoveries and performance incentives from AES Indiana's demand side management energy efficiency programs. Each of these tariff rate components function somewhat independently of one another, but the overall structure of IPL'sAES Indiana's rates is subject to review at the time of any review of IPL'sAES Indiana's basic rates and charges. Additionally, IPL'sAES Indiana's rider recoveries are reviewed through recurring filings.

On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement to increase IPL'sAES Indiana's annual revenues by $44 million, or 3% (the "2018 Base Rate Order"). This revenue increase primarily includes recovery through rates of costs associated with the CCGT at Eagle Valley, completed in the first half of 2018, and other construction projects. New base rates and charges became effective on December 5, 2018. The 2018 Base Rate Order was AES Indiana's most recent base rate order and also providesprovided customers with approximately $50 million in benefits over a two-year period through a rate adjustment mechanism that began in March 2019.over a two-year period.

IPLAES Indiana is one of many transmission system owner members in MISO, an 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. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region. IPLAES Indiana offers electricity in the MISO day-ahead and real-time markets.

Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that requests for recovery include a seven-year plan of at least five years and not more than seven for eligible investments. Once a plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation, and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in the public utility’s next generalbase rate case. The TDSIC mechanism is capped at an annual increase of two percent of total retail revenues.

On March 4, 2020, the IURC issued an order approving the projects in IPL'sAES Indiana's seven-year TDSIC Plan for eligible transmission, distribution, and storage system improvements totaling $1.2 billion from 2020 through 2027. On2026. Beginning in June 18, 2020, IPL filed its firstAES Indiana files an annual TDSIC rate adjustment for a return on, and of, investments through March 31 2020. On October 14, 2020,with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC issued an order approving thisand are filed each December. The total amount of AES Indiana’s equipment approved for TDSIC rate adjustment, whichrecovery as of December 31, 2022 was reflected in rates effective November 2020.$324 million.

AES Indiana's 2019 IRP included the retirement of 230 MW Petersburg Unit 1 on May 31, 2021 and plans to retire 415 MW Petersburg Unit 2 in 2023. In November 2021, AES Indiana received approval from the IURC for approvals and cost optionrecovery associated with the Petersburg retirements, which includes: (1) AES Indiana's creation of regulatory assets for the replacement capacity. Proposals were receivednet book value of Petersburg units 1 and 2 upon retirement; (2) a method for amortization of the regulatory assets; and (3) recovery of the regulatory assets through February 28, 2020ongoing amortization in AES Indiana’s future rate cases. The order reserves all rights of all the parties with respect to the ratemaking treatment related to the regulatory assets, including the proper rate of return and are currently being evaluated. On February 5,mechanisms for recovery.

In December 2021, IPL announced an agreement to acquireAES Indiana completed the acquisition of the Hardy Hills Solar Project, which is a 195 MW solar project subject to approvalbe developed and expected to commence operations in 2024. AES Indiana received an order from the IURC.IURC approving the project in June of 2021. In July 2021, AES Indiana executed an agreement to acquire the Petersburg Solar Project, which is a 250 MW solar and 180 MWh energy storage facility expected to commence operations in 2025. In November 2021, AES Indiana received an order from the IURC approving the project.

Electric customers within Ohio are permitted to purchase power under contract from a Competitive Retail Electric Service ("CRES") provider or from their local utility under SSO rates. The SSO generation supply is provided by third parties through a competitive bid process. Ohio utilities have the exclusive right to provide transmission and distribution services in their state-certified territories. While Ohio allows customers to choose retail generation providers, DP&LAES Ohio is required to provide retail generation service at SSO rates to any customer that has not signed a contract with a CRES provider or as a provider of last resort in the event of a CRES provider default. SSO rates are subject to rules and regulations of the PUCO and are established through a competitive bid process for the supply of power to SSO customers.

DP&L'sAES Ohio's distribution rates are regulated by the PUCO and are established through a traditional cost-based rate-setting process. DP&LAES Ohio 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'sAES Ohio's retail rates include various adjustment mechanisms including, but not limited to, the timely recovery of costs incurred related to power purchased through the competitive bid process,

AES Ohio is a member of PJM, an RTO that operates the transmission systems owned by utilities operating in all or parts of a multi-state region, including Ohio. PJM also administers the day-ahead and real-time energy markets, ancillary services market and forward capacity market for its members.

In September 2018, DP&L receivedOhio law requires utilities to file either an order fromElectric Security Plan ("ESP") or MRO plan to establish SSO rates. On December 18, 2019, the PUCO establishing new base distribution rates,approved AES Ohio's Notice of Withdrawal and reversion to its prior rate plan (ESP 1). Among other items, the PUCO Order approving the ESP 1 rate plan includes reinstating the non-bypassable RSC Rider, which became effective Octoberprovides annual revenues of approximately $79 million. The OCC has appealed to the Ohio Supreme Court, the Commission’s decision approving the reversion to ESP 1 2018. The order approved, without modification,as well as argued for a stipulationrefund of the Rate Stabilization Charge ("RSC") revenues dating back to August 2021. A decision is pending. We are unable to predict the outcome of this appeal, but if this results in terms that are more adverse than AES Ohio's current ESP rate plan, it could have a material adverse effect on our results of operations, financial condition and recommendation previouslycash flows.

On September 26, 2022, AES Ohio filed by DP&L, along with various intervening parties,its latest ESP ("ESP 4") with the PUCO staff. The order establishedPUCO. ESP 4 is a revenue requirementcomprehensive plan to enhance and upgrade its network and improve service reliability, provide greater safeguards for price stability and continue investments in local economic development. As part of $248 million for DP&L's electric service basethis plan, AES Ohio intends to increase investments in the distribution rates, which reflected an increase to distribution revenues of $30 million per year. In addition, the order authorized DP&L to collect from customers costs related to qualified investments throughinfrastructure and deploy a Distribution Investment Rider ("DIR"), changed the Decoupling Rider to reduce variability from the impact of weather and demand, partially resolved regulatory issues related to the TCJA, and authorized DP&L to defer certainproactive vegetation management costsprogram. The plan also includes proposals for future collection.

On November 30, 2020, DP&LAES Ohio filed a new Distribution Rate Case Application proposing a revenue increase of $121 million per year and incorporates DIR investments that were planned and approved in the lastdistribution rate case but not yet included in distribution rates, other distribution investments since September 2015, investments necessitated by the tornados that occurred on Memorial Day in 2019, and other proposed increases. The outcome of this filing is unknown at this time.

Separate from the ESP process, on January 23, 2020, DP&LAES Ohio filed with the PUCO requesting approval to defer its decoupling costs consistent with the methodology approved in its Distribution Rate Case. If approved, deferral would be effective December 18, 2019 and going forward would reduce impacts of weather, energy efficiency programs, and economic changes in customer demand. An evidentiary hearing was held on this matter on May 4, 2021. These amounts were also included in the ESP 4 application and are proposed to be recovered in a new rider.

A majority of solar projects under AES Clean Energy have been financed with tax equity structures. Under these tax equity structures, the tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes, that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in variability to earnings attributable to AES compared to the earnings reported at the facilities. In 2022, AES Clean Energy largely generated investment tax credits ("ITCs") from its renewable assets. We expect that the extension of the current ITCs and production tax credits ("PTCs"), as well as higher credits available for projects that satisfy wage and apprenticeship requirements under the IRA, will increase demand for our renewable products.

Laurel Mountain, Buffalo Gap I, Buffalo Gap II, and Buffalo Gap III are exposed to allow DP&L to leveragethe volatility of energy prices and integrate distributedtheir revenue may change materially as energy resources into its grid, including community solar,prices fluctuate in their respective markets of operations. Laurel Mountain also operates 16 MW of battery energy storage microgrids,that is sold into the PJM market as regulation energy. For these projects, PJM and electric vehicle charging infrastructure. DPL expectsERCOT power prices impact financial results.

To support this constructiongrowth and address challenges related to a primarily foreign supply chain for solar panels, AES has spearheaded the creation of a U.S. Solar Buyer Consortium, in cooperation with other leading solar companies, with the intent to support the development of U.S. domestic solar manufacturing.

AES Clean Energy is actively developing new products and renewable sites to serve the current and future needs of its customers. To further this aim, AES Clean Energy matured its pipeline and expanded it to a combinationtotal of cash on hand, short-term financing, long-term debt, equity capital contributions, and cash flows from operations.51 GW during 2022.

Many of our non-renewable 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. Some plants are eligible for availability bonuses if they meet certain requirements. Coal and natural gas are used as the primary fuels. Coal prices are set by market factors internationally, while natural gas prices are generally set domestically. Recently we have seen international impacts on domestic gas prices (Henry Hub) due to the large amount of U.S. natural gas that can be exported through the liquefaction plants that have come online in recent years. Price variations for these fuels can change the composition of generation costs and energy prices in our generation businesses.

Many of theseThe generation businesses have entered into long-term PPAs with utilities or other offtakers. Some businesses with PPAs have mechanisms to recover fuel costs from the offtaker, including an energy payment partially based on the market price of fuel. When market price fluctuations in fuel are borne by the offtaker, revenue may change as fuel prices fluctuate, but the variable margin or profitability should remain consistent. 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.

Warrior Run is one of our non-renewable generation businesses in the U.S. that currently operateoperates as a QF, as defined under the PURPA. This business entered into a long-term contract with an electric utility that had a mandatory obligation 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 application 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 or be a cogeneration facility that simultaneously generates electricity and processesprocess heat or steam.

Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators as defined under the EPActEnergy Policy Act of 1992, amending the Public Utility Holding Company Act (“PUHCA”). 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 FPAEnergy Policy Act and FERC's regulations, approval from FERC to sell wholesale power at market-based rates is generally dependent upon a showing to

The contracts are RAPAs with annual energy tolling put options. If Southland Energy exercises the annual put option, all capacity, energy and ancillary services will be sold to SCE in June 2019exchange for a monthly energy and commercial operationfixed capacity payment that covers fixed operating cost, debt service, and return on capital. In addition, SCE will reimburse variable costs and provide the natural gas. Southland Energy may exercise the annual put option for any contract year by delivering notice of such exercise to SCE at least one year before the start of such contract year, and no more than two years before the start of any contract year. If the annual put options are not exercised, Southland Energy is required to sell the physical output of the combined cycle gas-fired generation units to AES Integrated Energy. AES Integrated Energy is required to bid energy storageinto the California ISO market. Southland Energy continues to receive the monthly fixed capacity was achieved on January 1, 2021.payments for periods when the put option is not exercised.

Puerto Rico's electricity is 97%98% produced by thermal plants (43%(48% from petroleum, 33% from natural gas, 36%and 17% from petroleum,coal), while the remaining 2% is supplied by renewable resources (wind, solar, and 18% from coal)hydro).